The Southern Company (SO) 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Document Information [Line Items]	'	'	'
Entity Registrant Name	'SOUTHERN CO	'	'
Entity Central Index Key	'0000092122	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$38,600,000,000
Entity Common Stock, Shares Outstanding	'	887,940,630	'
Alabama Power [Member]	'	'	'
Document Information [Line Items]	'	'	'
Entity Registrant Name	'ALABAMA POWER CO	'	'
Entity Central Index Key	'0000003153	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	30,537,500	'
Georgia Power [Member]	'	'	'
Document Information [Line Items]	'	'	'
Entity Registrant Name	'GEORGIA POWER CO	'	'
Entity Central Index Key	'0000041091	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	9,261,500	'
Gulf Power [Member]	'	'	'
Document Information [Line Items]	'	'	'
Entity Registrant Name	'GULF POWER CO	'	'
Entity Central Index Key	'0000044545	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	5,442,717	'
Mississippi Power [Member]	'	'	'
Document Information [Line Items]	'	'	'
Entity Registrant Name	'MISSISSIPPI POWER CO	'	'
Entity Central Index Key	'0000066904	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	1,121,000	'
Southern Power [Member]	'	'	'
Document Information [Line Items]	'	'	'
Entity Registrant Name	'SOUTHERN POWER CO	'	'
Entity Central Index Key	'0001160661	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Filer Category	'Non-accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	1,000	'

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Operating Revenues:	'		'		'
Retail revenues	$14,541,000,000		$14,187,000,000		$15,071,000,000
Wholesale revenues	1,855,000,000		1,675,000,000		1,905,000,000
Other electric revenues	639,000,000		616,000,000		611,000,000
Other revenues	52,000,000		59,000,000		70,000,000
Total operating revenues	17,087,000,000		16,537,000,000		17,657,000,000
Operating Expenses:	'		'		'
Fuel	5,510,000,000		5,057,000,000		6,262,000,000
Purchased power	461,000,000		544,000,000		608,000,000
Other operations and maintenance	3,846,000,000		3,772,000,000		3,938,000,000
Depreciation and amortization	1,901,000,000		1,787,000,000		1,717,000,000
Taxes other than income taxes	934,000,000		914,000,000		901,000,000
Estimated loss on Kemper IGCC	1,180,000,000		0		0
Total operating expenses	13,832,000,000		12,074,000,000		13,426,000,000
Operating Income	3,255,000,000		4,463,000,000		4,231,000,000
Other Income and (Expense):	'		'		'
Allowance for equity funds used during construction	190,000,000		143,000,000		153,000,000
Interest income	19,000,000		40,000,000		21,000,000
Interest expense, net of amounts capitalized	-824,000,000		-859,000,000		-857,000,000
Other income (expense), net	-81,000,000		-38,000,000		-61,000,000
Total other income and (expense)	-696,000,000		-714,000,000		-744,000,000
Earnings Before Income Taxes	2,559,000,000		3,749,000,000		3,487,000,000
Income taxes	849,000,000		1,334,000,000		1,219,000,000
Net Income	1,710,000,000		2,415,000,000		2,268,000,000
Dividends on Preferred and Preference Stock	66,000,000		65,000,000		65,000,000
Net Income After Dividends on Preferred and Preference Stock	1,644,000,000	[1],[2]	2,350,000,000	[1]	2,203,000,000	[1]
Earnings per share (EPS) -	'		'		'
Basic EPS (in dollars per share)	$1.88		$2.70		$2.57
Diluted EPS (in dollars per share)	$1.87		$2.67		$2.55
Average number of shares of common stock outstanding	'		'		'
Basic (in shares)	877		871		857
Diluted (in shares)	881		879		864
Alabama Power [Member]	'		'		'
Operating Revenues:	'		'		'
Retail revenues	4,952,000,000		4,933,000,000		4,972,000,000
Wholesale revenues, non-affiliates	248,000,000		277,000,000		287,000,000
Wholesale revenues, affiliates	212,000,000		111,000,000		244,000,000
Other revenues	206,000,000		199,000,000		199,000,000
Total operating revenues	5,618,000,000		5,520,000,000		5,702,000,000
Operating Expenses:	'		'		'
Fuel	1,631,000,000		1,503,000,000		1,679,000,000
Purchased power, non-affiliates	100,000,000		73,000,000		73,000,000
Purchased power, affiliates	129,000,000		182,000,000		198,000,000
Other operations and maintenance	1,289,000,000		1,287,000,000		1,262,000,000
Depreciation and amortization	645,000,000		639,000,000		637,000,000
Taxes other than income taxes	348,000,000		340,000,000		339,000,000
Total operating expenses	4,142,000,000		4,024,000,000		4,188,000,000
Operating Income	1,476,000,000		1,496,000,000		1,514,000,000
Other Income and (Expense):	'		'		'
Allowance for equity funds used during construction	32,000,000		19,000,000		22,000,000
Interest income	16,000,000		16,000,000		18,000,000
Interest expense, net of amounts capitalized	-259,000,000		-287,000,000		-299,000,000
Other income (expense), net	-36,000,000		-24,000,000		-30,000,000
Total other income and (expense)	-247,000,000		-276,000,000		-289,000,000
Earnings Before Income Taxes	1,229,000,000		1,220,000,000		1,225,000,000
Income taxes	478,000,000		477,000,000		478,000,000
Net Income	751,000,000		743,000,000		747,000,000
Dividends on Preferred and Preference Stock	39,000,000		39,000,000		39,000,000
Net Income After Dividends on Preferred and Preference Stock	712,000,000		704,000,000		708,000,000
Georgia Power [Member]	'		'		'
Operating Revenues:	'		'		'
Retail revenues	7,620,000,000		7,362,000,000		8,099,000,000
Wholesale revenues, non-affiliates	281,000,000		281,000,000		341,000,000
Wholesale revenues, affiliates	20,000,000		20,000,000		32,000,000
Other revenues	353,000,000		335,000,000		328,000,000
Total operating revenues	8,274,000,000		7,998,000,000		8,800,000,000
Operating Expenses:	'		'		'
Fuel	2,307,000,000		2,051,000,000		2,789,000,000
Purchased power, non-affiliates	224,000,000		315,000,000		390,000,000
Purchased power, affiliates	660,000,000		666,000,000		713,000,000
Other operations and maintenance	1,654,000,000		1,644,000,000		1,777,000,000
Depreciation and amortization	807,000,000		745,000,000		715,000,000
Taxes other than income taxes	382,000,000		374,000,000		369,000,000
Total operating expenses	6,034,000,000		5,795,000,000		6,753,000,000
Operating Income	2,240,000,000		2,203,000,000		2,047,000,000
Other Income and (Expense):	'		'		'
Allowance for equity funds used during construction	30,000,000		53,000,000		96,000,000
Interest expense, net of amounts capitalized	-361,000,000		-366,000,000		-343,000,000
Other income (expense), net	5,000,000		-17,000,000		-13,000,000
Total other income and (expense)	-326,000,000		-330,000,000		-260,000,000
Earnings Before Income Taxes	1,914,000,000		1,873,000,000		1,787,000,000
Income taxes	723,000,000		688,000,000		625,000,000
Net Income	1,191,000,000		1,185,000,000		1,162,000,000
Dividends on Preferred and Preference Stock	17,000,000		17,000,000		17,000,000
Net Income After Dividends on Preferred and Preference Stock	1,174,000,000		1,168,000,000		1,145,000,000
Gulf Power [Member]	'		'		'
Operating Revenues:	'		'		'
Retail revenues	1,170,000,000		1,144,471,000		1,208,490,000
Wholesale revenues, non-affiliates	109,386,000		106,881,000		133,555,000
Wholesale revenues, affiliates	99,577,000		123,636,000		111,346,000
Other revenues	61,338,000		64,774,000		66,421,000
Total operating revenues	1,440,301,000		1,439,762,000		1,519,812,000
Operating Expenses:	'		'		'
Fuel	532,791,000		544,936,000		662,283,000
Purchased power, non-affiliates	52,443,000		51,421,000		48,882,000
Purchased power, affiliates	32,835,000		22,665,000		41,612,000
Other operations and maintenance	309,865,000		314,195,000		311,358,000
Depreciation and amortization	149,009,000		141,038,000		129,651,000
Taxes other than income taxes	98,355,000		97,313,000		101,302,000
Total operating expenses	1,175,298,000		1,171,568,000		1,295,088,000
Operating Income	265,003,000		268,194,000		224,724,000
Other Income and (Expense):	'		'		'
Allowance for equity funds used during construction	6,448,000		5,221,000		9,914,000
Interest income	369,000		1,408,000		54,000
Interest expense, net of amounts capitalized	-56,025,000		-60,250,000		-58,150,000
Other income (expense), net	-3,994,000		-3,227,000		-4,066,000
Total other income and (expense)	-53,202,000		-56,848,000		-52,248,000
Earnings Before Income Taxes	211,801,000		211,346,000		172,476,000
Income taxes	79,668,000		79,211,000		61,268,000
Net Income	132,133,000		132,135,000		111,208,000
Dividends on Preferred and Preference Stock	7,704,000		6,203,000		6,203,000
Net Income After Dividends on Preferred and Preference Stock	124,429,000		125,932,000		105,005,000
Mississippi Power [Member]	'		'		'
Operating Revenues:	'		'		'
Retail revenues	799,139,000		747,453,000		792,463,000
Wholesale revenues, non-affiliates	293,871,000		255,557,000		273,178,000
Wholesale revenues, affiliates	34,773,000		16,403,000		30,417,000
Other revenues	17,374,000		16,583,000		16,819,000
Total operating revenues	1,145,157,000		1,035,996,000		1,112,877,000
Operating Expenses:	'		'		'
Fuel	491,250,000		411,226,000		490,415,000
Purchased power, non-affiliates	5,752,000		5,221,000		6,239,000
Purchased power, affiliates	42,579,000		49,907,000		65,574,000
Other operations and maintenance	253,329,000		228,675,000		266,395,000
Depreciation and amortization	91,398,000		86,510,000		80,337,000
Taxes other than income taxes	80,694,000		79,445,000		70,127,000
Estimated loss on Kemper IGCC	1,102,000,000		78,000,000		0
Total operating expenses	2,067,002,000		938,984,000		979,087,000
Operating Income	-921,845,000		97,012,000		133,790,000
Other Income and (Expense):	'		'		'
Allowance for equity funds used during construction	121,629,000		64,793,000		24,707,000
Interest income	186,000		745,000		1,347,000
Interest expense, net of amounts capitalized	-36,481,000		-40,838,000		-21,691,000
Other income (expense), net	-6,216,000		519,000		-45,000
Total other income and (expense)	79,118,000		25,219,000		4,318,000
Earnings Before Income Taxes	-842,727,000		122,231,000		138,108,000
Income taxes	-367,835,000		20,556,000		42,193,000
Net Income	-474,892,000		101,675,000		95,915,000
Dividends on Preferred and Preference Stock	1,733,000		1,733,000		1,733,000
Net Income After Dividends on Preferred and Preference Stock	-476,625,000		99,942,000		94,182,000
Southern Power [Member]	'		'		'
Operating Revenues:	'		'		'
Wholesale revenues, non-affiliates	922,811,000		753,653,000		870,607,000
Wholesale revenues, affiliates	345,799,000		425,180,000		358,585,000
Other revenues	6,616,000		7,215,000		6,769,000
Total operating revenues	1,275,226,000		1,186,048,000		1,235,961,000
Operating Expenses:	'		'		'
Fuel	473,805,000		426,257,000		454,790,000
Purchased power, non-affiliates	75,954,000		80,438,000		78,368,000
Purchased power, affiliates	30,415,000		12,915,000		52,924,000
Other operations and maintenance	208,366,000		173,074,000		171,538,000
Depreciation and amortization	175,295,000		142,624,000		124,204,000
Taxes other than income taxes	21,416,000		19,309,000		17,686,000
Total operating expenses	985,251,000		854,617,000		899,510,000
Operating Income	289,975,000		331,431,000		336,451,000
Other Income and (Expense):	'		'		'
Interest expense, net of amounts capitalized	-74,475,000		-62,503,000		-77,334,000
Loss on extinguishment of debt	0		0		-19,806,000
Other income (expense), net	-4,072,000		-1,022,000		-1,223,000
Total other income and (expense)	-78,547,000		-63,525,000		-98,363,000
Earnings Before Income Taxes	211,428,000		267,906,000		238,088,000
Income taxes	45,895,000		92,621,000		75,857,000
Net Income	$165,533,000		$175,285,000		$162,231,000
[1]	(a) After dividends on preferred and preference stock of subsidiaries.
[2]	(b) Segment net income (loss) in 2013 includes $1.2 billion in pre-tax charges ($729 million after tax) for estimated probable losses on the Kemper IGCC. See Note (3) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Construction Schedule and Cost Estimate" for additional information.

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net Income	$1,710,000,000	$2,415,000,000	$2,268,000,000
Qualifying hedges:	'	'	'
Changes in fair value, net of tax	0	-12,000,000	-18,000,000
Reclassification adjustment for amounts included in net income, net of tax	9,000,000	11,000,000	9,000,000
Marketable securities:	'	'	'
Change in fair value, net of tax	-3,000,000	0	-4,000,000
Pension and other postretirement benefit plans:	'	'	'
Benefit plan net gain (loss),net of tax	36,000,000	-3,000,000	-2,000,000
Reclassification adjustment for amounts included in net income, net of tax	6,000,000	-8,000,000	-26,000,000
Total other comprehensive income (loss)	48,000,000	-12,000,000	-41,000,000
Dividends on preferred and preference stock	-66,000,000	-65,000,000	-65,000,000
Comprehensive Income	1,692,000,000	2,338,000,000	2,162,000,000
Alabama Power [Member]	'	'	'
Net Income	751,000,000	743,000,000	747,000,000
Qualifying hedges:	'	'	'
Changes in fair value, net of tax	0	-11,000,000	-9,000,000
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	2,000,000	-2,000,000
Pension and other postretirement benefit plans:	'	'	'
Total other comprehensive income (loss)	1,000,000	-9,000,000	-11,000,000
Dividends on preferred and preference stock	-39,000,000	-39,000,000	-39,000,000
Comprehensive Income	752,000,000	734,000,000	736,000,000
Georgia Power [Member]	'	'	'
Net Income	1,191,000,000	1,185,000,000	1,162,000,000
Qualifying hedges:	'	'	'
Reclassification adjustment for amounts included in net income, net of tax	2,000,000	2,000,000	2,000,000
Pension and other postretirement benefit plans:	'	'	'
Total other comprehensive income (loss)	2,000,000	2,000,000	2,000,000
Dividends on preferred and preference stock	-17,000,000	-17,000,000	-17,000,000
Comprehensive Income	1,193,000,000	1,187,000,000	1,164,000,000
Gulf Power [Member]	'	'	'
Net Income	132,133,000	132,135,000	111,208,000
Qualifying hedges:	'	'	'
Reclassification adjustment for amounts included in net income, net of tax	472,000	573,000	573,000
Pension and other postretirement benefit plans:	'	'	'
Total other comprehensive income (loss)	472,000	573,000	573,000
Dividends on preferred and preference stock	-7,704,000	-6,203,000	-6,203,000
Comprehensive Income	132,605,000	132,708,000	111,781,000
Mississippi Power [Member]	'	'	'
Net Income	-474,892,000	101,675,000	95,915,000
Qualifying hedges:	'	'	'
Changes in fair value, net of tax	0	-479,000	-8,870,000
Reclassification adjustment for amounts included in net income, net of tax	849,000	663,000	-29,000
Pension and other postretirement benefit plans:	'	'	'
Total other comprehensive income (loss)	849,000	184,000	-8,899,000
Dividends on preferred and preference stock	-1,733,000	-1,733,000	-1,733,000
Comprehensive Income	-474,043,000	101,859,000	87,016,000
Southern Power [Member]	'	'	'
Net Income	165,533,000	175,285,000	162,231,000
Qualifying hedges:	'	'	'
Changes in fair value, net of tax	0	-136,000	65,000
Reclassification adjustment for amounts included in net income, net of tax	3,695,000	6,189,000	7,125,000
Pension and other postretirement benefit plans:	'	'	'
Total other comprehensive income (loss)	3,695,000	6,053,000	7,190,000
Comprehensive Income	$169,228,000	$181,338,000	$169,421,000

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in fair value of qualifying hedges, tax	$0	($7,000,000)	($10,000,000)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	5,000,000	7,000,000	6,000,000
Change in fair value of marketable securities, tax	-2,000,000	0	-2,000,000
Benefit plan net gain (loss), tax	22,000,000	-2,000,000	-1,000,000
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	4,000,000	-4,000,000	-14,000,000
Alabama Power [Member]	'	'	'
Changes in fair value of qualifying hedges, tax	0	-7,000,000	-5,000,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	1,000,000	1,000,000	-1,000,000
Georgia Power [Member]	'	'	'
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	1,000,000	1,000,000	2,000,000
Gulf Power [Member]	'	'	'
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	297,000	360,000	360,000
Mississippi Power [Member]	'	'	'
Changes in fair value of qualifying hedges, tax	0	-296,000	-5,494,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	526,000	411,000	-18,000
Southern Power [Member]	'	'	'
Changes in fair value of qualifying hedges, tax	0	-90,000	55,000
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$2,357,000	$3,919,000	$4,837,000

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities:	'	'	'
Net Income	$1,710,000,000	$2,415,000,000	$2,268,000,000
Adjustments to reconcile net income to net cash provided from operating activities --	'	'	'
Depreciation and amortization, total	2,298,000,000	2,145,000,000	2,048,000,000
Deferred income taxes	496,000,000	1,096,000,000	1,155,000,000
Investment tax credits	302,000,000	128,000,000	85,000,000
Allowance for equity funds used during construction	-190,000,000	-143,000,000	-153,000,000
Pension, postretirement, and other employee benefits	131,000,000	-398,000,000	-45,000,000
Stock based compensation expense	59,000,000	55,000,000	42,000,000
Estimated loss on Kemper IGCC	1,180,000,000	0	0
Retail fuel cost-recovery - long-term	-123,000,000	123,000,000	0
Other, net	82,000,000	-72,000,000	-70,000,000
Changes in certain current assets and liabilities --	'	'	'
-Receivables	-153,000,000	234,000,000	362,000,000
-Fossil fuel stock	481,000,000	-452,000,000	-62,000,000
-Materials and supplies	36,000,000	-97,000,000	-60,000,000
-Other current assets	-11,000,000	-37,000,000	-17,000,000
-Accounts payable	72,000,000	-89,000,000	-5,000,000
-Accrued taxes	-85,000,000	-71,000,000	330,000,000
-Accrued compensation	-138,000,000	-28,000,000	10,000,000
-Retail fuel cost over-recovery—short-term	-66,000,000	129,000,000	-3,000,000
-Other current liabilities	16,000,000	-40,000,000	18,000,000
Net cash provided from operating activities	6,097,000,000	4,898,000,000	5,903,000,000
Investing Activities:	'	'	'
Property additions	-5,463,000,000	-4,809,000,000	-4,525,000,000
Investment in restricted cash	-149,000,000	-280,000,000	1,000,000
Distribution of restricted cash	96,000,000	284,000,000	63,000,000
Nuclear decommissioning trust fund purchases	-986,000,000	-1,046,000,000	-2,195,000,000
Nuclear decommissioning trust fund sales	984,000,000	1,043,000,000	2,190,000,000
Cost of removal, net of salvage	-131,000,000	-149,000,000	-93,000,000
Change in construction payables	-126,000,000	-84,000,000	198,000,000
Other investing activities	33,000,000	-127,000,000	178,000,000
Net cash used for investing activities	-5,742,000,000	-5,168,000,000	-4,183,000,000
Financing Activities:	'	'	'
Increase (decrease) in notes payable, net	662,000,000	-30,000,000	-438,000,000
Proceeds --	'	'	'
Long-term debt issuances	2,938,000,000	4,404,000,000	3,719,000,000
Interest-bearing refundable deposit related to asset sale	0	150,000,000	0
Issuance of preference stock	50,000,000	0	0
Common stock issuances	695,000,000	397,000,000	723,000,000
Redemptions and repurchases --	'	'	'
Long-term debt	-2,830,000,000	-3,169,000,000	-3,170,000,000
Common stock repurchased	-20,000,000	-430,000,000	0
Payment of common stock dividends	-1,762,000,000	-1,693,000,000	-1,601,000,000
Payment of dividends on preferred and preference stock of subsidiaries	-66,000,000	-65,000,000	-65,000,000
Other financing activities	9,000,000	19,000,000	-20,000,000
Net cash provided from (used for) financing activities	-324,000,000	-417,000,000	-852,000,000
Net Change in Cash and Cash Equivalents	31,000,000	-687,000,000	868,000,000
Cash and Cash Equivalents at Beginning of Year	628,000,000	1,315,000,000	447,000,000
Cash and Cash Equivalents at End of Year	659,000,000	628,000,000	1,315,000,000
Supplemental Cash Flow Information [Abstract]	'	'	'
Interest paid, net of amounts capitalized	759,000,000	803,000,000	832,000,000
Income taxes (net of refunds)	139,000,000	38,000,000	-401,000,000
Alabama Power [Member]	'	'	'
Operating Activities:	'	'	'
Net Income	751,000,000	743,000,000	747,000,000
Adjustments to reconcile net income to net cash provided from operating activities --	'	'	'
Depreciation and amortization, total	816,000,000	767,000,000	749,000,000
Deferred income taxes	198,000,000	164,000,000	459,000,000
Allowance for equity funds used during construction	-32,000,000	-19,000,000	-22,000,000
Pension, postretirement, and other employee benefits	9,000,000	-21,000,000	-41,000,000
Stock based compensation expense	10,000,000	9,000,000	6,000,000
Natural disaster reserve	3,000,000	3,000,000	34,000,000
Other, net	-41,000,000	-27,000,000	-41,000,000
Changes in certain current assets and liabilities --	'	'	'
-Receivables	2,000,000	23,000,000	18,000,000
-Fossil fuel stock	146,000,000	-132,000,000	47,000,000
-Materials and supplies	19,000,000	-21,000,000	-33,000,000
-Other current assets	5,000,000	-4,000,000	-6,000,000
-Accounts payable	35,000,000	-77,000,000	11,000,000
-Accrued taxes	-23,000,000	-12,000,000	157,000,000
-Accrued compensation	-23,000,000	-3,000,000	-12,000,000
-Retail fuel cost over-recovery—short-term	42,000,000	1,000,000	0
-Other current liabilities	-3,000,000	-18,000,000	-25,000,000
Net cash provided from operating activities	1,914,000,000	1,376,000,000	2,048,000,000
Investing Activities:	'	'	'
Property additions	-1,107,000,000	-867,000,000	-977,000,000
Investment in restricted cash from pollution control bonds	0	1,000,000	4,000,000
Distribution of restricted cash	0	0	13,000,000
Nuclear decommissioning trust fund purchases	-280,000,000	-194,000,000	-350,000,000
Nuclear decommissioning trust fund sales	279,000,000	193,000,000	349,000,000
Cost of removal, net of salvage	-47,000,000	-33,000,000	-28,000,000
Change in construction payables	-13,000,000	12,000,000	-9,000,000
Other investing activities	26,000,000	-46,000,000	9,000,000
Net cash used for investing activities	-1,142,000,000	-934,000,000	-989,000,000
Proceeds --	'	'	'
Capital contributions from parent company	24,000,000	27,000,000	12,000,000
Senior note issuances	300,000,000	1,000,000,000	700,000,000
Redemptions and repurchases --	'	'	'
Pollution control revenue bonds	0	-1,000,000	-4,000,000
Senior notes	-250,000,000	-950,000,000	-750,000,000
Payment of preferred and preference stock dividends	-39,000,000	-39,000,000	-39,000,000
Payment of common stock dividends	-644,000,000	-684,000,000	-774,000,000
Other financing activities	-5,000,000	-2,000,000	-14,000,000
Net cash provided from (used for) financing activities	-614,000,000	-649,000,000	-869,000,000
Net Change in Cash and Cash Equivalents	158,000,000	-207,000,000	190,000,000
Cash and Cash Equivalents at Beginning of Year	137,000,000	344,000,000	154,000,000
Cash and Cash Equivalents at End of Year	295,000,000	137,000,000	344,000,000
Supplemental Cash Flow Information [Abstract]	'	'	'
Interest paid, net of amounts capitalized	243,000,000	273,000,000	286,000,000
Income taxes (net of refunds)	296,000,000	309,000,000	-139,000,000
Noncash transactions - accrued property additions at year-end	18,000,000	31,000,000	19,000,000
Georgia Power [Member]	'	'	'
Operating Activities:	'	'	'
Net Income	1,191,000,000	1,185,000,000	1,162,000,000
Adjustments to reconcile net income to net cash provided from operating activities --	'	'	'
Depreciation and amortization, total	979,000,000	912,000,000	867,000,000
Deferred income taxes	476,000,000	377,000,000	500,000,000
Allowance for equity funds used during construction	-30,000,000	-53,000,000	-96,000,000
Pension, postretirement, and other employee benefits	59,000,000	9,000,000	-29,000,000
Retail fuel cost-recovery - long-term	-123,000,000	123,000,000	0
Other, net	37,000,000	-12,000,000	-23,000,000
Changes in certain current assets and liabilities --	'	'	'
-Receivables	-58,000,000	205,000,000	235,000,000
-Fossil fuel stock	250,000,000	-269,000,000	-99,000,000
-Prepaid income taxes	-17,000,000	-7,000,000	72,000,000
-Other current assets	40,000,000	-53,000,000	-21,000,000
-Accounts payable	67,000,000	-165,000,000	44,000,000
-Accrued taxes	-14,000,000	-76,000,000	-36,000,000
-Accrued compensation	-37,000,000	-18,000,000	7,000,000
-Retail fuel cost over-recovery—short-term	-49,000,000	107,000,000	0
-Other current liabilities	-5,000,000	30,000,000	49,000,000
Net cash provided from operating activities	2,766,000,000	2,295,000,000	2,632,000,000
Investing Activities:	'	'	'
Property additions	-1,743,000,000	-1,723,000,000	-1,861,000,000
Investment in restricted cash from pollution control bonds	-89,000,000	-284,000,000	0
Distribution of restricted cash from pollution control revenue bonds	89,000,000	284,000,000	0
Nuclear decommissioning trust fund purchases	-706,000,000	-852,000,000	-1,845,000,000
Nuclear decommissioning trust fund sales	705,000,000	850,000,000	1,841,000,000
Cost of removal, net of salvage	-59,000,000	-82,000,000	-42,000,000
Change in construction payables, net of joint owner portion	-67,000,000	-149,000,000	123,000,000
Other investing activities	-20,000,000	-17,000,000	-7,000,000
Net cash used for investing activities	-1,890,000,000	-1,973,000,000	-1,791,000,000
Financing Activities:	'	'	'
Increase (decrease) in notes payable, net	1,047,000,000	-513,000,000	-61,000,000
Proceeds --	'	'	'
Capital contributions from parent company	37,000,000	42,000,000	214,000,000
Pollution control revenue bonds issuances and remarketings	194,000,000	284,000,000	604,000,000
Senior note issuances	850,000,000	2,300,000,000	550,000,000
Other long-term debt issuances	0	0	250,000,000
Redemptions and repurchases --	'	'	'
Pollution control revenue bonds	-298,000,000	-284,000,000	-339,000,000
Senior notes	-1,775,000,000	-850,000,000	-427,000,000
Other long-term debt	0	-250,000,000	-303,000,000
Long-term debt to affiliate trust	0	0	-206,000,000
Payment of preferred and preference stock dividends	-17,000,000	-17,000,000	-17,000,000
Payment of common stock dividends	-907,000,000	-983,000,000	-1,096,000,000
Other financing activities	-22,000,000	-19,000,000	-5,000,000
Net cash provided from (used for) financing activities	-891,000,000	-290,000,000	-836,000,000
Net Change in Cash and Cash Equivalents	-15,000,000	32,000,000	5,000,000
Cash and Cash Equivalents at Beginning of Year	45,000,000	13,000,000	8,000,000
Cash and Cash Equivalents at End of Year	30,000,000	45,000,000	13,000,000
Supplemental Cash Flow Information [Abstract]	'	'	'
Interest paid, net of amounts capitalized	344,000,000	337,000,000	346,000,000
Income taxes (net of refunds)	298,000,000	312,000,000	54,000,000
Noncash transactions - accrued property additions at year-end	208,000,000	261,000,000	391,000,000
Gulf Power [Member]	'	'	'
Operating Activities:	'	'	'
Net Income	132,133,000	132,135,000	111,208,000
Adjustments to reconcile net income to net cash provided from operating activities --	'	'	'
Depreciation and amortization, total	155,798,000	147,723,000	135,790,000
Deferred income taxes	77,069,000	174,305,000	63,228,000
Allowance for equity funds used during construction	-6,448,000	-5,221,000	-9,914,000
Pension, postretirement, and other employee benefits	11,422,000	-8,109,000	-356,000
Stock based compensation expense	1,749,000	1,647,000	1,318,000
Other, net	5,866,000	4,518,000	-8,258,000
Changes in certain current assets and liabilities --	'	'	'
-Receivables	-49,051,000	8,713,000	21,518,000
-Prepayments	-337,000	417,000	10,150,000
-Fossil fuel stock	19,468,000	-6,144,000	17,519,000
-Materials and supplies	-1,570,000	-3,035,000	-5,073,000
-Prepaid income taxes	15,526,000	355,000	26,901,000
-Other current assets	1,018,000	0	40,000
-Accounts payable	-6,964,000	-5,195,000	-2,528,000
-Accrued taxes	-4,759,000	-4,705,000	1,475,000
-Accrued compensation	-3,309,000	481,000	25,000
-Over recovered regulatory clause revenues	-17,092,000	-10,858,000	10,247,000
-Other current liabilities	-782,000	-7,837,000	2,937,000
Net cash provided from operating activities	329,737,000	419,190,000	376,227,000
Investing Activities:	'	'	'
Property additions	-292,914,000	-313,257,000	-324,372,000
Cost of removal, net of salvage	-13,827,000	-28,993,000	-14,471,000
Change in construction payables	6,796,000	1,161,000	2,902,000
Payments pursuant to long-term service agreements	-7,109,000	-8,119,000	-8,007,000
Other investing activities	496,000	656,000	420,000
Net cash used for investing activities	-306,558,000	-348,552,000	-343,528,000
Financing Activities:	'	'	'
Increase (decrease) in notes payable, net	12,108,000	16,075,000	21,324,000
Proceeds --	'	'	'
Issuance of preference stock	50,000,000	0	0
Capital contributions from parent company	2,987,000	2,106,000	2,101,000
Pollution control revenue bonds issuances and remarketings	63,000,000	13,000,000	0
Common stock issuances	40,000,000	40,000,000	50,000,000
Senior note issuances	90,000,000	100,000,000	125,000,000
Redemptions and repurchases --	'	'	'
Pollution control revenue bonds	-76,000,000	-13,000,000	0
Senior notes	-90,000,000	-91,363,000	-608,000
Other long-term debt	0	0	-110,000,000
Payment of preferred and preference stock dividends	-7,004,000	-6,203,000	-6,203,000
Payment of common stock dividends	-115,400,000	-115,800,000	-110,000,000
Other financing activities	-3,284,000	-614,000	-3,419,000
Net cash provided from (used for) financing activities	-33,593,000	-55,799,000	-31,805,000
Net Change in Cash and Cash Equivalents	-10,414,000	14,839,000	894,000
Cash and Cash Equivalents at Beginning of Year	32,167,000	17,328,000	16,434,000
Cash and Cash Equivalents at End of Year	21,753,000	32,167,000	17,328,000
Supplemental Cash Flow Information [Abstract]	'	'	'
Interest paid, net of amounts capitalized	53,401,000	58,255,000	55,486,000
Income taxes (net of refunds)	-10,727,000	-96,639,000	-26,345,000
Noncash transactions - accrued property additions at year-end	31,546,000	27,369,000	19,439,000
Mississippi Power [Member]	'	'	'
Operating Activities:	'	'	'
Net Income	-474,892,000	101,675,000	95,915,000
Adjustments to reconcile net income to net cash provided from operating activities --	'	'	'
Depreciation and amortization, total	92,465,000	86,981,000	83,787,000
Deferred income taxes	-396,400,000	17,688,000	71,764,000
Investment tax credits received	144,036,000	82,464,000	0
Allowance for equity funds used during construction	-121,629,000	-64,793,000	-24,707,000
Pension, postretirement, and other employee benefits	13,953,000	-35,425,000	3,169,000
Stock based compensation expense	2,510,000	2,084,000	1,548,000
Estimated loss on Kemper IGCC	1,102,000,000	78,000,000	0
Kemper regulatory deferral	90,524,000	0	0
Hedge settlements	0	-15,983,000	848,000
Regulatory assets associated with Kemper IGCC	-35,220,000	-15,445,000	-7,719,000
Other, net	14,585,000	10,516,000	-433,000
Changes in certain current assets and liabilities --	'	'	'
-Receivables	-25,001,000	-6,589,000	5,864,000
-Fossil fuel stock	63,093,000	-36,206,000	-27,933,000
-Materials and supplies	-11,087,000	-3,473,000	-2,116,000
-Prepaid income taxes	16,644,000	-3,852,000	12,907,000
-Other current assets	-4,363,000	-19,851,000	1,606,000
-Accounts payable	12,693,000	8,814,000	24,143,000
-Accrued taxes	11,141,000	13,768,000	1,209,000
Accrued interest	16,768,000	17,627,000	6,817,000
-Accrued compensation	-6,382,000	-183,000	-187,000
-Over recovered regulatory clause revenues	-58,979,000	16,836,000	-16,544,000
-Other current liabilities	1,109,000	757,000	1,557,000
Net cash provided from operating activities	447,568,000	235,410,000	231,495,000
Investing Activities:	'	'	'
Property additions	-1,640,782,000	-1,620,047,000	-964,233,000
Cash paid for acquisitions	0	0	-84,803,000
Distribution of restricted cash	0	0	50,000,000
Cost of removal, net of salvage	-10,386,000	-4,355,000	-7,432,000
Change in construction payables	-50,000,000	78,961,000	97,079,000
Capital grant proceeds	4,500,000	13,372,000	232,442,000
Proceeds from asset sales	79,020,000	0	0
Other investing activities	14,903,000	-16,706,000	-5,736,000
Net cash used for investing activities	-1,602,745,000	-1,548,775,000	-682,683,000
Proceeds --	'	'	'
Interest-bearing refundable deposit related to asset sale	0	150,000,000	0
Bonds-Other	42,342,000	51,471,000	0
Capital contributions from parent company	1,077,088,000	702,971,000	299,305,000
Senior note issuances	0	600,000,000	300,000,000
Other long-term debt issuances	475,000,000	50,000,000	115,000,000
Redemptions and repurchases --	'	'	'
Bonds-Other	-82,563,000	0	0
Senior notes	-50,000,000	-90,000,000	0
Other long-term debt	-125,000,000	-115,000,000	-130,000,000
Return of paid in capital	-104,804,000	0	0
Payment of preferred and preference stock dividends	-1,733,000	-1,733,000	-1,733,000
Payment of common stock dividends	-71,956,000	-106,800,000	-75,500,000
Other financing activities	-3,040,000	5,879,000	-5,078,000
Net cash provided from (used for) financing activities	1,155,334,000	1,246,788,000	501,994,000
Net Change in Cash and Cash Equivalents	157,000	-66,577,000	50,806,000
Cash and Cash Equivalents at Beginning of Year	145,008,000	211,585,000	160,779,000
Cash and Cash Equivalents at End of Year	145,165,000	145,008,000	211,585,000
Supplemental Cash Flow Information [Abstract]	'	'	'
Interest paid, net of amounts capitalized	20,285,000	32,589,000	14,814,000
Income taxes (net of refunds)	-134,198,000	-77,580,000	-41,024,000
Noncash transactions - accrued property additions at year-end	164,863,000	214,863,000	135,902,000
Noncash transactions - capital lease obligation	82,915,000	0	0
Assumption of debt due to plant acquisition	0	0	346,051,000
Southern Power [Member]	'	'	'
Operating Activities:	'	'	'
Net Income	165,533,000	175,285,000	162,231,000
Adjustments to reconcile net income to net cash provided from operating activities --	'	'	'
Depreciation and amortization, total	177,704,000	153,635,000	138,787,000
Deferred income taxes	171,301,000	228,780,000	4,481,000
Investment tax credits received	158,096,000	45,047,000	84,723,000
Deferred revenues	-18,477,000	-12,633,000	-10,594,000
Mark-to-market adjustments	850,000	-9,275,000	8,000,000
Loss on extinguishment of debt	0	0	19,806,000
Other, net	3,335,000	3,104,000	495,000
Changes in certain current assets and liabilities --	'	'	'
-Receivables	-11,178,000	-1,384,000	10,448,000
-Fossil fuel stock	2,438,000	-8,578,000	532,000
-Materials and supplies	-8,410,000	-7,825,000	-4,097,000
-Prepaid income taxes	-29,609,000	-3,223,000	10,693,000
-Other current assets	-2,219,000	-1,624,000	-485,000
-Accounts payable	-11,572,000	10,514,000	-6,138,000
-Accrued taxes	-299,000	431,000	2,134,000
Accrued interest	6,093,000	385,000	-8,102,000
-Other current liabilities	777,000	492,000	-535,000
Net cash provided from operating activities	604,363,000	573,131,000	412,379,000
Investing Activities:	'	'	'
Property additions	-500,756,000	-116,633,000	-254,725,000
Cash paid for acquisitions	-132,163,000	-124,059,000	0
Change in construction payables, net of joint owner portion	-4,072,000	-27,387,000	-14,291,000
Payments pursuant to long-term service agreements	-57,269,000	-63,932,000	-57,969,000
Other investing activities	-1,725,000	-446,000	-1,387,000
Net cash used for investing activities	-695,985,000	-332,457,000	-328,372,000
Financing Activities:	'	'	'
Increase (decrease) in notes payable, net	-70,968,000	-108,552,000	-90,267,000
Proceeds --	'	'	'
Capital contributions from parent company	1,487,000	-662,000	127,241,000
Senior note issuances	300,000,000	0	575,000,000
Other long-term debt issuances	23,583,000	5,470,000	0
Redemptions and repurchases --	'	'	'
Senior notes	0	0	-575,000,000
Other long-term debt	-9,284,000	-2,450,000	-3,691,000
Premium for early debt extinguishment	0	0	-19,375,000
Payment of common stock dividends	-129,120,000	-127,000,000	-91,200,000
Other financing activities	16,076,000	4,169,000	-3,976,000
Net cash provided from (used for) financing activities	131,774,000	-229,025,000	-81,268,000
Net Change in Cash and Cash Equivalents	40,152,000	11,649,000	2,739,000
Cash and Cash Equivalents at Beginning of Year	28,592,000	16,943,000	14,204,000
Cash and Cash Equivalents at End of Year	68,744,000	28,592,000	16,943,000
Supplemental Cash Flow Information [Abstract]	'	'	'
Interest paid, net of amounts capitalized	60,396,000	50,248,000	74,989,000
Income taxes (net of refunds)	-226,179,000	-175,269,000	-26,486,000
Noncash transactions - accrued property additions at year-end	$5,567,000	$11,203,000	$32,590,000

Consolidated_Statements_of_Cas1

Consolidated Statements of Cash Flows (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net cash paid for capitalized interest	$92,000	$83,000	$78,000
Alabama Power [Member]	'	'	'
Net cash paid for capitalized interest	11,000	7,000	9,000
Georgia Power [Member]	'	'	'
Net cash paid for capitalized interest	14,000	21,000	37,000
Gulf Power [Member]	'	'	'
Net cash paid for capitalized interest	3,421	2,500	3,951
Mississippi Power [Member]	'	'	'
Net cash paid for capitalized interest	54,118	32,816	10,065
Southern Power [Member]	'	'	'
Net cash paid for capitalized interest	$9,178	$19,092	$18,001

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
Current Assets:	'	'
Cash and cash equivalents	$659,000,000	$628,000,000
Restricted cash and cash equivalents	0	7,000,000
Receivables --	'	'
Customer accounts receivable	1,027,000,000	961,000,000
Unbilled revenues	448,000,000	441,000,000
Under recovered regulatory clause revenues	58,000,000	29,000,000
Other accounts and notes receivable	304,000,000	235,000,000
Accumulated provision for uncollectible accounts	-18,000,000	-17,000,000
Fossil fuel stock, at average cost	1,339,000,000	1,819,000,000
Materials and supplies, at average cost	959,000,000	1,000,000,000
Vacation pay	171,000,000	165,000,000
Prepaid expenses	489,000,000	657,000,000
Other regulatory assets, current	124,000,000	163,000,000
Other current assets	39,000,000	74,000,000
Total current assets	5,599,000,000	6,162,000,000
Property, Plant, and Equipment:	'	'
In service	66,021,000,000	63,251,000,000
Less accumulated depreciation	23,059,000,000	21,964,000,000
Plant in service, net of depreciation	42,962,000,000	41,287,000,000
Other utility plant, net	240,000,000	263,000,000
Nuclear fuel, at amortized cost	855,000,000	851,000,000
Construction work in progress	7,151,000,000	5,989,000,000
Total property, plant, and equipment	51,208,000,000	48,390,000,000
Other Property and Investments:	'	'
Nuclear decommissioning trusts, at fair value	1,465,000,000	1,303,000,000
Leveraged leases	665,000,000	670,000,000
Miscellaneous property and investments	218,000,000	216,000,000
Total other property and investments	2,348,000,000	2,189,000,000
Deferred Charges and Other Assets:	'	'
Deferred charges related to income taxes	1,432,000,000	1,385,000,000
Prepaid pension costs	419,000,000	0
Unamortized debt issuance expense	139,000,000	133,000,000
Unamortized loss on reacquired debt	293,000,000	309,000,000
Other regulatory assets, deferred	2,557,000,000	4,032,000,000
Other deferred charges and assets	551,000,000	549,000,000
Total deferred charges and other assets	5,391,000,000	6,408,000,000
Total Assets	64,546,000,000	63,149,000,000
Current Liabilities:	'	'
Securities due within one year	469,000,000	2,335,000,000
Interest-bearing refundable deposit related to asset sale	150,000,000	150,000,000
Notes payable	1,482,000,000	825,000,000
Accounts payable	1,376,000,000	1,387,000,000
Customer deposits	380,000,000	370,000,000
Accrued taxes --	'	'
Accrued income taxes	13,000,000	10,000,000
Other accrued taxes	456,000,000	391,000,000
Accrued interest	251,000,000	237,000,000
Accrued vacation pay	217,000,000	212,000,000
Accrued compensation	303,000,000	433,000,000
Other regulatory liabilities, current	92,000,000	107,000,000
Other current liabilities	347,000,000	557,000,000
Total current liabilities	5,536,000,000	7,014,000,000
Senior notes -	'	'
Unamortized debt premium	79,000,000	88,000,000
Unamortized debt discount	-30,000,000	-35,000,000
Long-term Debt	21,344,000,000	19,274,000,000
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes	10,563,000,000	9,938,000,000
Deferred credits related to income taxes	202,000,000	211,000,000
Accumulated deferred investment tax credits	966,000,000	894,000,000
Employee benefit obligations	1,461,000,000	2,540,000,000
Asset retirement obligations	2,006,000,000	1,748,000,000
Other cost of removal obligations	1,270,000,000	1,194,000,000
Other regulatory liabilities, deferred	475,000,000	289,000,000
Other deferred credits and liabilities	584,000,000	668,000,000
Total deferred credits and other liabilities	17,527,000,000	17,482,000,000
Total Liabilities	44,407,000,000	43,770,000,000
Redeemable Preferred Stock of Subsidiaries	375,000,000	375,000,000
Common Stockholders' Equity:	'	'
Common stock	4,461,000,000	4,389,000,000
Paid-in capital	5,362,000,000	4,855,000,000
Retained earnings	9,510,000,000	9,626,000,000
Accumulated other comprehensive loss	-75,000,000	-123,000,000
Total Common Stockholders' Equity	19,008,000,000	18,297,000,000
Total stockholders' equity	19,764,000,000	19,004,000,000
Total Liabilities and Stockholders' Equity	64,546,000,000	63,149,000,000
Commitments and Contingent Matters	'	'
Alabama Power [Member]	'	'
Current Assets:	'	'
Cash and cash equivalents	295,000,000	137,000,000
Receivables --	'	'
Customer accounts receivable	341,000,000	321,000,000
Unbilled revenues	142,000,000	138,000,000
Under recovered regulatory clause revenues	0	23,000,000
Other accounts and notes receivable	30,000,000	42,000,000
Affiliated companies	54,000,000	55,000,000
Accumulated provision for uncollectible accounts	-8,000,000	-8,000,000
Fossil fuel stock, at average cost	329,000,000	475,000,000
Materials and supplies, at average cost	375,000,000	395,000,000
Vacation pay	63,000,000	61,000,000
Prepaid expenses	57,000,000	81,000,000
Other regulatory assets, current	7,000,000	24,000,000
Other current assets	6,000,000	13,000,000
Total current assets	1,691,000,000	1,757,000,000
Property, Plant, and Equipment:	'	'
In service	22,092,000,000	21,407,000,000
Less accumulated depreciation	8,114,000,000	7,761,000,000
Plant in service, net of depreciation	13,978,000,000	13,646,000,000
Nuclear fuel, at amortized cost	332,000,000	354,000,000
Construction work in progress	748,000,000	438,000,000
Total property, plant, and equipment	15,058,000,000	14,438,000,000
Other Property and Investments:	'	'
Equity investments in unconsolidated subsidiaries	54,000,000	53,000,000
Nuclear decommissioning trusts, at fair value	714,000,000	605,000,000
Miscellaneous property and investments	80,000,000	78,000,000
Total other property and investments	848,000,000	736,000,000
Deferred Charges and Other Assets:	'	'
Deferred charges related to income taxes	519,000,000	525,000,000
Prepaid pension costs	276,000,000	0
Deferred under recovered regulatory clause revenues	25,000,000	11,000,000
Other regulatory assets, deferred	692,000,000	1,083,000,000
Other deferred charges and assets	142,000,000	162,000,000
Total deferred charges and other assets	1,654,000,000	1,781,000,000
Total Assets	19,251,000,000	18,712,000,000
Current Liabilities:	'	'
Securities due within one year	0	250,000,000
Affiliated	198,000,000	191,000,000
Accounts payable	339,000,000	318,000,000
Customer deposits	85,000,000	85,000,000
Accrued taxes --	'	'
Accrued income taxes	11,000,000	5,000,000
Other accrued taxes	33,000,000	33,000,000
Accrued interest	61,000,000	62,000,000
Accrued vacation pay	53,000,000	50,000,000
Accrued compensation	74,000,000	94,000,000
Other regulatory liabilities, current	37,000,000	3,000,000
Other current liabilities	41,000,000	52,000,000
Total current liabilities	932,000,000	1,143,000,000
Senior notes -	'	'
Long-term Debt	6,233,000,000	5,929,000,000
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes	3,603,000,000	3,404,000,000
Deferred credits related to income taxes	75,000,000	79,000,000
Accumulated deferred investment tax credits	133,000,000	141,000,000
Employee benefit obligations	195,000,000	321,000,000
Asset retirement obligations	730,000,000	589,000,000
Other cost of removal obligations	828,000,000	759,000,000
Other regulatory liabilities, deferred	259,000,000	183,000,000
Deferred over recovered regulatory clause revenues	15,000,000	0
Other deferred credits and liabilities	61,000,000	81,000,000
Total deferred credits and other liabilities	5,899,000,000	5,557,000,000
Total Liabilities	13,064,000,000	12,629,000,000
Redeemable Preferred Stock of Subsidiaries	342,000,000	342,000,000
Redeemable Preferred Stock	342,000,000	342,000,000
Preference Stock	343,000,000	343,000,000
Common Stockholders' Equity:	'	'
Common stock	1,222,000,000	1,222,000,000
Paid-in capital	2,262,000,000	2,227,000,000
Retained earnings	2,044,000,000	1,976,000,000
Accumulated other comprehensive loss	-26,000,000	-27,000,000
Total Common Stockholders' Equity	5,502,000,000	5,398,000,000
Total stockholders' equity	5,502,000,000	5,398,000,000
Total Liabilities and Stockholders' Equity	19,251,000,000	18,712,000,000
Commitments and Contingent Matters	'	'
Georgia Power [Member]	'	'
Current Assets:	'	'
Cash and cash equivalents	30,000,000	45,000,000
Receivables --	'	'
Customer accounts receivable	512,000,000	484,000,000
Unbilled revenues	209,000,000	217,000,000
Joint owner accounts receivable	67,000,000	51,000,000
Other accounts and notes receivable	117,000,000	68,000,000
Affiliated companies	21,000,000	23,000,000
Accumulated provision for uncollectible accounts	-5,000,000	-6,000,000
Fossil fuel stock, at average cost	742,000,000	992,000,000
Materials and supplies, at average cost	409,000,000	452,000,000
Vacation pay	88,000,000	85,000,000
Prepaid income taxes	97,000,000	164,000,000
Other regulatory assets, current	66,000,000	72,000,000
Other current assets	54,000,000	104,000,000
Total current assets	2,407,000,000	2,751,000,000
Property, Plant, and Equipment:	'	'
In service	30,132,000,000	29,244,000,000
Less accumulated depreciation	10,970,000,000	10,431,000,000
Plant in service, net of depreciation	19,162,000,000	18,813,000,000
Other utility plant, net	240,000,000	263,000,000
Nuclear fuel, at amortized cost	523,000,000	497,000,000
Construction work in progress	3,500,000,000	2,893,000,000
Total property, plant, and equipment	23,425,000,000	22,466,000,000
Other Property and Investments:	'	'
Equity investments in unconsolidated subsidiaries	46,000,000	45,000,000
Nuclear decommissioning trusts, at fair value	751,000,000	698,000,000
Miscellaneous property and investments	44,000,000	44,000,000
Total other property and investments	841,000,000	787,000,000
Deferred Charges and Other Assets:	'	'
Deferred charges related to income taxes	718,000,000	733,000,000
Prepaid pension costs	118,000,000	0
Other regulatory assets, deferred	1,152,000,000	1,798,000,000
Other deferred charges and assets	246,000,000	268,000,000
Total deferred charges and other assets	2,234,000,000	2,799,000,000
Total Assets	28,907,000,000	28,803,000,000
Current Liabilities:	'	'
Securities due within one year	5,000,000	1,680,000,000
Notes payable	1,047,000,000	2,000,000
Affiliated	417,000,000	417,000,000
Accounts payable	472,000,000	436,000,000
Customer deposits	246,000,000	237,000,000
Accrued taxes --	'	'
Accrued income taxes	0	6,000,000
Other accrued taxes	321,000,000	260,000,000
Accrued interest	91,000,000	100,000,000
Accrued vacation pay	61,000,000	61,000,000
Accrued compensation	80,000,000	113,000,000
Liabilities from risk management activities	13,000,000	30,000,000
Other regulatory liabilities, current	17,000,000	73,000,000
Over recovered regulatory clause revenues, current	14,000,000	107,000,000
Other current liabilities	122,000,000	146,000,000
Total current liabilities	2,906,000,000	3,668,000,000
Senior notes -	'	'
Long-term Debt	8,633,000,000	7,994,000,000
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes	5,200,000,000	4,861,000,000
Deferred credits related to income taxes	112,000,000	115,000,000
Accumulated deferred investment tax credits	203,000,000	208,000,000
Employee benefit obligations	542,000,000	950,000,000
Deferred capacity expense	162,000,000	169,000,000
Asset retirement obligations	1,210,000,000	1,097,000,000
Other cost of removal obligations	43,000,000	63,000,000
Other deferred credits and liabilities	201,000,000	308,000,000
Total deferred credits and other liabilities	7,511,000,000	7,602,000,000
Total Liabilities	19,050,000,000	19,264,000,000
Redeemable Preferred Stock	45,000,000	45,000,000
Preference Stock	221,000,000	221,000,000
Common Stockholders' Equity:	'	'
Common stock	398,000,000	398,000,000
Paid-in capital	5,633,000,000	5,585,000,000
Retained earnings	3,565,000,000	3,297,000,000
Accumulated other comprehensive loss	-5,000,000	-7,000,000
Total Common Stockholders' Equity	9,591,000,000	9,273,000,000
Total stockholders' equity	9,591,000,000	9,273,000,000
Total Liabilities and Stockholders' Equity	28,907,000,000	28,803,000,000
Commitments and Contingent Matters	'	'
Gulf Power [Member]	'	'
Current Assets:	'	'
Cash and cash equivalents	21,753,000	32,167,000
Receivables --	'	'
Customer accounts receivable	64,884,000	58,449,000
Unbilled revenues	57,282,000	53,363,000
Under recovered regulatory clause revenues	48,282,000	6,138,000
Other accounts and notes receivable	8,620,000	11,859,000
Affiliated companies	8,259,000	13,624,000
Accumulated provision for uncollectible accounts	-1,131,000	-1,490,000
Fossil fuel stock, at average cost	135,050,000	153,710,000
Materials and supplies, at average cost	54,935,000	53,365,000
Prepaid expenses	33,186,000	62,877,000
Other regulatory assets, current	18,536,000	30,576,000
Other current assets	6,120,000	2,690,000
Total current assets	455,776,000	477,328,000
Property, Plant, and Equipment:	'	'
In service	4,363,664,000	4,260,844,000
Less accumulated depreciation	1,211,336,000	1,168,055,000
Plant in service, net of depreciation	3,152,328,000	3,092,789,000
Construction work in progress	280,626,000	136,062,000
Total property, plant, and equipment	3,432,954,000	3,228,851,000
Other Property and Investments:	'	'
Total other property and investments	15,314,000	15,737,000
Deferred Charges and Other Assets:	'	'
Deferred charges related to income taxes	50,597,000	50,139,000
Prepaid pension costs	11,533,000	0
Other regulatory assets, deferred	340,415,000	372,294,000
Other deferred charges and assets	30,982,000	33,053,000
Total deferred charges and other assets	433,527,000	455,486,000
Total Assets	4,337,571,000	4,177,402,000
Current Liabilities:	'	'
Securities due within one year	75,000,000	60,000,000
Notes payable	135,878,000	127,002,000
Affiliated	76,897,000	66,161,000
Accounts payable	47,038,000	54,551,000
Customer deposits	34,433,000	34,749,000
Accrued taxes --	'	'
Accrued income taxes	45,000	45,000
Other accrued taxes	7,486,000	7,036,000
Accrued interest	10,272,000	12,364,000
Accrued compensation	11,657,000	14,966,000
Liabilities from risk management activities	6,470,000	16,529,000
Other regulatory liabilities, current	13,408,000	25,887,000
Other current liabilities	22,972,000	19,930,000
Total current liabilities	441,556,000	439,220,000
Senior notes -	'	'
Long-term Debt	1,158,163,000	1,185,870,000
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes	734,355,000	648,952,000
Accumulated deferred investment tax credits	4,055,000	5,408,000
Employee benefit obligations	76,338,000	126,871,000
Deferred capacity expense	180,149,000	137,568,000
Other cost of removal obligations	228,148,000	213,413,000
Other regulatory liabilities, deferred	56,051,000	47,863,000
Other deferred credits and liabilities	77,126,000	93,497,000
Total deferred credits and other liabilities	1,356,222,000	1,273,572,000
Total Liabilities	2,955,941,000	2,898,662,000
Preference Stock	146,504,000	97,998,000
Common Stockholders' Equity:	'	'
Common stock	433,060,000	393,060,000
Paid-in capital	552,681,000	547,798,000
Retained earnings	250,494,000	241,465,000
Accumulated other comprehensive loss	-1,109,000	-1,581,000
Total Common Stockholders' Equity	1,235,126,000	1,180,742,000
Total stockholders' equity	1,235,126,000	1,180,742,000
Total Liabilities and Stockholders' Equity	4,337,571,000	4,177,402,000
Commitments and Contingent Matters	'	'
Mississippi Power [Member]	'	'
Current Assets:	'	'
Cash and cash equivalents	145,165,000	145,008,000
Receivables --	'	'
Customer accounts receivable	40,978,000	29,561,000
Unbilled revenues	38,895,000	32,688,000
Other accounts and notes receivable	4,600,000	7,517,000
Affiliated companies	34,920,000	27,160,000
Accumulated provision for uncollectible accounts	-3,018,000	-373,000
Fossil fuel stock, at average cost	113,285,000	176,378,000
Materials and supplies, at average cost	45,347,000	34,260,000
Prepaid income taxes	34,751,000	129,835,000
Other regulatory assets, current	52,496,000	55,302,000
Other current assets	9,357,000	17,170,000
Total current assets	516,776,000	654,506,000
Property, Plant, and Equipment:	'	'
In service	3,458,770,000	3,036,159,000
Less accumulated depreciation	1,095,352,000	1,065,474,000
Plant in service, net of depreciation	2,363,418,000	1,970,685,000
Construction work in progress	2,586,031,000	2,393,145,000
Total property, plant, and equipment	4,949,449,000	4,363,830,000
Other Property and Investments:	'	'
Total other property and investments	4,857,000	4,887,000
Deferred Charges and Other Assets:	'	'
Deferred charges related to income taxes	139,834,000	71,869,000
Other regulatory assets, deferred	200,620,000	236,225,000
Other deferred charges and assets	36,673,000	42,304,000
Total deferred charges and other assets	377,127,000	350,398,000
Total Assets	5,848,209,000	5,373,621,000
Current Liabilities:	'	'
Securities due within one year	13,789,000	276,471,000
Interest-bearing refundable deposit related to asset sale	150,000,000	150,000,000
Affiliated	70,299,000	54,769,000
Accounts payable	210,191,000	262,992,000
Customer deposits	14,379,000	14,202,000
Accrued taxes --	'	'
Accrued income taxes	5,590,000	2,339,000
Other accrued taxes	77,958,000	69,376,000
Accrued interest	47,144,000	30,376,000
Accrued compensation	9,324,000	15,706,000
Other regulatory liabilities, current	24,981,000	5,376,000
Over recovered regulatory clause liabilities	18,358,000	77,338,000
Other current liabilities	21,413,000	31,882,000
Total current liabilities	663,426,000	990,827,000
Senior notes -	'	'
Unamortized debt premium	71,807,000	80,912,000
Unamortized debt discount	-2,113,000	-9,145,000
Long-term Debt	2,167,067,000	1,564,462,000
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes	72,808,000	244,958,000
Deferred credits related to income taxes	9,145,000	10,106,000
Accumulated deferred investment tax credits	284,248,000	370,554,000
Employee benefit obligations	94,430,000	157,421,000
Other cost of removal obligations	151,340,000	143,461,000
Other regulatory liabilities, deferred	140,880,000	56,984,000
Other deferred credits and liabilities	55,534,000	52,860,000
Total deferred credits and other liabilities	808,385,000	1,036,344,000
Total Liabilities	3,638,878,000	3,591,633,000
Redeemable Preferred Stock	32,780,000	32,780,000
Common Stockholders' Equity:	'	'
Common stock	37,691,000	37,691,000
Paid-in capital	2,376,595,000	1,401,520,000
Retained earnings	-229,871,000	318,710,000
Accumulated other comprehensive loss	-7,864,000	-8,713,000
Total Common Stockholders' Equity	2,176,551,000	1,749,208,000
Total stockholders' equity	2,176,551,000	1,749,208,000
Total Liabilities and Stockholders' Equity	5,848,209,000	5,373,621,000
Commitments and Contingent Matters	'	'
Southern Power [Member]	'	'
Current Assets:	'	'
Cash and cash equivalents	68,744,000	28,592,000
Receivables --	'	'
Customer accounts receivable	73,497,000	62,857,000
Other accounts and notes receivable	3,983,000	3,135,000
Affiliated companies	38,391,000	38,269,000
Fossil fuel stock, at average cost	19,178,000	21,616,000
Materials and supplies, at average cost	54,780,000	46,370,000
Prepaid service agreements - current	81,206,000	80,629,000
Prepaid income taxes	54,732,000	4,498,000
Prepaid expenses	7,915,000	5,637,000
Assets from risk management activities	182,000	375,000
Total current assets	402,608,000	291,978,000
Property, Plant, and Equipment:	'	'
In service	4,696,134,000	4,059,839,000
Less accumulated depreciation	871,963,000	786,620,000
Plant in service, net of depreciation	3,824,171,000	3,273,219,000
Construction work in progress	9,843,000	24,835,000
Total property, plant, and equipment	3,834,014,000	3,298,054,000
Other Property and Investments:	'	'
Goodwill	1,839,000	1,839,000
Other intangible assets, net of amortization	43,505,000	45,979,000
Total other property and investments	45,344,000	47,818,000
Deferred Charges and Other Assets:	'	'
Prepaid long-term service agreements	73,676,000	100,921,000
Other deferred charges and assets -- affiliated	4,605,000	3,468,000
Other deferred charges and assets	68,853,000	37,688,000
Total deferred charges and other assets	147,134,000	142,077,000
Total Assets	4,429,100,000	3,779,927,000
Current Liabilities:	'	'
Securities due within one year	599,000	259,000
Notes payable	0	70,968,000
Affiliated	56,661,000	65,832,000
Accounts payable	20,747,000	26,204,000
Accrued taxes --	'	'
Accrued income taxes	161,000	87,000
Other accrued taxes	2,662,000	3,031,000
Accrued interest	28,352,000	22,259,000
Other current liabilities	18,492,000	8,932,000
Total current liabilities	127,674,000	197,572,000
Senior notes -	'	'
Unamortized debt premium	2,467,000	2,557,000
Unamortized debt discount	-1,013,000	-286,000
Long-term Debt	1,619,241,000	1,306,099,000
Deferred Credits and Other Liabilities:	'	'
Accumulated deferred income taxes	724,390,000	550,685,000
Deferred convertible investment tax credits	340,269,000	167,130,000
Deferred capacity revenues -- affiliated	15,279,000	19,514,000
Other deferred credits and liabilities -- affiliated	1,621,000	2,638,000
Other deferred credits and liabilities	7,896,000	5,863,000
Total deferred credits and other liabilities	1,089,455,000	745,830,000
Total Liabilities	2,836,370,000	2,249,501,000
Redeemable Noncontrolling Interest	28,778,000	8,069,000
Common Stockholders' Equity:	'	'
Common stock	0	0
Paid-in capital	1,029,035,000	1,027,548,000
Retained earnings	531,998,000	495,585,000
Accumulated other comprehensive loss	2,919,000	-776,000
Total Common Stockholders' Equity	1,563,952,000	1,522,357,000
Total stockholders' equity	1,563,952,000	1,522,357,000
Total Liabilities and Stockholders' Equity	4,429,100,000	3,779,927,000
Commitments and Contingent Matters	'	'
Southern Power [Member] | 4.875% due 2015	'	'
Senior notes -	'	'
Senior notes	525,000,000	525,000,000
Southern Power [Member] | 6.375% due 2036	'	'
Senior notes -	'	'
Senior notes	200,000,000	200,000,000
Southern Power [Member] | 5.15% due 2041	'	'
Senior notes -	'	'
Senior notes	575,000,000	575,000,000
Southern Power [Member] | 5.25% due 2043	'	'
Senior notes -	'	'
Senior notes	300,000,000	0
Southern Power [Member] | 3.25% due 2032-2033	'	'
Senior notes -	'	'
Other long-term notes (3.25% due 2032-2033)	$17,787,000	$3,828,000

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Common stock, par value per share	5	5
Common stock, shares authorized	1,500,000,000	1,500,000,000
Alabama Power [Member]	'	'
Common stock, par value per share	40	40
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares outstanding	30,537,500	30,537,500
Georgia Power [Member]	'	'
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	9,261,500	9,261,500
Gulf Power [Member]	'	'
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	4,942,717	4,542,717
Mississippi Power [Member]	'	'
Fixed stated interest rate of debt obligation	9.93%	9.97%
Common stock, shares authorized	1,130,000	1,130,000
Common stock, shares outstanding	1,121,000	1,121,000
Southern Power [Member]	'	'
Amortization expense on other intangible assets	5,614	3,141
Common stock, par value per share	0.01	0.01
Common stock, shares authorized	1,000,000	1,000,000
Common stock, shares outstanding	1,000	1,000
Southern Power [Member] | 4.875% due 2015	'	'
Fixed stated interest rate of debt obligation	4.88%	4.88%
Southern Power [Member] | 6.375% due 2036	'	'
Fixed stated interest rate of debt obligation	6.38%	6.38%
Southern Power [Member] | 5.15% due 2041	'	'
Fixed stated interest rate of debt obligation	5.15%	5.15%
Southern Power [Member] | 5.25% due 2043	'	'
Fixed stated interest rate of debt obligation	5.25%	'
Southern Power [Member] | 3.25% due 2032-2033	'	'
Fixed stated interest rate of debt obligation	3.25%	3.25%

Consolidated_Statements_of_Cap

Consolidated Statements of Capitalization (USD $)	Dec. 31, 2013	Dec. 31, 2012
Maturity	'	'
Total long term debt payable to affiliated trusts	$206,000,000	$206,000,000
Long-term senior notes and debt:	'	'
Long-term debt maturities, 2016	1,360,000,000	1,360,000,000
Long-term debt maturities, 2017	1,095,000,000	1,095,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Five	850,000,000	250,000,000
Long-term debt maturities, thereafter	10,798,000,000	9,823,000,000
2013	0	1,436,000,000
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	428,000,000	434,000,000
Long-term debt maturities, 2015	2,375,000,000	2,375,000,000
Total long -term senior notes and debt	17,892,000,000	17,649,000,000
Pollution control revenue bonds --	'	'
Total other long -term debt	3,503,000,000	3,621,000,000
Capitalized lease obligations	163,000,000	80,000,000
Unamortized debt premium (related to plant acquisition)	79,000,000	88,000,000
Unamortized debt discount	-30,000,000	-35,000,000
Total long-term debt (annual interest requirement )	21,813,000,000	21,609,000,000
Less amount due within one year	469,000,000	2,335,000,000
Long-term debt excluding amount due within one year	21,344,000,000	19,274,000,000
Percent capitalization	51.50%	49.90%
Redeemable Preferred and Preference Stock:	'	'
Redeemable preferred stock	375,000,000	375,000,000
Total redeemable preferred stock - percent capitalization	0.90%	1.00%
Preferred and preference stock of subsidiaries	756,000,000	707,000,000
Total preferred and preference stock of subsidiaries - percent capitalization	1.80%	1.80%
Common Stockholders' Equity:	'	'
Common stock	4,461,000,000	4,389,000,000
Paid-in capital	5,362,000,000	4,855,000,000
Treasury, at cost	-250,000,000	-450,000,000
Retained earnings	9,510,000,000	9,626,000,000
Accumulated other comprehensive loss	-75,000,000	-123,000,000
Total Common Stockholders' Equity	19,008,000,000	18,297,000,000
Total common stockholders' equity - percent capitalization	45.80%	47.30%
Total stockholders' equity	19,764,000,000	19,004,000,000
Total Capitalization	41,483,000,000	38,653,000,000
Percent Capitalization	100.00%	100.00%
Redeemable Preferred Stock, $100 par or stated value | Cumulative Preferred Stock	'	'
Redeemable Preferred and Preference Stock:	'	'
Redeemable preferred stock	81,000,000	81,000,000
Redeemable Preferred Stock, $1 par value | Cumulative Preferred Stock	'	'
Redeemable Preferred and Preference Stock:	'	'
Redeemable preferred stock	294,000,000	294,000,000
Noncumulative Preferred Stock	'	'
Redeemable Preferred and Preference Stock:	'	'
Preferred and preference stock of subsidiaries	45,000,000	45,000,000
Preference Stock, $1 par value	'	'
Redeemable Preferred and Preference Stock:	'	'
Preferred and preference stock of subsidiaries	343,000,000	343,000,000
Preference Stock , $100 par or stated value	'	'
Redeemable Preferred and Preference Stock:	'	'
Preferred and preference stock of subsidiaries	368,000,000	319,000,000
2014 | Adjustable Rate Loans [Member]	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	1.29%	'
Variable rate, Due 2042	'	'
Maturity	'	'
Total long term debt payable to affiliated trusts	206,000,000	206,000,000
Fixed stated interest rate of debt obligation	3.35%	'
2019 through 2049	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	1,478,000,000	1,593,000,000
Variable rate, Due 2015	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	0.04%	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	54,000,000	54,000,000
Variable rate, Due 2016	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	0.06%	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	4,000,000	4,000,000
Variable rate, Due 2017	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	36,000,000	36,000,000
Variable rate, Due 2018	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	0.04%	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	19,000,000	19,000,000
Variable rate, Due 2020 to 2052	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	1,642,000,000	1,645,000,000
Due 2021	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	7.13%	7.13%
Pollution control revenue bonds --	'	'
Taxable Revenue Bonds	270,000,000	270,000,000
Adjustable Rate Loans [Member]	'	'
Long-term senior notes and debt:	'	'
Long-term debt maturities, 2016	450,000,000	0
2013	0	876,000,000
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	11,000,000	0
Long-term debt maturities, 2015	525,000,000	0
Alabama Power [Member]	'	'
Maturity	'	'
Total long term debt payable to affiliated trusts	206,000,000	206,000,000
Long-term senior notes and debt:	'	'
Long-term debt maturities, 2016	200,000,000	200,000,000
Long-term debt maturities, 2017	525,000,000	525,000,000
Long-term debt maturities, thereafter	3,750,000,000	3,450,000,000
2013	0	250,000,000
Long-term debt maturities, 2015	400,000,000	400,000,000
Total long-term notes payable	4,875,000,000	4,825,000,000
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	1,200,000,000	1,200,000,000
Total other long -term debt	1,151,000,000	1,151,000,000
Capitalized lease obligations	5,000,000	0
Unamortized debt (discount), net	-4,000,000	-3,000,000
Total long-term debt (annual interest requirement )	6,233,000,000	6,179,000,000
Less amount due within one year	0	250,000,000
Long-term debt excluding amount due within one year	6,233,000,000	5,929,000,000
Percent capitalization	50.20%	49.40%
Redeemable Preferred and Preference Stock:	'	'
Redeemable preferred stock	342,000,000	342,000,000
Total redeemable preferred stock - percent capitalization	2.70%	2.80%
Preference stock	343,000,000	343,000,000
Preferred stock	342,000,000	342,000,000
Total preferred and preference stock of subsidiaries - percent capitalization	2.80%	2.90%
Common Stockholders' Equity:	'	'
Common stock	1,222,000,000	1,222,000,000
Paid-in capital	2,262,000,000	2,227,000,000
Retained earnings	2,044,000,000	1,976,000,000
Accumulated other comprehensive loss	-26,000,000	-27,000,000
Total Common Stockholders' Equity	5,502,000,000	5,398,000,000
Total common stockholders' equity - percent capitalization	44.30%	44.90%
Total stockholders' equity	5,502,000,000	5,398,000,000
Total Capitalization	12,420,000,000	12,012,000,000
Percent Capitalization	100.00%	100.00%
Alabama Power [Member] | Redeemable Preferred Stock, $100 par or stated value | Cumulative Preferred Stock	'	'
Redeemable Preferred and Preference Stock:	'	'
Redeemable preferred stock	48,000,000	48,000,000
Alabama Power [Member] | Redeemable Preferred Stock, $1 par value | Cumulative Preferred Stock	'	'
Redeemable Preferred and Preference Stock:	'	'
Redeemable preferred stock	294,000,000	294,000,000
Alabama Power [Member] | 2013	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	'	5.80%
Alabama Power [Member] | 2015	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	0.55%	0.55%
Alabama Power [Member] | 2016	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	5.20%	5.20%
Alabama Power [Member] | Variable rate, Due 2042	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	3.35%	'
Alabama Power [Member] | Variable rate, Due 2017	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	36,000,000	36,000,000
Alabama Power [Member] | Maturity of Pollution Control Bonds Two Thousand Thirty Four [Member]	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	367,000,000	367,000,000
Alabama Power [Member] | Variable rate, Due 2015	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	0.04%	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	54,000,000	54,000,000
Alabama Power [Member] | Maturity Of Pollution Control Bonds Variable Rate Two Thousand Twenty One To Two Thousand Thirty Eight [Member]	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	694,000,000	694,000,000
Georgia Power [Member]	'	'
Long-term senior notes and debt:	'	'
Long-term debt maturities, 2016	250,000,000	250,000,000
Long-term debt maturities, 2017	450,000,000	450,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Five	250,000,000	250,000,000
Long-term debt maturities, thereafter	4,475,000,000	4,175,000,000
Variable, 2013	0	650,000,000
Long Term Debt Maturities Repayments of Principal Variable in Year Four	450,000,000	0
2013	0	1,025,000,000
Long-term debt maturities, 2015	1,050,000,000	1,050,000,000
Total long-term notes payable	6,925,000,000	7,850,000,000
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	1,700,000,000	1,800,000,000
Total other long -term debt	1,680,000,000	1,784,000,000
Capitalized lease obligations	45,000,000	50,000,000
Unamortized debt (discount), net	-12,000,000	-10,000,000
Total long-term debt (annual interest requirement )	8,638,000,000	9,674,000,000
Less amount due within one year	5,000,000	1,680,000,000
Long-term debt excluding amount due within one year	8,633,000,000	7,994,000,000
Percent capitalization	46.70%	45.60%
Redeemable Preferred and Preference Stock:	'	'
Preference stock	221,000,000	221,000,000
Preferred stock	45,000,000	45,000,000
Total preferred and preference stock of subsidiaries - percent capitalization	1.40%	1.50%
Common Stockholders' Equity:	'	'
Common stock	398,000,000	398,000,000
Paid-in capital	5,633,000,000	5,585,000,000
Retained earnings	3,565,000,000	3,297,000,000
Accumulated other comprehensive loss	-5,000,000	-7,000,000
Total Common Stockholders' Equity	9,591,000,000	9,273,000,000
Total common stockholders' equity - percent capitalization	51.90%	52.90%
Total stockholders' equity	9,591,000,000	9,273,000,000
Total Capitalization	18,490,000,000	17,533,000,000
Percent Capitalization	100.00%	100.00%
Georgia Power [Member] | Noncumulative Preferred Stock	'	'
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	'	'
Redeemable Preferred and Preference Stock:	'	'
Preferred stock	45,000,000	45,000,000
Georgia Power [Member] | Noncumulative Preferred Stock, $100 par value	'	'
Redeemable Preferred and Preference Stock:	'	'
Preference stock	221,000,000	221,000,000
Georgia Power [Member] | 2016	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	3.00%	3.00%
Georgia Power [Member] | 2017	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	5.70%	5.70%
Georgia Power [Member] | 2018	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	5.40%	5.40%
Georgia Power [Member] | Variable rate, Due 2016	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	0.06%	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	4,000,000	4,000,000
Georgia Power [Member] | Variable rate, Due 2018	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	0.04%	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	20,000,000	20,000,000
Georgia Power [Member] | 2022 - 2049	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	818,000,000	919,000,000
Georgia Power [Member] | Maturity of Pollution Control Bonds Variable Rate Due Two Thousand Twenty Two to Two Thousand Fifty Two [Member]	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	838,000,000	841,000,000
Gulf Power [Member]	'	'
Long-term senior notes and debt:	'	'
Long-term debt maturities, 2016	110,000,000	110,000,000
Long-term debt maturities, 2017	85,000,000	85,000,000
Long-term debt maturities, thereafter	675,000,000	615,000,000
2013	0	60,000,000
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	75,000,000	75,000,000
Total long-term notes payable	945,000,000	945,000,000
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	296,000,000	309,000,000
Total other long -term debt	295,955,000	308,955,000
Unamortized debt (discount), net	-7,792,000	-8,085,000
Total long-term debt (annual interest requirement )	1,233,163,000	1,245,870,000
Less amount due within one year	75,000,000	60,000,000
Long-term debt excluding amount due within one year	1,158,163,000	1,185,870,000
Percent capitalization	45.60%	48.10%
Redeemable Preferred and Preference Stock:	'	'
Total redeemable preferred stock - percent capitalization	5.80%	4.00%
Preference stock	146,504,000	97,998,000
Common Stockholders' Equity:	'	'
Common stock	433,060,000	393,060,000
Paid-in capital	552,681,000	547,798,000
Retained earnings	250,494,000	241,465,000
Accumulated other comprehensive loss	-1,109,000	-1,581,000
Total Common Stockholders' Equity	1,235,126,000	1,180,742,000
Total common stockholders' equity - percent capitalization	48.60%	47.90%
Total stockholders' equity	1,235,126,000	1,180,742,000
Total Capitalization	2,539,793,000	2,464,610,000
Percent Capitalization	100.00%	100.00%
Gulf Power [Member] | 6% Preference stock	'	'
Redeemable Preferred and Preference Stock:	'	'
Preference stock	53,886,000	53,886,000
Gulf Power [Member] | 6.45 % Preference stock	'	'
Redeemable Preferred and Preference Stock:	'	'
Preference stock	44,112,000	44,112,000
Gulf Power [Member] | Five Point Six Percentage Hundred Dollar Par or Stated Value [Member]	'	'
Redeemable Preferred and Preference Stock:	'	'
Preference stock	48,506,000	0
Gulf Power [Member] | 2013	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	'	4.35%
Gulf Power [Member] | 2014	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	4.90%	4.90%
Gulf Power [Member] | 2016	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	5.30%	5.30%
Gulf Power [Member] | 2017	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	5.90%	5.90%
Gulf Power [Member] | 2022 - 2049	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	226,625,000	239,625,000
Gulf Power [Member] | Variable Rate, Due 2022-2039	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	69,330,000	69,330,000
Mississippi Power [Member]	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	9.93%	9.97%
Long-term senior notes and debt:	'	'
Long-term debt maturities, 2016	300,000,000	300,000,000
Long-term debt maturities, 2017	35,000,000	35,000,000
Long-term debt maturities, thereafter	805,000,000	805,000,000
Long Term Debt Maturities Repayments of Principal Adjustable in Last Twelve Months	0	226,471,000
Adjustable, 2014	11,250,000	0
Long Term Debt Maturities Repayments of Principal Adjustable in Year Two	525,000,000	0
2013	0	50,000,000
Total long-term notes payable	1,676,250,000	1,416,471,000
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	82,700,000	82,700,000
Taxable Revenue Bonds	11,300,000	51,500,000
Total other long -term debt	352,695,000	352,695,000
Capitalized lease obligations	82,217,000	0
Unamortized debt premium (related to plant acquisition)	71,807,000	80,912,000
Unamortized debt discount	-2,113,000	-9,145,000
Total long-term debt (annual interest requirement )	2,180,856,000	1,840,933,000
Less amount due within one year	13,789,000	276,471,000
Long-term debt excluding amount due within one year	2,167,067,000	1,564,462,000
Percent capitalization	49.60%	46.70%
Redeemable Preferred and Preference Stock:	'	'
Total redeemable preferred stock - percent capitalization	0.70%	1.00%
Preferred stock	32,780,000	32,780,000
Common Stockholders' Equity:	'	'
Common stock	37,691,000	37,691,000
Paid-in capital	2,376,595,000	1,401,520,000
Retained earnings	-229,871,000	318,710,000
Accumulated other comprehensive loss	-7,864,000	-8,713,000
Total Common Stockholders' Equity	2,176,551,000	1,749,208,000
Total common stockholders' equity - percent capitalization	49.70%	52.30%
Total stockholders' equity	2,176,551,000	1,749,208,000
Total Capitalization	4,376,398,000	3,346,450,000
Percent Capitalization	100.00%	100.00%
Mississippi Power [Member] | 2013	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	'	6.00%
Mississippi Power [Member] | 2016	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	2.35%	2.35%
Mississippi Power [Member] | 2017	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	5.60%	5.60%
Mississippi Power [Member] | Due 2021	'	'
Maturity	'	'
Fixed stated interest rate of debt obligation	7.13%	7.13%
Pollution control revenue bonds --	'	'
Taxable Revenue Bonds	270,000,000	270,000,000
Mississippi Power [Member] | Variable Rate, Due 2020-2028	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	40,070,000	40,070,000
Mississippi Power [Member] | 2028	'	'
Pollution control revenue bonds --	'	'
Long-term pollution control bonds	$42,625,000	$42,625,000

Consolidated_Statements_of_Cap1

Consolidated Statements of Capitalization (Parenthetical) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Common stock, Par value	$5	$5
Common stock, shares authorized	1,500,000,000	1,500,000,000
Common stock, shares issued	893,000,000	878,000,000
Treasury shares	5,700,000	10,000,000
Annual interest requirement	$805	'
Annual dividend requirement	48	'
Redeemable Preferred Stock, $1 par value	'	'
Preferred Stock, Par or Stated Value Per Share	$1	$1
Redeemable Cumulative preferred stock, Authorized	28,000,000	28,000,000
Redeemable Cumulative preferred stock, Outstanding	12,000,000	12,000,000
Redeemable Preferred Stock, $1 par value | Cumulative Preferred Stock	'	'
Dividend Rate, Minimum	5.20%	5.20%
Dividend Rate, Maximum	5.83%	5.83%
Redeemable Preferred Stock, $100 par or stated value	'	'
Preferred Stock, Par or Stated Value Per Share	$100	$100
Redeemable Cumulative preferred stock, Authorized	20,000,000	20,000,000
Redeemable Cumulative preferred stock, Outstanding	1,000,000	1,000,000
Redeemable Preferred Stock, $100 par or stated value | Cumulative Preferred Stock	'	'
Dividend Rate, Minimum	4.20%	4.20%
Dividend Rate, Maximum	5.44%	5.44%
Redeemable Preferred Stock, $25 stated value	'	'
Preferred Stock, Par or Stated Value Per Share	$25	$25
Preference Stock , $100 par or stated value	'	'
Preferred Stock, Par or Stated Value Per Share	$100	$100
Preference stock, Outstanding	4,000,000	3,000,000
Dividend Rate, Minimum	5.60%	5.60%
Dividend Rate, Maximum	6.50%	6.50%
Preference Stock, $1 par value	'	'
Preferred Stock, Par or Stated Value Per Share	$1	$1
Preference stock, Authorized	65,000,000	65,000,000
Preference stock, Outstanding	14,000,000	14,000,000
Dividend Rate, Minimum	5.63%	5.63%
Dividend Rate, Maximum	6.50%	6.50%
Redeemable Preferred Stock of Subsidiaries	'	'
Annual dividend requirement	20	'
Noncumulative Preferred Stock	'	'
Preferred Stock, Par or Stated Value Per Share	$25	$25
Preference stock, Authorized	60,000,000	60,000,000
Preference stock, Outstanding	2,000,000	2,000,000
Dividend Rate, Minimum	6.00%	6.00%
Dividend Rate, Maximum	6.13%	6.13%
2013	'	'
Interest Rates, Minimum	'	1.30%
Interest Rates, Maximum	'	6.00%
2014	'	'
Interest Rates, Minimum	3.25%	3.25%
Interest Rates, Maximum	4.90%	4.90%
2015	'	'
Interest Rates, Minimum	0.55%	0.55%
Interest Rates, Maximum	5.25%	5.25%
2016	'	'
Interest Rates, Minimum	1.95%	1.95%
Interest Rates, Maximum	5.30%	5.30%
2017	'	'
Interest Rates, Minimum	5.50%	5.50%
Interest Rates, Maximum	5.90%	5.90%
Maturity of Long Term Senior Notes and Debt in Year Six [Member]	'	'
Interest Rates, Minimum	2.20%	2.20%
Interest Rates, Maximum	5.40%	5.40%
2019 through 2051	'	'
Interest Rates, Minimum	1.63%	1.63%
Interest Rates, Maximum	8.20%	8.20%
Variable rate, Due 2016	'	'
Fixed stated interest rate of debt obligation	0.06%	'
Variable rate, Due 2018	'	'
Fixed stated interest rate of debt obligation	0.04%	'
Maturity Of Pollution Control Bonds Variable Rate Due Two Thousand Fifteen Member	'	'
Fixed stated interest rate of debt obligation	0.04%	'
Due 2021	'	'
Fixed stated interest rate of debt obligation	7.13%	7.13%
Variable rate, Due 2042	'	'
Fixed stated interest rate of debt obligation	3.35%	'
Variable rate, Due 2020 to 2052	'	'
Interest Rates, Minimum	0.02%	'
Interest Rates, Maximum	0.13%	'
Maturity of Pollution Control Bonds Period One [Member]	'	'
Interest Rates, Minimum	0.04%	0.04%
Interest Rates, Maximum	6.00%	6.00%
Variable rate, Due 2017	'	'
Interest Rates, Minimum	0.09%	'
Interest Rates, Maximum	0.10%	'
Adjustable Rate Loans [Member] | 2014	'	'
Fixed stated interest rate of debt obligation	1.29%	'
Adjustable Rate Loans [Member] | 2015	'	'
Interest Rates, Minimum	0.77%	'
Interest Rates, Maximum	0.97%	'
Adjustable Rate Loans [Member] | 2016	'	'
Interest Rates, Minimum	0.57%	'
Interest Rates, Maximum	0.65%	'
Adjustable Rate Loans [Member] | Variable rate, due 2013	'	'
Interest Rates, Minimum	'	0.58%
Interest Rates, Maximum	'	1.21%
Alabama Power [Member]	'	'
Common stock, Par value	$40	$40
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares outstanding	30,537,500	30,537,500
Annual interest requirement	243	'
Annual dividend requirement	21	'
Alabama Power [Member] | Redeemable Preferred Stock, $1 par value	'	'
Preferred Stock, Par or Stated Value Per Share	$1	$1
Redeemable Cumulative preferred stock, Authorized	27,500,000	27,500,000
Redeemable Cumulative preferred stock, Outstanding	12,000,000	12,000,000
Dividend Rate, Minimum	5.20%	5.20%
Dividend Rate, Maximum	5.83%	5.83%
Alabama Power [Member] | Redeemable Preferred Stock, $100 par or stated value	'	'
Preferred Stock, Par or Stated Value Per Share	$100	$100
Redeemable Cumulative preferred stock, Authorized	3,850,000	3,850,000
Redeemable Cumulative preferred stock, Outstanding	475,115	475,115
Alabama Power [Member] | Redeemable Preferred Stock, $100 par or stated value | Cumulative Preferred Stock	'	'
Dividend Rate, Minimum	4.20%	4.20%
Dividend Rate, Maximum	4.92%	4.92%
Alabama Power [Member] | Redeemable Preferred Stock, $25 stated value	'	'
Preferred Stock, Par or Stated Value Per Share	$25	$25
Alabama Power [Member] | Preference Stock, $1 par value	'	'
Preferred Stock, Par or Stated Value Per Share	$1	$1
Dividend Rate, Minimum	5.63%	5.63%
Dividend Rate, Maximum	6.50%	6.50%
Alabama Power [Member] | Redeemable Preferred Stock of Subsidiaries	'	'
Annual dividend requirement	18	'
Alabama Power [Member] | Noncumulative Preferred Stock	'	'
Preferred Stock, Par or Stated Value Per Share	$25	$25
Preference stock, Authorized	40,000,000	40,000,000
Preference stock, Outstanding	14,000,000	14,000,000
Alabama Power [Member] | 2013	'	'
Fixed stated interest rate of debt obligation	'	5.80%
Alabama Power [Member] | 2015	'	'
Fixed stated interest rate of debt obligation	0.55%	0.55%
Alabama Power [Member] | 2016	'	'
Fixed stated interest rate of debt obligation	5.20%	5.20%
Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Nineteen to Two Thousand Forty Two [Member]	'	'
Interest Rates, Minimum	3.38%	3.38%
Interest Rates, Maximum	6.13%	6.13%
Alabama Power [Member] | Maturity of Long Term Senior Notes And Debt Two Thousand Seventeen [Member]	'	'
Interest Rates, Minimum	5.50%	5.50%
Interest Rates, Maximum	5.55%	5.55%
Alabama Power [Member] | Maturity of Pollution Control Bonds Two Thousand Thirty Four [Member]	'	'
Interest Rates, Minimum	0.40%	0.40%
Interest Rates, Maximum	5.00%	5.00%
Alabama Power [Member] | Maturity Of Pollution Control Bonds Variable Rate Two Thousand Twenty One To Two Thousand Thirty Eight [Member]	'	'
Interest Rates, Minimum	0.02%	'
Interest Rates, Maximum	0.13%	'
Alabama Power [Member] | Variable rate, Due 2015	'	'
Fixed stated interest rate of debt obligation	0.04%	'
Alabama Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Seventeen [Member]	'	'
Interest Rates, Minimum	0.09%	'
Interest Rates, Maximum	0.10%	'
Alabama Power [Member] | Variable rate, Due 2042	'	'
Fixed stated interest rate of debt obligation	3.35%	'
Georgia Power [Member]	'	'
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	9,261,500	9,261,500
Annual interest requirement	298	'
Annual dividend requirement	17	'
Georgia Power [Member] | Noncumulative Preferred Stock, $25 par value	'	'
Preferred Stock, Par or Stated Value Per Share	$25	$25
Preference stock, Authorized	50,000,000	50,000,000
Preference stock, Outstanding	1,800,000	1,800,000
Dividend Rate	6.13%	6.13%
Georgia Power [Member] | Noncumulative Preferred Stock, $100 par value	'	'
Preferred Stock, Par or Stated Value Per Share	$100	$100
Preference stock, Authorized	15,000,000	15,000,000
Preference stock, Outstanding	2,250,000	2,250,000
Dividend Rate	6.50%	6.50%
Georgia Power [Member] | 2013	'	'
Interest Rates, Minimum	1.30%	1.30%
Interest Rates, Maximum	6.00%	6.00%
Georgia Power [Member] | 2015	'	'
Interest Rates, Minimum	0.63%	0.63%
Interest Rates, Maximum	5.25%	5.25%
Georgia Power [Member] | 2016	'	'
Fixed stated interest rate of debt obligation	3.00%	3.00%
Georgia Power [Member] | 2017	'	'
Fixed stated interest rate of debt obligation	5.70%	5.70%
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt in Year Six [Member]	'	'
Fixed stated interest rate of debt obligation	5.40%	5.40%
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Nineteen to Two Thousand Forty Eight [Member]	'	'
Interest Rates, Minimum	2.85%	2.85%
Interest Rates, Maximum	8.20%	8.20%
Georgia Power [Member] | Variable rate, due 2013	'	'
Interest Rates, Minimum	'	0.58%
Interest Rates, Maximum	'	0.63%
Georgia Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Sixteen [Member]	'	'
Interest Rates, Minimum	0.57%	'
Interest Rates, Maximum	0.65%	'
Georgia Power [Member] | Variable rate, Due 2016	'	'
Fixed stated interest rate of debt obligation	0.06%	'
Georgia Power [Member] | Variable rate, Due 2018	'	'
Fixed stated interest rate of debt obligation	0.04%	'
Georgia Power [Member] | 2022 - 2049	'	'
Interest Rates, Minimum	0.80%	0.80%
Interest Rates, Maximum	5.75%	5.75%
Georgia Power [Member] | Variable rate, Due 2022-2052	'	'
Interest Rates, Minimum	0.04%	'
Interest Rates, Maximum	0.11%	'
Gulf Power [Member]	'	'
Preference stock, Authorized	20,000,000	20,000,000
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	4,942,717	4,542,717
Annual interest requirement	53.8	'
Annual dividend requirement	9	'
Gulf Power [Member] | Preference Stock , $100 par or stated value	'	'
Preferred Stock, Par or Stated Value Per Share	$100	$100
Preference stock, Outstanding	550,000	550,000
Gulf Power [Member] | Preference Stock Type Three [Member]	'	'
Preference stock, Outstanding	450,000	450,000
Gulf Power [Member] | Preference Stock Type Four [Member]	'	'
Preference stock, Outstanding	500,000	0
Gulf Power [Member] | Preference Stock, $1 par value	'	'
Preference stock, Authorized	10,000,000	10,000,000
Gulf Power [Member] | 2013	'	'
Fixed stated interest rate of debt obligation	'	4.35%
Gulf Power [Member] | 2014	'	'
Fixed stated interest rate of debt obligation	4.90%	4.90%
Gulf Power [Member] | 2016	'	'
Fixed stated interest rate of debt obligation	5.30%	5.30%
Gulf Power [Member] | 2017	'	'
Fixed stated interest rate of debt obligation	5.90%	5.90%
Gulf Power [Member] | 2020-2051	'	'
Interest Rates, Minimum	3.10%	3.10%
Interest Rates, Maximum	5.75%	5.75%
Gulf Power [Member] | 2022 - 2049	'	'
Interest Rates, Minimum	0.55%	0.55%
Interest Rates, Maximum	6.00%	6.00%
Gulf Power [Member] | Variable Rate, Due 2022-2039	'	'
Interest Rates, Minimum	0.05%	'
Interest Rates, Maximum	0.06%	'
Gulf Power [Member] | 6.0% preference stock | Preference Stock , $100 par or stated value	'	'
Fixed stated interest rate of debt obligation	6.00%	6.00%
Gulf Power [Member] | 6.45% preference stock | Preference Stock , $100 par or stated value	'	'
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	'	'
Fixed stated interest rate of debt obligation	5.60%	'
Mississippi Power [Member]	'	'
Fixed stated interest rate of debt obligation	9.93%	9.97%
Preferred Stock, Par or Stated Value Per Share	$100	$100
Redeemable Cumulative preferred stock, Authorized	1,244,139	1,244,139
Redeemable Cumulative preferred stock, Outstanding	334,210	334,210
Common stock, shares authorized	1,130,000	1,130,000
Common stock, shares outstanding	1,121,000	1,121,000
Annual interest requirement	75	'
Annual dividend requirement	$1.70	'
Dividend Rate, Minimum	4.40%	4.40%
Dividend Rate, Maximum	5.25%	5.25%
Mississippi Power [Member] | 2013	'	'
Fixed stated interest rate of debt obligation	'	6.00%
Mississippi Power [Member] | 2016	'	'
Fixed stated interest rate of debt obligation	2.35%	2.35%
Mississippi Power [Member] | 2017	'	'
Fixed stated interest rate of debt obligation	5.60%	5.60%
Mississippi Power [Member] | Variable rate, due 2013	'	'
Interest Rates, Minimum	'	0.63%
Interest Rates, Maximum	'	1.21%
Mississippi Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Nineteen to Two Thousand Forty Two [Member]	'	'
Interest Rates, Minimum	1.63%	1.63%
Interest Rates, Maximum	5.55%	5.55%
Mississippi Power [Member] | 2028	'	'
Fixed stated interest rate of debt obligation	5.15%	5.15%
Mississippi Power [Member] | Variable Rate, Due 2020-2028	'	'
Interest Rates, Minimum	0.04%	'
Interest Rates, Maximum	0.05%	'
Mississippi Power [Member] | Due 2021	'	'
Fixed stated interest rate of debt obligation	7.13%	7.13%
Mississippi Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Fourteen [Member]	'	'
Fixed stated interest rate of debt obligation	1.29%	0.00%
Mississippi Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Fifteen [Member]	'	'
Interest Rates, Minimum	0.77%	'
Interest Rates, Maximum	0.97%	'

Consolidated_Statements_of_Com2

Consolidated Statements of Common Stockholders Equity (USD $)

Total

Common Stock

Treasury Stock

Paid In Capital

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Preferred and Preference Stock of Subsidiaries

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Share data in Thousands

Common Stock

Paid In Capital

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Common Stock

Paid In Capital

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Common Stock

Paid In Capital

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Common Stock

Paid In Capital

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Common Stock

Paid In Capital

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Beginning Balance at Dec. 31, 2010

$16,909,000,000

$4,219,000,000

($15,000,000)

$3,702,000,000

$8,366,000,000

($70,000,000)

$707,000,000

$5,393,000,000

$1,222,000,000

$2,156,000,000

$2,022,000,000

($7,000,000)

$8,741,000,000

$398,000,000

$5,291,000,000

$3,063,000,000

($11,000,000)

$1,075,036,000

$303,060,000

$538,375,000

$236,328,000

($2,727,000)

$737,368,000

$37,691,000

$392,790,000

$306,885,000

$2,000

$1,263,220,000

$0

$900,969,000

$376,270,000

($14,019,000)

Beginning Balance, Shares at Dec. 31, 2010

'

843,814

474

'

'

'

'

'

31,000

'

'

'

'

9,000

'

'

'

'

3,643

'

'

'

'

1,121

'

'

'

'

1

'

'

'

Net income after dividends on preferred and preference stock

2,203,000,000

[1]

'

'

'

2,203,000,000

'

'

708,000,000

'

'

708,000,000

'

1,145,000,000

'

'

1,145,000,000

'

105,005,000

'

'

105,005,000

'

94,182,000

'

'

94,182,000

'

'

'

'

'

'

Net Income

2,268,000,000

'

'

'

'

'

'

747,000,000

'

'

'

'

1,162,000,000

'

'

'

'

111,208,000

'

'

'

'

95,915,000

'

'

'

'

162,231,000

'

'

162,231,000

'

Capital contributions from parent company

'

'

'

'

'

'

'

26,000,000

'

26,000,000

'

'

231,000,000

'

231,000,000

'

'

4,334,000

'

4,334,000

'

'

302,065,000

'

302,065,000

'

'

127,241,000

'

127,241,000

'

'

Other comprehensive income (loss)

-41,000,000

'

'

'

'

-41,000,000

'

-11,000,000

'

'

'

-11,000,000

2,000,000

'

'

'

2,000,000

573,000

'

'

'

573,000

-8,899,000

'

'

'

-8,899,000

7,190,000

'

'

'

7,190,000

Stock issued, shares

'

21,850

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock issued

725,000,000

109,000,000

'

616,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock-based compensation

89,000,000

'

'

89,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash dividends on common stock

-1,601,000,000

'

'

'

-1,601,000,000

'

'

-774,000,000

'

'

-774,000,000

'

-1,096,000,000

'

'

-1,096,000,000

'

-110,000,000

'

'

-110,000,000

'

-75,500,000

'

'

-75,500,000

'

-91,200,000

'

'

-91,200,000

'

Other, shares

'

'

-65

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other

1,000,000

'

-2,000,000

3,000,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

1,000

'

'

'

'

'

'

Ending Balance at Dec. 31, 2011

18,285,000,000

4,328,000,000

-17,000,000

4,410,000,000

8,968,000,000

-111,000,000

707,000,000

5,342,000,000

1,222,000,000

2,182,000,000

1,956,000,000

-18,000,000

9,023,000,000

398,000,000

5,522,000,000

3,112,000,000

-9,000,000

1,124,948,000

353,060,000

542,709,000

231,333,000

-2,154,000

1,049,217,000

37,691,000

694,855,000

325,568,000

-8,897,000

1,468,682,000

0

1,028,210,000

447,301,000

-6,829,000

Ending Balance, Shares at Dec. 31, 2011

'

865,664

539

'

'

'

'

'

31,000

'

'

'

'

9,000

'

'

'

'

4,143

'

'

'

'

1,121

'

'

'

'

1

'

'

'

Net income after dividends on preferred and preference stock

368,000,000

'

'

'

'

'

'

126,000,000

'

'

'

'

167,000,000

'

'

'

'

20,666,000

'

'

'

'

25,255,000

'

'

'

'

29,316,000

'

'

'

'

Ending Balance at Mar. 31, 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Beginning Balance at Dec. 31, 2011

18,285,000,000

4,328,000,000

-17,000,000

4,410,000,000

8,968,000,000

-111,000,000

707,000,000

5,342,000,000

1,222,000,000

2,182,000,000

1,956,000,000

-18,000,000

9,023,000,000

398,000,000

5,522,000,000

3,112,000,000

-9,000,000

1,124,948,000

353,060,000

542,709,000

231,333,000

-2,154,000

1,049,217,000

37,691,000

694,855,000

325,568,000

-8,897,000

1,468,682,000

0

1,028,210,000

447,301,000

-6,829,000

Beginning Balance, Shares at Dec. 31, 2011

'

865,664

539

'

'

'

'

'

31,000

'

'

'

'

9,000

'

'

'

'

4,143

'

'

'

'

1,121

'

'

'

'

1

'

'

'

Net income after dividends on preferred and preference stock

2,350,000,000

[1]

'

'

'

2,350,000,000

'

'

704,000,000

'

'

704,000,000

'

1,168,000,000

'

'

1,168,000,000

'

125,932,000

'

'

125,932,000

'

99,942,000

'

'

99,942,000

'

'

'

'

'

'

Net Income

2,415,000,000

'

'

'

'

'

'

743,000,000

'

'

'

'

1,185,000,000

'

'

'

'

132,135,000

'

'

'

'

101,675,000

'

'

'

'

175,285,000

'

'

175,285,000

'

Capital contributions from parent company

'

'

'

'

'

'

'

45,000,000

'

45,000,000

'

'

63,000,000

'

63,000,000

'

'

5,089,000

'

5,089,000

'

'

706,665,000

'

706,665,000

'

'

-662,000

'

-662,000

'

'

Other comprehensive income (loss)

-12,000,000

'

'

'

'

-12,000,000

'

-9,000,000

'

'

'

-9,000,000

2,000,000

'

'

'

2,000,000

573,000

'

'

'

573,000

184,000

'

'

'

184,000

6,053,000

'

'

'

6,053,000

Stock issued, shares

'

12,139

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock issued

397,000,000

61,000,000

'

336,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

40,000,000

40,000,000

0

'

'

'

'

'

'

'

'

'

'

'

'

Stock repurchased, at cost, shares

'

'

-9,440

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock repurchased, at cost

-430,000,000

'

-430,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock-based compensation

106,000,000

'

'

106,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash dividends on common stock

-1,693,000,000

'

'

'

-1,693,000,000

'

'

-684,000,000

'

'

-684,000,000

'

-983,000,000

'

'

-983,000,000

'

-115,800,000

'

'

-115,800,000

'

-106,800,000

'

'

-106,800,000

'

-127,000,000

'

'

-127,000,000

'

Other, shares

'

'

-56

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other

1,000,000

'

-3,000,000

3,000,000

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-1,000

'

Ending Balance at Dec. 31, 2012

19,004,000,000

4,389,000,000

-450,000,000

4,855,000,000

9,626,000,000

-123,000,000

'

5,398,000,000

1,222,000,000

2,227,000,000

1,976,000,000

-27,000,000

9,273,000,000

398,000,000

5,585,000,000

3,297,000,000

-7,000,000

1,180,742,000

393,060,000

547,798,000

241,465,000

-1,581,000

1,749,208,000

37,691,000

1,401,520,000

318,710,000

-8,713,000

1,522,357,000

0

1,027,548,000

495,585,000

-776,000

Ending Balance, Shares at Dec. 31, 2012

'

877,803

10,035

'

'

'

'

'

31,000

'

'

'

'

9,000

'

'

'

'

4,543

'

'

'

'

1,121

'

'

'

'

1

'

'

'

Beginning Balance at Sep. 30, 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income after dividends on preferred and preference stock

383,000,000

'

'

'

'

'

'

113,000,000

'

'

'

'

181,000,000

'

'

'

'

22,549,000

'

'

'

'

-14,965,000

'

'

'

'

30,991,000

'

'

'

'

Ending Balance at Dec. 31, 2012

19,004,000,000

'

'

'

'

'

'

5,398,000,000

1,222,000,000

'

'

'

9,273,000,000

398,000,000

'

'

'

1,180,742,000

'

'

'

'

1,749,208,000

37,691,000

'

'

'

1,522,357,000

0

'

'

'

Ending Balance, Shares at Dec. 31, 2012

'

'

'

'

'

'

'

'

31,000

'

'

'

'

9,000

'

'

'

'

'

'

'

'

'

1,121

'

'

'

'

1

'

'

'

Net income after dividends on preferred and preference stock

81,000,000

'

'

'

'

'

'

141,000,000

'

'

'

'

197,000,000

'

'

'

'

21,792,000

'

'

'

'

-246,321,000

'

'

'

'

29,192,000

'

'

'

'

Ending Balance at Mar. 31, 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Beginning Balance at Dec. 31, 2012

19,004,000,000

4,389,000,000

-450,000,000

4,855,000,000

9,626,000,000

-123,000,000

707,000,000

5,398,000,000

1,222,000,000

2,227,000,000

1,976,000,000

-27,000,000

9,273,000,000

398,000,000

5,585,000,000

3,297,000,000

-7,000,000

1,180,742,000

393,060,000

547,798,000

241,465,000

-1,581,000

1,749,208,000

37,691,000

1,401,520,000

318,710,000

-8,713,000

1,522,357,000

0

1,027,548,000

495,585,000

-776,000

Beginning Balance, Shares at Dec. 31, 2012

'

877,803

10,035

'

'

'

'

'

31,000

'

'

'

'

9,000

'

'

'

'

4,543

'

'

'

'

1,121

'

'

'

'

1

'

'

'

Net income after dividends on preferred and preference stock

1,644,000,000

[1],[2]

'

'

'

1,644,000,000

'

'

712,000,000

'

'

712,000,000

'

1,174,000,000

'

'

1,174,000,000

'

124,429,000

'

'

124,429,000

'

-476,625,000

'

'

-476,625,000

'

'

'

'

'

'

Net Income

1,710,000,000

'

'

'

'

'

'

751,000,000

'

'

'

'

1,191,000,000

'

'

'

'

132,133,000

'

'

'

'

-474,892,000

'

'

'

'

165,533,000

'

'

165,533,000

'

Capital contributions from parent company

'

'

'

'

'

'

'

35,000,000

'

35,000,000

'

'

48,000,000

'

48,000,000

'

'

4,883,000

'

4,883,000

'

'

975,075,000

'

975,075,000

'

'

1,487,000

'

1,487,000

'

'

Other comprehensive income (loss)

48,000,000

'

'

'

'

48,000,000

'

1,000,000

'

'

'

1,000,000

2,000,000

'

'

'

2,000,000

472,000

'

'

'

472,000

849,000

'

'

'

849,000

3,695,000

'

'

'

3,695,000

Stock issued, shares

'

14,930

4,443

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock issued

765,000,000

72,000,000

203,000,000

441,000,000

'

'

49,000,000

'

'

'

'

'

'

'

'

'

'

40,000,000

40,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock-based compensation

65,000,000

'

'

65,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash dividends on common stock

-1,762,000,000

'

'

'

-1,762,000,000

'

'

-644,000,000

'

'

-644,000,000

'

-907,000,000

'

'

-907,000,000

'

-115,400,000

'

'

-115,400,000

'

-71,956,000

'

'

-71,956,000

'

-129,120,000

'

'

-129,120,000

'

Other, shares

'

'

-55

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other

0

'

-3,000,000

1,000,000

2,000,000

'

'

'

'

'

'

'

1,000,000

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ending Balance at Dec. 31, 2013

19,764,000,000

4,461,000,000

-250,000,000

5,362,000,000

9,510,000,000

-75,000,000

756,000,000

5,502,000,000

1,222,000,000

2,262,000,000

2,044,000,000

-26,000,000

9,591,000,000

398,000,000

5,633,000,000

3,565,000,000

-5,000,000

1,235,126,000

433,060,000

552,681,000

250,494,000

-1,109,000

2,176,551,000

37,691,000

2,376,595,000

-229,871,000

-7,864,000

1,563,952,000

0

1,029,035,000

531,998,000

2,919,000

Ending Balance, Shares at Dec. 31, 2013

'

892,733

5,647

'

'

'

'

'

31,000

'

'

'

'

9,000

'

'

'

'

4,943

'

'

'

'

1,121

'

'

'

'

1

'

'

'

Beginning Balance at Sep. 30, 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income after dividends on preferred and preference stock

414,000,000

'

'

'

'

'

'

140,000,000

'

'

'

'

208,000,000

'

'

'

'

25,301,000

'

'

'

'

12,921,000

'

'

'

'

23,266,000

'

'

'

'

Ending Balance at Dec. 31, 2013

$19,764,000,000

'

'

'

'

'

'

$5,502,000,000

$1,222,000,000

'

'

'

$9,591,000,000

$398,000,000

'

'

'

$1,235,126,000

'

'

'

'

$2,176,551,000

$37,691,000

'

'

'

$1,563,952,000

$0

'

'

'

Ending Balance, Shares at Dec. 31, 2013

'

'

'

'

'

'

'

'

31,000

'

'

'

'

9,000

'

'

'

'

'

'

'

'

'

1,121

'

'

'

'

1

'

'

'

[1]

(a) After dividends on preferred and preference stock of subsidiaries.

[2]

(b) Segment net income (loss) in 2013 includes $1.2 billion in pre-tax charges ($729 million after tax) for estimated probable losses on the Kemper IGCC. See Note (3) under "Integrated Coal Gasification Combined Cycle b Kemper IGCC Construction Schedule and Cost Estimate" for additional information.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	General
	The Southern Company (Southern Company or the Company) is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants.
	The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary. All material intercompany transactions have been eliminated in consolidation. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
	The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), and the traditional operating companies are also subject to regulation by their respective state public service commissions (PSC). The companies follow generally accepted accounting principles (GAAP) in the U.S. and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates.
	Regulatory Assets and Liabilities
	The traditional operating companies are subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
	Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
		2013				2012			Note
		(in millions)
	Deferred income tax charges	$	1,376			$	1,318		(a)
	Deferred income tax charges — Medicare subsidy	65				72			(j)
	Asset retirement obligations-asset	145				141			(a,h)
	Asset retirement obligations-liability	(139		)		(71		)	(a,h)
	Other cost of removal obligations	(1,289		)		(1,225		)	(a)
	Deferred income tax credits	(203		)		(212		)	(a)
	Loss on reacquired debt	293				309			(b)
	Vacation pay	171				165			(c,h)
	Under recovered regulatory clause revenues	70				38			(d)
	Property damage reserves	(191		)		(193		)	(g)
	Cancelled construction projects	70				65			(m)
	Power purchase agreement charges	180				138			(h,n)
	Fuel-hedging-asset	58				118			(h,o)
	Other regulatory assets	337				276			(f)
	Environmental remediation-asset	62				74			(g,h)
	Other regulatory liabilities	(126		)		(100		)	(b,l,i)
	Kemper IGCC* regulatory assets	76				36			(k)
	Kemper regulatory deferral	(91		)		—			(k)
	Retiree benefit plans	1,760				3,373			(e,h)
	Total regulatory assets (liabilities), net	$	2,624			$	4,322
	*	Integrated coal gasification combined cycle electric generating plant located in Kemper County, Mississippi (Kemper IGCC).
	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 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period from January 2014 through December 2016 in accordance with Georgia Power's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP). See Note 3 under "Retail Regulatory Matters" for additional information.
	(b)	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.
	(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 appropriate state PSCs over periods generally not exceeding 10 years.
	(e)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.
	(f)	Comprised of numerous immaterial components including storm damage reserves, nuclear and generating plant outage costs, property taxes, post-retirement benefits, generation site selection/evaluation costs, power purchase agreement (PPA) capacity, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4 regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding, as applicable, 10 years or over the remaining life of the asset but not beyond 2031.
	(g)	Recovered as storm restoration and potential reliability-related expenses or environmental remediation expenses are incurred as approved by the appropriate state PSCs.
	(h)	Not earning a return as offset in rate base by a corresponding asset or liability.
	(i)	Recovered and amortized as approved or accepted by the appropriate state PSC over the life of the contract.
	(j)	Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years.
	(k)	For additional information, See Note 3 under "Integrated Coal Gasification Combined Cycle."
	(l)	Comprised of immaterial components including over recovered regulatory clause revenues, state income tax credits, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years, except for PPA credits that are recovered over the life of the PPA for periods up to 14 years.
	(m)	Costs associated with construction of environmental controls that will not be completed as a result of unit retirements and amortized over nine years in accordance with the 2013 ARP.
	(n)	Recovered over the life of the PPA for periods up to 14 years.
	(o)	Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.
	In the event that a portion of a traditional operating company's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated other comprehensive income (OCI) related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional operating company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Georgia Power," and "Integrated Coal Gasification Combined Cycle" for additional information.
	Revenues
	Wholesale capacity revenues 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 traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.
	Southern Company's electric utility subsidiaries have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
	Fuel Costs
	Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under "Nuclear Fuel Disposal Costs" for additional information.
	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 investment tax credits (ITCs) for the traditional operating companies are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $16 million in 2013, $23 million in 2012, and $19 million in 2011. At December 31, 2013, all ITCs available to reduce federal income taxes payable had not been utilized. The remaining ITCs will be carried forward and utilized in future years. Additionally, several subsidiaries have state ITCs, which are recognized in the period in which the credit is claimed on the state income tax return. A portion of the state ITCs available to reduce state income taxes payable was not utilized currently and will be carried forward and utilized in future years.
	Under the American Recovery and Reinvestment Act of 2009, certain projects at Southern Power are eligible for ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit, and are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $5.5 million and $2.6 million in 2013 and 2012, respectively. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period.
	In accordance with accounting standards related to the uncertainty in income taxes, Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
	Property, Plant, and Equipment
	Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
	The Southern Company system's property, plant, and equipment in service consisted of the following at December 31:
		2013				2012
		(in millions)
Generation	$	35,360			$	33,444
Transmission	9,289				8,747
Distribution	16,499				15,958
General	3,958				4,208
Plant acquisition adjustment	123				124
Utility plant in service	65,229				62,481
Information technology equipment and software	242				230
Communications equipment	437				430
Other	113				110
Other plant in service	792				770
Total plant in service	$	66,021			$	63,251
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 and Georgia Power range from 18 to 24 months for each unit. In accordance with a Georgia PSC order, Georgia Power deferred the costs of certain significant inspection costs for the combustion turbine units at Plant McIntosh and amortized such costs over 10 years, which approximated the expected maintenance cycle of the units. All inspection costs were fully amortized in 2013.
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,
	2013				2012
	(in millions)
Office building	$	61			$	61
Nitrogen plant	83				—
Computer-related equipment	62				58
Gas pipeline	6				—
Less: Accumulated amortization	(48		)		(39		)
Balance, net of amortization	$	164			$	80
The amount of non-cash property additions recognized for the years ended December 31, 2013, 2012, and 2011 was $411 million, $524 million, and $929 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, 2013, 2012, and 2011 were $107 million, $14 million, and $21 million, respectively.
Acquisitions
Southern Power acquires generation assets as part of its overall growth strategy. Southern Power accounts for business acquisitions from non-affiliates as business combinations. Accordingly, Southern Power has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition was allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business in accordance with GAAP are accounted for as asset acquisitions. The purchase price of each asset acquisition was allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by Southern Power for successful or potential acquisitions have been expensed as incurred.
Acquisitions entered into or made by Southern Power and Turner Renewable Energy through Southern Turner Renewable Energy, LLC during 2013 and 2012 are detailed in the table below:
	MW Capacity*		Year of Operation	Party Under PPA Contract for Plant Output	PPA Contract Period	Purchase Price
						(millions)
Adobe Solar, LLC (a)	20		2014	Southern California Edison Company	20 years	$100.00
Campo Verde Solar, LLC (b)	139		2013	San Diego Gas & Electric Company	20 years	$136.60
Spectrum Nevada Solar, LLC (c)	30		2013	Nevada Power Company	25 years	$17.60
Apex Nevada Solar, LLC	20		2012	Nevada Power Company	25 years	$102.00
* megawatt (MW)
(a) This acquisition is expected to occur in spring 2014, and the purchase price is expected to be $100 million.
(b) Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar Inc. to complete the construction of the solar facility.
(c) Under an engineering, procurement, and construction agreement, an additional $104 million was paid to a subsidiary of Sun Edison, LLC to complete the construction of the solar facility.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3% in 2013, 3.2% in 2012, and 3.2% in 2011. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and the FERC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $22.5 billion and $21.5 billion at December 31, 2013 and 2012, 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.
In 2009, the Georgia PSC approved an accounting order allowing Georgia Power to amortize a portion of its regulatory liability related to other cost of removal obligations. Under the terms of Georgia Power's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), Georgia Power amortized approximately $31 million annually of the remaining regulatory liability related to other cost of removal obligations over the three years ended December 31, 2013. Under the terms of the 2013 ARP, an additional $43 million will be amortized ratably over the three years ending December 31, 2016. See Note 3 under "Retail Regulatory Matters – Georgia Power – Rate Plans" for additional information.
Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 25 years. Accumulated depreciation for other plant in service totaled $513 million and $479 million at December 31, 2013 and 2012, respectively.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Each traditional operating company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The liability for asset retirement obligations primarily relates to the decommissioning of the Southern Company system's nuclear facilities, Plants Farley, Hatch, and Vogtle. In addition, the Southern Company system has retirement obligations related to various landfill sites, ash ponds, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these asset retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the asset retirement obligation. 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 asset retirement obligations included in the balance sheets are as follows:
	2013				2012
	(in millions)
Balance at beginning of year	$	1,757			$	1,344
Liabilities incurred	6				45
Liabilities settled	(16		)		(16		)
Accretion	97				112
Cash flow revisions	174				272
Balance at end of year	$	2,018			$	1,757
The increase in cash flow revisions in 2013 related to revisions to the nuclear decommissioning ARO based on Alabama Power's updated decommissioning study and Georgia Power's updated estimates for ash ponds in connection with the retirement of certain coal-fired generating units. The increase in cash flow revisions in 2012 related to updated estimates for some of the Southern Company system's ash ponds in connection with the retirement of certain coal-fired units and revisions to the nuclear decommissioning ARO based on Georgia Power's updated decommissioning study.
Nuclear Decommissioning
The U.S. Nuclear Regulatory Commission (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 Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds' managers to exercise the standard of care in investing that a "prudent investor" would use in the same circumstances. The FERC regulations also require that the Funds' managers may not invest in any securities of the utility for which it manages funds or its affiliates, except for investments tied to market indices or other mutual funds. While Southern Company is 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 asset retirement obligations 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 so loaned are fully collateralized by cash, letters of credit, and securities issued or guaranteed by the U.S. government, its agencies, and the instrumentalities. As of December 31, 2013 and 2012, approximately $32 million and $91 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 $33 million and $93 million at December 31, 2013 and 2012, 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, 2013, investment securities in the Funds totaled $1.5 billion, consisting of equity securities of $896 million, debt securities of $528 million, and $40 million of other securities. At December 31, 2012, investment securities in the Funds totaled $1.3 billion, consisting of equity securities of $718 million, debt securities of $564 million, and $20 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 $1.0 billion, $1.0 billion, and $2.2 billion in 2013, 2012, and 2011, respectively, all of which were reinvested. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $181 million, of which $5 million related to realized gains and $119 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $137 million, of which $4 million related to realized gains and $75 million related to unrealized gains related to securities held in the Funds at December 31, 2012. For 2011, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $29 million, of which $41 million related to realized gains and $60 million related to unrealized losses related to securities held in the Funds at December 31, 2011. 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 and purpose for which the securities were acquired.
For Alabama Power, amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
At December 31, 2013 and 2012, the accumulated provisions for decommissioning were as follows:
	External Trust Funds							Internal Reserves							Total
	2013				2012			2013			2012				2013		2012
	(in millions)
Plant Farley	$	713			$	604		$	21		$	22			$	734	$	626
Plant Hatch	469				435			—			—				469		435
Plant Vogtle Units 1 and 2	277				256			—			—				277		256
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, 2013 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2012 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2:
	Plant Farley				Plant Hatch			Plant Vogtle
								Units 1 and 2
Decommissioning periods:
Beginning year	2037				2034			2047
Completion year	2076				2068			2072
	(in millions)
Site study costs:
Radiated structures	$	1,362			$	680		$	568
Non-radiated structures	80				51			76
Total site study costs	$	1,442			$	731		$	644
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study, and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. The Georgia PSC approved annual decommissioning cost for ratemaking of $2 million for Plant Hatch for 2011 through 2013. Under the 2013 ARP, the annual decommissioning cost through 2016 for ratemaking is $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively.
Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
Allowance for Funds Used During Construction and Interest Capitalized
In accordance with regulatory treatment, the traditional operating companies record allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies' regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 15.0%, 8.2%, and 9.1% of net income for 2013, 2012, and 2011, respectively.
Cash payments for interest totaled $759 million, $803 million, and $832 million in 2013, 2012, and 2011, respectively, net of amounts capitalized of $92 million, $83 million, and $78 million, respectively.
Impairment of Long-Lived Assets and Intangibles
Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Storm Damage Reserves
Each traditional operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional operating companies accrued $28 million in 2013 and 2012. 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 2013 and 2012, there were no such additional accruals. See Note 3 under "Retail Regulatory Matters – Alabama Power – Natural Disaster Reserve" for additional information regarding Alabama Power's natural disaster reserve.
Leveraged Leases
Southern Company has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. The Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows.
Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31:
	2013				2012
	(in millions)
Net rentals receivable	$	1,440			$	1,214
Unearned income	(775		)		(544		)
Investment in leveraged leases	665				670
Deferred taxes from leveraged leases	(287		)		(278		)
Net investment in leveraged leases	$	378			$	392
A summary of the components of income from the leveraged leases follows:
	2013				2012			2011
	(in millions)
Pretax leveraged lease income (loss)	$	(5	)		$	21		$	25
Income tax expense	2				(8		)	(9		)
Net leveraged lease income (loss)	$	(3	)		$	13		$	16
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.
Financial Instruments
Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional operating companies' fuel-hedging programs. This results 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 are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2013, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial.
Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries.
Accumulated OCI (loss) balances, net of tax effects, were as follows:
	Qualifying				Marketable			Pension and Other				Accumulated Other
	Hedges				Securities			Postretirement				Comprehensive
								Benefit Plans				Income (Loss)
	(in millions)
Balance at December 31, 2012	$	(45	)		$	3		$	(81	)		$	(123	)
Current period change	9				(3		)	42				48
Balance at December 31, 2013	$	(36	)		$	—		$	(39	)		$	(75	)
Alabama Power [Member]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	General
	Alabama Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – the Company, Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Farley.
	The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary.
	The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Alabama Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
	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 $340 million, $340 million, and $347 million during 2013, 2012, and 2011, 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 U.S. Securities and Exchange Commission (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 $211 million, $218 million, and $215 million during 2013, 2012, and 2011, respectively.
	The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which were $13 million in 2013, $12 million in 2012, and $12 million in 2011. Also, Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities, which were $27 million in 2013, $28 million in 2012, and $21 million in 2011. See Note 4 for additional information.
	The Company has an agreement with Gulf Power under which the Company will make transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA. In 2009, Gulf Power entered into a PPA for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. The total cost committed by the Company related to the upgrades is approximately $22 million in 2013 and $31 million in 2014. The Company expects to recover a majority of these costs through a tariff with Gulf Power until 2023. The remainder of these costs will be recovered through normal rate mechanisms.
	The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2013, 2012, or 2011.
	Also, see Note 4 for information regarding the Company's ownership in, a PPA, and a gas pipeline ownership agreement with Southern Electric Generating Company (SEGCO).
	The traditional operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
	Regulatory Assets and Liabilities
	The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
	Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
		2013				2012			Note
		(in millions)
	Deferred income tax charges	$	519			$	525		(a,k)
	Loss on reacquired debt	86				93			(b)
	Vacation pay	63				61			(c,j)
	Under/(over) recovered regulatory clause revenues	(18		)		34			(d)
	Fuel-hedging (realized and unrealized) losses	8				18			(e)
	Other regulatory assets	52				51			(f)
	Asset retirement obligations	(132		)		(64		)	(a)
	Other cost of removal obligations	(828		)		(759		)	(a)
	Deferred income tax credits	(75		)		(79		)	(a)
	Fuel-hedging (realized and unrealized) gains	(8		)		(5		)	(e)
	Nuclear outage	51				33			(d)
	Natural disaster reserve	(96		)		(103		)	(h)
	Other regulatory liabilities	(11		)		(13		)	(d,g)
	Retiree benefit plans	461				911			(i,j)
	Regulatory deferrals	20				—			(l)
	Total regulatory assets (liabilities), net	$	92			$	703
	Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
	(a)	Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.
	(b)	Recovered over the remaining life of the original issue, which may range up to 50 years.
	(c)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.
	(d)	Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding ten years.
	(e)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.
	(f)	Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable.
	(g)	Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities.
	(h)	Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC.
	(i)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.
	(j)	Not earning a return as offset in rate base by a corresponding asset or liability.
	(k)	Included in the deferred income tax charges are $20 million for 2013 and $21 million for 2012 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 2015 through 2017.
	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 other comprehensive income (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, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Energy Cost Recovery" and "Retail Regulatory Matters – Rate CNP" for additional information.
	The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
	Fuel Costs
	Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under "Nuclear Fuel Disposal Costs" for additional information.
	Income and Other Taxes
	The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits (ITCs) utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
	In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
	Property, Plant, and Equipment
	Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
	The Company's property, plant, and equipment in service consisted of the following at December 31:
		2013				2012
		(in millions)
	Generation	$	11,314			$	11,110
	Transmission	3,287				3,137
Distribution	5,934				5,714
General	1,545				1,434
Plant acquisition adjustment	12				12
Total plant in service	$	22,092			$	21,407
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.
In 2010, the Alabama PSC approved the Company's request to stop accruing for nuclear refueling outage costs in advance of the refueling outages when the most recent 18-month amortization cycle ended in December 2010 and to begin deferring nuclear outage expenses. The amortization will begin after each outage has occurred and the associated outage expenses are known.
During 2011, the Company deferred $38 million of nuclear outage expenses associated with the fall 2011 outage and began the first 18-month amortization cycle for expenses in January 2012. These expenses were fully amortized in June 2013. The Company deferred an additional $31 million of nuclear outage expenses associated with the spring 2012 outage and began the second amortization cycle in July 2012. These expenses were fully amortized in December 2013.
During 2013, the Company deferred $28 million of nuclear outage expenses associated with the spring 2013 outage and began the 18-month amortization cycle for expenses in July 2013. The Company deferred an additional $32 million of nuclear outage expenses associated with the fall 2013 outage and began the 18-month amortization cycle for expenses in January 2014.
The total unamortized deferred nuclear outage expense balance of $51 million is included in the 2013 balance sheet as a regulatory asset.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.2% in 2013 and 2012, and 3.3% in 2011. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and the FERC. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
In 2011, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates beginning January 2012. The study was also provided to the Alabama PSC.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The liability for asset retirement obligations primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets are indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these asset retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the asset retirement obligation. 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 asset retirement obligations included in the balance sheets are as follows:
	2013				2012
	(in millions)
Balance at beginning of year	$	589			$	553
Liabilities incurred	—				—
Liabilities settled	(1		)		(1		)
Accretion	40				37
Cash flow revisions (a)	102				—
Balance at end of year	$	730			$	589
(a) Updated based on results from the 2013 nuclear decommissioning study
Nuclear Decommissioning
The U.S. Nuclear Regulatory Commission (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 Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds' managers to exercise the standard of care in investing that a "prudent investor" would use in the same circumstances. The FERC regulations also require that the Funds' managers may not invest in any securities of the utility for which it manages funds or its affiliates, except for investments tied to market indices or other mutual funds. 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 asset retirement obligations 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, 2013, investment securities in the Funds totaled $713 million, consisting of equity securities of $566 million, debt securities of $131 million, and $16 million of other securities. At December 31, 2012, investment securities in the Funds totaled $604 million, consisting of equity securities of $438 million, debt securities of $156 million, and $10 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 $279 million, $193 million, and $349 million in 2013, 2012, and 2011, respectively, all of which were reinvested. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $120 million, of which $5 million related to realized gains and $85 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $70 million, of which $4 million related to realized gains and $50 million related to unrealized gains related to securities held in the Funds at December 31, 2012. For 2011, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $6 million, of which $41 million related to realized gains and $51 million related to unrealized losses related to securities held in the Funds at December 31, 2011. 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 and purpose for which the securities were acquired.
Amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
At December 31, the accumulated provisions for decommissioning were as follows:
	2013				2012
	(in millions)
External trust funds	$	713			$	604
Internal reserves	21				22
Total	$	734			$	626
Site study costs is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2013 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 the NRC and other applicable requirements.
Allowance for Funds Used During Construction
In accordance with regulatory treatment, the Company records allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 9.1% in 2013, 9.4% in 2012, and 9.2% in 2011. AFUDC, net of income taxes, as a percent of net income after dividends on preferred and preference stock was 5.4% in 2013, 3.3% in 2012, and 3.9% in 2011.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Natural Disaster Reserve
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 Natural Disaster Reserve (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 Natural Disaster Reserve (NDR) when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. See Note 3 under "Retail Regulatory Matters – Natural Disaster Reserve" herein for additional information.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel-hedging program. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. If any, immaterial ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations and had immaterial reclaim collateral arising from derivative instruments recognized at December 31, 2013.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiary of the trust. Therefore, the investment in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debt in the balance sheets.
Georgia Power [Member]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	General
	Georgia Power Company (the Company) is a wholly-owned subsidiary of The Southern Company (Southern Company), which is the parent company of the Company and three other traditional operating companies, as well as Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power Company (Alabama Power), Gulf Power Company (Gulf Power), and Mississippi Power Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Hatch and Plant Vogtle.
	The equity method is used for subsidiaries in which the Company has significant influence but does not control.
	The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Georgia Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
	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 $504 million in 2013, $540 million in 2012, and $550 million in 2011. 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 U.S. Securities and Exchange Commission (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 $555 million in 2013, $574 million in 2012, and $537 million in 2011.
	The Company has entered into several power purchase agreements (PPA) with Southern Power for capacity and energy. Expenses associated with these PPAs were $136 million, $147 million, and $171 million in 2013, 2012, and 2011, respectively. Additionally, the Company had $15 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2013 and 2012. 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 $10 million in 2013, $7 million in 2012, and $7 million in 2011. See Note 4 for additional information.
	The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2013, 2012, or 2011.
	See Note 4 for information regarding the Company's ownership in and a PPA with Southern Electric Generating Company (SEGCO). SEGCO plans to add natural gas as the primary fuel source for its generating units in 2015. SEGCO has entered into a joint ownership agreement with Alabama Power, which owns and operates a generating unit adjacent to the SEGCO units, for the ownership of the gas pipeline. SEGCO will own 86% of the pipeline with the remaining 14% owned by Alabama Power.
	The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
	Regulatory Assets and Liabilities
	The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
	Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
		2013				2012			Note
		(in millions)
	Retiree benefit plans	$	691			$	1,331		(a, k)
	Deferred income tax charges	684				695			(b)
	Deferred income tax charges — Medicare subsidy	38				43			(c)
	Loss on reacquired debt	181				190			(d)
	Asset retirement obligations	137				131			(b, k)
	Fuel-hedging (realized and unrealized) losses	22				49			(e)
	Vacation pay	88				85			(f, k)
	Building leases	37				40			(g)
	Cancelled construction projects	70				65			(h)
	Remaining net book value of retired units	28				—			(i)
	Other regulatory assets	86				100			(c)
	Other cost of removal obligations	(58		)		(94		)	(b)
	Deferred income tax credits	(112		)		(115		)	(b)
	State income tax credits	—				(36		)	(j)
	Other regulatory liabilities	(6		)		(13		)	(e)
	Total regulatory assets (liabilities), net	$	1,886			$	2,471
	Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
	(a)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.
	(b)	Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period of January 2014 through December 2016 in accordance with the Company's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP).
	(c)	Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding nine years.
	(d)	Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 39 years.
	(e)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the Company's fuel cost recovery mechanism.
	(f)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.
	(g)	See Note 6 under "Capital Leases." Recovered over the remaining lives of the buildings through 2026.
	(h)	Costs associated with construction of environmental controls that will not be completed as a result of unit retirements and amortized over nine years in accordance with the 2013 ARP.
	(i)	Amortization period over original remaining life beginning October 2013 through December 2022 as approved by the Georgia PSC in the 2013 ARP.
	(j)	Additional tax benefits resulting from the Georgia state income tax credit settlement that were amortized over a 21-month period that began in April 2012 and ended in December 2013, in accordance with a Georgia PSC order. See Note 5 under "Current and Deferred Income Taxes" for additional information.
	(k)	Not earning a return as 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 other comprehensive income (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. 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 includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under "Nuclear Fuel Disposal Costs" for additional information.
	Income and Other Taxes
	The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
	Federal investment tax credits (ITCs) utilized are deferred and amortized to income as a credit to reduce depreciation over the average life of the related property. State ITCs are recognized in the period in which the credits are claimed on the state income tax return. A portion of the ITCs available to reduce income taxes payable was not utilized currently and will be carried forward and utilized in future years.
	In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
	Property, Plant, and Equipment
	Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the cost of equity and debt funds used during construction.
	The Company's property, plant, and equipment in service consisted of the following at December 31:
		2013				2012
		(in millions)
	Generation	$	14,872			$	14,567
	Transmission	4,859				4,581
Distribution	8,620				8,373
General	1,753				1,695
Plant acquisition adjustment	28				28
Total plant in service	$	30,132			$	29,244
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. Also, in accordance with a Georgia PSC order, the Company deferred the costs of certain significant inspection costs for the combustion turbine units at Plant McIntosh and amortized such costs over 10 years, which approximated the expected maintenance cycle of the units. All inspection costs were fully amortized in 2013.
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 2013, 2.9% in 2012, and 2.8% in 2011. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC and the FERC. Effective January 1, 2014, the Company's depreciation rates were revised by the Georgia PSC in connection with the 2013 ARP. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
In 2009, the Georgia PSC approved an accounting order allowing the Company to amortize a portion of its regulatory liability related to other cost of removal obligations. Under the terms of the Company's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), the Company amortized approximately $31 million annually of the remaining regulatory liability related to other cost of removal obligations over the three years ended December 31, 2013. Under the terms of the 2013 ARP, an additional $43 million will be amortized ratably over the three years ending December 31, 2016.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The asset retirement obligation liability relates to the decommissioning of the Company's nuclear facilities, which include the Company's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, as well as various landfill sites, ash ponds, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with the Company's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these asset retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the asset retirement obligation. The Company will continue to recognize in the statements of income the allowed removal costs in accordance with its regulatory treatment. Any difference 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 asset retirement obligations included in the balance sheets are as follows:
	2013				2012
	(in millions)
Balance at beginning of year	$	1,105			$	757
Liabilities incurred	2				24
Liabilities settled	(13		)		(15		)
Accretion	55				72
Cash flow revisions	73				267
Balance at end of year	$	1,222			$	1,105
The increase in cash flow revisions is related to updated estimates for ash ponds in connection with the retirement of certain coal-fired generating units and revisions to the nuclear decommissioning asset retirement obligations based on the latest decommissioning study.
Nuclear Decommissioning
The U.S. Nuclear Regulatory Commission (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 Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds' managers to exercise the standard of care in investing that a "prudent investor" would use in the same circumstances. The FERC regulations also require that the Funds' managers may not invest in any securities of the utility for which it manages funds or its affiliates, except for investments tied to market indices or other mutual funds. 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 discussed 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 asset retirement obligations 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 so loaned are fully collateralized by cash, letters of credit, and securities issued or guaranteed by the U.S. government, its agencies, and the instrumentalities. As of December 31, 2013 and 2012, approximately $32 million and $91 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 $33 million and $93 million at December 31, 2013 and 2012, 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, 2013, investment securities in the Funds totaled $751 million, consisting of equity securities of $330 million, debt securities of $397 million, and $24 million of other securities. At December 31, 2012, investment securities in the Funds totaled $698 million, consisting of equity securities of $280 million, debt securities of $408 million, and $10 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 $705 million, $850 million, and $1.8 billion in 2013, 2012, and 2011, respectively, all of which were reinvested. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $61 million, of which $34 million related to unrealized gains on securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $67 million, of which $25 million related to unrealized gains on securities held in the Funds at December 31, 2012. For 2011, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $23 million, of which $9 million related to unrealized losses on securities held in the Funds at December 31, 2011. 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 and purpose for which the securities were acquired.
The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning are based on the most current study performed in 2012. The site study costs and external trust funds for decommissioning as of December 31, 2013 based on the Company's ownership interests were as follows:
	Plant Hatch				Plant Vogtle
					Units 1 and 2
Decommissioning periods:
Beginning year	2034				2047
Completion year	2068				2072
	(in millions)
Site study costs:
Radiated structures	$	549			$	453
Spent fuel management	131				115
Non-radiated structures	51				76
Total site study costs	$	731			$	644
External trust funds	$	469			$	277
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. The Georgia PSC approved annual decommissioning costs for ratemaking of $2 million annually for Plant Hatch for 2011 through 2013. Under the 2013 ARP, the annual decommissioning cost through 2016 for ratemaking is $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4%. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs.
Allowance for Funds Used During Construction
In accordance with regulatory treatment, the Company records allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 2013, 2012, and 2011, the average AFUDC rates were 5.3%, 6.8%, and 7.5%, respectively, and AFUDC capitalized was $44 million, $75 million, and $134 million, respectively. AFUDC, net of income taxes, was 3.3%, 5.7%, and 10.4% of net income after dividends on preferred and preference stock for 2013, 2012, and 2011, respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information on the inclusion of construction costs related to the construction of two new nuclear generating units at Plant Vogtle (Plant Vogtle Units 3 and 4) in rate base effective January 1, 2011.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Storm Damage Recovery
The Company defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Under the 2010 ARP, the Company accrued $18 million annually that was recoverable through base rates. At December 31, 2013, the Company's regulatory asset related to storm damage was $37 million, with approximately $30 million included in other regulatory assets, current and approximately $7 million included as other regulatory assets, deferred. Beginning January 1, 2014, the Company is accruing $30 million annually under the 2013 ARP. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs.
Environmental Remediation Recovery
The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. On December 17, 2013, the Georgia PSC approved the 2013 ARP including the recovery of approximately $2 million annually through the environmental compliance cost recovery (ECCR) tariff from 2014 through 2016. The Company recovered approximately $3 million annually through the ECCR tariff from 2011 through 2013 under the 2010 ARP. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and cost recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this regulatory treatment, environmental remediation liabilities generally are not expected to have a material impact on the Company's financial statements. As of December 31, 2013, the balance of the environmental remediation liability was $18 million, with approximately $2 million included in other regulatory assets, current and approximately $9 million included as other regulatory assets, deferred. See Note 3 under "Environmental Matters – Environmental Remediation" for additional information.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average cost of coal, natural gas, and oil, as well as transportation and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel-hedging program. This results 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 are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2013.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.
Gulf Power [Member]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	General
	Gulf Power Company (the Company) is a wholly-owned subsidiary of The Southern Company (Southern Company), which is the parent company of four traditional operating companies, as well as Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants.
	The equity method is used for entities in which the Company has significant influence but does not control.
	The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Florida Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
	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 $78.4 million, $95.9 million, and $97.4 million during 2013, 2012, and 2011, 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 U.S. Securities and Exchange Commission (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 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 $10.2 million, $6.9 million, and $6.7 million and Mississippi Power $16.5 million, $21.1 million, and $23.4 million in 2013, 2012, and 2011, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information.
	The Company entered into a power purchase agreement (PPA) with Southern Power for approximately 292 megawatts (MWs) annually from June 2009 through May 2014. Purchased power expenses associated with the PPA were $14.2 million, $14.7 million, and $14.3 million in 2013, 2012, and 2011, respectively, and fuel costs associated with the PPA were $0.8 million, $2.6 million, and $1.8 million in 2013, 2012, and 2011, respectively. These costs have been approved for recovery by the Florida PSC through the Company's fuel and purchased power capacity cost recovery clauses. Additionally, the Company had $4.2 million of deferred capacity expenses included in prepaid expenses and other regulatory liabilities, current in the balance sheets at December 31, 2013 and 2012, respectively. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
	The Company has an agreement with Georgia Power under the transmission facility cost allocation tariff for delivery of power from the Company's resources in the state of Georgia. The Company reimbursed Georgia Power $2.4 million in each of the years 2013, 2012, and 2011 for its share of related expenses.
	The Company has an agreement with Alabama Power under which Alabama Power will make transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA, which was entered into in 2009 for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. Revenue requirement obligations to Alabama Power for these upgrades are estimated to be $135.0 million for the entire project. These costs began in July 2012 and will continue through 2023. The Company reimbursed Alabama Power $7.9 million and $3.0 million in 2013 and 2012, respectively, for the revenue requirements. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff.
	The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2013 or 2012. In 2011, the Company provided storm restoration assistance to Alabama Power totaling $1.4 million.
	The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
	Regulatory Assets and Liabilities
	The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
	Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
		2013				2012			Note
		(in thousands)
	Deferred income tax charges	$	47,573			$	46,788		(a)
	Deferred income tax charges — Medicare subsidy	3,351				3,678			(b)
	Asset retirement obligations	(6,089		)		(5,793		)	(a,j)
	Other cost of removal obligations	(228,148		)		(213,413		)	(a)
	Deferred income tax credits	(5,238		)		(6,515		)	(a)
	Loss on reacquired debt	16,565				16,400			(c)
	Vacation pay	9,521				9,238			(d,j)
	Under recovered regulatory clause revenues	45,191				3,523			(e)
	Over recovered regulatory clause revenues	—				(17,092		)	(e)
	Property damage reserve	(35,380		)		(31,956		)	(f)
	Fuel-hedging (realized and unrealized) losses	17,043				29,038			(g,j)
	Fuel-hedging (realized and unrealized) gains	(6,962		)		(4,358		)	(g,j)
	PPA charges	180,149				137,568			(j,k)
	Other regulatory assets	12,772				11,034			(l)
	Environmental remediation	50,384				60,452			(h,j)
	PPA credits	(7,496		)		(7,502		)	(j,k)
	Other regulatory liabilities	(1,308		)		(534		)	(f)
	Retiree benefit plans, net	68,296				141,429			(i,j)
	Total regulatory assets (liabilities), net	$	160,224			$	171,985
	Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
	(a)	Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.
	(b)	Recovered and amortized over periods not exceeding 14 years.
	(c)	Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years.
	(d)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.
	(e)	Recorded and recovered or amortized as approved by the Florida PSC, generally within one year.
	(f)	Recorded and recovered or amortized as approved by the Florida PSC.
	(g)	Fuel-hedging assets and liabilities are recognized over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, costs are recovered through the fuel cost recovery clause.
	(h)	Recovered through the environmental cost recovery clause when the remediation is performed.
	(i)	Recovered and amortized over the average remaining service period which may range up to 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)	Recovered over the life of the PPA for periods up to 14 years.
	(l)	Comprised primarily of net book value of retired meters, deferred rate case expenses, and generation site evaluation costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years, or deferred pursuant to Florida statute while the Company continues to evaluate certain potential new generating projects.
	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 other comprehensive income (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's wholesale business consists of two types of agreements. The first type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where a portion of that unit is reserved for the customer. These agreements are associated with the Company's co-ownership of a unit with Georgia Power Company (Georgia Power) at Plant Scherer and consist of both capacity and energy sales. Capacity revenues represent the majority of the Company’s wholesale earnings. The Company currently has long-term sales agreements for 100% of the Company's ownership of that unit for the next two years and 57% for the next five years. The second type, referred to as requirements service, provides that the Company serves the customer's capacity and energy requirements from other Company resources.
	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. Investment tax credits (ITCs) utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
	In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
	Property, Plant, and Equipment
	Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
	The Company's property, plant, and equipment in service consisted of the following at December 31:
	2013				2012
	(in thousands)
Generation	$	2,607,166			$	2,598,773
Transmission	473,378				429,341
Distribution	1,117,024				1,069,065
General	164,065				161,379
Plant acquisition adjustment	2,031				2,286
Total plant in service	$	4,363,664			$	4,260,844
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.6% in both 2013 and 2012 and 3.5% in 2011. 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.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The liability for asset retirement obligations primarily relates to the Company's combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, ash ponds, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these asset retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the asset retirement obligation. 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 asset retirement obligations included in the balance sheets are as follows:
	2013				2012
	(in thousands)
Balance at beginning of year	$	16,055			$	10,729
Liabilities incurred	518				—
Liabilities settled	(1,913		)		(107		)
Accretion	751				507
Cash flow revisions	773				4,926
Balance at end of year	$	16,184			$	16,055
Allowance for Funds Used During Construction
In accordance with regulatory treatment, the Company records allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 6.26% for 2013, 6.72% for 2012, and 7.65% for 2011. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 6.87%, 5.36%, and 11.75% for 2013, 2012, and 2011, respectively.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Property Damage Reserve
The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The costs of such damage are charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $48.0 million and $55.0 million. The Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company's discretion. The Company accrued total expenses of $3.5 million in each of 2013, 2012, and 2011. As of December 31, 2013 and 2012, the balance in the Company's property damage reserve totaled approximately $35.4 million and $32.0 million, respectively, which is included in deferred liabilities in the balance sheets.
When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. In 2013, the Florida PSC approved a settlement agreement (Settlement Agreement) that, among other things, provides for recovery of costs associated with any tropical systems named by the National Hurricane Center through the initiation of a storm surcharge. The storm surcharge will begin, on an interim basis, 60 days following the filing of a cost recovery petition. The storm surcharge generally may not exceed $4.00/1,000 kilowatt hours (KWHs) on monthly residential bills in aggregate for a calendar year. This limitation does not apply if the Company incurs in excess of $100 million in storm recovery costs that qualify for recovery in a given calendar year. This threshold amount is inclusive of the amount necessary to replenish the storm reserve to the level that existed as of December 31, 2013. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case" for details of the Settlement Agreement.
Injuries and Damages Reserve
The Company is subject to claims and lawsuits arising in the ordinary course of business. As permitted by the Florida PSC, the Company accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the reserve does not exceed $2.0 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. The injuries and damages reserve was $3.6 million and $3.1 million at December 31, 2013 and 2012, respectively. For 2013, $1.6 million and $2.0 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. For 2012, $1.6 million and $1.5 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. There were no liabilities in excess of the reserve balance at December 31, 2013 or 2012.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average cost of oil, natural gas, coal, transportation and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC approved fuel-hedging program. This results 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 are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 10 for additional information.
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2013.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.
Mississippi Power [Member]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	General
	Mississippi Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which is the parent company of the Company and three other traditional operating companies, as well as Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company (Alabama Power), Georgia Power Company, Gulf Power Company (Gulf Power), and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants.
	The equity method is used for entities 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 Federal Energy Regulatory Commission (FERC) and the Mississippi Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
	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 $205.0 million, $212.7 million, and $185.5 million during 2013, 2012, and 2011, 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 U.S. Securities and Exchange Commission (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 $12.5 million, $11.7 million, and $12.2 million in 2013, 2012, and 2011, respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility, which were $27.1 million, $28.1 million, and $20.9 million in 2013, 2012, and 2011, 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 $16.5 million, $21.2 million, and $23.3 million in 2013, 2012, and 2011, respectively. See Note 4 for additional information.
	The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2013 or 2011. The Company received storm assistance from other Southern Company subsidiaries totaling $2.0 million in 2012.
	The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
	Regulatory Assets and Liabilities
	The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
	Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
		2013				2012			Note
		(in thousands)
	Retiree benefit plans – regulatory assets	$	82,799			$	162,293		(a,g)
	Retiree benefit plans – regulatory liabilities	(3,111		)		—			(a,g)
	Property damage	(60,092		)		(58,789		)	(i)
	Deferred income tax charges	140,185				68,175			(c)
	Property tax	31,206				27,882			(d)
	Vacation pay	10,214				9,635			(e,g)
	Loss on reacquired debt	9,178				9,815			(k)
	Plant Daniel Units 3 and 4 regulatory assets	18,821				12,386			(j)
	Other regulatory assets	1,201				2,035			(b)
	Fuel-hedging (realized and unrealized) losses	10,340				20,906			(f,g)
	Asset retirement obligations	8,918				9,353			(c)
	Deferred income tax credits	(10,191		)		(11,157		)	(c)
	Other cost of removal obligations	(156,683		)		(143,461		)	(c)
	Fuel-hedging (realized and unrealized) gains	(5,335		)		(2,519		)	(f,g)
	Kemper IGCC* regulatory assets	75,873				36,047			(h)
	Kemper regulatory deferral	(90,524		)		—			(h)
	Other regulatory liabilities	(409		)		—			(b)
	Deferred income tax charges – Medicare subsidy	4,214				4,868			(l)
	Total regulatory assets (liabilities), net	$	66,604			$	147,469
	*    Integrated coal gasification combined cycle electric generating plant located in Kemper County, Mississippi (Kemper IGCC).
	Note:    The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
	(a)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.
	(b)	Recorded and recovered as approved by the Mississippi PSC.
	(c)	Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.
	(d)	Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information.
	(e)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.
	(f)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the Energy Cost Management clause (ECM).
	(g)	Not earning a return as offset in rate base by a corresponding asset or liability.
	(h)	For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle."
	(i)	For additional information, see Note 1 under "Provision for Property Damage" and Note 3 under "Retail Regulatory Matters – System Restoration Rider."
	(j)	Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term.
	(k)	Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.
	(l)	Recovered and amortized over a 10-year period beginning in 2012, as approved by the Mississippi PSC for the retail portion and a five-year period for the wholesale portion, as approved by FERC.
	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 other comprehensive income (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 2008, the Company requested that the U.S. Department of Energy (DOE) transfer the remaining funds previously granted under the Clean Coal Power Initiative Round 2 (DOE Grants) from a cancelled integrated coal gasification combined cycle project of one of Southern Company's subsidiaries that would have been located in Orlando, Florida. In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270.0 million of the Kemper IGCC through the DOE Grants funds. Through December 31, 2013, the Company has received grant funds of $245.3 million, used for the construction of the Kemper IGCC, which is reflected in the Company's financial statements as a reduction to the Kemper IGCC capital costs. An additional $25 million is expected to be received for its initial operation.
	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 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 electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 22.2% of the Company's total operating revenues in 2013 and are largely subject to rolling 10-year cancellation notices.
	The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
	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. Investment tax credits (ITCs) utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
	In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
	Property, Plant, and Equipment
	Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction for projects where recovery of construction work in progress (CWIP) is not allowed in rates.
	The Company's property, plant, and equipment in service consisted of the following at December 31:
	2013				2012
	(in thousands)
Generation	$	1,475,264			$	1,363,269
Transmission	633,903				563,037
Distribution	828,470				802,718
General	439,721				225,723
Plant acquisition adjustment	81,412				81,412
Total plant in service	$	3,458,770			$	3,036,159
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 lignite mine for the Kemper IGCC and a portion of the railway track maintenance costs, which are charged to fuel stock and recovered through the Company's fuel clause.
Purchase of the Plant Daniel Combined Cycle Generating Units
In 2011, the Company purchased the combined cycle generating Units 3 and 4 at Plant Daniel (Plant Daniel Units 3 and 4) for $84.8 million in cash and the assumption of $270.0 million face value of debt obligations of the lessor related to Plant Daniel Units 3 and 4, which mature in 2021, bear interest at a fixed stated interest rate of 7.13% per annum, and had a fair value at the time of purchase of $346.1 million. These obligations are secured by Plant Daniel Units 3 and 4 and certain personal property. The fair value of the debt was determined using a discounted cash flow model based on the Company's borrowing rate at the closing date. The fair value is considered a Level 2 disclosure for financial reporting purposes. Accordingly, Plant Daniel Units 3 and 4 were reflected in the Company's financial statements as follows:
	(in thousands)
Assumption of debt obligations	$	270,000
Fair value adjustment at date of purchase	76,051
Total debt	346,051
Cash payment for the purchase	84,803
Total value of Plant Daniel Units 3 and 4	$	430,854
See Note 3 under "Retail Regulatory Matters – Performance Evaluation Plan" for additional information.
Depreciation, Depletion, and Amortization
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.4% in 2013, 3.5% in 2012, and 3.9% in 2011. Depreciation studies are conducted periodically to update the composite rates. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities.
The Company, in compliance with FERC guidance, classified $81.4 million as a plant acquisition adjustment on the purchase of Plant Daniel Units 3 and 4. This includes $76.1 million recorded in conjunction with the premium on long-term debt and is being amortized over 10 years beginning October 2011. See "Purchase of the Plant Daniel Combined Cycle Generating Units" herein for additional information.
In January 2012, the Mississippi PSC issued an order allowing the Company to defer in a regulatory asset the difference between the revenue requirement under the purchase option of Plant Daniel Units 3 and 4 and the revenue requirement assuming operating lease accounting treatment for the extended term. The regulatory asset will be deferred for a 10-year period ending October 2021. At the conclusion of the deferral period, the unamortized deferral balance will be amortized into rates over the remaining life of the units.
The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation on June 5, 2013. Depreciation associated with fixed assets, amortization associated with rolling stock, and depletion associated with minerals and minerals rights will be recognized and charged to fuel stock and recovered through the Company’s fuel clause.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The Company has AROs related to various landfill sites, ash ponds, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified AROs related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the AROs related to these assets is indeterminable and, therefore, the fair value of the AROs cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of 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 Mississippi PSC, and are reflected in the balance sheets.
Details of the ARO included in the balance sheets are as follows:
	2013				2012
	(in thousands)
Balance at beginning of year	$	42,115			$	19,148
Liabilities incurred	—				20,989
Liabilities settled	(24		)		(282		)
Accretion	1,840				1,874
Cash flow revisions	(2,021		)		386
Balance at end of year	$	41,910			$	42,115
Allowance for Funds Used During Construction
In accordance with regulatory treatment, the Company records allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 6.89%, 7.04%, and 7.06% for the years ended December 31, 2013, 2012, and 2011, respectively.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.
Provision for Property Damage
The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. In 2009, the Mississippi PSC approved the System Restoration Rider (SRR) stipulation between the Company and the Mississippi Public Utilities Staff (MPUS). In accordance with the stipulation, every three years the Mississippi PSC, MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. Each year the Company will set rates to collect the approved SRR revenues. 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 2013, 2012, and 2011, the Company made retail accruals of $3.2 million, $3.5 million, and $3.8 million, respectively, per the annual SRR rate filings. 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. See Note 3 under "Retail Regulatory Matters – System Restoration Rider" for additional information. The Company accrued $0.3 million annually in 2013, 2012, and 2011 for the wholesale jurisdiction.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, mining, and generating plant materials. Materials are charged to inventory when purchased and then expensed, capitalized to plant, or charged to fuel stock, as appropriate, at weighted-average cost when utilized.
Fuel Inventory
Fuel inventory includes the average cost of coal, lignite, natural gas, oil, transportation and emissions allowances. Fuel is charged to inventory when purchased, except for the cost of owning and operating the lignite mine related to the Kemper IGCC which is charged to inventory as incurred, and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates. The retail rate is approved by the Mississippi PSC and the wholesale rates are approved by the FERC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information. 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. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Foreign currency exchange rate hedges are designated as fair value hedges. Settled foreign currency exchange hedges are recorded in CWIP. Any ineffectiveness arising from these would be recognized currently in net income; however, the Company has regulatory approval allowing it to defer any ineffectiveness arising from hedging instruments relating to the Kemper IGCC to a regulatory asset. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. The amounts related to derivatives on the cash flow statement are classified in the same category as the items being hedged. See Note 10 for additional information.
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2013.
The Company has an ECM clause which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company's jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
The Company is required to provide financing for all costs associated with the mine development and operation under a contract with Liberty Fuels Company, LLC, a subsidiary of North American Coal Corporation (Liberty Fuels), in conjunction with the construction of the Kemper IGCC. Liberty Fuels qualifies as a VIE for which the Company is the primary beneficiary. For the year ended December 31, 2013, the VIE consolidation resulted in an ARO and an associated liability in the amounts of $21.0 million and $22.7 million, respectively. For the year ended December 31, 2012, the VIE consolidation resulted in an ARO and an associated liability in the amounts of $21.0 million and $21.8 million, respectively. For the year ended 2011, Liberty Fuels did not have a material impact on the financial position and results of operations of the Company. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information.
Southern Power [Member]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	General
	Southern Power Company is a wholly-owned subsidiary of The Southern Company (Southern Company), which is also the parent company of four traditional operating companies, Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company, Georgia Power Company (Georgia Power), Gulf Power Company, and Mississippi Power Company – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) construct, acquire, own, and manage generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants.
	Southern Power Company and certain of its generation subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC). The Company follows generally accepted accounting principles (GAAP). The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
	The financial statements include the accounts of Southern Power Company and its wholly-owned subsidiaries, Southern Company - Florida LLC, Oleander Power Project, LP, and Nacogdoches Power LLC, which own, operate, and maintain the Company's ownership interests in Plants Stanton Unit A, Oleander, and Nacogdoches, respectively. The financial statements also include the accounts of Southern Power Company's wholly-owned subsidiary, Southern Renewable Energy, Inc. (SRE). SRE was formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. Through Southern Turner Renewable Energy LLC (STR), a jointly-owned subsidiary owned 90% by SRE and 10% by Turner Renewable Energy, LLC (TRE), SRE and its subsidiaries own, operate, and maintain Plants Cimarron, Apex, Granville, Spectrum, and Campo Verde. All intercompany accounts and transactions have been eliminated in consolidation.
	Affiliate Transactions
	Southern Power Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations, construction management, and transactions associated with the Southern Company system's fleet of generating units. Because the Company has no employees, all employee-related charges are rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for these services from SCS amounted to approximately $117.6 million in 2013, $125.4 million in 2012, and $112.7 million in 2011. Approximately $114.3 million in 2013, $107.7 million in 2012, and $87.9 million in 2011 were operations and maintenance expenses; the remainder was recorded to plant in service. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the U.S. Securities and Exchange Commission (SEC). Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
	The Company has several agreements with SCS for transmission services. Transmission purchased from affiliates totaled $8.3 million in 2013, $6.6 million in 2012, and $7.1 million in 2011. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC.
	Total billings for all power purchase agreements (PPAs) with affiliates totaled $148.4 million, $159.9 million, and $175.9 million in 2013, 2012, and 2011, respectively. The deferred amounts outstanding were $17.6 million and $19.0 million as of December 31, 2013 and 2012, respectively, which are recorded as "Deferred capacity revenues – affiliated" on the balance sheets. Revenue recognized under affiliate PPAs accounted for as operating leases totaled $69.0 million, $76.2 million, and $75.6 million in 2013, 2012, and 2011, respectively. The Company and the traditional operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information.
	The Company and the traditional operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.
	Acquisition Accounting
	The Company acquires generation assets as part of its overall growth strategy. The Company accounts for business acquisitions from non-affiliates as business combinations. Accordingly, the Company has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition was allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business in accordance with GAAP are accounted for as asset acquisitions. The purchase price of each asset acquisition was allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions have been expensed as incurred.
	Revenues
	The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements.
	The Company may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 for further information.
	Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. All revenues under solar PPAs are accounted for as contingent revenues and recognized as services are performed. Transmission revenues and other fees are recognized as earned as other operating revenues. Revenues are recorded on a gross basis for all full requirements PPAs. See "Financial Instruments" herein for additional information.
	Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. For the year ended December 31, 2013, Florida Power & Light Company (FPL) accounted for 11.8% of total revenues, Georgia Power accounted for 10.7% of total revenues, and Duke Energy Corporation (resulting from a merger between Duke Energy Corporation and Progress Energy, Inc.) accounted for 10.3% of total revenues. For the year ended December 31, 2012, FPL accounted for 12.8% of total revenues, Georgia Power accounted for 12.5% of total revenues, and Progress Energy Florida, Inc. accounted for 5.9% of total revenues. For the year ended December 31, 2011, FPL accounted for 14.7% of total revenues, Georgia Power accounted for 14% of total revenues, and Progress Energy Carolinas, Inc. accounted for 8.3% of total revenues.
	Fuel Costs
	Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur.
	Income and Other Taxes
	The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.
	Under the American Recovery and Reinvestment Act of 2009 (ARRA), certain projects are eligible for investment tax credits (ITCs) or cash grants. The Company has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Credits amortized in this manner amount to $5.5 million and $2.6 million in 2013 and 2012, respectively. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period. At December 31, 2013, all ITCs available to reduce federal income taxes payable have been utilized. Additionally, state ITCs are recognized at the time the credit is claimed on the state income tax return. A portion of the state ITCs available to reduce state income taxes payable were not utilized currently and will be carried forward and utilized in future years.
	In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
	Property, Plant, and Equipment
	The Company's depreciable property, plant, and equipment consists entirely of generation assets.
	Property, plant, and equipment is stated at original cost. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, minor items of property, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred.
	Depreciation
	Depreciation of the original cost of assets is computed under the straight-line method and applies a composite depreciation rate based on the assets' estimated useful lives determined by the Company. The primary assets in property, plant, and equipment are power plants, which have estimated composite depreciable lives ranging from 18 to 34 years. These lives reflect a composite of the significant components (retirement units) that make up the plants. 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.
	When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.
	Beginning in 2014, the Company changed to component depreciation. Certain generation assets will be depreciated on a units-of-production basis to better match outage and maintenance costs to the usage of and revenues from these 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 of acquired PPAs that are amortized over the term of the PPA and goodwill resulting from acquisitions. The average term of these PPAs is 20 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
	The amortization expense for the acquired PPAs is as follows:
		Amortization
		Expense
		(in millions)
	2013	$	2.5
	2014	2.5
	2015	2.5
	2016	2.5
	2017	2.5
	2018 and beyond	33.5
	Total	$	46
	Deferred Project Development Costs
	The Company capitalizes project development costs once it is determined that it is probable that a specific site will be acquired and a plant constructed. These costs include professional services, permits, and other costs directly related to the construction of a project. In addition, the Company has acquired emission reduction credits necessary for future unspecified construction in areas designated by the U.S. Environmental Protection Agency (EPA) as non-attainment areas for nitrogen oxide or volatile organic compound emissions. These credits are reflected on the balance sheets at historical cost. Deferred project development costs, including the cost of emission reduction offsets to be surrendered, are generally transferred to construction work in progress (CWIP) upon commencement of construction. The total deferred project development costs were $11.2 million at December 31, 2013 and 2012.
	Cash and Cash Equivalents
	For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
	Materials and Supplies
	Generally, materials and supplies include the average cost of generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
	Fuel Inventory
	Fuel inventory includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost.
	Financial Instruments
	The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 8 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions. This results in the deferral of related gains and losses in accumulated other comprehensive income (AOCI) until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. See Note 9 for additional information. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item.
	The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2013.
	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.
	Other Income and (Expense)
	Other income and (expense) includes non-operating revenues and expenses. Revenues are recognized when earned and expenses are recognized when incurred.
	Comprehensive Income
	The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications of amounts included in net income.
	Variable Interest Entities
	The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
	The Company has certain wholly-owned subsidiaries that are determined to be VIEs. The Company is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.

Retirement_Benefits

Retirement Benefits	12 Months Ended
	Dec. 31, 2013
RETIREMENT BENEFITS	'
	RETIREMENT BENEFITS
	Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions were made to the qualified pension plan during 2013. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2014. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2014, other postretirement trust contributions are expected to total approximately $13 million.
	Actuarial Assumptions
	The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.52% and 5.40%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.02	%		4.26	%		4.98	%
	Other postretirement benefit plans	4.85			4.05			4.88
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	7.13			7.29			7.39
	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 of 7.00% for 2014, decreasing gradually to 5.00% through the year 2021 and remaining at that level thereafter. 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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in millions)
	Benefit obligation	$	103			$	(88	)
	Service and interest costs	5				(4		)
	Pension Plans
	The total accumulated benefit obligation for the pension plans was $8.1 billion at December 31, 2013 and $8.5 billion at December 31, 2012. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
		2013				2012
		(in millions)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	9,302			$	8,079
	Service cost	232				198
	Interest cost	389				393
	Benefits paid	(357		)		(336		)
	Actuarial (gain) loss	(703		)		968
	Balance at end of year	8,863				9,302
	Change in plan assets
	Fair value of plan assets at beginning of year	7,953				6,800
	Actual return on plan assets	1,098				1,010
	Employer contributions	39				479
	Benefits paid	(357		)		(336		)
	Fair value of plan assets at end of year	8,733				7,953
	Accrued liability	$	(130	)		$	(1,349	)
	At December 31, 2013, the projected benefit obligations for the qualified and non-qualified pension plans were $8.3 billion and $549 million, respectively. All pension plan assets are related to the qualified pension plan.
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in millions)
	Prepaid pension costs	$	419			$	—
	Other regulatory assets, deferred	1,651				3,013
	Other current liabilities	(40		)		(37		)
	Employee benefit obligations	(509		)		(1,312		)
	Accumulated OCI	64				125
	Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2013 and 2012 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 2014.
		Prior Service Cost				Net (Gain) Loss
		(in millions)
	Balance at December 31, 2013:
	Accumulated OCI	$	5			$	59
	Regulatory assets	75				1,575
	Total	$	80			$	1,634
	Balance at December 31, 2012:
	Accumulated OCI	$	7			$	118
	Regulatory assets	100				2,913
	Total	$	107			$	3,031
	Estimated amortization in net periodic pension cost in 2014:
	Accumulated OCI	$	1			$	4
	Regulatory assets	25				106
	Total	$	26			$	110
	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, 2013 and 2012 are presented in the following table:
		Accumulated				Regulatory Assets
OCI
	(in millions)
Balance at December 31, 2011	$	109			$	2,614
Net loss	21				519
Reclassification adjustments:
Amortization of prior service costs	(1		)		(29		)
Amortization of net gain (loss)	(4		)		(91		)
Total reclassification adjustments	(5		)		(120		)
Total change	16				399
Balance at December 31, 2012	$	125			$	3,013
Net gain	(52		)		(1,145		)
Change in prior service costs	—				1
Reclassification adjustments:
Amortization of prior service costs	(1		)		(26		)
Amortization of net gain (loss)	(8		)		(192		)
Total reclassification adjustments	(9		)		(218		)
Total change	(61		)		(1,362		)
Balance at December 31, 2013	$	64			$	1,651
Components of net periodic pension cost were as follows:
	2013				2012				2011
	(in millions)
Service cost	$	232			$	198			$	184
Interest cost	389				393				389
Expected return on plan assets	(603		)		(581		)		(607		)
Recognized net loss	200				95				21
Net amortization	27				30				32
Net periodic pension cost	$	245			$	135			$	19
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, 2013, estimated benefit payments were as follows:
	Benefit Payments
	(in millions)
2014	$	399
2015	422
2016	446
2017	471
2018	492
2019 to 2023	2,795
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
	2013				2012
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	1,872			$	1,787
Service cost	24				21
Interest cost	74				85
Benefits paid	(94		)		(99		)
Actuarial (gain) loss	(200		)		71
Retiree drug subsidy	6				7
Balance at end of year	1,682				1,872
Change in plan assets
Fair value of plan assets at beginning of year	821				765
Actual return on plan assets	129				93
Employer contributions	39				55
Benefits paid	(88		)		(92		)
Fair value of plan assets at end of year	901				821
Accrued liability	$	(781	)		$	(1,051	)
Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
	2013				2012
	(in millions)
Other regulatory assets, deferred	$	109			$	360
Other current liabilities	(4		)		(3		)
Employee benefit obligations	(777		)		(1,048		)
Other regulatory liabilities, deferred	(36		)		—
Accumulated OCI	1				7
Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2013 and 2012 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 2014.
	Prior Service				Net (Gain)				Transition
	Cost				Loss				Obligation
					(in millions)
Balance at December 31, 2013:
Accumulated OCI	$	—			$	1			$	—
Net regulatory assets (liabilities)	9				64				—
Total	$	9			$	65			$	—
Balance at December 31, 2012:
Accumulated OCI	$	—			$	7			$	—
Net regulatory assets (liabilities)	13				342				5
Total	$	13			$	349			$	5
Estimated amortization as net periodic postretirement benefit cost in 2014:
Accumulated OCI	$	—			$	—			$	—
Net regulatory assets (liabilities)	4				2				—
Total	$	4			$	2			$	—
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, 2013 and 2012 are presented in the following table:
	Accumulated				Net Regulatory
	OCI				Assets (Liabilities)
	(in millions)
Balance at December 31, 2011	$	6			$	345
Net loss	1				35
Reclassification adjustments:
Amortization of transition obligation	—				(10		)
Amortization of prior service costs	—				(4		)
Amortization of net gain (loss)	—				(6		)
Total reclassification adjustments	—				(20		)
Total change	1				15
Balance at December 31, 2012	$	7			$	360
Net gain	(6		)		(266		)
Reclassification adjustments:
Amortization of transition obligation	—				(5		)
Amortization of prior service costs	—				(4		)
Amortization of net gain (loss)	—				(12		)
Total reclassification adjustments	—				(21		)
Total change	(6		)		(287		)
Balance at December 31, 2013	$	1			$	73
Components of the other postretirement benefit plans' net periodic cost were as follows:
	2013				2012				2011
	(in millions)
Service cost	$	24			$	21			$	21
Interest cost	74				85				92
Expected return on plan assets	(56		)		(60		)		(64		)
Net amortization	21				20				20
Net periodic postretirement benefit cost	$	63			$	66			$	69
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)
2014	$	110			$	(9	)		$	101
2015	115				(10		)		105
2016	120				(11		)		109
2017	124				(13		)		111
2018	130				(14		)		116
2019 to 2023	654				(75		)		579
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, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
	Target			2013			2012
Pension plan assets:
Domestic equity	26	%		31	%		28	%
International equity	25			25			24
Fixed income	23			23			27
Special situations	3			1			1
Real estate investments	14			14			13
Private equity	9			6			7
Total	100	%		100	%		100	%
Other postretirement benefit plan assets:
Domestic equity	40	%		40	%		38	%
International equity	21			25			24
Domestic fixed income	25			24			28
Global fixed income	4			4			3
Special situations	1			—			—
Real estate investments	6			5			5
Private equity	3			2			2
Total	100	%		100	%		100	%
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:
•	Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
•	International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
•	Fixed income. A mix of domestic and international bonds.
•	Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.
•	Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
•	Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
•	Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2013 and 2012. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
•	Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
•	TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.
•	Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant				Significant
					Other				Unobservable
					Observable				Inputs
					Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	1,433			$	839			$	—		$	2,272
International equity*	1,101				1,018				—			2,119
Fixed income:
U.S. Treasury, government, and agency bonds	—				599				—			599
Mortgage- and asset-backed securities	—				156				—			156
Corporate bonds	—				978				—			978
Pooled funds	—				471				—			471
Cash equivalents and other	1				223				—			224
Real estate investments	260				—				1,000			1,260
Private equity	—				—				571			571
Total	$	2,795			$	4,284			$	1,571		$	8,650
Liabilities:
Derivatives	—				(3		)		—			(3		)
Total	$	2,795			$	4,281			$	1,571		$	8,647
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant				Significant
					Other				Unobservable
					Observable				Inputs
					Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	1,163			$	670			$	—		$	1,833
International equity*	912				979				—			1,891
Fixed income:
U.S. Treasury, government, and agency bonds	—				516				—			516
Mortgage- and asset-backed securities	—				127				—			127
Corporate bonds	—				876				3			879
Pooled funds	—				399				—			399
Cash equivalents and other	5				548				—			553
Real estate investments	258				—				841			1,099
Private equity	—				—				593			593
Total	$	2,338			$	4,115			$	1,437		$	7,890
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
	(in millions)
Beginning balance	$	841			$	593			$	782		$	582
Actual return on investments:
Related to investments held at year end	74				8				56			1
Related to investments sold during the year	30				51				3			41
Total return on investments	104				59				59			42
Purchases, sales, and settlements	55				(81		)		—			(31		)
Ending balance	$	1,000			$	571			$	841		$	593
The fair values of other postretirement benefit plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant				Significant			Total
					Other				Unobservable
					Observable				Inputs
					Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)
	(in millions)
Assets:
Domestic equity*	$	157			$	45			$	—		$	202
International equity*	39				82				—			121
Fixed income:
U.S. Treasury, government, and agency bonds	—				34				—			34
Mortgage- and asset-backed securities	—				6				—			6
Corporate bonds	—				35				—			35
Pooled funds	—				46				—			46
Cash equivalents and other	—				19				—			19
Trust-owned life insurance	—				369				—			369
Real estate investments	10				—				36			46
Private equity	—				—				20			20
Total	$	206			$	636			$	56		$	898
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant				Significant
					Other				Unobservable
					Observable				Inputs
					Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	140			$	43			$	—		$	183
International equity*	33				75				—			108
Fixed income:
U.S. Treasury, government, and agency bonds	—				24				—			24
Mortgage- and asset-backed securities	—				4				—			4
Corporate bonds	—				31				—			31
Pooled funds	—				42				—			42
Cash equivalents and other	—				44				—			44
Trust-owned life insurance	—				320				—			320
Real estate investments	10				—				30			40
Private equity	—				—				21			21
Total	$	183			$	583			$	51		$	817
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
	(in millions)
Beginning balance	$	30			$	21			$	30		$	23
Actual return on investments:
Related to investments held at year end	3				—				—			—
Related to investments sold during the year	1				2				—			1
Total return on investments	4				2				—			1
Purchases, sales, and settlements	2				(3		)		—			(3		)
Ending balance	$	36			$	20			$	30		$	21
Employee Savings Plan
Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2013, 2012, and 2011 were $84 million, $82 million, and $78 million, respectively.
Alabama Power [Member]	'
RETIREMENT BENEFITS	'
	RETIREMENT BENEFITS
	The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions were made to the qualified pension plan during 2013. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2014. 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. No contributions to the other postretirement trusts are expected during the year ending December 31, 2014.
	Actuarial Assumptions
	The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.52% and 5.41%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.02	%		4.27	%		4.98	%
	Other postretirement benefit plans	4.86			4.06			4.88
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	7.36			7.19			7.39
	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 of 7.00% for 2014, decreasing gradually to 5.00% through the year 2021 and remaining at that level thereafter. 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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in millions)
	Benefit obligation	$	26			$	(22	)
	Service and interest costs	1				(1		)
	Pension Plans
	The total accumulated benefit obligation for the pension plans was $1.9 billion at December 31, 2013 and $2.0 billion at December 31, 2012. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
		2013				2012
		(in millions)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	2,218			$	1,932
	Service cost	52				44
	Interest cost	93				94
	Benefits paid	(93		)		(90		)
	Actuarial (gain) loss	(158		)		238
	Balance at end of year	2,112				2,218
	Change in plan assets
	Fair value of plan assets at beginning of year	2,077				1,885
	Actual return on plan assets	285				274
	Employer contributions	9				8
	Benefits paid	(93		)		(90		)
	Fair value of plan assets at end of year	2,278				2,077
	Prepaid pension costs (accrued liability)	$	166			$	(141	)
	At December 31, 2013, the projected benefit obligations for the qualified and non-qualified pension plans were $2.0 billion and $110 million, respectively. All pension plan assets are related to the qualified pension plan.
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in millions)
	Prepaid pension costs	$	276			$	—
	Other regulatory assets, deferred	476				822
	Other current liabilities	(9		)		(8		)
	Employee benefit obligations	(101		)		(133		)
	Presented below are the amounts included in regulatory assets at December 31, 2013 and 2012 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 2014.
		2013				2012				Estimated
										Amortization
										in 2014
						(in millions)
	Prior service cost	$	19			$	26			$	7
	Net (gain) loss	457				796				31
	Regulatory assets	$	476			$	822
	The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2013 and 2012 are presented in the following table:
		2013			2012
		(in millions)
	Regulatory assets:
	Beginning balance	$	822		$	727
	Net (gain) loss	(287		)	125
	Reclassification adjustments:
	Amortization of prior service costs	(7		)	(7		)
	Amortization of net gain (loss)	(52		)	(23		)
	Total reclassification adjustments	(59		)	(30		)
Total change	(346		)	95
Ending balance	$	476		$	822
Components of net periodic pension cost (income) were as follows:
	2013				2012				2011
	(in millions)
Service cost	$	52			$	44			$	43
Interest cost	93				94				96
Expected return on plan assets	(157		)		(162		)		(173		)
Recognized net (gain) loss	52				23				4
Net amortization	7				7				9
Net periodic pension cost (income)	$	47			$	6			$	(21	)
Net periodic pension cost (income) 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, 2013, estimated benefit payments were as follows:
	Benefit Payments
	(in millions)
2014	$	104
2015	108
2016	113
2017	118
2018	122
2019 to 2023	669
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
	2013				2012
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	490			$	470
Service cost	6				5
Interest cost	19				22
Benefits paid	(24		)		(24		)
Actuarial (gain) loss	(62		)		15
Retiree drug subsidy	2				2
Balance at end of year	431				490
Change in plan assets
Fair value of plan assets at beginning of year	343				315
Actual return on plan assets	61				39
Employer contributions	7				11
Benefits paid	(22		)		(22		)
Fair value of plan assets at end of year	389				343
Accrued liability	$	(42	)		$	(147	)
Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
	2013				2012
	(in millions)
Other regulatory assets, deferred	$	6			$	89
Other regulatory liabilities, deferred	(21		)		—
Employee benefit obligations	(42		)		(147		)
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2013 and 2012 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 2014.
	2013				2012				Estimated
									Amortization
									in 2014
	(in millions)
Prior service cost	$	19			$	22			$	4
Net (gain) loss	(34		)		67				—
Net regulatory assets (liabilities)	$	(15	)		$	89
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2013 and 2012 are presented in the following table:
	2013			2012
	(in millions)
Net regulatory assets (liabilities):
Beginning balance	$	89		$	96
Net gain	(99		)	(1		)
Reclassification adjustments:
Amortization of transition obligation	—			(2		)
Amortization of prior service costs	(3		)	(4		)
Amortization of net gain (loss)	(2		)	—
Total reclassification adjustments	(5		)	(6		)
Total change	(104		)	(7		)
Ending balance	$	(15	)	$	89
Components of the other postretirement benefit plans' net periodic cost were as follows:
	2013				2012				2011
	(in millions)
Service cost	$	6			$	5			$	5
Interest cost	19				22				24
Expected return on plan assets	(23		)		(23		)		(25		)
Net amortization	5				6				7
Net periodic postretirement benefit cost	$	7			$	10			$	11
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. 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)
2014	$	30			$	(3	)		$	27
2015	31				(3		)		28
2016	31				(3		)		28
2017	33				(4		)		29
2018	33				(4		)		29
2019 to 2023	164				(22		)		142
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, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
	Target			2013			2012
Pension plan assets:
Domestic equity	26	%		31	%		28	%
International equity	25			25			24
Fixed income	23			23			27
Special situations	3			1			1
Real estate investments	14			14			13
Private equity	9			6			7
Total	100	%		100	%		100	%
Other postretirement benefit plan assets:
Domestic equity	44	%		47	%		46	%
International equity	20			20			20
Domestic fixed income	24			27			28
Special situations	1			—			—
Real estate investments	8			4			4
Private equity	3			2			2
Total	100	%		100	%		100	%
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:
•	Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
•	International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
•	Fixed income. A mix of domestic and international bonds.
•	Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.
•	Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
•	Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
•	Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2013 and 2012. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
•	Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
•	TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.
•	Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	374			$	219			$	—		$	593
International equity*	287				265				—			552
Fixed income:
U.S. Treasury, government, and agency bonds	—				156				—			156
Mortgage- and asset-backed securities	—				41				—			41
Corporate bonds	—				255				—			255
Pooled funds	—				123				—			123
Cash equivalents and other	—				58				—			58
Real estate investments	68				—				261			329
Private equity	—				—				149			149
Total	$	729			$	1,117			$	410		$	2,256
Liabilities:
Derivatives	—				(1		)		—			(1		)
Total	$	729			$	1,116			$	410		$	2,255
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	304			$	175			$	—		$	479
International equity*	238				256				—			494
Fixed income:
U.S. Treasury, government, and agency bonds	—				135				—			135
Mortgage- and asset-backed securities	—				33				—			33
Corporate bonds	—				230				1			231
Pooled funds	—				104				—			104
Cash equivalents and other	1				143				—			144
Real estate investments	67				—				220			287
Private equity	—				—				155			155
Total	$	610			$	1,076			$	376		$	2,062
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
	(in millions)
Beginning balance	$	220			$	155			$	217		$	161
Actual return on investments:
Related to investments held at year end	19				2				2			—
Related to investments sold during the year	8				13				1			2
Total return on investments	27				15				3			2
Purchases, sales, and settlements	14				(21		)		—			(8		)
Ending balance	$	261			$	149			$	220		$	155
The fair values of other postretirement benefit plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	67			$	11			$	—		$	78
International equity*	14				13				—			27
Fixed income:
U.S. Treasury, government, and agency bonds	—				17				—			17
Mortgage- and asset-backed securities	—				2				—			2
Corporate bonds	—				12				—			12
Pooled funds	—				6				—			6
Cash equivalents and other	—				10				—			10
Trust-owned life insurance	—				211				—			211
Real estate investments	4				—				13			17
Private equity	—				—				7			7
Total	$	85			$	282			$	20		$	387
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	62			$	9			$	—		$	71
International equity*	12				13				—			25
Fixed income:
U.S. Treasury, government, and agency bonds	—				7				—			7
Mortgage- and asset-backed securities	—				2				—			2
Corporate bonds	—				11				—			11
Pooled funds	—				5				—			5
Cash equivalents and other	—				19				—			19
Trust-owned life insurance	—				178				—			178
Real estate investments	4				—				11			15
Private equity	—				—				8			8
Total	$	78			$	244			$	19		$	341
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
	(in millions)
Beginning balance	$	11			$	8			$	11		$	8
Actual return on investments:
Related to investments held at year end	1				—				—			—
Related to investments sold during the year	—				—				—			—
Total return on investments	1				—				—			—
Purchases, sales, and settlements	1				(1		)		—			—
Ending balance	$	13			$	7			$	11		$	8
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 2013, 2012, and 2011 were $20 million, $19 million, and $18 million, respectively.
Georgia Power [Member]	'
RETIREMENT BENEFITS	'
	RETIREMENT BENEFITS
	The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made during 2013. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2014. 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, 2014, other postretirement trust contributions are expected to total approximately $13 million.
	Actuarial Assumptions
	The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.52% and 5.40%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.02	%		4.27	%		4.98	%
	Other postretirement benefit plans	4.85			4.04			4.87
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	6.74			7.24			7.25
	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 of 7.00% for 2014, decreasing gradually to 5.00% through the year 2021 and remaining at that level thereafter. 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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in millions)
	Benefit obligation	$	51			$	(43	)
	Service and interest costs	2				(2		)
	Pension Plans
	The total accumulated benefit obligation for the pension plans was $2.9 billion at December 31, 2013 and $3.1 billion at December 31, 2012. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
		2013				2012
		(in millions)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	3,312			$	2,909
	Service cost	69				60
	Interest cost	138				141
	Benefits paid	(141		)		(136		)
	Actuarial (gain) loss	(262		)		338
	Balance at end of year	3,116				3,312
	Change in plan assets
	Fair value of plan assets at beginning of year	2,827				2,575
	Actual return on plan assets	387				377
	Employer contributions	12				11
	Benefits paid	(141		)		(136		)
	Fair value of plan assets at end of year	3,085				2,827
	Accrued liability	$	(31	)		$	(485	)
	At December 31, 2013, the projected benefit obligations for the qualified and non-qualified pension plans were $3.0 billion and $148 million, respectively. All pension plan assets are related to the qualified pension plan.
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in millions)
	Prepaid pension costs	$	118			$	—
	Other regulatory assets, deferred	610				1,132
	Current liabilities, other	(12		)		(11		)
	Employee benefit obligations	(137		)		(474		)
	Presented below are the amounts included in regulatory assets at December 31, 2013 and 2012 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 2014.
		2013				2012				Estimated
										Amortization
										in 2014
		(in millions)
	Prior service cost	$	26			$	37			$	10
	Net (gain) loss	584				1,095				41
	Regulatory assets	$	610			$	1,132
	The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2013 and 2012 are presented in the following table:
		2013			2012
		(in millions)
	Regulatory assets:
	Beginning balance	$	1,132		$	995
	Net (gain) loss	(438		)	182
	Reclassification adjustments:
	Amortization of prior service costs	(10		)	(12		)
	Amortization of net gain (loss)	(74		)	(33		)
	Total reclassification adjustments	(84		)	(45		)
Total change	(522		)	137
Ending balance	$	610		$	1,132
Components of net periodic pension cost (income) were as follows:
	2013				2012				2011
	(in millions)
Service cost	$	69			$	60			$	57
Interest cost	138				141				144
Expected return on plan assets	(212		)		(221		)		(234		)
Recognized net loss	74				33				6
Net amortization	10				12				12
Net periodic pension cost (income)	$	79			$	25			$	(15	)
Net periodic pension cost (income) 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, 2013, estimated benefit payments were as follows:
	Benefit Payments
	(in millions)
2014	$	154
2015	161
2016	167
2017	175
2018	181
2019 to 2023	995
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
	2013				2012
	(in millions)
Change in benefit obligation
Benefit obligation at beginning of year	$	800			$	774
Service cost	7				7
Interest cost	31				37
Benefits paid	(45		)		(46		)
Actuarial (gain) loss	(73		)		25
Retiree drug subsidy	3				3
Balance at end of year	723				800
Change in plan assets
Fair value of plan assets at beginning of year	382				365
Actual return on plan assets	56				43
Employer contributions	11				17
Benefits paid	(42		)		(43		)
Fair value of plan assets at end of year	407				382
Accrued liability	$	(316	)		$	(418	)
Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
	2013				2012
	(in millions)
Other regulatory assets, deferred	$	69			$	187
Employee benefit obligations	(316		)		(418		)
Presented below are the amounts included in regulatory assets at December 31, 2013 and 2012 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 2014.
	2013				2012				Estimated
									Amortization
									in 2014
	(in millions)
Prior service cost	$	(4	)		$	(4	)		$	—
Net (gain) loss	73				186				2
Transition obligation	—				5				—
Regulatory assets	$	69			$	187
The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2013 and 2012 are presented in the following table:
	2013			2012
	(in millions)
Regulatory assets:
Beginning balance	$	187		$	186
Net (gain) loss	(106		)	11
Reclassification adjustments:
Amortization of transition obligation	(4		)	(6		)
Amortization of prior service costs	—			—
Amortization of net gain (loss)	(8		)	(4		)
Total reclassification adjustments	(12		)	(10		)
Total change	(118		)	1
Ending balance	$	69		$	187
Components of the other postretirement benefit plans' net periodic cost were as follows:
	2013				2012				2011
	(in millions)
Service cost	$	7			$	7			$	7
Interest cost	31				37				41
Expected return on plan assets	(24		)		(29		)		(30		)
Net amortization	12				10				11
Net periodic postretirement benefit cost	$	26			$	25			$	29
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)
2014	$	49			$	(4	)		$	45
2015	50				(4		)		46
2016	53				(5		)		48
2017	54				(5		)		49
2018	58				(6		)		52
2019 to 2023	287				(30		)		257
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (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, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
	Target			2013			2012
Pension plan assets:
Domestic equity	26	%		31	%		28	%
International equity	25			25			24
Fixed income	23			23			27
Special situations	3			1			1
Real estate investments	14			14			13
Private equity	9			6			7
Total	100	%		100	%		100	%
Other postretirement benefit plan assets:
Domestic equity	41	%		36	%		34	%
International equity	21			30			27
Domestic fixed income	24			21			27
Global fixed income	8			8			7
Special situations	1			—			—
Real estate investments	3			3			3
Private equity	2			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, 2013 and 2012. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
•	Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
•	TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.
•	Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	506			$	296			$	—		$	802
International equity*	389				359				—			748
Fixed income:
U.S. Treasury, government, and agency bonds	—				212				—			212
Mortgage- and asset-backed securities	—				55				—			55
Corporate bonds	—				346				—			346
Pooled funds	—				166				—			166
Cash equivalents and other	—				79				—			79
Real estate investments	92				—				353			445
Private equity	—				—				202			202
Total	$	987			$	1,513			$	555		$	3,055
Liabilities:
Derivatives	—				(1		)		—			(1		)
Total	$	987			$	1,512			$	555		$	3,054
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	413			$	238			$	—		$	651
International equity*	324				348				—			672
Fixed income:
U.S. Treasury, government, and agency bonds	—				183				—			183
Mortgage- and asset-backed securities	—				45				—			45
Corporate bonds	—				312				1			313
Pooled funds	—				142				—			142
Cash equivalents and other	2				195				—			197
Real estate investments	92				—				299			391
Private equity	—				—				211			211
Total	$	831			$	1,463			$	511		$	2,805
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
	(in millions)
Beginning balance	$	299			$	211			$	296		$	220
Actual return on investments:
Related to investments held at year end	25				3				2			—
Related to investments sold during the year	10				17				1			2
Total return on investments	35				20				3			2
Purchases, sales, and settlements	19				(29		)		—			(11		)
Ending balance	$	353			$	202			$	299		$	211
The fair values of other postretirement benefit plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	74			$	25			$	—		$	99
International equity*	12				57				—			69
Fixed income:
U.S. Treasury, government, and agency bonds	—				7				—			7
Mortgage- and asset-backed securities	—				2				—			2
Corporate bonds	—				11				—			11
Pooled funds	—				34				—			34
Cash equivalents and other	—				6				—			6
Trust-owned life insurance	—				158				—			158
Real estate investments	3				—				11			14
Private equity	—				—				6			6
Total	$	89			$	300			$	17		$	406
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in millions)
Assets:
Domestic equity*	$	65			$	27			$	—		$	92
International equity*	10				51				—			61
Fixed income:
U.S. Treasury, government, and agency bonds	—				6				—			6
Mortgage- and asset-backed securities	—				1				—			1
Corporate bonds	—				10				—			10
Pooled funds	—				32				—			32
Cash equivalents and other	—				18				—			18
Trust-owned life insurance	—				142				—			142
Real estate investments	3				—				10			13
Private equity	—				—				7			7
Total	$	78			$	287			$	17		$	382
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
	(in millions)
Beginning balance	$	10			$	7			$	9		$	7
Actual return on investments:
Related to investments held at year end	1				—				1			—
Related to investments sold during the year	—				—				—			—
Total return on investments	1				—				1			—
Purchases, sales, and settlements	—				(1		)		—			—
Ending balance	$	11			$	6			$	10		$	7
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2013, 2012, and 2011 were $24 million, $24 million, and $24 million, respectively.
Gulf Power [Member]	'
RETIREMENT BENEFITS	'
	RETIREMENT BENEFITS
	The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions were made to the qualified pension plan during 2013. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2014. 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, 2014, no other postretirement trust contributions are expected.
	Actuarial Assumptions
	The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.53% and 5.41%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.02	%		4.27	%		4.98	%
	Other postretirement benefit plans	4.86			4.06			4.88
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	8.04			8.02			8.11
	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 of 7.00% for 2014, decreasing gradually to 5.00% through the year 2021 and remaining at that level thereafter. 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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in thousands)
	Benefit obligation	$	2,884			$	(2,479	)
	Service and interest costs	138				(119		)
	Pension Plans
	The total accumulated benefit obligation for the pension plans was $353 million at December 31, 2013 and $371 million at December 31, 2012. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
		2013				2012
		(in thousands)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	413,501			$	352,834
	Service cost	11,128				9,101
	Interest cost	17,321				17,199
	Benefits paid	(14,831		)		(14,046		)
	Plan amendments	—				426
	Actuarial (gain) loss	(31,791		)		47,987
	Balance at end of year	395,328				413,501
	Change in plan assets
	Fair value of plan assets at beginning of year	350,260				304,324
	Actual return on plan assets	49,076				45,762
	Employer contributions	1,134				14,220
	Benefits paid	(14,831		)		(14,046		)
	Fair value of plan assets at end of year	385,639				350,260
	Accrued liability	$	(9,689	)		$	(63,241	)
	At December 31, 2013, the projected benefit obligations for the qualified and non-qualified pension plans were $374 million and $21 million, respectively. All pension plan assets are related to the qualified pension plan.
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in thousands)
	Prepaid pension costs	$	11,533			$	—
	Other regulatory assets, deferred	75,280				139,261
	Current liabilities, other	(1,183		)		(855		)
	Employee benefit obligations	(20,039		)		(62,386		)
	Presented below are the amounts included in regulatory assets at December 31, 2013 and 2012 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 2014.
		2013				2012				Estimated Amortization in 2014
		(in thousands)
	Prior service cost	$	4,401			$	5,565			$	1,115
	Net (gain) loss	70,879				133,696				4,559
	Regulatory assets	$	75,280			$	139,261
	The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2013 and 2012 are presented in the following table:
		2013			2012
		(in thousands)
	Regulatory assets:
	Beginning balance	$	139,261		$	115,853
	Net (gain) loss	(54,432		)	28,157
	Change in prior service costs	—			426
	Reclassification adjustments:
	Amortization of prior service costs	(1,164		)	(1,262		)
	Amortization of net gain (loss)	(8,385		)	(3,913		)
	Total reclassification adjustments	(9,549		)	(5,175		)
Total change	(63,981		)	23,408
Ending balance	$	75,280		$	139,261
Components of net periodic pension cost were as follows:
	2013				2012				2011
	(in thousands)
Service cost	$	11,128			$	9,101			$	8,431
Interest cost	17,321				17,199				17,074
Expected return on plan assets	(26,435		)		(25,932		)		(27,232		)
Recognized net (gain) loss	8,385				3,913				512
Net amortization	1,164				1,262				1,262
Net periodic pension cost	$	11,563			$	5,543			$	47
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2013, estimated benefit payments were as follows:
	Benefit Payments
	(in thousands)
2014	$	16,548
2015	17,440
2016	18,405
2017	19,649
2018	20,681
2019 to 2023	121,864
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
	2013				2012
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of year	$	75,395			$	70,923
Service cost	1,355				1,167
Interest cost	2,982				3,367
Benefits paid	(3,583		)		(3,854		)
Actuarial (gain) loss	(7,900		)		3,468
Retiree drug subsidy	330				324
Balance at end of year	68,579				75,395
Change in plan assets
Fair value of plan assets at beginning of year	16,227				14,978
Actual return on plan assets	2,119				2,131
Employer contributions	2,381				2,648
Benefits paid	(3,253		)		(3,530		)
Fair value of plan assets at end of year	17,474				16,227
Accrued liability	$	(51,105	)		$	(59,168	)
Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
	2013				2012
	(in thousands)
Other regulatory assets, deferred	$	—			$	2,169
Current liabilities, other	(687		)		(661		)
Other regulatory liabilities, deferred	(6,984		)		—
Employee benefit obligations	(50,418		)		(58,507		)
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2013 and 2012 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 2014.
	2013				2012				Estimated Amortization in 2014
	(in thousands)
Prior service cost	$	138			$	324			$	186
Net (gain) loss	(7,122		)		1,845				(24		)
Net regulatory assets (liabilities)	$	(6,984	)		$	2,169
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2013 and 2012 are presented in the following table:
	2013			2012
	(in thousands)
Net regulatory assets (liabilities):
Beginning balance	$	2,169		$	239
Net (gain) loss	(8,967		)	2,309
Reclassification adjustments:
Amortization of transition obligation	—			(193		)
Amortization of prior service costs	(186		)	(186		)
Amortization of net gain (loss)	—			—
Total reclassification adjustments	(186		)	(379		)
Total change	(9,153		)	1,930
Ending balance	$	(6,984	)	$	2,169
Components of the other postretirement benefit plans' net periodic cost were as follows:
	2013				2012				2011
	(in thousands)
Service cost	$	1,355			$	1,167			$	1,132
Interest cost	2,982				3,367				3,658
Expected return on plan assets	(1,238		)		(1,311		)		(1,445		)
Net amortization	186				379				396
Net periodic postretirement benefit cost	$	3,285			$	3,602			$	3,741
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
	Benefit				Subsidy				Total
	Payments				Receipts
	(in thousands)
2014	$	4,447			$	(409	)		$	4,038
2015	4,630				(456		)		4,174
2016	4,856				(504		)		4,352
2017	4,994				(557		)		4,437
2018	5,168				(611		)		4,557
2019 to 2023	26,272				(3,251		)		23,021
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, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
	Target			2013			2012
Pension plan assets:
Domestic equity	26	%		31	%		28	%
International equity	25			25			24
Fixed income	23			23			27
Special situations	3			1			1
Real estate investments	14			14			13
Private equity	9			6			7
Total	100	%		100	%		100	%
Other postretirement benefit plan assets:
Domestic equity	25	%		30	%		27	%
International equity	24			24			23
Domestic fixed income	25			25			29
Special situations	3			1			1
Real estate investments	14			14			13
Private equity	9			6			7
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, 2013 and 2012. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
•	Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
•	Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
	(in thousands)
Assets:
Domestic equity*	$	63,269			$	37,037			$	—		$	100,306
International equity*	48,606				44,941				—			93,547
Fixed income:
U.S. Treasury, government, and agency bonds	—				26,461				—			26,461
Mortgage- and asset-backed securities	—				6,873				—			6,873
Corporate bonds	—				43,222				—			43,222
Pooled funds	—				20,810				—			20,810
Cash equivalents and other	38				9,851				—			9,889
Real estate investments	11,493				—				44,139			55,632
Private equity	—				—				25,201			25,201
Total	$	123,406			$	189,195			$	69,340		$	381,941
Liabilities:
Derivatives	—				(115		)		—			(115		)
Total	$	123,406			$	189,080			$	69,340		$	381,826
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in thousands)
Assets:
Domestic equity*	$	51,215			$	29,499			$	—		$	80,714
International equity*	40,166				43,120				—			83,286
Fixed income:
U.S. Treasury, government, and agency bonds	—				22,724				—			22,724
Mortgage- and asset-backed securities	—				5,594				—			5,594
Corporate bonds	—				38,534				139			38,673
Pooled funds	—				17,581				—			17,581
Cash equivalents and other	208				24,148				—			24,356
Real estate investments	11,362				—				37,039			48,401
Private equity	—				—				26,129			26,129
Total	$	102,951			$	181,200			$	63,307		$	347,458
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
	(in thousands)
Beginning balance	$	37,039			$	26,129			$	34,989		$	26,053
Actual return on investments:
Related to investments held at year end	3,357				376				1,918			44
Related to investments sold during the year	1,310				2,282				132			1,396
Total return on investments	4,667				2,658				2,050			1,440
Purchases, sales, and settlements	2,433				(3,586		)		—			(1,364		)
Ending balance	$	44,139			$	25,201			$	37,039		$	26,129
The fair values of other postretirement benefit plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
	(in thousands)
Assets:
Domestic equity*	$	2,778			$	1,628			$	—		$	4,406
International equity*	2,136				1,973				—			4,109
Fixed income:
U.S. Treasury, government, and agency bonds	—				1,161				—			1,161
Mortgage- and asset-backed securities	—				303				—			303
Corporate bonds	—				1,897				—			1,897
Pooled funds	—				1,417				—			1,417
Cash equivalents and other	1				433				—			434
Real estate investments	504				—				1,939			2,443
Private equity	—				—				1,108			1,108
Total	$	5,419			$	8,812			$	3,047		$	17,278
Liabilities:
Derivatives	—				(5		)		—			(5		)
Total	$	5,419			$	8,807			$	3,047		$	17,273
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in thousands)
Assets:
Domestic equity*	$	2,290			$	1,319			$	—		$	3,609
International equity*	1,795				1,928				—			3,723
Fixed income:
U.S. Treasury, government, and agency bonds	—				1,016				—			1,016
Mortgage- and asset-backed securities	—				250				—			250
Corporate bonds	—				1,722				6			1,728
Pooled funds	—				1,298				—			1,298
Cash equivalents and other	9				1,078				—			1,087
Real estate investments	508				—				1,667			2,175
Private equity	—				15				1,155			1,170
Total	$	4,602			$	8,626			$	2,828		$	16,056
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate				Private				Real Estate			Private
	Investments				Equity				Investments			Equity
	(in thousands)
Beginning balance	$	1,667			$	1,155			$	1,657		$	1,232
Actual return on investments:
Related to investments held at year end	108				16				107			(1		)
Related to investments sold during the year	57				104				6			80
Total return on investments	165				120				113			79
Purchases, sales, and settlements	107				(167		)		(103		)	(156		)
Ending balance	$	1,939			$	1,108			$	1,667		$	1,155
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 2013, 2012, and 2011 were $4.1 million, $4.0 million, and $3.7 million, respectively.
Mississippi Power [Member]	'
RETIREMENT BENEFITS	'
	RETIREMENT BENEFITS
	The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions were made to the qualified pension plan during 2013. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2014. 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, 2014, no other postretirement trust contributions are expected.
	Actuarial Assumptions
	The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.51% and 5.39%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.01	%		4.26	%		4.98	%
	Other postretirement benefit plans	4.85			4.04			4.87
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	7.04			6.96			7.53
	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 of 7.00% for 2014, decreasing gradually to 5.00% through the year 2021 and remaining at that level thereafter. 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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in thousands)
	Benefit obligation	$	4,665			$	(4,004	)
	Service and interest costs	224				(192		)
	Pension Plans
	The total accumulated benefit obligation for the pension plans was $370 million at December 31, 2013 and $392 million at December 31, 2012. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
		2013				2012
		(in thousands)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	432,553			$	369,680
	Service cost	11,067				9,416
	Interest cost	18,062				18,019
	Benefits paid	(16,207		)		(14,949		)
	Actuarial (gain) loss	(36,080		)		50,387
	Balance at end of year	409,395				432,553
	Change in plan assets
	Fair value of plan assets at beginning of year	351,749				282,100
	Actual return on plan assets	49,431				39,668
	Employer contributions	2,430				44,930
	Benefits paid	(16,207		)		(14,949		)
	Fair value of plan assets at end of year	387,403				351,749
	Accrued liability	$	(21,992	)		$	(80,804	)
	At December 31, 2013, the projected benefit obligations for the qualified and non-qualified pension plans were $382 million and $28 million, respectively. All pension plan assets are related to the qualified pension plan.
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in thousands)
	Prepaid pension costs	$	5,698			$	—
	Other regulatory assets, deferred	77,572				146,838
	Other current liabilities	(2,134		)		(2,087		)
	Employee benefit obligations	(25,556		)		(78,717		)
	Presented below are the amounts included in regulatory assets at December 31, 2013 and 2012 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 2014.
		2013				2012				Estimated Amortization in 2014
		(in thousands)
	Prior service cost	$	4,118			$	5,261			$	1,088
	Net (gain) loss	73,454				141,577				4,937
	Regulatory assets	$	77,572			$	146,838
	The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2013 and 2012 are presented in the following table:
		2013			2012
		(in thousands)
	Regulatory assets:
	Beginning balance	$	146,838		$	117,354
	Net (gain) loss	(58,662		)	34,893
	Reclassification adjustments:
	Amortization of prior service costs	(1,143		)	(1,309		)
	Amortization of net gain (loss)	(9,461		)	(4,100		)
	Total reclassification adjustments	(10,604		)	(5,409		)
	Total change	(69,266		)	29,484
	Ending balance	$	77,572		$	146,838
Components of net periodic pension cost were as follows:
	2013				2012				2011
	(in thousands)
Service cost	$	11,067			$	9,416			$	8,838
Interest cost	18,062				18,019				17,827
Expected return on plan assets	(26,849		)		(24,121		)		(25,166		)
Recognized net (gain) loss	9,461				4,100				1,114
Net amortization	1,143				1,309				1,309
Net periodic pension cost	$	12,884			$	8,723			$	3,922
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, 2013, estimated benefit payments were as follows:
	Benefit
	Payments
	(in thousands)
2014	$	17,245
2015	18,076
2016	18,993
2017	20,172
2018	21,237
2019 to 2023	124,728
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
	2013				2012
	(in thousands)
Change in benefit obligation
Benefit obligation at beginning of year	$	91,783			$	87,447
Service cost	1,151				1,038
Interest cost	3,619				4,155
Benefits paid	(4,080		)		(4,432		)
Actuarial (gain) loss	(11,959		)		3,166
Retiree drug subsidy	426				409
Balance at end of year	80,940				91,783
Change in plan assets
Fair value of plan assets at beginning of year	21,990				20,534
Actual return on plan assets	2,379				2,427
Employer contributions	2,562				3,052
Benefits paid	(3,654		)		(4,023		)
Fair value of plan assets at end of year	23,277				21,990
Accrued liability	$	(57,663	)		$	(69,793	)
Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
	2013				2012
	(in thousands)
Other regulatory assets, deferred	$	5,227			$	15,454
Other regulatory liabilities, deferred	(3,111		)		—
Employee benefit obligations	(57,663		)		(69,793		)
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2013 and 2012 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 2014.
	2013				2012				Estimated Amortization in 2014
	(in thousands)
Prior service cost	$	(2,311	)		$	(2,498	)		$	(188	)
Net (gain) loss	4,427				17,952				—
Net regulatory assets (liabilities)	$	2,116			$	15,454
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2013 and 2012 are presented in the following table:
	2013			2012
	(in thousands)
Net regulatory assets (liabilities):
Beginning balance	$	15,454		$	13,324
Net (gain) loss	(12,867		)	2,600
Reclassification adjustments:
Amortization of transition obligation	—			(171		)
Amortization of prior service costs	188			188
Amortization of net gain (loss)	(659		)	(487		)
Total reclassification adjustments	(471		)	(470		)
Total change	(13,338		)	2,130
Ending balance	$	2,116		$	15,454
Components of the other postretirement benefit plans' net periodic cost were as follows:
	2013				2012				2011
	(in thousands)
Service cost	$	1,151			$	1,038			$	1,012
Interest cost	3,619				4,155				4,292
Expected return on plan assets	(1,472		)		(1,552		)		(1,763		)
Net amortization	471				470				274
Net periodic postretirement benefit cost	$	3,769			$	4,111			$	3,815
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 thousands)
2014	$	5,051			$	(526	)		$	4,525
2015	5,335				(577		)		4,758
2016	5,569				(632		)		4,937
2017	5,849				(689		)		5,160
2018	6,091				(748		)		5,343
2019 to 2023	32,600				(3,793		)		28,807
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, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
	Target			2013			2012
Pension plan assets:
Domestic equity	26	%		31	%		28	%
International equity	25			25			24
Fixed income	23			23			27
Special situations	3			1			1
Real estate investments	14			14			13
Private equity	9			6			7
Total	100	%		100	%		100	%
Other postretirement benefit plan assets:
Domestic equity	21	%		25	%		22	%
International equity	20			20			19
Fixed income	38			38			42
Special situations	3			1			1
Real estate investments	11			11			10
Private equity	7			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, 2013 and 2012. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
•	Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
•	Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
	(in thousands)
Assets:
Domestic equity*	$	63,558			$	37,206			$	—		$	100,764
International equity*	48,829				45,146				—			93,975
Fixed income:
U.S. Treasury, government, and agency bonds	—				26,582				—			26,582
Mortgage- and asset-backed securities	—				6,904				—			6,904
Corporate bonds	—				43,420				—			43,420
Pooled funds	—				20,905				—			20,905
Cash equivalents and other	38				9,896				—			9,934
Real estate investments	11,546				—				44,341			55,887
Private equity	—				—				25,316			25,316
Total	$	123,971			$	190,059			$	69,657		$	383,687
Liabilities:
Derivatives	—				(115		)		—			(115		)
Total	$	123,971			$	189,944			$	69,657		$	383,572
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in thousands)
Assets:
Domestic equity*	$	51,433			$	29,624			$	—		$	81,057
International equity*	40,337				43,303				—			83,640
Fixed income:
U.S. Treasury, government, and agency bonds	—				22,820				—			22,820
Mortgage- and asset-backed securities	—				5,618				—			5,618
Corporate bonds	—				38,696				140			38,836
Pooled funds	—				17,656				—			17,656
Cash equivalents and other	209				24,251				—			24,460
Real estate investments	11,410				—				37,196			48,606
Private equity	—				—				26,240			26,240
Total	$	103,389			$	181,968			$	63,576		$	348,933
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate				Private Equity				Real Estate			Private Equity
	Investments								Investments
	(in thousands)
Beginning balance	$	37,196			$	26,240			$	32,434		$	24,151
Actual return on investments:
Related to investments held at year end	3,385				378				4,629			44
Related to investments sold during the year	1,316				2,300				133			3,415
Total return on investments	4,701				2,678				4,762			3,459
Purchases, sales, and settlements	2,444				(3,602		)		—			(1,370		)
Ending balance	$	44,341			$	25,316			$	37,196		$	26,240
The fair values of other postretirement benefit plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
	(in thousands)
Assets:
Domestic equity*	$	3,089			$	1,809			$	—		$	4,898
International equity*	2,375				2,193				—			4,568
Fixed income:
U.S. Treasury, government, and agency bonds	—				5,213				—			5,213
Mortgage- and asset-backed securities	—				337				—			337
Corporate bonds	—				2,109				—			2,109
Pooled funds	—				1,016				—			1,016
Cash equivalents and other	1				968				—			969
Real estate investments	560				—				2,156			2,716
Private equity	—				—				1,231			1,231
Total	$	6,025			$	13,645			$	3,387		$	23,057
Liabilities:
Derivatives	—				(5		)		—			(5		)
Total	$	6,025			$	13,640			$	3,387		$	23,052
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
	Fair Value Measurements Using
	Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
	(in thousands)
Assets:
Domestic equity*	$	2,561			$	1,475			$	—		$	4,036
International equity*	2,008				2,156				—			4,164
Fixed income:
U.S. Treasury, government, and agency bonds	—				5,187				—			5,187
Mortgage- and asset-backed securities	—				280				—			280
Corporate bonds	—				1,925				7			1,932
Pooled funds	—				879				—			879
Cash equivalents and other	11				1,612				—			1,623
Real estate investments	569				—				1,865			2,434
Private equity	—				14				1,293			1,307
Total	$	5,149			$	13,528			$	3,165		$	21,842
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
	2013								2012
	Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
	(in thousands)
Beginning balance	$	1,865			$	1,293			$	1,851		$	1,377
Actual return on investments:
Related to investments held at year end	158				18				119			(1		)
Related to investments sold during the year	64				110				7			90
Total return on investments	222				128				126			89
Purchases, sales, and settlements	69				(190		)		(112		)	(173		)
Ending balance	$	2,156			$	1,231			$	1,865		$	1,293
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 2013, 2012, and 2011 were $4.1 million, $3.9 million, and $3.8 million, respectively.

Acquisitions

Acquisitions (Southern Power [Member])	12 Months Ended
	Dec. 31, 2013
Southern Power [Member]	'
ACQUISITIONS	'
	ACQUISITIONS
	Adobe Solar, LLC
	On August 27, 2013, the Company and TRE, through STR, entered into a purchase agreement with Sun Edison, LLC, the developer of the project, which provides for the acquisition of all of the outstanding membership interests of Adobe Solar, LLC (Adobe) by STR. Adobe is constructing an approximately 20-megawatt (MW) solar generating facility in Kern County, California. The solar facility is expected to begin commercial operation in spring 2014. The output of the plant is contracted under a 20-year PPA with Southern California Edison Company, which is expected to begin in spring 2014. The acquisition is in accordance with the Company's overall growth strategy.
	The Company's acquisition of Adobe is expected to occur in spring 2014 and the purchase price is expected to be approximately $100 million.
	The completion of the acquisition is subject to Sun Edison, LLC achieving certain construction and project milestones by certain dates and various customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.
	Campo Verde Solar, LLC
	On April 23, 2013, the Company and TRE, through STR, acquired all of the outstanding membership interests of Campo Verde Solar, LLC (Campo Verde) from First Solar, Inc., the developer of the project. Campo Verde constructed and owns an approximately 139-MW solar photovoltaic facility in Southern California. The solar facility began commercial operation on October 25, 2013. The output of the plant is contracted under a 20-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy, which began on the commercial operation date. The asset acquisition was in accordance with the Company's overall growth strategy.
	The Company's acquisition of Campo Verde included cash consideration of $136.6 million, of which $132.2 million has been paid and $4.4 million remains to be paid upon completion of certain milestones. The purchase price was allocated primarily to CWIP and $1.0 million to other assets. As of December 31, 2013, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration and due diligence costs were expensed as incurred and were not material. Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar, Inc. for construction of the solar facility.
	Spectrum Nevada Solar, LLC
	On September 28, 2012, the Company and TRE, through STR, acquired all of the outstanding membership interests of Spectrum Nevada Solar, LLC (Spectrum) from Sun Edison, LLC, the original developer of the project. Spectrum constructed and owns an approximately 30-MW solar photovoltaic facility in North Las Vegas, Nevada. The solar facility began commercial operation on September 23, 2013. The output of the plant is contracted under a 25-year PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., which began on the commercial operation date. The asset acquisition was in accordance with the Company's overall growth strategy.
	The Company's acquisition of Spectrum consisted of cash consideration of $17.6 million paid at closing which was allocated to CWIP and did not include any contingent consideration. Due diligence costs were expensed as incurred and were not material. Under an engineering, procurement, and construction agreement, an additional $104.0 million was paid in 2013 to a subsidiary of Sun Edison, LLC to complete the construction of the solar facility.
	Apex Nevada Solar, LLC
	On June 29, 2012, the Company and TRE, through STR, acquired all of the outstanding membership interests of Apex Nevada Solar, LLC (Apex) from Sun Edison, LLC, the original developer of the project. Apex constructed and owns an approximately 20-MW solar photovoltaic facility in North Las Vegas, Nevada. The solar facility began commercial operation on July 21, 2012. The output of the plant is contracted under a 25-year PPA with Nevada Power Company, a subsidiary of NV Energy, Inc., that began in July 2012. The business acquisition was in accordance with the Company's overall growth strategy.
	The Company's acquisition of Apex included cash consideration of $102.0 million, of which $96.0 million was paid in 2012 and $6.0 million will be paid upon completion of certain milestones. The purchase price was allocated to CWIP. The acquisition did not include any contingent consideration. Due diligence costs were expensed as incurred and were not material.

Contingencies_and_Regulatory_M

Contingencies and Regulatory Matters	12 Months Ended
	Dec. 31, 2013
CONTINGENCIES AND REGULATORY MATTERS	'
	CONTINGENCIES AND REGULATORY MATTERS
	General Litigation Matters
	Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide (CO2) and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements.
	Insurance Recovery
	Mirant Corporation (Mirant) was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and other countries. Mirant was a wholly-owned subsidiary of Southern Company until its initial public offering in 2000. In 2001, Southern Company completed a spin-off to its stockholders of its remaining ownership, and Mirant became an independent corporate entity.
	In 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. In 2005, Mirant, as a debtor in possession, and the unsecured creditors' committee filed a complaint against Southern Company. Later in 2005, this complaint was transferred to MC Asset Recovery, LLC (MC Asset Recovery) as part of Mirant's plan of reorganization. In 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve this action. The settlement included an agreement where Southern Company paid MC Asset Recovery $202 million. Southern Company filed an insurance claim in 2009 to recover a portion of this settlement and received payments from its insurance provider of $25 million in June 2012 and $15 million on December 10, 2013. Additionally, legal fees related to these insurance settlements totaled approximately $6 million in 2012 and $4 million in 2013. As a result, the net reduction to expense presented as MC Asset Recovery insurance settlement in the statement of income was approximately $19 million in 2012 and $11 million in 2013.
	Environmental Matters
	New Source Review Actions
	As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for Alabama Power on all remaining claims and dismissal of the case with prejudice in 2011. On September 19, 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of Alabama Power, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.
	Southern Company believes the traditional operating companies complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time.
	Environmental Remediation
	The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.
	Georgia Power's environmental remediation liability as of December 31, 2013 was $18 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.
	Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.
	In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. On February 1, 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted Georgia Power's summary judgment motion, ruling that Georgia Power has no liability in the private action. On May 10, 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit.
	The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the regulatory recovery mechanisms, these matters are not expected to have a material impact on Southern Company's financial statements.
	Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $50 million as of December 31, 2013. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, there was no impact on net income as a result of these liabilities.
	The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the financial statements.
	Nuclear Fuel Disposal Costs
	Acting through the U.S. Department of Energy (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. The DOE failed to timely perform and has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel beginning no later than January 31, 1998. Consequently, Alabama Power and Georgia Power have pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.
	As a result of the first lawsuit, Georgia Power recovered approximately $27 million, based on its ownership interests, and Alabama Power recovered approximately $17 million, representing the vast majority of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In April 2012, Alabama Power credited the award to cost of service for the benefit of customers. In July 2012, Georgia Power credited the award to accounts where the original costs were charged and used it to reduce rate base, fuel, and cost of service for the benefit of customers.
	In 2008, Alabama Power and Georgia Power filed a second lawsuit 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. Damages are being sought for the period from January 1, 2005 through December 31, 2010. 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, 2013 for any potential recoveries from the second lawsuit. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's net income is expected.
	An on-site dry storage facility at Plant Vogtle Units 1 and 2 began operation in October 2013. At Plants Hatch and Farley, on-site dry spent fuel storage facilities are also operational. Facilities at all plants can be expanded to accommodate spent fuel through the expected life of each plant.
	Retail Regulatory Matters
	Alabama Power
	Retail Rate Adjustments
	In 2011, the Alabama PSC issued an order to eliminate a tax-related adjustment under Alabama Power's rate structure effective with October 2011 billings. The elimination of this adjustment resulted in additional revenues of approximately $31 million for 2011. In accordance with the order, Alabama Power made additional accruals to the natural disaster reserve (NDR) in the fourth quarter 2011 of an amount equal to such additional 2011 revenues. The NDR was impacted as a result of operations and maintenance expenses incurred in connection with the 2011 storms in Alabama. See "Natural Disaster Reserve" below for additional information. The elimination of this adjustment resulted in additional revenues of approximately $106 million for 2012.
	Rate RSE
	Alabama Power operates under a rate stabilization and equalization plan (Rate RSE) approved by the Alabama PSC. Alabama Power's Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the allowed equity return range. Prior to 2014, retail rates remained unchanged when the retail return on common equity (ROE) was projected to be between 13.0% and 14.5%.
	During 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. On August 13, 2013, the Alabama PSC voted to issue a report on Rate RSE that found that Alabama Power's Rate RSE mechanism continues to be just and reasonable to customers and Alabama Power, but recommended Alabama Power modify Rate RSE as follows:
	•	Eliminate the provision of Rate RSE establishing an allowed range of ROE.
	•	Eliminate the provision of Rate RSE limiting Alabama Power's capital structure to an allowed equity ratio of 45%.
	•	Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.
	•	Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.
	Substantially all other provisions of Rate RSE were unchanged.
	On August 21, 2013, Alabama Power filed its consent to these recommendations with the Alabama PSC. The changes became effective for calendar year 2014. On November 27, 2013, Alabama Power made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2014; projected earnings were within the specified WCE range and, therefore, retail rates under Rate RSE remained unchanged for 2014. In 2012 and 2013, retail rates under Rate RSE remained unchanged from 2011. Under the terms of Rate RSE, the maximum possible increase for 2015 is 5.00%.
	Rate CNP
	Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under rate certificated new plant (Rate CNP). Alabama Power may also recover retail costs associated with certificated PPAs under rate certificated new plant (Rate CNP PPA). There was no adjustment to Rate CNP PPA in 2012. On March 5, 2013, 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, 2013 through March 31, 2014. It is anticipated that no adjustment will be made to Rate CNP PPA in 2014. As of December 31, 2013, Alabama Power had an under recovered certificated PPA balance of $18 million, all of which is included in deferred under recovered regulatory clause revenues in the balance sheet.
	In 2011, the Alabama PSC approved and certificated a PPA of approximately 200 MWs of energy from wind-powered generating facilities which became operational in December 2012. In September 2012, the Alabama PSC approved and certificated a second wind PPA of approximately 200 MWs which became operational in January 2014. The terms of the wind PPAs permit Alabama Power to use the energy and retire the associated environmental attributes in service of its customers or to sell environmental attributes, separately or bundled with energy. Alabama Power has elected the normal purchase normal sale (NPNS) scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry’s application of the NPNS exception to certain physical forward transactions in nodal markets is currently under review by the U.S. Securities and Exchange Commission (SEC) at the request of the electric utility industry. The outcome of the SEC’s review cannot now be determined. If Alabama Power is ultimately required to record these PPAs at fair value, an offsetting regulatory asset or regulatory liability will be recorded.
	Alabama Power's retail rates, approved by the Alabama PSC also allows for the recovery of Alabama Power's retail costs associated with environmental laws, regulations, or other such mandates (Rate CNP Environmental). Rate CNP Environmental is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. There was no adjustment to Rate CNP Environmental in 2012 or 2013. On August 13, 2013, the Alabama PSC approved Alabama Power's petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets previously being recovered through Rate RSE. The revenue impact as a result of this revision is estimated to be $58 million in 2014. On November 21, 2013, Alabama Power submitted calculations associated with its cost of complying with environmental mandates, as provided under Rate CNP Environmental. The filing reflected a projected unrecovered retail revenue requirement for environmental compliance of approximately $72 million, which is to be recovered in the billing months of January 2014 through December 2014. On December 3, 2013, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2014 the factors associated with Alabama Power's environmental compliance costs for the year 2013. Any unrecovered amounts associated with 2014 will be reflected in the 2015 filing. As of December 31, 2013, Alabama Power had an under recovered environmental clause balance of $7 million which is included in deferred under recovered regulatory clause revenues in the balance sheet.
	Environmental Accounting Order
	Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs would be amortized over the affected unit's remaining useful life, as established prior to the decision regarding early retirement.
	Compliance and Pension Cost Accounting Order
	In November 2012, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain compliance-related operations and maintenance expenditures for the years 2013 through 2017, as well as the incremental increase in operations expense related to pension cost for 2013. These deferred costs are to be amortized over a three-year period beginning in January 2015. The compliance related expenditures were related to (i) standards addressing Critical Infrastructure Protection issued by the North American Electric Reliability Corporation, (ii) cyber security requirements issued by the NRC, and (iii) NRC guidance addressing the readiness at nuclear facilities within the U.S. for severe events. The compliance-related expenses to be afforded regulatory asset treatment over the five-year period are currently estimated to be approximately $37 million. The amount of operations and maintenance expenses deferred to a regulatory asset in 2013 associated with compliance-related expenditures and pension cost was approximately $8 million and $12 million, respectively. Pursuant to the accounting order, Alabama Power has the ability to accelerate the amortization of the regulatory assets with notification to the Alabama PSC.
	Retail Energy Cost Recovery
	Alabama Power has established energy cost recovery rates under Alabama Power's energy cost recovery rate (Rate ECR) as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per kilowatt hour (KWH). On December 3, 2013, the Alabama PSC issued a consent order that Alabama Power leave in effect the energy cost recovery rates which began in April 2011 for 2014. Therefore, the Rate ECR factor as of January 1, 2014 remained at 2.681 cents per KWH. Effective with billings beginning in January 2015, the Rate ECR factor will be 5.910 cents per KWH, absent a further order from the Alabama PSC.
	Alabama Power's over recovered fuel costs at December 31, 2013 totaled $42 million as compared to under recovered fuel costs of $4 million at December 31, 2012. At December 31, 2013, $27 million is included in other regulatory liabilities, current and $15 million is included in deferred over recovered regulatory clause revenues. The under recovered fuel costs at December 31, 2012 are included in deferred under recovered regulatory clause revenues in the balance sheets. 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 of the under recovered fuel costs.
	Natural Disaster Reserve
	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 Natural Disaster Reserve (Rate NDR) charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.
	As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
	In accordance with the order that was issued by the Alabama PSC in 2011 to eliminate a tax-related adjustment under Alabama Power's rate structure that resulted in additional revenues, Alabama Power made additional accruals to the NDR in the fourth quarter 2011 of an amount equal to the additional 2011 revenues, which were approximately $31 million.
	The accumulated balances in the NDR for the years ended December 31, 2013 and December 31, 2012 were approximately $96 million and $103 million, respectively. Any accruals to the NDR are included in the balance sheets under other regulatory liabilities, deferred and are reflected as other operations and maintenance expenses in the statements of income.
	Nuclear Outage Accounting Order
	In accordance with a 2010 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 the subsequent 18-month operational cycle.
	Approximately $31 million of nuclear outage costs from the spring of 2012 was amortized to nuclear operations and maintenance expenses over the 18-month period ended in December 2013. During the spring of 2013, approximately $28 million of nuclear outage costs was deferred to a regulatory asset, and beginning in July 2013, these deferred costs are being amortized over an 18-month period. During the fall of 2013, approximately $32 million of nuclear outage costs associated with the second unit was deferred to a regulatory asset, and beginning in January 2014, these deferred costs are being amortized over an 18-month period. Alabama Power will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period pursuant to the Alabama PSC order.
	Non-Nuclear Outage Accounting Order
	On August 13, 2013, the Alabama PSC approved Alabama Power's petition requesting authorization to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. The 2014 outage expenditures to be deferred and amortized are estimated to total approximately $78 million.
	Georgia Power
	Rate Plans
	In 2010, the Georgia PSC approved the 2010 ARP, which resulted in base rate increases of approximately $562 million, $17 million, $125 million, and $74 million effective January 1, 2011, January 1, 2012, April 1, 2012, and January 1, 2013, respectively.
	On December 17, 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among Georgia Power, the Georgia PSC’s Public Interest Advocacy Staff, and 11 of the 13 intervenors, which was filed with the Georgia PSC on November 18, 2013.
	On January 1, 2014, in accordance with the 2013 ARP, Georgia Power increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million; (2) Environmental Compliance Cost Recovery (ECCR) tariff by an additional $25 million; (3) Demand-Side Management (DSM) tariffs by an additional $1 million; and (4) Municipal Franchise Fee (MFF) tariff by an additional $4 million, for a total increase in base revenues of approximately $110 million.
	Under the 2013 ARP, the following additional rate adjustments will be made to Georgia Power’s tariffs in 2015 and 2016 based on annual compliance filings to be made at least 90 days prior to the effective date of the tariffs:
•	Effective January 1, 2015 and 2016, the traditional base tariff rates will increase by an estimated $101 million and $36 million, respectively, to recover additional generation capacity-related costs;
•	Effective January 1, 2015 and 2016, the ECCR tariff will increase by an estimated $76 million and $131 million, respectively, to recover additional environmental compliance costs;
•	Effective January 1, 2015, the DSM tariffs will increase by an estimated $6 million and decrease by an estimated $1 million effective January 1, 2016; and
•	The MFF tariff will increase consistent with these adjustments.
Georgia Power currently estimates these adjustments will result in base revenue increases of approximately $187 million in 2015 and $170 million in 2016. The estimated traditional base tariff rate increases for 2015 and 2016 do not include additional Qualifying Facility (QF) PPA expenses; however, compliance filings will include QF PPA expenses for those facilities that are projected to provide capacity to Georgia Power during the following year.
Under the 2013 ARP, Georgia Power’s retail ROE is set at 10.95%, and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. However, if at any time during the term of the 2013 ARP, Georgia Power projects that its retail earnings will be below 10.00% for any calendar year, it may petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff that would be used to adjust Georgia Power’s earnings back to a 10.00% retail ROE. The Georgia PSC would have 90 days to rule on Georgia Power’s request. The ICR tariff will expire at the earlier of January 1, 2017 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, Georgia Power may file a full rate case.
Except as provided above, Georgia Power will not file for a general base rate increase while the 2013 ARP is in effect. Georgia Power is required to file a general rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued.
Integrated Resource Plans
On January 31, 2013, Georgia Power filed its triennial IRP (2013 IRP). The filing included Georgia Power's request to decertify 16 coal- and oil-fired units totaling 2,093 MWs. Several factors, including the cost to comply with existing and future environmental regulations, recent and forecasted economic conditions, and lower natural gas prices, contributed to the decision to close these units.
On April 17, 2013, the Georgia PSC approved the decertification of Plant Bowen Unit 6 (32 MWs), which was retired on April 25, 2013. On September 30, 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 Integrated Resource Plan Update (2011 IRP Update) in order to comply with the State of Georgia's Multi-Pollutant Rule.
On July 11, 2013, the Georgia PSC approved Georgia Power's request to decertify and retire Plant Boulevard Units 2 and 3 (28 MWs) effective July 17, 2013. Plant Branch Units 3 and 4 (1,016 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) will be decertified and retired by April 16, 2015, the compliance date of the Mercury and Air Toxics Standards (MATS) rule. The decertification date of Plant Branch Unit 1 was extended from December 31, 2013 as specified in the final order in the 2011 IRP Update to coincide with the decertification date of Plant Branch Units 3 and 4. The decertification and retirement of Plant Kraft Units 1 through 4 (316 MWs) was also approved and will be effective by April 16, 2016, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division on September 10, 2013 to allow for necessary transmission system reliability improvements.
Additionally, the Georgia PSC approved Georgia Power's proposed MATS rule compliance plan for emissions controls necessary for the continued operation of Plants Bowen Units 1 through 4, Wansley Units 1 and 2, Scherer Units 1 through 3, and Hammond Units 1 through 4, the switch to natural gas as the primary fuel at Plant Yates Units 6 and 7 and Southern Electric Generating Company's (SEGCO) Plant Gaston Units 1 through 4, as well as the fuel switch at Plant McIntosh Unit 1 to operate on Powder River Basin coal.
In the 2013 ARP, the Georgia PSC approved the amortization of the construction work in progress (CWIP) balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years beginning in January 2014 and the amortization of any remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024. The Georgia PSC deferred a decision regarding the appropriate recovery period for the costs associated with unusable materials and supplies remaining at the retiring plants to Georgia Power's next base rate case, which Georgia Power expects to file in 2016 (2016 Rate Case). In the 2013 IRP, the Georgia PSC also deferred decisions regarding the recovery of any fuel related costs that could be incurred in connection with the retirement units to be addressed in future fuel cases.
A request was filed with the Georgia PSC on January 10, 2014 to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. The filing also notified the Georgia PSC of Georgia Power’s plans to seek decertification later this year. Plant Mitchell Unit 3 will continue to operate as a coal unit until April 2015 when it will be required to cease operation or install additional environmental controls to comply with the MATS rule. In connection with the retirement decision, Georgia Power reclassified the retail portion of the net carrying value of Plant Mitchell Unit 3 from plant in service, net of depreciation, to other utility plant, net.
The decertification of these units and fuel conversions are not expected to have a material impact on Southern Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's order in the 2016 Rate Case and future fuel cases and cannot be determined at this time.
Renewables Development
On December 17, 2013, four PPAs totaling 50 MWs of utility scale solar generation under the Georgia Power Advanced Solar Initiative (GPASI) were approved by the Georgia PSC, with Georgia Power as the purchaser. These contracts will begin in 2015 and end in 2034. The resulting purchases will be for energy only and recovered through Georgia Power’s fuel cost recovery mechanism. Under the 2013 IRP, the Georgia PSC approved an additional 525 MWs of solar generation to be purchased by Georgia Power. The 525 MWs will be divided into 425 MWs of utility scale projects and 100 MWs of distributed generation.
On November 4, 2013, Georgia Power filed an application for the certification of two PPAs which were executed on April 22, 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.
During 2013, Georgia Power executed four PPAs to purchase a total of 169 MWs of biomass capacity and energy from four facilities in Georgia that will begin in 2015 and end in 2035. On May 21, 2013, the Georgia PSC approved two of the biomass PPAs and the remaining two were approved on December 17, 2013. The four biomass PPAs are contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation. 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. The Georgia PSC approved reductions in Georgia Power's total annual billings of approximately $43 million effective June 1, 2011, $567 million effective June 1, 2012, and $122 million effective January 1, 2013. The 2013 reduction was due to the Georgia PSC authorizing an Interim Fuel Rider, which is set to expire June 1, 2014. Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power's fuel cost recovery includes costs associated with a natural gas hedging program as revised and approved by the Georgia PSC on February 7, 2013, requiring it to use options and hedges within a 24-month time horizon. On February 18, 2014, the Georgia PSC approved the deferral of Georgia Power's next fuel case, which is now expected to be filed by March 1, 2015.
Georgia Power's over recovered fuel balance totaled approximately $58 million and $230 million at December 31, 2013 and 2012, respectively, and is included in current liabilities and other deferred credits and liabilities.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow.
Storm Damage Recovery
Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of December 31, 2013, the balance in the regulatory asset related to storm damage was $37 million. As a result of this regulatory treatment, the costs related to storms are generally not expected to have a material impact on Southern Company's financial statements.
Nuclear Construction
In 2008, Georgia Power, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. The Vogtle 3 and 4 Agreement provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.
Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain 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 Owners, Owner insolvency, and certain other events.
In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, effective December 30, 2011, and issued combined construction and operating licenses (COLs) in February 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds.
In 2009, the Georgia PSC approved inclusion of the construction of two new nuclear generating units at Plant Vogtle (Plant Vogtle Units 3 and 4) related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the Nuclear Construction Cost Recovery (NCCR) tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At December 31, 2013, approximately $37 million of these 2009 and 2010 costs remained unamortized in CWIP.
Georgia Power is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, Georgia Power's eighth VCM report requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively.
On September 3, 2013, the Georgia PSC approved a stipulation entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the commercial operation date of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. As required by the stipulation, Georgia Power filed an abbreviated status update with the Georgia PSC on September 3, 2013, which reflected approximately $2.4 billion of total construction capital costs incurred through June 30, 2013. On October 15, 2013, the Georgia PSC voted to approve Georgia Power's eighth VCM report, reflecting construction capital costs incurred, which through December 31, 2012 totaled approximately $2.2 billion. Also in accordance with the stipulation, Georgia Power will file with the Georgia PSC on February 28, 2014 a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), which will request approval for an additional $0.4 billion of construction capital costs. The Ninth/Tenth VCM report will reflect estimated in-service construction capital costs of $4.8 billion and associated financing costs during the construction period, which are estimated to total approximately $2.0 billion. Georgia Power expects to resume filing semi-annual VCM reports in August 2014.
In July 2012, the Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The portion of the additional costs claimed by the Contractor that would be attributable to Georgia Power (based on Georgia Power's ownership interest) with respect to these issues is approximately $425 million (in 2008 dollars). The Contractor also has asserted it is entitled to further schedule extensions. Georgia Power has not agreed with either the proposed cost or schedule adjustments or that the Owners have any responsibility for costs related to these issues. In November 2012, Georgia Power and the other Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Owners are not responsible for these costs. Also in November 2012, the Contractor filed suit against Georgia Power and the other Owners in the U.S. District Court for the District of Columbia alleging the Owners are responsible for these costs. On August 30, 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit on September 27, 2013. While litigation has commenced and Georgia Power intends to vigorously defend its positions, Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.
Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Owners, the Contractor, or both.
As construction continues, the risk remains that additional challenges in the fabrication, assembly, delivery, and installation of structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. Additional claims by the Contractor or Georgia Power (on behalf of the Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.
The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
Retail Base Rate Case
On December 3, 2013, the Florida PSC voted to approve the Settlement Agreement (Gulf Power Settlement Agreement) among Gulf Power and all of the intervenors to the docketed proceeding with respect to Gulf Power's request to increase retail base rates. Under the terms of the Gulf Power Settlement Agreement, Gulf Power (1) increased base rates designed to produce an additional $35 million in annual revenues effective January 2014 and will increase base rates designed to produce an additional $20 million in annual revenues effective January 2015; (2) continued its current authorized retail ROE midpoint and range; and (3) will accrue a return similar to AFUDC on certain transmission system upgrades that go into service after January 2014 until Gulf Power's next retail rate case or January 1, 2017, whichever comes first.
The Gulf Power Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized ROE midpoint and range by 25 basis points in the event the 30-year treasury yield rate increases by an average of at least 75 basis points above 3.7947% for a consecutive six-month period.
The Gulf Power Settlement Agreement also provides that Gulf Power may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an amount up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in Gulf Power’s next base rate case or next depreciation and dismantlement study proceeding, whichever comes first.
The Gulf Power Settlement Agreement also provides for recovery of costs associated with any tropical systems named by the National Hurricane Center through the initiation of a storm surcharge. The storm surcharge will begin, on an interim basis, 60 days following the filing of a cost recovery petition. The storm surcharge generally may not exceed $4.00/1,000 KWHs on monthly residential bills in aggregate for a calendar year. This limitation does not apply if Gulf Power 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.
Pursuant to the Gulf Power Settlement Agreement, Gulf Power may not request an increase in its retail base rates to be effective until after June 2017, unless Gulf Power's actual retail ROE falls below the authorized ROE range.
Integrated Coal Gasification Combined Cycle
Kemper IGCC Overview
Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an integrated coal gasification combined cycle technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation on June 5, 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Project Approval
In April 2012, the Mississippi PSC issued a detailed order confirming the certificate of public convenience and necessity (CPCN) originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC (2012 MPSC CPCN Order), which the Sierra Club appealed to the Chancery Court of Harrison County, Mississippi (Chancery Court). In December 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. On January 8, 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court. The ultimate outcome of the CPCN challenge cannot be determined at this time.
Kemper IGCC Schedule and Cost Estimate
The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include 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 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 the ratepayers, relative to the original proposal for the CPCN) (Cost Cap Exceptions), as contemplated in the settlement agreement between Mississippi Power and the Mississippi PSC entered into on January 24, 2013 (Settlement Agreement) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC. The Kemper IGCC was originally scheduled to be placed in service in May 2014 and is currently scheduled to be placed in service in the fourth quarter 2014.
Mississippi Power’s 2010 project estimate, current cost estimate, and actual costs incurred as of December 31, 2013 for the Kemper IGCC are as follows:
Cost Category	2010 Project Estimate(d)		Current Estimate		Actual Costs at 12/31/2013
	(in billions)
Plant Subject to Cost Cap(a)	$	2.4	$	4.06	$	3.25
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.09
AFUDC(b)	0.17		0.45		0.28
General Exceptions	0.05		0.1		0.07
Regulatory Asset(c)	—		0.09		0.07
Total Kemper IGCC(a)	$	2.97	$	5.04	$	3.99
(a)	The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions.
(b)	Mississippi Power’s original estimate included recovery of financing costs during construction which was not approved by the Mississippi PSC in June 2012 as described in "Rate Recovery of Kemper IGCC Costs."
(c)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets."
(d)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
Of the total costs incurred as of December 31, 2013, $2.74 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.18 billion), $70.5 million in other regulatory assets, and $3.9 million in other deferred charges and assets in the balance sheet, and $1.0 million was previously expensed.
Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any related costs that exceed the $2.88 billion cost cap, excluding the Cost Cap Exceptions and net of the DOE Grants. Southern Company recorded pre-tax charges to income for revisions to the cost estimate of $1.2 billion ($729 million after-tax) in 2013. The revised cost estimates reflect increased labor costs, piping and other material costs, start-up costs, decreases in construction labor productivity, the change in the in-service date, and an increase in the contingency for risks associated with start-up activities.
Mississippi Power could experience further construction cost increases and/or schedule extensions with respect to the Kemper IGCC as a result of factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, or non-performance under construction or other agreements. Furthermore, Mississippi Power could also experience further schedule extensions associated with start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems, which would result in further cost increases and could result in the loss of certain tax benefits related to bonus depreciation. In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap will be reflected in Southern Company's statements of income and these changes could be material.
Rate Recovery of Kemper IGCC Costs
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company’s results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN.
In June 2012, the Mississippi PSC denied Mississippi Power's proposed rate schedule for recovery of financing costs during construction, pending a final ruling from the Mississippi Supreme Court regarding the Sierra Club's appeal of the Mississippi PSC's issuance of the CPCN for the Kemper IGCC (2012 MPSC CWIP Order).
In July 2012, Mississippi Power appealed the Mississippi PSC's June 2012 decision to the Mississippi Supreme Court and requested interim rates under bond. In July 2012, the Mississippi Supreme Court denied Mississippi Power's request for interim rates under bond.
Settlement Agreement
On January 24, 2013, Mississippi Power entered into the Settlement Agreement with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order. Under the Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The Settlement Agreement also allows Mississippi Power to secure alternate financing for costs that are not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the Settlement Agreement. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law on February 26, 2013. Mississippi Power intends to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs as approved by the Mississippi PSC. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective after the Kemper IGCC is placed in service and following completion of the Mississippi PSC's final prudence review of costs for the Kemper IGCC.
The Settlement Agreement provides that Mississippi Power may terminate the Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the Settlement Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff to implement the procedural schedules set forth in the Settlement Agreement and variations to the schedule are likely.
2013 MPSC Rate Order
Consistent with the terms of the Settlement Agreement, on January 25, 2013, Mississippi Power filed a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013, to be recorded to a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service.
On March 5, 2013, the Mississippi PSC issued an order (2013 MPSC Rate Order) approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. Amounts collected through these rates are being recorded as a regulatory liability to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. As of December 31, 2013, $98.1 million had been collected, with $10.3 million recognized in retail revenues in the statement of income and the remainder deferred in other regulatory liabilities and included in the balance sheet.
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi (Baseload Act), Mississippi Power continues to record AFUDC on the Kemper IGCC during the construction period. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates during the construction period unless directed to do otherwise by the Mississippi PSC. On March 21, 2013, a legal challenge to the 2013 MPSC Rate Order was filed by Thomas A. Blanton with the Mississippi Supreme Court, which remains pending against Mississippi Power and the Mississippi PSC.
Seven-Year Rate Plan
Also consistent with the Settlement Agreement, on February 26, 2013, Mississippi Power filed with the Mississippi PSC a rate recovery plan for the Kemper IGCC for the first seven years of its operation, along with a proposed revenue requirement under such plan for 2014 through 2020 (Seven-Year Rate Plan).
On March 22, 2013, Mississippi Power, in compliance with the 2013 MPSC Rate Order, filed a revision to the Seven-Year Rate Plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020, which is still under review by the Mississippi PSC. In the Seven-Year Rate Plan, Mississippi Power proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning on March 19, 2013, is integral to the Seven-Year Rate Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan filing, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020. At the time of the filing of the Seven-Year Rate Plan, the proposed revenue requirement approximated the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent that the actual annual cost of service differs from the forecast approved in the Seven-Year Rate Plan, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of the Seven-Year Rate Plan term, the Mississippi PSC will review the amount and determine the appropriate method and period of disposition.
The revenue requirements set forth in the Seven-Year Rate Plan assume the sale of a 15% undivided interest in the Kemper IGCC to South Mississippi Electric Power Association (SMEPA) and utilization of bonus depreciation as provided by the American Taxpayer Relief Act of 2012 (ATRA), which currently requires that the Kemper IGCC be placed in service in 2014. See "Investment Tax Credits and Bonus Depreciation" herein for additional information regarding bonus depreciation.
In 2014, Mississippi Power plans to amend the Seven-Year Rate Plan to reflect changes including the revised in-service date, the change in expected benefits relating to tax credits, various other revenue requirement items, and other tax matters, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated to be approximately $35 million through 2020. The amendment to the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power that, if approved by the Mississippi PSC, would result in no change to the total customer rate impacts contemplated in the original Seven-Year Rate Plan.
Further cost increases and/or schedule extensions with respect to the Kemper IGCC could have an adverse impact on the Seven-Year Rate Plan, such as the inability to recover items considered as Cost Cap Exceptions, potential costs subject to securitization financing in excess of $1.0 billion, and the loss of certain tax benefits related to bonus depreciation. While the Kemper IGCC is scheduled to be placed in service in the fourth quarter 2014, any schedule extension beyond 2014 would result in the loss of the tax benefits related to bonus depreciation. The estimated value of the bonus depreciation tax benefits to retail customers is approximately $200 million. Loss of these tax benefits would require further adjustment to the Seven-Year Rate Plan and approval by the Mississippi PSC to ensure compliance with the normalization requirements of the Internal Revenue Code. In the event that the Mississippi PSC does not approve or Mississippi Power withdraws the Seven-Year Rate Plan, Mississippi Power would seek rate recovery through an alternate means, which could include a traditional rate case.
Prudence Reviews
The Mississippi PSC’s prudence review of Kemper IGCC costs incurred through March 31, 2013, as provided for in the Settlement Agreement, is expected to occur in the second quarter 2014. A final review of all costs incurred after March 31, 2013 is expected to be completed within six months of the Kemper IGCC’s in-service date. Furthermore, regardless of any prudence determinations made during the construction and start-up period, the Mississippi PSC has the right to make a final prudence determination after the Kemper IGCC has been placed in service.
Regulatory Assets
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period, subject to review of such costs by the Mississippi PSC. The amortization period for any such costs approved for recovery will be determined by the Mississippi PSC at a later date. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation on June 5, 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC, a wholly-owned subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
In addition, Mississippi Power will acquire, construct, and operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC.
The ultimate outcome of these matters cannot be determined at this time.
Proposed Sale of Undivided Interest to SMEPA
In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In February 2012, the Mississippi PSC approved the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. In June 2012, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. On March 29, 2013, Mississippi Power and SMEPA signed an amendment to the asset purchase agreement whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in April 2011 to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the April 2011 power supply agreement were $17.5 million in 2013. On December 24, 2013, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014. The sale and transfer of an interest in the Kemper IGCC to SMEPA is subject to approval by the Mississippi PSC.
The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In September 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.
In March 2012 and subsequent to December 31, 2013, Mississippi Power received $150 million and $75 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc. (S&P) or Baa1 or lower by Moody's Investors Service, Inc. (Moody's) or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the March 2012 deposit has been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. On July 18, 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.
The ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. There are legal challenges to the constitutionality of the Baseload Act currently pending before the Mississippi Supreme Court. The ultimate outcome of any legal challenges to this legislation cannot be determined at this time. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.
Investment Tax Credits and Bonus Depreciation
The IRS allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. On May 15, 2013, the IRS notified Mississippi Power that no additional tax credits under the Internal Revenue Code Section 48A Phase III were allocated to the Kemper IGCC. As a result of the schedule extension for the Kemper IGCC, the Phase I credits have been recaptured. Through December 31, 2013, Mississippi Power had recorded tax benefits totaling $276.4 million for the remaining Phase II credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the Phase II tax credits will be subject to recapture upon successful completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.
On January 2, 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is expected to apply to the Kemper IGCC and have a positive impact on the future cash flows of Mississippi Power of between $560 million and $620 million in 2014. These estimated positive cash flow impacts are dependent upon placing the Kemper IGCC in service in 2014. See "Rate Recovery of Kemper IGCC Costs – Seven-Year Rate Plan" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Alabama Power [Member]	'
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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
	Environmental Matters
	New Source Review Actions
	As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against the Company alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against the Company (including claims involving a unit co-owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for the Company on all remaining claims and dismissal of the case with prejudice in 2011. On September 19, 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of the Company, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.
	The Company believes it complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time.
	Environmental Remediation
	The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation.
	Nuclear Fuel Disposal Costs
	Acting through the U.S. Department of Energy (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. The DOE failed to timely perform and has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel beginning no later than January 31, 1998. Consequently, the Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract.
	As a result of the first lawsuit, the Company recovered approximately $17 million, representing the vast majority of the Company's direct costs of the expansion of spent nuclear fuel storage facilities at Plant Farley from 1998 through 2004. In April 2012, the award was credited to cost of service for the benefit of customers.
	In 2008, the Company filed a second lawsuit against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Farley. Damages are being sought for the period from January 1, 2005 through December 31, 2010. 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, 2013 for any potential recoveries from the second lawsuit. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected.
	At Plant Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of the plant.
	Retail Regulatory Matters
	Retail Rate Adjustments
	In 2011, the Alabama PSC issued an order to eliminate a tax-related adjustment under the Company's rate structure effective with October 2011 billings. The elimination of this adjustment resulted in additional revenues of approximately $31 million for 2011. In accordance with the order, the Company made additional accruals to the NDR in the fourth quarter 2011 of an amount equal to such additional 2011 revenues. The NDR was impacted as a result of operations and maintenance expenses incurred in connection with the 2011 storms in Alabama. See "Natural Disaster Reserve" below for additional information. The elimination of this adjustment resulted in additional revenues of approximately $106 million for 2012.
	Rate RSE
	Rate stabilization and equalization plan (Rate RSE) adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed equity return range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the allowed equity return range. Prior to 2014, retail rates remained unchanged when the retail return on common equity (ROE) was projected to be between 13.0% and 14.5%.
	During 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. On August 13, 2013, the Alabama PSC voted to issue a report on Rate RSE that found that the Company's Rate RSE mechanism continues to be just and reasonable to customers and the Company, but recommended the Company modify Rate RSE as follows:
	•	Eliminate the provision of Rate RSE establishing an allowed range of ROE.
	•	Eliminate the provision of Rate RSE limiting the Company's capital structure to an allowed equity ratio of 45%.
	•	Replace these two provisions with a provision that establishes rates based upon an allowed weighted cost of equity (WCE) range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%.
	•	Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.
	Substantially all other provisions of Rate RSE were unchanged.
	On August 21, 2013, the Company filed its consent to these recommendations with the Alabama PSC. The changes became effective for calendar year 2014. On November 27, 2013, the Company made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2014; projected earnings were within the specified WCE range and, therefore, retail rates under Rate RSE remained unchanged for 2014. In 2012 and 2013, retail rates under Rate RSE remained unchanged from 2011. Under the terms of Rate RSE, the maximum possible increase for 2015 is 5.00%.
	Rate CNP
	The Company's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under rate certificated new plant (Rate CNP). The Company may also recover retail costs associated with certificated PPAs under rate certificated new plant (Rate CNP PPA). There was no adjustment to Rate CNP PPA in 2012. On March 5, 2013, 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, 2013 through March 31, 2014. It is anticipated that no adjustment will be made to Rate CNP PPA in 2014. As of December 31, 2013, the Company had an under recovered certificated PPA balance of $18 million, all of which is included in deferred under recovered regulatory clause revenues in the balance sheet.
	In 2011, the Alabama PSC approved and certificated a PPA of approximately 200 megawatts (MWs) of energy from wind-powered generating facilities which became operational in December 2012. In September 2012, the Alabama PSC approved and certificated a second wind PPA of approximately 200 MWs which became operational in January 2014. The terms of the wind PPAs permit the Company to use the energy and retire the associated environmental attributes in service of its customers or to sell environmental attributes, separately or bundled with energy. The Company has elected the normal purchase normal sale (NPNS) scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry's application of the NPNS exception to certain physical forward transactions in nodal markets is currently under review by the SEC at the request of the electric utility industry. The outcome of the SEC's review cannot now be determined. If the Company is ultimately required to record these PPAs at fair value, an offsetting regulatory asset or regulatory liability will be recorded.
	Rate certificated new plant environmental (Rate CNP Environmental) also allows for the recovery of the Company's retail costs associated with environmental laws, regulations, or other such mandates. Rate CNP Environmental is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. There was no adjustment to Rate CNP Environmental in 2012 or 2013. On August 13, 2013, the Alabama PSC approved the Company's petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets previously being recovered through Rate RSE. The revenue impact as a result of this revision is estimated to be $58 million in 2014. On November 21, 2013, the Company submitted calculations associated with its cost of complying with environmental mandates, as provided under Rate CNP Environmental. The filing reflected a projected unrecovered retail revenue requirement for environmental compliance of approximately $72 million, which is to be recovered in the billing months of January 2014 through December 2014. On December 3, 2013, the Alabama PSC issued a consent order that the Company leave in effect for 2014 the factors associated with the Company's environmental compliance costs for the year 2013. Any unrecovered amounts associated with 2014 will be reflected in the 2015 filing. As of December 31, 2013, the Company had an under recovered environmental clause balance of $7 million which is included in deferred under recovered regulatory clause revenues in the balance sheet.
	Environmental Accounting Order
	Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs would be amortized over the affected unit's remaining useful life, as established prior to the decision regarding early retirement.
	Compliance and Pension Cost Accounting Order
	In November 2012, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain compliance-related operations and maintenance expenditures for the years 2013 through 2017, as well as the incremental increase in operations expense related to pension cost for 2013. These deferred costs are to be amortized over a three-year period beginning in January 2015. The compliance related expenditures were related to (i) standards addressing Critical Infrastructure Protection issued by the North American Electric Reliability Corporation, (ii) cyber security requirements issued by the NRC, and (iii) NRC guidance addressing the readiness at nuclear facilities within the U.S. for severe events. The compliance-related expenses to be afforded regulatory asset treatment over the five-year period are currently estimated to be approximately $37 million. The amount of operations and maintenance expenses deferred to a regulatory asset in 2013 associated with compliance-related expenditures and pension cost was approximately $8 million and $12 million, respectively. Pursuant to the accounting order, the Company has the ability to accelerate the amortization of the regulatory assets with notification to the Alabama PSC.
	Retail Energy Cost Recovery
	The Company has established energy cost recovery rates under the Company's energy cost recovery rate (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 kilowatt hour (KWH). On December 3, 2013, the Alabama PSC issued a consent order that the Company leave in effect the energy cost recovery rates which began in April 2011 for 2014. Therefore, the Rate ECR factor as of January 1, 2014 remained at 2.681 cents per KWH. Effective with billings beginning in January 2015, the Rate ECR factor will be 5.910 cents per KWH, absent a further order from the Alabama PSC.
	The Company's over recovered fuel costs at December 31, 2013 totaled $42 million as compared to under recovered fuel costs of $4 million at December 31, 2012. At December 31, 2013, $27 million is included in other regulatory liabilities, current and $15 million is included in deferred over recovered regulatory clause revenues. The under recovered fuel costs at December 31, 2012 are included in deferred under recovered regulatory clause revenues in the balance sheets. 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 of the under recovered fuel costs.
	Natural Disaster Reserve
	Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.
	As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
	In accordance with the order that was issued by the Alabama PSC in 2011 to eliminate a tax-related adjustment under the Company's rate structure that resulted in additional revenues, the Company made additional accruals to the NDR in the fourth quarter 2011 of an amount equal to the additional 2011 revenues, which were approximately $31 million.
	The accumulated balances in the NDR for the years ended December 31, 2013 and December 31, 2012 were approximately $96 million and $103 million, respectively. Any accruals to the NDR are included in the balance sheets under other regulatory liabilities, deferred and are reflected as other operations and maintenance expenses in the statements of income.
	Nuclear Outage Accounting Order
	In accordance with a 2010 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 the subsequent 18-month operational cycle.
	Approximately $31 million of nuclear outage costs from the spring of 2012 was amortized to nuclear operations and maintenance expenses over the 18-month period ended in December 2013. During the spring of 2013, approximately $28 million of nuclear outage costs was deferred to a regulatory asset, and beginning in July 2013, these deferred costs are being amortized over an 18-month period. During the fall of 2013, approximately $32 million of nuclear outage costs associated with the second unit was deferred to a regulatory asset, and beginning in January 2014, these deferred costs are being amortized over an 18-month period. The Company will continue the pattern of deferral of nuclear outage expenses as incurred and the recognition of expenses over a subsequent 18-month period pursuant to the Alabama PSC order.
	Non-Nuclear Outage Accounting Order
	On August 13, 2013, the Alabama PSC approved the Company's petition requesting authorization to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. The 2014 outage expenditures to be deferred and amortized are estimated to total approximately $78 million.
Georgia Power [Member]	'
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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
	Environmental Matters
	New Source Review Actions
	As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against the Company alleging violations of the New Source Review provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by Gulf Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against the Company (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001.
	The Company believes it complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time.
	Environmental Remediation
	The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. See Note 1 under "Environmental Remediation Recovery" for additional information.
	The Company has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List (NPL). The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.
	The Company and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to the Company and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, the Company filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified the Company in 2011 that it is considering enforcement options against the Company and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.
	In addition to the EPA's action at this site, the Company, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. On February 1, 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted the Company's summary judgment motion, ruling that the Company has no liability in the private action. On May 10, 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit.
	The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the regulatory recovery mechanisms 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 U.S. Department of Energy (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. The DOE failed to timely perform and has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel beginning no later than January 31, 1998. Consequently, the Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract.
	As a result of its first lawsuit, the Company recovered approximately $27 million, based on its ownership interests, representing the vast majority of the Company's direct costs of the expansion of spent nuclear fuel storage facilities at Plant Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. The proceeds were received in July 2012 and credited to the Company accounts where the original costs were charged and were used to reduce rate base, fuel, and cost of service for the benefit of customers.
	In 2008, the Company filed a second lawsuit 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. Damages are being sought for the period from January 1, 2005 through December 31, 2010. 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, 2013 for any potential recoveries from the second 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 as a significant portion of any damage amounts collected from the government is expected to be credited to the Company accounts where the original costs were charged and used to reduce rate base, fuel, and cost of service for the benefit of customers.
	An on-site dry storage facility at Plant Vogtle Units 1 and 2 began operation in October 2013. At Plant Hatch, an on-site dry spent fuel storage facility is also operational. Facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant.
	Retail Regulatory Matters
	Rate Plans
	In 2010, the Georgia PSC approved the 2010 ARP, which resulted in base rate increases of approximately $562 million, $17 million, $125 million, and $74 million effective January 1, 2011, January 1, 2012, April 1, 2012, and January 1, 2013, respectively.
	On December 17, 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among the Company, the Georgia PSC’s Public Interest Advocacy Staff, and 11 of the 13 intervenors, which was filed with the Georgia PSC on November 18, 2013.
	On January 1, 2014, in accordance with the 2013 ARP, the Company increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million; (2) ECCR tariff by an additional $25 million; (3) Demand-Side Management (DSM) tariffs by an additional $1 million; and (4) Municipal Franchise Fee (MFF) tariff by an additional $4 million, for a total increase in base revenues of approximately $110 million.
	Under the 2013 ARP, the following additional rate adjustments will be made to the Company’s tariffs in 2015 and 2016 based on annual compliance filings to be made at least 90 days prior to the effective date of the tariffs:
	•	Effective January 1, 2015 and 2016, the traditional base tariff rates will increase by an estimated $101 million and $36 million, respectively, to recover additional generation capacity-related costs;
	•	Effective January 1, 2015 and 2016, the ECCR tariff will increase by an estimated $76 million and $131 million, respectively, to recover additional environmental compliance costs;
	•	Effective January 1, 2015, the DSM tariffs will increase by an estimated $6 million and decrease by an estimated $1 million effective January 1, 2016; and
	•	The MFF tariff will increase consistent with these adjustments.
	The Company currently estimates these adjustments will result in base revenue increases of approximately $187 million in 2015 and $170 million in 2016. The estimated traditional base tariff rate increases for 2015 and 2016 do not include additional Qualifying Facility (QF) PPA expenses; however, compliance filings will include QF PPA expenses for those facilities that are projected to provide capacity to the Company during the following year.
	Under the 2013 ARP, the Company’s retail return on common equity (ROE) is set at 10.95%, and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by the Company. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. However, if at any time during the term of the 2013 ARP, the Company projects that its retail earnings will be below 10.00% for any calendar year, it may petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff that would be used to adjust the Company’s earnings back to a 10.00% retail ROE. The Georgia PSC would have 90 days to rule on the Company’s request. The ICR tariff will expire at the earlier of January 1, 2017 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, the Company may file a full rate case.
	Except as provided above, the Company will not file for a general base rate increase while the 2013 ARP is in effect. The Company is required to file a general rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued.
	Integrated Resource Plans
	On January 31, 2013, the Company filed its triennial Integrated Resource Plan (2013 IRP). The filing included the Company's request to decertify 16 coal- and oil-fired units totaling 2,093 megawatts (MWs). Several factors, including the cost to comply with existing and future environmental regulations, recent and forecasted economic conditions, and lower natural gas prices, contributed to the decision to close these units.
	On April 17, 2013, the Georgia PSC approved the decertification of Plant Bowen Unit 6 (32 MWs), which was retired on April 25, 2013. On September 30, 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 Integrated Resource Plan Update (2011 IRP Update) in order to comply with the State of Georgia's Multi-Pollutant Rule.
	On July 11, 2013, the Georgia PSC approved the Company's request to decertify and retire Plant Boulevard Units 2 and 3 (28 MWs) effective July 17, 2013. Plant Branch Units 3 and 4 (1,016 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) will be decertified and retired by April 16, 2015, the compliance date of the Mercury and Air Toxics Standards (MATS) rule. The decertification date of Plant Branch Unit 1 was extended from December 31, 2013 as specified in the final order in the 2011 IRP Update to coincide with the decertification date of Plant Branch Units 3 and 4. The decertification and retirement of Plant Kraft Units 1 through 4 (316 MWs) was also approved and will be effective by April 16, 2016, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division on September 10, 2013 to allow for necessary transmission system reliability improvements.
	Additionally, the Georgia PSC approved the Company's proposed MATS rule compliance plan for emissions controls necessary for the continued operation of Plants Bowen Units 1 through 4, Wansley Units 1 and 2, Scherer Units 1 through 3, and Hammond Units 1 through 4, the switch to natural gas as the primary fuel at Plant Yates Units 6 and 7 and SEGCO's Plant Gaston Units 1 through 4, as well as the fuel switch at Plant McIntosh Unit 1 to operate on Powder River Basin coal. See Note 1 under "Affiliate Transactions" herein for additional information regarding the fuel switch at SEGCO's generating units.
	In the 2013 ARP, the Georgia PSC approved the amortization of the construction work in progress (CWIP) balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years beginning in January 2014 and the amortization of any remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024. The Georgia PSC deferred a decision regarding the appropriate recovery period for the costs associated with unusable materials and supplies remaining at the retiring plants to the Company's next base rate case, which the Company expects to file in 2016 (2016 Rate Case). In the 2013 IRP, the Georgia PSC also deferred decisions regarding the recovery of any fuel related costs that could be incurred in connection with the retirement units to be addressed in future fuel cases.
	A request was filed with the Georgia PSC on January 10, 2014 to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. The filing also notified the Georgia PSC of the Company’s plans to seek decertification later this year. Plant Mitchell Unit 3 will continue to operate as a coal unit until April 2015 when it will be required to cease operation or install additional environmental controls to comply with the MATS rule. In connection with the retirement decision, the Company reclassified the retail portion of the net carrying value of Plant Mitchell Unit 3 from plant in service, net of depreciation, to other utility plant, net.
	The decertification of these units and fuel conversions are not expected to have a material impact on the Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's order in the 2016 Rate Case and future fuel cases and cannot be determined at this time.
	Renewables Development
	On December 17, 2013, four PPAs totaling 50 MWs of utility scale solar generation under the Georgia Power Advanced Solar Initiative (GPASI) were approved by the Georgia PSC, with the Company as the purchaser. These contracts will begin in 2015 and end in 2034. The resulting purchases will be for energy only and recovered through the Company’s fuel cost recovery mechanism. Under the 2013 IRP, the Georgia PSC approved an additional 525 MWs of solar generation to be purchased by the Company. The 525 MWs will be divided into 425 MWs of utility scale projects and 100 MWs of distributed generation.
	On November 4, 2013, the Company filed an application for the certification of two PPAs which were executed on April 22, 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.
	During 2013, the Company executed four PPAs to purchase a total of 169 MWs of biomass capacity and energy from four facilities in Georgia that will begin in 2015 and end in 2035. On May 21, 2013, the Georgia PSC approved two of the biomass PPAs and the remaining two were approved on December 17, 2013. The four biomass PPAs are contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation. 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. The Georgia PSC approved reductions in the Company's total annual billings of approximately $43 million effective June 1, 2011, $567 million effective June 1, 2012, and $122 million effective January 1, 2013. The 2013 reduction was due to the Georgia PSC authorizing an Interim Fuel Rider, which is set to expire June 1, 2014. The Company continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. The Company's fuel cost recovery includes costs associated with a natural gas hedging program as revised and approved by the Georgia PSC on February 7, 2013, requiring it to use options and hedges within a 24-month time horizon. See Note 11 under "Energy-Related Derivatives" for additional information. On February 18, 2014, the Georgia PSC approved the deferral of the Company's next fuel case, which is now expected to be filed by March 1, 2015.
	The Company's over recovered fuel balance totaled approximately $58 million and $230 million at December 31, 2013 and 2012, respectively, and is included in current liabilities and other deferred credits and liabilities.
	Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on the Company's revenues or net income, but will affect cash flow.
	Nuclear Construction
	In 2008, the Company, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Each 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%. The Vogtle 3 and 4 Agreement provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.
	Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain 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 Owners, Owner insolvency, and certain other events.
	In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, effective December 30, 2011, and issued combined construction and operating licenses (COLs) in February 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds.
	In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows the Company to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the Nuclear Construction Cost Recovery (NCCR) tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. Through the NCCR tariff, the Company is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At December 31, 2013, approximately $37 million of these 2009 and 2010 costs remained unamortized in CWIP.
	The Company is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by the Company increase by 5% or the projected in-service dates are significantly extended, the Company is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Accordingly, the Company's eighth VCM report requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively.
	On September 3, 2013, the Georgia PSC approved a stipulation entered into by the Company and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the commercial operation date of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and the Company. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by the Company in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. As required by the stipulation, the Company filed an abbreviated status update with the Georgia PSC on September 3, 2013, which reflected approximately $2.4 billion of total construction capital costs incurred through June 30, 2013. On October 15, 2013, the Georgia PSC voted to approve the Company's eighth VCM report, reflecting construction capital costs incurred, which through December 31, 2012 totaled approximately $2.2 billion. Also in accordance with the stipulation, the Company will file with the Georgia PSC on February 28, 2014 a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), which will request approval for an additional $0.4 billion of construction capital costs. The Ninth/Tenth VCM report will reflect estimated in-service construction capital costs of $4.8 billion and associated financing costs during the construction period, which are estimated to total approximately $2.0 billion. The Company expects to resume filing semi-annual VCM reports in August 2014.
	In July 2012, the Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The portion of the additional costs claimed by the Contractor that would be attributable to the Company (based on the Company's ownership interest) with respect to these issues is approximately $425 million (in 2008 dollars). The Contractor also has asserted it is entitled to further schedule extensions. The Company has not agreed with either the proposed cost or schedule adjustments or that the Owners have any responsibility for costs related to these issues. In November 2012, the Company and the other Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Owners are not responsible for these costs. Also in November 2012, the Contractor filed suit against the Company and the other Owners in the U.S. District Court for the District of Columbia alleging the Owners are responsible for these costs. On August 30, 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit on September 27, 2013. While litigation has commenced and the Company intends to vigorously defend its positions, the Company also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.
	Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Owners, the Contractor, or both.
	As construction continues, the risk remains that additional challenges in the fabrication, assembly, delivery, and installation of structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. Additional claims by the Contractor or the Company (on behalf of the Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.
	The ultimate outcome of these matters cannot be determined at this time.
Gulf Power [Member]	'
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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
	Environmental Matters
	New Source Review Actions
	As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by the Company. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to the Company with respect to the Company's Plant Crist. The case against Georgia Power (including claims related to a unit co-owned by the Company) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001.
	The Company believes it complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time.
	Environmental Remediation
	The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company received authority from the Florida PSC to recover approved environmental compliance costs through the environmental cost recovery clause. The Florida PSC reviews costs and adjusts rates up or down annually.
	The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable. At December 31, 2013, the Company's environmental remediation liability included estimated costs of environmental remediation projects of approximately $50.4 million. For 2013, approximately $3.1 million was included in under recovered regulatory clause revenues and other current liabilities, and approximately $47.3 million was included in other regulatory assets, deferred and other deferred credits and liabilities. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at the Company's substations. The schedule for completion of the remediation projects will be subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through the Company's environmental cost recovery clause; therefore, there was no impact on net income as a result of these liabilities.
	The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, the Company does not believe that additional liabilities, if any, at these sites would be material to the Company's financial statements.
	Retail Regulatory Matters
	The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company's base rates.
	Retail Base Rate Case
	On December 3, 2013, the Florida PSC voted to approve the Settlement Agreement among the Company and all of the intervenors to the docketed proceeding with respect to the Company's request to increase retail base rates. Under the terms of the Settlement Agreement, the Company (1) increased base rates designed to produce an additional $35 million in annual revenues effective January 2014 and will increase base rates designed to produce an additional $20 million in annual revenues effective January 2015; (2) continued its current authorized retail return on equity (ROE) midpoint and range; and (3) will accrue a return similar to AFUDC on certain transmission system upgrades that go into service after January 2014 until the next retail rate case or January 1, 2017, whichever comes first.
	The Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized ROE midpoint and range by 25 basis points in the event the 30-year treasury yield rate increases by an average of at least 75 basis points above 3.7947% for a consecutive six-month period.
	The Settlement Agreement also provides that the Company may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an amount up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in the Company’s next base rate case or next depreciation and dismantlement study proceeding, whichever comes first.
	The Settlement Agreement also provides for recovery of costs associated with any tropical systems named by the National Hurricane Center through the initiation of a storm surcharge. The storm surcharge will begin, on an interim basis, 60 days following the filing of a cost recovery petition. The storm surcharge generally may not exceed $4.00/1,000 KWHs on monthly residential bills in aggregate for a calendar year. This limitation does not apply if the Company incurs in excess of $100 million in storm recovery costs that qualify for recovery in a given calendar year. This threshold amount is inclusive of the amount necessary to replenish the storm reserve to the level that existed as of December 31, 2013.
	Pursuant to the Settlement Agreement, the Company may not request an increase in its retail base rates to be effective until after June 2017, unless the Company's actual retail ROE falls below the authorized ROE range.
	Cost Recovery Clauses
	On November 4, 2013, the Florida PSC approved the Company's annual request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2014. The net effect of the approved changes is a $65.2 million increase in annual revenue for 2014.
	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.
	Fuel Cost Recovery
	The Company has established fuel cost recovery rates as approved by the Florida PSC. If, at any time during the year, the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested.
	The change in the fuel cost over recovered balance to an under recovered balance during 2013 was primarily due to higher than expected fuel costs and purchased power energy expenses, partially offset by approximately $26.6 million received during 2013 as a result of a payment from one of the Company's fuel vendors pursuant to the resolution of a coal contract dispute. At December 31, 2013, the under recovered fuel balance was approximately $21.0 million, which is included in under recovered regulatory clause revenues in the balance sheets. At December 31, 2012, the over recovered fuel balance was approximately $17.1 million, 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, 2013 and 2012, the under recovered purchased power capacity balance was approximately $2.8 million and $0.8 million, respectively, which is included in under recovered regulatory clause revenues in the balance sheets.
	Environmental Cost Recovery
	The Florida Legislature adopted legislation for an environmental cost recovery clause, which allows an electric utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operations and maintenance expenses, emissions allowance expense, depreciation, and a return on net average investment. This legislation also allows recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA.
	In 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company's plan for complying with certain federal and state regulations addressing air quality. The Company's environmental compliance plan as filed in 2007 contemplated implementation of specific projects identified in the plan from 2007 through 2018. The stipulation covers all elements of the original plan that were committed for implementation at the time of the stipulation. The Florida PSC's approval of the stipulation also required the Company to file annual updates to the plan and outlined a process for approval of additional elements in the plan when they became committed projects. In the 2010 update filing, the Company identified several elements of the updated plan that the Company had decided to implement. Following the process outlined in the original approved stipulation, these additional projects were approved by the Florida PSC later in 2010. The Florida PSC acknowledged that the costs of the approved projects associated with the Company's Clean Air Interstate Rule and Clean Air Visibility Rule compliance plans are eligible for recovery through the environmental cost recovery clause.
	Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2013 and 2012, the under recovered environmental balance was approximately $14.4 million and $1.9 million, respectively, which is included in under recovered regulatory clause revenues in the balance sheets.
	In April 2012, the Mississippi PSC approved Mississippi Power's request for a certificate of public convenience and necessity to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. In May 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi. These units are jointly owned by Mississippi Power and the Company, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with the Company's portion being $330 million, excluding AFUDC, and it is scheduled for completion in December 2015. The Company's portion of the cost is expected to be recovered through the environmental cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.
	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.
	The most recent goal setting process established new DSM goals for the period 2010 through 2019. The new goals are significantly higher than the goals established in the previous five-year cycle due to a change in the cost-effectiveness test on which the Florida PSC relies to set the goals. The DSM program standards were approved in April 2011. The Company implemented several new programs in June 2011, and the costs related to these programs were reflected in the 2012 and 2013 ECCR factors approved by the Florida PSC. Higher cost recovery rates and achievement of the new DSM goals may result in reduced sales of electricity which could negatively impact results of operations, cash flows, and financial condition if base rates cannot be adjusted on a timely basis.
	At December 31, 2013 and 2012, the under recovered energy conservation balance was approximately $7.0 million and $0.8 million, respectively, which is included in under recovered regulatory clause revenues in the balance sheets.
Mississippi Power [Member]	'
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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide (CO2) and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
	Environmental Matters
	New Source Review Actions
	As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by the Company. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. These actions were filed concurrently with the issuance of notices of violation to the Company with respect to the Company's Plant Watson. The case against Alabama Power (including claims involving a unit co-owned by the Company) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for Alabama Power on all remaining claims and dismissal of the case with prejudice in 2011. On September 19, 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of Alabama Power, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.
	The Company believes it complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time.
	Environmental Remediation
	The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through regulatory mechanisms.
	In 2003, the Texas Commission on Environmental Quality (TCEQ) designated the Company as a potentially responsible party at a site in Texas. The site was owned by an electric transformer company that handled the Company's transformers as well as those of many other entities. The site owner is bankrupt and the State of Texas has entered into an agreement with the Company and several other utilities to investigate and remediate the site. Hundreds of entities have received notices from the TCEQ requesting their participation in the anticipated site remediation. The TCEQ approved the final site remediation plan in December 2013.
	Amounts expensed and accrued during 2011, 2012, and 2013 related to this work were not material. The final impact of this matter on the Company will depend upon further environmental assessment and the ultimate number of potentially responsible parties. The remediation expenses incurred by the Company are expected to be recovered through the Environmental Compliance Overview (ECO) Plan.
	The final outcome of this matter cannot now be determined. However, based on the currently known conditions at this site and the nature and extent of activities relating to this site, the Company does not believe that additional liabilities, if any, at this site would be material to the financial statements.
	FERC Matters
	In November 2011, the Company filed a request with the FERC for an increase in wholesale base revenues of approximately $32 million under the wholesale cost-based electric tariff. In its filing with the FERC, the Company sought (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 March 2012, the Company entered into a settlement agreement with its wholesale customers with respect to the Company's request for revised rates under the wholesale cost-based electric tariff. The settlement agreement provided that base rates under the cost-based electric tariff increase by approximately $22.6 million over a 12-month period with revised rates effective April 1, 2012. A significant portion of the difference between the requested base rate increase and the agreed upon rate increase was due to a change in the recovery methodology for the return on the Kemper IGCC CWIP. Under the settlement agreement, a portion of CWIP will continue to accrue AFUDC. The tariff customers specifically agreed to the same regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking by the Mississippi PSC with respect to (i) the accounting for Kemper IGCC-related costs that cannot be capitalized, (ii) the accounting for the lease termination and purchase of Plant Daniel Units 3 and 4, and (iii) the establishment of a regulatory asset for certain potential plant retirement costs.
	In March 2012, the FERC approved a motion to place interim rates into effect beginning in May 2012. In September 2012, the Company, with its wholesale customers, filed a final settlement agreement with the FERC. On May 3, 2013, the Company received an order from the FERC accepting the settlement agreement.
	On April 1, 2013, the Company reached a settlement agreement with its wholesale customers and filed a request with the FERC for an additional increase in the Municipal and Rural Associations (MRA) cost-based electric tariff, which was accepted by the FERC on May 30, 2013. The 2013 settlement agreement provided that base rates under the MRA cost-based electric tariff will increase by approximately $24.2 million annually, effective April 1, 2013.
	Retail Regulatory Matters
	General
	In August 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing for informational purposes only the return on equity (ROE) formulas used by the Company and all other regulated electric utilities in Mississippi. On March 14, 2013, the Mississippi Public Utilities Staff (MPUS) filed with the Mississippi PSC its report on the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. The ultimate outcome of this matter cannot be determined at this time.
	Energy Efficiency
	On July 11, 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 customers to implement energy efficiency programs and standards. Quick Start Plans, which include a portfolio of energy efficiency programs that are intended to provide benefits to a majority of customers, were required to be filed within six months of the order and will be in effect for two to three years. An annual report addressing the performance of all energy efficiency programs is required. On January 10, 2014, the Company submitted its 2014 Energy Efficiency Quick Start Plan filing which proposed a portfolio of energy efficiency programs. 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 Performance Evaluation Plan (PEP), a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on projected revenue requirement, and the PEP lookback filing, which is filed after the year and allows for review of actual revenue requirement compared to the projected filing. PEP was designed with the objective to reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high. PEP is a mechanism for rate adjustments based on three indicators: price, customer satisfaction, and service reliability.
	In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the Company received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. In May 2012, the Mississippi PSC issued an order suspending the Company's annual lookback filing for 2011. On March 15, 2013, the Company submitted its annual PEP lookback filing for 2012, which indicated a refund due to customers of $4.7 million, which was accrued in retail revenues in 2013. On May 1, 2013, the MPUS contested the filing. Unresolved matters related to certain costs included in the 2010 PEP lookback filing, which are currently under review, also impact the 2012 PEP lookback filing.
	On March 5, 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.925%, or $15.3 million, annually, with the new rates effective March 19, 2013. The Company may be entitled to $3.3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase.
	While the Company does not expect the resolution of these matters to have a material impact on its financial statements, the ultimate outcome cannot be determined at this time.
	Environmental Compliance Overview Plan
	In 2011, the Company filed a request to establish a regulatory asset to defer certain plant retirement costs if such costs are incurred. This request was made to minimize the potential rate impact to customers arising from pending and final environmental regulations which may require the premature retirement of some generating units. These environmental rules and regulations are continuously monitored by the Company and all options are evaluated. In December 2011, an order was issued by the Mississippi PSC authorizing the Company to defer all plant retirement related costs resulting from compliance with environmental regulations as a regulatory asset for future recovery.
	In April 2012, the Mississippi PSC approved the Company's request for a certificate of public convenience and necessity (CPCN) to construct a flue gas desulfurization system (scrubber) on Plant Daniel Units 1 and 2. In May 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court of Harrison County, Mississippi (Chancery Court). These units are jointly owned by the Company and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with the Company's portion being $330 million, excluding AFUDC. The Company's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project in December 2015. As of December 31, 2013, total project expenditures were $320.6 million, of which the Company's portion was $162.3 million, excluding AFUDC of $8.5 million.
	In June 2012, the Mississippi PSC approved the Company's 2012 ECO Plan filing, including a 0.16%, or $1.5 million, decrease in annual revenues, effective June 29, 2012. On August 13, 2013, the Mississippi PSC approved the Company’s 2013 ECO Plan filing which proposed no change in rates.
	The ultimate outcome of these matters cannot be determined at this time.
	Fuel Cost Recovery
	The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually; the most recent filing occurred on November 15, 2013. The Mississippi PSC approved the 2014 retail fuel cost recovery factor on January 7, 2014, with the new rates effective in February 2014. The retail fuel cost recovery factor will result in an annual increase of 3.4% of total 2013 retail revenue, or $30.1 million. At December 31, 2013, the amount of over recovered retail fuel costs included in the balance sheets was $14.5 million compared to $56.6 million at December 31, 2012. The Company also has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2014, the wholesale MRA fuel rate increased resulting in an annual increase of $10.1 million. Effective February 1, 2014, the wholesale MB fuel rate increased, resulting in an annual increase of $1.2 million. At December 31, 2013, the amount of over recovered wholesale MRA and MB fuel costs included in the balance sheets was $7.3 million and $0.3 million compared to $19.0 million and $2.1 million, respectively, at December 31, 2012. In addition, at December 31, 2013, the amount of under recovered MRA emissions allowance cost included in the balance sheets was $3.8 million compared to $0.4 million at December 31, 2012. 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 have no significant effect on the Company's revenues or net income, but will affect cash flow.
	In March 2011, a portion of the Company's territorial wholesale loads that was formerly served under the MB tariff terminated service. Beginning in April 2011, a new power purchase agreement (PPA) went into effect to cover these MB customers as non-territorial load. In June 2011, the Company and South Mississippi Electric Power Association (SMEPA) reached an agreement to allocate $3.7 million of the over recovered fuel balance at March 31, 2011 to the PPA. This amount was subsequently refunded to SMEPA in June 2011.
	The Mississippi PSC engaged an independent professional audit firm to conduct an audit of the Company's fuel-related expenditures included in the retail fuel adjustment clause and ECM. The 2013, 2012, and 2011 audits of fuel-related expenditures were completed with no audit findings.
	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 4, 2013, the Mississippi PSC approved an annual rate increase of 0.9%, or $7.1 million, due to an increase in ad valorem taxes resulting from the expiration of a tax exemption related to Plant Daniel Units 3 and 4.
	System Restoration Rider
	The Company is required to make annual SRR filings to review charges to the property damage reserve and to determine the revenue requirement associated with property damage. The purpose of the SRR is to provide for recovery of costs associated with property damage (including certain property insurance and the costs of self-insurance) and to facilitate the Mississippi PSC's review of these costs. The Mississippi PSC periodically agrees on SRR revenue levels that are developed based on historical data, expected exposure, type and amount of insurance coverage excluding insurance costs, and other relevant information. The applicable SRR rate level will be reviewed every three years, unless a significant change in circumstances occurs such that the Company and the MPUS or the Mississippi PSC deems that a more frequent change in rates would be appropriate. The Company will submit annual filings setting forth SRR-related revenues, expenses, and investment for the projected filing period, as well as the true-up for the prior period.
	For 2011, 2012, and 2013, the SRR rate was zero. The Mississippi PSC approved accruals to the property damage reserve of $3.8 million and $3.2 million in 2012 and 2013, respectively. On February 3, 2014, the Company submitted its 2014 SRR rate filing with the Mississippi PSC, which proposed that the 2014 SRR rate level remain at zero and the Company be allowed to accrue $3.3 million to the property damage reserve in 2014. The ultimate outcome of this matter cannot be determined at this time.
	Storm Damage Cost Recovery
	The Company maintains a reserve to cover the cost of damage from major storms to its transmission and distribution facilities and generally the cost of uninsured damage to its generation facilities and other property. The total storm restoration costs incurred in 2013 and 2012 were $2.3 million and $10.5 million, respectively. At December 31, 2013, the balance in the property damage reserve was $60.1 million.
	Baseload Act
	In 2008, legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi (Baseload Act) was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. There are legal challenges to the constitutionality of the Baseload Act currently pending before the Mississippi Supreme Court. The ultimate outcome of any legal challenges to this legislation cannot be determined at this time. See "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" herein for additional information.
	Integrated Coal Gasification Combined Cycle
	Kemper IGCC Overview
	Construction of the Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an integrated coal gasification combined cycle technology with an output capacity of 582 megawatts (MWs). The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation on June 5, 2013. In connection with the Kemper IGCC, the Company constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
	Kemper IGCC Project Approval
	In April 2012, the Mississippi PSC issued a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC (2012 MPSC CPCN Order), which the Sierra Club appealed to the Chancery Court. In December 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. On January 8, 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court. The ultimate outcome of the CPCN challenge cannot be determined at this time.
	Kemper IGCC Schedule and Cost Estimate
	The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of the $245.3 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include 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 the ratepayers, relative to the original proposal for the CPCN) (Cost Cap Exceptions), as contemplated in the settlement agreement between the Company and the Mississippi PSC entered into on January 24, 2013 (Settlement Agreement) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC. The Kemper IGCC was originally scheduled to be placed in service in May 2014 and is currently scheduled to be placed in service in the fourth quarter 2014.
	The Company's 2010 project estimate, current cost estimate, and actual costs incurred as of December 31, 2013 for the Kemper IGCC are as follows:
	Cost Category	2010 Project Estimate(d)		Current Estimate		Actual Costs at 12/31/2013
		(in billions)
	Plant Subject to Cost Cap(a)	$	2.4	$	4.06	$	3.25
	Lignite Mine and Equipment	0.21		0.23		0.23
	CO2 Pipeline Facilities	0.14		0.11		0.09
	AFUDC(b)	0.17		0.45		0.28
	General Exceptions	0.05		0.1		0.07
	Regulatory Asset(c)	—		0.09		0.07
	Total Kemper IGCC(a)	$	2.97	$	5.04	$	3.99
	(a)	The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions.
(b)	The Company’s original estimate included recovery of financing costs during construction which was not approved by the Mississippi PSC in June 2012 as described in "Rate Recovery of Kemper IGCC Costs."
(c)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets."
(d)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
Of the total costs incurred as of December 31, 2013, $2.74 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.18 billion), $70.5 million in other regulatory assets, and $3.9 million in other deferred charges and assets in the balance sheet, and $1.0 million was previously expensed.
The Company does not intend to seek any rate recovery or joint owner contributions for any related costs that exceed the $2.88 billion cost cap, excluding the Cost Cap Exceptions and net of the DOE Grants. The Company recorded pre-tax charges to income for revisions to the cost estimate of $78.0 million ($48.2 million after tax) and $1.1 billion ($680.5 million after tax) in 2012 and 2013, respectively. The revised cost estimates reflect increased labor costs, piping and other material costs, start-up costs, decreases in construction labor productivity, the change in the in-service date, and an increase in the contingency for risks associated with start-up activities.
The Company could experience further construction cost increases and/or schedule extensions with respect to the Kemper IGCC as a result of factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, or non-performance under construction or other agreements. Furthermore, the Company could also experience further schedule extensions associated with start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems, which would result in further cost increases and could result in the loss of certain tax benefits related to bonus depreciation. In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap will be reflected in the Company's statements of income and these changes could be material.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" for additional information regarding the Company’s MRA cost based tariff relating to recovery of a portion of the Kemper IGCC costs from the Company’s wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See "Retail Regulatory Matters – Baseload Act" for additional information.
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company’s results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both the Company's recovery of financing costs during the course of construction of the Kemper IGCC and the Company's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in the Company's petition for the CPCN.
In June 2012, the Mississippi PSC denied the Company's proposed rate schedule for recovery of financing costs during construction, pending a final ruling from the Mississippi Supreme Court regarding the Sierra Club's appeal of the Mississippi PSC's issuance of the CPCN for the Kemper IGCC (2012 MPSC CWIP Order).
In July 2012, the Company appealed the Mississippi PSC's June 2012 decision to the Mississippi Supreme Court and requested interim rates under bond. In July 2012, the Mississippi Supreme Court denied the Company's request for interim rates under bond.
Settlement Agreement
On January 24, 2013, the Company entered into the Settlement Agreement with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC and dismissed the Company's appeal of the 2012 MPSC CWIP Order. Under the Settlement Agreement, the Company agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The Settlement Agreement also allows the Company to secure alternate financing for costs that are not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the Settlement Agreement. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law on February 26, 2013. The Company intends to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs as approved by the Mississippi PSC. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective after the Kemper IGCC is placed in service and following completion of the Mississippi PSC's final prudence review of costs for the Kemper IGCC.
The Settlement Agreement provides that the Company may terminate the Settlement Agreement if certain conditions are not met, if the Company is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the Settlement Agreement. The Company continues to work with the Mississippi PSC and the MPUS to implement the procedural schedules set forth in the Settlement Agreement and variations to the schedule are likely.
2013 MPSC Rate Order
Consistent with the terms of the Settlement Agreement, on January 25, 2013, the Company filed a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013, to be recorded to a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service.
On March 5, 2013, the Mississippi PSC issued an order (2013 MPSC Rate Order) approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. Amounts collected through these rates are being recorded as a regulatory liability to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. As of December 31, 2013, $98.1 million had been collected, with $10.3 million recognized in retail revenues in the statement of operations and the remainder deferred in other regulatory liabilities and included in the balance sheet.
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, the Company continues to record AFUDC on the Kemper IGCC during the construction period. The Company will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. The Company will continue to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates during the construction period unless directed to do otherwise by the Mississippi PSC. On March 21, 2013, a legal challenge to the 2013 MPSC Rate Order was filed by Thomas A. Blanton with the Mississippi Supreme Court, which remains pending against the Company and the Mississippi PSC.
Seven-Year Rate Plan
Also consistent with the Settlement Agreement, on February 26, 2013, the Company filed with the Mississippi PSC the proposed Seven-Year Rate Plan, which is a rate recovery plan for the Kemper IGCC for the first seven years of its operation, along with a proposed revenue requirement under such plan for 2014 through 2020.
On March 22, 2013, the Company, in compliance with the 2013 MPSC Rate Order, filed a revision to the Seven-Year Rate Plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020, which is still under review by the Mississippi PSC. In the Seven-Year Rate Plan, the Company proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning on March 19, 2013, is integral to the Seven-Year Rate Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Seven-Year Rate Plan filing, the Company proposed annual rate recovery to remain the same from 2014 through 2020. At the time of the filing of the Seven-Year Rate Plan, the proposed revenue requirement approximated the forecasted cost of service for the period 2014 through 2020. Under the Company's proposal, to the extent that the actual annual cost of service differs from the forecast approved in the Seven-Year Rate Plan, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of the Seven-Year Rate Plan term, the Mississippi PSC will review the amount and determine the appropriate method and period of disposition.
The revenue requirements set forth in the Seven-Year Rate Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act of 2012 (ATRA), which currently requires that the Kemper IGCC be placed in service in 2014. See "Investment Tax Credits and Bonus Depreciation" herein for additional information regarding bonus depreciation.
In 2014, the Company plans to amend the Seven-Year Rate Plan to reflect changes including the revised in-service date, the change in expected benefits relating to tax credits, various other revenue requirement items, and other tax matters, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated to be approximately $35 million through 2020. The amendment to the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by the Company that, if approved by the Mississippi PSC, would result in no change to the total customer rate impacts contemplated in the original Seven-Year Rate Plan.
Further cost increases and/or schedule extensions with respect to the Kemper IGCC could have an adverse impact on the Seven-Year Rate Plan, such as the inability to recover items considered as Cost Cap Exceptions, potential costs subject to securitization financing in excess of $1.0 billion, and the loss of certain tax benefits related to bonus depreciation. While the Kemper IGCC is scheduled to be placed in service in the fourth quarter 2014, any schedule extension beyond 2014 would result in the loss of the tax benefits related to bonus depreciation. The estimated value of the bonus depreciation tax benefits to retail customers is approximately $200 million. Loss of these tax benefits would require further adjustment to the Seven-Year Rate Plan and approval by the Mississippi PSC to ensure compliance with the normalization requirements of the Internal Revenue Code. In the event that the Mississippi PSC does not approve or the Company withdraws the Seven-Year Rate Plan, the Company would seek rate recovery through an alternate means, which could include a traditional rate case.
Prudence Reviews
The Mississippi PSC’s prudence review of Kemper IGCC costs incurred through March 31, 2013, as provided for in the Settlement Agreement, is expected to occur in the second quarter 2014. A final review of all costs incurred after March 31, 2013 is expected to be completed within six months of the Kemper IGCC’s in-service date. Furthermore, regardless of any prudence determinations made during the construction and start-up period, the Mississippi PSC has the right to make a final prudence determination after the Kemper IGCC has been placed in service.
Regulatory Assets
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted the Company the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period, subject to review of such costs by the Mississippi PSC. The amortization period for any such costs approved for recovery will be determined by the Mississippi PSC at a later date. In addition, the Company is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, the Company will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation on June 5, 2013.
In 2010, the Company executed a 40-year management fee contract with Liberty Fuels, which will develop, construct, and manage the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and the Company has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, the Company currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
In addition, the Company will acquire, construct, and operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. The Company has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC.
The ultimate outcome of these matters cannot be determined at this time.
Proposed Sale of Undivided Interest to SMEPA
In 2010, the Company and SMEPA entered into an asset purchase agreement whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In February 2012, the Mississippi PSC approved the sale and transfer of 17.5% of the Kemper IGCC to SMEPA. In June 2012, the Company and SMEPA signed an amendment to the asset purchase agreement whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. On March 29, 2013, the Company and SMEPA signed an amendment to the asset purchase agreement whereby the Company and SMEPA agreed to amend the power supply agreement entered into by the parties in April 2011 to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the April 2011 power supply agreement were $17.5 million in 2013. On December 24, 2013, the Company and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014. The sale and transfer of an interest in the Kemper IGCC to SMEPA is subject to approval by the Mississippi PSC.
The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In September 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.
In March 2012 and subsequent to December 31, 2013, the Company received $150 million and $75 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, the Company would be required to refund the deposits upon the termination of the asset purchase agreement, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that the Company is assigned a senior unsecured credit rating of BBB+ or lower by Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc. (S&P) or Baa1 or lower by Moody's Investors Service, Inc. (Moody's) or ceases to be rated by either of these rating agencies. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the March 2012 deposit has been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. On July 18, 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of the Company with respect to any required refund of the deposits.
The ultimate outcome of these matters cannot be determined at this time.
Investment Tax Credits and Bonus Depreciation
The Internal Revenue Service (IRS) allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to the Company in connection with the Kemper IGCC. On May 15, 2013, the IRS notified the Company that no additional tax credits under the Internal Revenue Code Section 48A Phase III were allocated to the Kemper IGCC. As a result of the schedule extension for the Kemper IGCC, the Phase I credits have been recaptured. Through December 31, 2013, the Company had recorded tax benefits totaling $276.4 million for the remaining Phase II credits, which will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. A portion of the Phase II tax credits will be subject to recapture upon successful completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.
On January 2, 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is expected to apply to the Kemper IGCC and have a positive impact on the future cash flows of the Company of between $560 million and $620 million in 2014. These estimated positive cash flow impacts are dependent upon placing the Kemper IGCC in service in 2014. See "Rate Recovery of Kemper IGCC Costs – Seven-Year Rate Plan" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Southern Power [Member]	'
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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by carbon dioxide and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent. The ultimate outcome of such pending or potential litigation against the Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.

Joint_Ownership_Agreements

Joint Ownership Agreements	12 Months Ended
	Dec. 31, 2013
Joint Ownership Agreements [Line Items]	'
JOINT OWNERSHIP AGREEMENTS	'
	JOINT OWNERSHIP AGREEMENTS
	Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, the City of Dalton, Georgia, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Duke Energy Florida, Inc. for a combustion turbine unit at Intercession City, Florida. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency.
	At December 31, 2013, Alabama Power's, Georgia Power's, and Southern Power's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:
	Facility (Type)	Percent			Plant in Service				Accumulated				CWIP
		Ownership							Depreciation
					(in millions)
	Plant Vogtle (nuclear) Units 1 and 2	45.7	%		$	3,375			$	2,028			$	53
	Plant Hatch (nuclear)	50.1			1,092				551				52
	Plant Miller (coal) Units 1 and 2	91.8			1,410				575				89
	Plant Scherer (coal) Units 1 and 2	8.4			209				80				24
	Plant Wansley (coal)	53.5			800				260				36
	Rocky Mountain (pumped storage)	25.4			182				120				—
	Intercession City (combustion turbine)	33.3			14				4				—
	Plant Stanton (combined cycle) Unit A	65			156				42				—
	Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4 that are currently under construction. See Note 3 under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" for additional information.
	Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly-owned facilities, except for Rocky Mountain and Intercession City, as agents for their respective co-owners. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing.
Alabama Power [Member]	'
Joint Ownership Agreements [Line Items]	'
JOINT OWNERSHIP AGREEMENTS	'
	JOINT OWNERSHIP AGREEMENTS
	The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power under a power contract. The Company and Georgia Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and ROE. The Company's share of purchased power totaled $88 million in 2013, $109 million in 2012, and $142 million in 2011 and is included in "Purchased power from affiliates" in the statements of income. The Company accounts for SEGCO using the equity method.
	In addition, the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $25 million principal amount of pollution control revenue bonds are outstanding. The Company has guaranteed $100 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. These senior notes mature on December 1, 2018. The Company had guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes, which matured on May 15, 2013. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guarantee.
	At December 31, 2013, the capitalization of SEGCO consisted of $84 million of equity and $125 million of long-term debt on which the annual interest requirement is $3 million. SEGCO paid dividends of $7 million in 2013, $14 million in 2012, and $15 million in 2011, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO's net income.
	SEGCO plans to add natural gas as the primary fuel source in 2015 for 1,000 MWs of its generating capacity. It is currently planning, developing, and constructing the necessary natural gas pipeline. The Company, which owns and operates a generating unit adjacent to the SEGCO generating units, has entered into a joint ownership agreement with SEGCO for the ownership of the gas pipeline. The Company will own 14% of the pipeline with the remaining 86% owned by SEGCO. At December 31, 2013, the Company's portion of the construction work in progress associated with the pipeline is $1 million.
	In addition to the Company's ownership of SEGCO and joint ownership of the natural gas pipeline, the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2013 were as follows:
	Facility	Total Megawatt Capacity			Company Ownership				Plant in Service				Accumulated Depreciation		Construction Work in Progress
									(in millions)
	Greene County	500			60	%	(1)		$	157			$	91	$	5
	Plant Miller
	Units 1 and 2	1,320			91.84	%	(2)		1,410				575		89
	-1	Jointly owned with an affiliate, Mississippi Power.
	-2	Jointly owned with PowerSouth Energy Cooperative, Inc.
	The Company has contracted to operate and maintain the jointly-owned facilities as agent for their co-owners. The Company's proportionate share of its plant operating expenses is included in operating expenses in the statements of income and the Company is responsible for providing its own financing.
Georgia Power [Member]	'
Joint Ownership Agreements [Line Items]	'
JOINT OWNERSHIP AGREEMENTS	'
	JOINT OWNERSHIP AGREEMENTS
	The Company and Alabama Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Alabama Power under a power contract. The Company and Alabama Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and a return on equity. The Company's share of purchased power totaled $91 million in 2013, $107 million in 2012, and $141 million in 2011 and is included in purchased power, affiliates in the statements of income. The Company accounts for SEGCO using the equity method.
	The Company owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, Dalton, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has been contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC who is the operator of the plant. The Company and Duke Energy Florida, Inc. jointly own a combustion turbine unit (Intercession City) operated by Duke Energy Florida, Inc.
	At December 31, 2013, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:
	Facility (Type)	Company Ownership		Plant in Service				Accumulated Depreciation			CWIP
		(in millions)
	Plant Vogtle (nuclear)
	Units 1 and 2	45.70%		$	3,375			$	2,028		$	53
	Plant Hatch (nuclear)	50.1		1,092				551			52
	Plant Wansley (coal)	53.5		800				260			36
	Plant Scherer (coal)
	Units 1 and 2	8.4		209				80			24
	Unit 3	75		1,155				398			19
	Rocky Mountain (pumped storage)	25.4		182				120			—
	Intercession City (combustion-turbine)	33.3		14				4			—
	The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing.
	The Company also owns 45.7% of Plant Vogtle Units 3 and 4 that are currently under construction. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information.
Gulf Power [Member]	'
Joint Ownership Agreements [Line Items]	'
JOINT OWNERSHIP AGREEMENTS	'
	JOINT OWNERSHIP AGREEMENTS
	The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 MWs. Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company's agent with respect to the construction, operation, and maintenance of these units.
	The Company and Georgia Power jointly own the 818 MWs capacity Plant Scherer Unit 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company's agent with respect to the construction, operation, and maintenance of the unit.
	At December 31, 2013, the Company's percentage ownership and investment in these jointly-owned facilities were as follows:
		Plant Scherer				Plant Daniel Units 1 & 2 (coal)
		Unit 3 (coal)
		(in thousands)
	Plant in service	$	382,374		(a)	$	282,370
	Accumulated depreciation	123,862				172,365
	Construction work in progress	6,303				169,085
	Company Ownership	25		%		50		%
	(a)	Includes net plant acquisition adjustment of $2.0 million.
	The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing.
Mississippi Power [Member]	'
Joint Ownership Agreements [Line Items]	'
JOINT OWNERSHIP AGREEMENTS	'
	JOINT OWNERSHIP AGREEMENTS
	The Company and Alabama Power own, as tenants in common, Units 1 and 2 (total capacity of 500 MWs) at Greene County Steam Plant, which is located in Alabama and operated by Alabama Power. Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2 (total capacity of 1,000 MWs) at Plant Daniel, which is located in Mississippi and operated by the Company.
	At December 31, 2013, the Company's percentage ownership and investment in these jointly-owned facilities in commercial operation were as follows:
	Generating	Company			Plant in Service				Accumulated			Construction Work in Progress
	Plant	Ownership							Depreciation
					(in thousands)
	Greene County
	Units 1 and 2	40	%		$	96,153			$	49,731		$	3,017
	Daniel
	Units 1 and 2	50	%		$	299,179			$	152,952		$	168,539
	The Company's proportionate share of plant operating expenses is included in the statements of income and the Company is responsible for providing its own financing.
	See Note 3 under "Retail Regulatory Matters – Environmental Compliance Overview Plan" for additional information.
Southern Power [Member]	'
Joint Ownership Agreements [Line Items]	'
JOINT OWNERSHIP AGREEMENTS	'
	JOINT OWNERSHIP AGREEMENTS
	The Company is a 65% owner of Plant Stanton A, a combined-cycle project unit with a nameplate capacity of 659 MWs. The unit is co-owned by the Orlando Utilities Commission (28%), Florida Municipal Power Agency (3.5%), and Kissimmee Utility Authority (3.5%). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2013, $156.0 million was recorded in plant in service with associated accumulated depreciation of $41.8 million. These amounts represent the Company's share of the total plant assets and each owner is responsible for providing its own financing. The Company's proportionate share of Plant Stanton A's operating expense is included in the corresponding operating expenses in the statements of income.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Line Items]	'
INCOME TAXES	'
	INCOME TAXES
	Southern Company files a consolidated federal income tax return, combined state income tax returns for the States of Alabama, Georgia, and Mississippi, and unitary income tax returns for the States of California, North Carolina, and Texas. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
	Current and Deferred Income Taxes
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in millions)
	Federal —
	Current	$	363			$	177			$	57
	Deferred	386				1,011				1,035
		749				1,188				1,092
	State —
	Current	(10		)		61				8
	Deferred	110				85				119
		100				146				127
	Total	$	849			$	1,334			$	1,219
	Net cash payments/(refunds) for income taxes in 2013, 2012, and 2011 were $139 million, $38 million, and $(401) 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:
		2013				2012
		(in millions)
	Deferred tax liabilities —
	Accelerated depreciation	$	9,710			$	9,022
	Property basis differences	1,515				1,254
	Leveraged lease basis differences	287				278
	Employee benefit obligations	491				536
	Premium on reacquired debt	113				84
	Regulatory assets associated with employee benefit obligations	705				988
	Regulatory assets associated with asset retirement obligations	824				1,108
	Other	350				349
	Total	13,995				13,619
	Deferred tax assets —
	Federal effect of state deferred taxes	421				394
	Employee benefit obligations	1,048				1,678
	Over recovered fuel clause	30				135
	Other property basis differences	157				134
	Deferred costs	84				39
	ITC carryforward	121				256
	Unbilled revenue	116				101
	Other comprehensive losses	54				84
	Asset retirement obligations	824				720
	Estimated Loss on Kemper IGCC	472				—
	Deferred state tax assets	77				68
	Other	220				363
	Total	3,624				3,972
	Valuation allowance	(49		)		(54		)
	Total deferred tax assets	3,575				3,918
	Total deferred tax liabilities, net	10,420				9,701
	Portion included in prepaid expenses (accrued income taxes), net	143				237
	Accumulated deferred income taxes	$	10,563			$	9,938
	At December 31, 2013, Southern Company had subsidiaries with State of Georgia net operating loss (NOL) carryforwards totaling $707 million, which could result in net state income tax benefits of $41 million, if utilized. However, the subsidiaries have established a valuation allowance for the potential $41 million tax benefit due to the remote likelihood that the tax benefit will be realized. These NOLs expire between 2018 and 2021. Beginning in 2002, the State of Georgia allowed Southern Company to file a combined return, which has prevented the creation of any additional NOL carryforwards.
	At December 31, 2013, Southern Company had an ITC carryforward which is expected to result in $28 million of federal income tax benefit. The ITC carryforward expires in 2023, but is expected to be utilized in 2014. Additionally, Southern Company had a state ITC carryforward of $118 million, which will expire between 2020 and 2024.
	At December 31, 2013, the tax-related regulatory assets to be recovered from customers were $1.4 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, 2013, the tax-related regulatory liabilities to be credited to customers were $202 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.
	In accordance with regulatory requirements, deferred federal ITCs are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $16 million in 2013, $23 million in 2012, and $19 million in 2011. At December 31, 2013, all ITCs available to reduce federal income taxes payable had not been utilized. The remaining ITCs will be carried forward and utilized in future years.
	In 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term production-period projects placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term production-period projects placed in service in 2013).
	On January 2, 2013, ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014, including the Kemper IGCC, which is scheduled for completion in 2014).
	The application of the bonus depreciation provisions in these laws significantly increased deferred tax liabilities related to accelerated depreciation in 2013, 2012, and 2011.
	Effective Tax Rate
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	2.5			2.5			2.4
	Employee stock plans dividend deduction	(1.6	)		(1.0	)		(1.1	)
	Non-deductible book depreciation	1.5			0.9			0.7
AFUDC-Equity	(2.6	)		(1.3	)		(1.5	)
ITC basis difference	(1.2	)		(0.3	)		(0.2	)
Other	(0.5	)		(0.2	)		(0.3	)
Effective income tax rate	33.1	%		35.6	%		35	%
Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction and non-taxable AFUDC equity. Additionally, the 2013 effective rate decrease, as compared to 2012, is primarily due to an increase in non-taxable AFUDC equity. No material change occurred in the effective tax rate from 2011 to 2012.
Unrecognized Tax Benefits
Changes during the year in unrecognized tax benefits were as follows:
	2013				2012				2011
	(in millions)
Unrecognized tax benefits at beginning of year	$	70			$	120			$	296
Tax positions from current periods	3				13				46
Tax positions increase from prior periods	—				7				1
Tax positions decrease from prior periods	(66		)		(56		)		(111		)
Reductions due to settlements	—				(10		)		(112		)
Reductions due to expired statute of limitations	—				(4		)		—
Balance at end of year	$	7			$	70			$	120
The tax positions decrease from prior periods for 2013 relate primarily to the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information.
The impact on Southern Company's effective tax rate, if recognized, is as follows:
	2013				2012				2011
	(in millions)
Tax positions impacting the effective tax rate	$	7			$	5			$	69
Tax positions not impacting the effective tax rate	—				65				51
Balance of unrecognized tax benefits	$	7			$	70			$	120
The tax positions impacting the effective tax rate for 2013 primarily relate to state income tax credits. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognized tax benefits was as follows:
	2013				2012				2011
	(in millions)
Interest accrued at beginning of year	$	1			$	10			$	29
Interest reclassified due to settlements	—				(9		)		(24		)
Interest accrued during the year	—				—				5
Balance at end of year	$	1			$	1			$	10
Southern Company classifies interest on tax uncertainties as interest expense. Southern Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2011. Southern Company has filed its 2012 federal income tax return and has received a full acceptance letter from the IRS; however, the IRS has not finalized its audit. For tax years 2012 and 2013, Southern Company was 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 2007.
Tax Method of Accounting for Repairs
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, on April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. On September 19, 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company is currently reviewing this new guidance. The ultimate outcome of this matter cannot be determined at this time; however, these regulations are not expected to have a material impact on the Company's financial statements.
Alabama Power [Member]	'
Income Tax Disclosure [Line Items]	'
INCOME TAXES	'
	INCOME TAXES
	On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. In addition, the Company files a separate company income tax return for the State of Tennessee. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
	Current and Deferred Income Taxes
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in millions)
	Federal —
	Current	$	243			$	262			$	20
	Deferred	160				137				377
		403				399				397
	State —
	Current	36				51				(1		)
	Deferred	39				27				82
		75				78				81
	Total	$	478			$	477			$	478
	The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
		2013				2012
		(in millions)
	Deferred tax liabilities —
	Accelerated depreciation	$	3,187			$	2,989
	Property basis differences	458				420
	Premium on reacquired debt	33				36
	Employee benefit obligations	209				218
	Under recovered energy clause	—				16
	Regulatory assets associated with employee benefit obligations	198				378
	Asset retirement obligations	38				—
	Regulatory assets associated with asset retirement obligations	265				248
	Other	128				114
	Total	4,516				4,419
	Deferred tax assets —
	Federal effect of state deferred taxes	205				194
	Unbilled fuel revenue	41				39
	Storm reserve	32				34
	Employee benefit obligations	231				408
	Other comprehensive losses	18				19
	Asset retirement obligations	303				248
	Other	108				98
	Total	938				1,040
	Total deferred tax liabilities, net	3,578				3,379
	Portion included in prepaid expenses (accrued income taxes)	25				25
	Accumulated deferred income taxes	$	3,603			$	3,404
	At December 31, 2013, the Company's tax-related regulatory assets to be recovered from customers were $519 million. These assets are primarily attributable to tax benefits that flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest.
	At December 31, 2013, the Company's tax-related regulatory liabilities to be credited to customers were $75 million. These liabilities are primarily attributable to unamortized ITCs.
	In accordance with regulatory requirements, deferred ITCs are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $8 million in each of 2013, 2012, and 2011. At December 31, 2013, all ITCs available to reduce federal income taxes payable had been utilized.
	In 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term production-period projects placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term production-period projects placed in service in 2013).
	On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014).
	The application of the bonus depreciation provisions in these laws significantly increased deferred tax liabilities related to accelerated depreciation in 2013, 2012, and 2011.
	Effective Tax Rate
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	4			4.1			4.3
	Non-deductible book depreciation	1			0.9			0.8
	Differences in prior years' deferred and current tax rates	(0.1	)		(0.1	)		(0.1	)
	AFUDC equity	(0.9	)		(0.5	)		(0.6	)
	Other	(0.1	)		(0.3	)		(0.4	)
	Effective income tax rate	38.9	%		39.1	%		39	%
	The changes in the Company's 2013 and 2012 effective tax rates were not material.
	Unrecognized Tax Benefits
	Changes during the year in unrecognized tax benefits were as follows:
		2013				2012				2011
						(in millions)
	Unrecognized tax benefits at beginning of year	$	31			$	32			$	43
Tax positions from current periods	—				5				6
Tax positions from prior periods	(31		)		(4		)		(17		)
Reductions due to settlements	—				(2		)		—
Balance at end of year	$	—			$	31			$	32
The tax positions decrease from prior periods for 2013 relates primarily to the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information.
The impact on the Company's effective tax rate, if recognized, is as follows:
	2013				2012				2011
					(in millions)
Tax positions impacting the effective tax rate	$	—			$	—			$	5
Tax positions not impacting the effective tax rate	—				31				27
Balance of unrecognized tax benefits	$	—			$	31			$	32
The tax positions not impacting the effective tax rate for 2012 relate to the timing difference associated with the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognized tax benefits is as follows:
	2013				2012				2011
					(in millions)
Interest accrued at beginning of year	$	—			$	1.9			$	1.5
Interest reclassified due to settlements	—				(1.9		)		—
Interest accrued during the year	—				—				0.4
Balance at end of year	$	—			$	—			$	1.9
The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2011. Southern Company has filed its 2012 federal income tax return and has received a full acceptance letter from the IRS; however, the IRS has not finalized its audit. For tax years 2012 and 2013, Southern Company was 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 2007.
Tax Method of Accounting for Repairs
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, on April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. On September 19, 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company is currently reviewing this new guidance. The ultimate outcome of this matter cannot be determined at this time; however, these regulations are not expected to have a material impact on the Company's financial statements.
Georgia Power [Member]	'
Income Tax Disclosure [Line Items]	'
INCOME TAXES	'
	INCOME TAXES
	On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
	Current and Deferred Income Taxes
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in millions)
	Federal –
	Current	$	277			$	273			$	106
	Deferred	374				370				479
		651				643				585
	State –
	Current	(30		)		38				19
	Deferred	102				7				21
		72				45				40
	Total	$	723			$	688			$	625
	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:
		2013				2012
		(in millions)
	Deferred tax liabilities –
	Accelerated depreciation	$	4,479			$	4,201
	Property basis differences	873				757
	Employee benefit obligations	232				255
	Premium on reacquired debt	73				77
	Regulatory assets associated with employee benefit obligations	276				536
	Asset retirement obligations	495				446
	Other	168				93
	Total	6,596				6,365
	Deferred tax assets –
	Federal effect of state deferred taxes	159				142
	Employee benefit obligations	388				644
	Other property basis differences	93				100
	Other deferred costs	84				39
	Cost of removal obligations	17				29
	State tax credit carry forward	118				86
	Federal tax credit carry forward	3				—
	Over-recovered fuel costs	22				89
	Unbilled fuel revenue	53				39
	Asset retirement obligations	495				446
	Other	32				42
	Total	1,464				1,656
	Total deferred tax liabilities, net	5,132				4,709
	Portion included in current assets/(liabilities), net	68				152
	Accumulated deferred income taxes	$	5,200			$	4,861
	At December 31, 2013, tax-related regulatory assets were $722 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, 2013, tax-related regulatory liabilities to be credited to customers were $112 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than current enacted tax law and to unamortized ITCs. In 2011, the Company recorded a regulatory liability of $62 million related to a settlement with the Georgia Department of Revenue resolving claims for certain tax credits in 2005 through 2009. Amortization of the regulatory liability occurred ratably over the period from April 2012 through December 2013.
	In accordance with regulatory requirements, deferred federal ITCs are amortized over the 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 $5 million in 2013, $13 million in 2012, and $9 million in 2011. State ITCs are recognized in the period in which the credits are claimed on the state income tax return and totaled $27 million in 2013, $36 million in 2012, and $53 million in 2011. At December 31, 2013, the Company had $3 million in federal tax credit carry forwards that will expire by 2032 and $118 million in state ITC carry forwards that will expire between 2020 and 2024.
	In 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term production-period projects placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term production-period projects placed in service in 2013).
	On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014).
	The application of the bonus depreciation provisions in these laws significantly increased deferred tax liabilities related to accelerated depreciation in 2013, 2012, and 2011.
	Effective Tax Rate
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	2.5			1.6			1.5
	Non-deductible book depreciation	1.3			1.2			0.8
	AFUDC equity	(0.6	)		(1.0	)		(1.9	)
	Other	(0.4	)		(0.1	)		(0.5	)
	Effective income tax rate	37.8	%		36.7	%		34.9	%
	The increase in the Company's 2013 effective tax rate is primarily the result of a decrease in state income tax credits and non-taxable AFUDC equity. The increase in the Company's 2012 effective tax rate is primarily the result of an increase in non-deductible book depreciation and a decrease in non-taxable AFUDC equity.
	Unrecognized Tax Benefits
	Changes during the year in unrecognized tax benefits were as follows:
		2013				2012				2011
		(in millions)
Unrecognized tax benefits at beginning of year	$	23			$	47			$	237
Tax positions from current periods	—				3				9
Tax positions increase from prior periods	—				3				—
Tax positions decrease from prior periods	(23		)		(19		)		(87		)
Reductions due to settlements	—				(8		)		(112		)
Reductions due to expired statute of limitations	—				(3		)		—
Balance at end of year	$	—			$	23			$	47
The tax positions decrease from prior periods for 2013 relates primarily to the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information.
In addition, the tax reductions due to expired statute of limitations for 2012 relate to the Georgia jobs and retraining tax credits and the Georgia manufacturer's ITCs.
The impact on the Company's effective tax rate, if recognized, is as follows:
	2013				2012				2011
	(in millions)
Tax positions impacting the effective tax rate	$	—			$	—			$	28
Tax positions not impacting the effective tax rate	—				23				19
Balance of unrecognized tax benefits	$	—			$	23			$	47
The tax positions not impacting the effective tax rate for 2012 relate to the timing difference associated with the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognized tax benefits was as follows:
	2013				2012				2011
	(in millions)
Interest accrued at beginning of year	$	—			$	6			$	27
Interest reclassified due to settlements	—				(6		)		(24		)
Interest accrued during the year	—				—				3
Balance at end of year	$	—			$	—			$	6
The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2011. Southern Company has filed its 2012 federal income tax return and has received a full acceptance letter from the IRS; however, the IRS has not finalized its audit. For tax years 2012 and 2013, Southern Company was 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 2007.
Tax Method of Accounting for Repairs
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, on April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. On September 19, 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company is currently reviewing this new guidance. The ultimate outcome of this matter cannot be determined at this time; however, these regulations are not expected to have a material impact on the Company's financial statements.
Gulf Power [Member]	'
Income Tax Disclosure [Line Items]	'
INCOME TAXES	'
	INCOME TAXES
	On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. In addition, the Company files a separate company income tax return for the State of Florida. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with Internal Revenue Service (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:
		2013				2012				2011
		(in thousands)
	Federal -
	Current	$	5,009			$	(92,610	)		$	(1,548	)
	Deferred	63,134				161,096				56,087
		68,143				68,486				54,539
	State -
	Current	(2,410		)		(2,484		)		(412		)
	Deferred	13,935				13,209				7,141
		11,525				10,725				6,729
	Total	$	79,668			$	79,211			$	61,268
	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:
		2013				2012
		(in thousands)
	Deferred tax liabilities-
	Accelerated depreciation	$	721,087			$	696,502
	Property basis differences	45,960				—
	Fuel recovery clause	7,972				—
	Pension and other employee benefits	25,800				28,579
	Regulatory assets associated with employee benefit obligations	27,660				57,279
	Regulatory assets associated with asset retirement obligations	6,554				6,502
	Other	23,947				16,019
	Total	858,980				804,881
	Deferred tax assets-
	Federal effect of state deferred taxes	24,277				20,656
	Postretirement benefits	17,816				17,905
	Fuel recovery clause	—				6,922
	Pension and other employee benefits	33,015				61,939
	Other basis differences	—				23,549
	Property reserve	15,144				13,773
	Other comprehensive loss	696				993
	Asset retirement obligations	6,554				6,502
	Alternative minimum tax carryforward	18,420				938
	Other	17,084				4,724
	Total	133,006				157,901
	Net deferred tax liabilities	725,974				646,980
	Portion included in current assets (liabilities), net	8,381				1,972
	Accumulated deferred income taxes	$	734,355			$	648,952
	At December 31, 2013, the tax-related regulatory assets to be recovered from customers were $50.9 million. These assets are primarily attributable to tax benefits that flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest.
	At December 31, 2013, the tax-related regulatory liabilities to be credited to customers were $5.2 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 ITCs are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $1.4 million in 2013, $1.4 million in 2012, and $1.3 million in 2011. At December 31, 2013, all ITCs available to reduce federal income taxes payable had been utilized.
	In 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term production-period projects placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term production-period projects placed in service in 2013).
	On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014).
	The application of the bonus depreciation provisions in these laws significantly increased deferred tax liabilities related to accelerated depreciation in 2013, 2012, and 2011.
	Effective Tax Rate
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	3.5			3.3			2.5
	Non-deductible book depreciation	0.5			0.5			0.5
	Differences in prior years' deferred and current tax rates	(0.2	)		(0.2	)		(0.3	)
	AFUDC equity	(1.1	)		(0.9	)		(2.0	)
	Other, net	(0.1	)		(0.2	)		(0.2	)
	Effective income tax rate	37.6	%		37.5	%		35.5	%
	The increase in the 2013 effective tax rate was not material. The increase in the 2012 effective tax rate is primarily the result of a decrease in AFUDC equity, which is not taxable, and a decrease in state tax credits.
	Unrecognized Tax Benefits
	Changes during the year in unrecognized tax benefits were as follows:
		2013				2012				2011
		(in thousands)
Unrecognized tax benefits at beginning of year	$	5,007			$	2,892			$	3,870
Tax positions from current periods	45				2,630				540
Tax positions from prior periods	(5,007		)		515				(1,518		)
Reductions due to settlements	—				(1,030		)		—
Balance at end of year	$	45			$	5,007			$	2,892
The tax positions decrease from prior periods for 2013 relates primarily to the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information.
The impact on the Company's effective tax rate, if recognized, was as follows:
	2013				2012				2011
	(in thousands)
Tax positions impacting the effective tax rate	$	45			$	45			$	1,804
Tax positions not impacting the effective tax rate	—				4,962				1,088
Balance of unrecognized tax benefits	$	45			$	5,007			$	2,892
The tax positions impacting the effective tax rate for 2013 relate primarily to the research and development credit. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognized tax benefits was not material for years 2013, 2012, and 2011.
The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2011. Southern Company has filed its 2012 federal income tax return and has received a full acceptance letter from the IRS; however, the IRS has not finalized its audit. For tax years 2012 and 2013, Southern Company was 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 2007.
Tax Method of Accounting for Repairs
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, on April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. On September 19, 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company is currently reviewing this new guidance. The ultimate outcome of this matter cannot be determined at this time; however, these regulations are not expected to have a material impact on the Company's financial statements.
Mississippi Power [Member]	'
Income Tax Disclosure [Line Items]	'
INCOME TAXES	'
	INCOME TAXES
	On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama and Mississippi. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
	Current and Deferred Income Taxes
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in thousands)
	Federal —
	Current	$	23,345			$	1,212			$	(27,099	)
	Deferred	(342,870		)		16,994				65,206
		(319,525		)		18,206				38,107
	State —
	Current	5,219				1,656				(2,473		)
	Deferred	(53,529		)		694				6,559
		(48,310		)		2,350				4,086
	Total	$	(367,835	)		$	20,556			$	42,193
	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:
		2013				2012
		(in thousands)
	Deferred tax liabilities —
	Accelerated depreciation	$	371,553			$	385,899
	Property basis differences	130,679				72,451
	Energy cost management clause under recovered	1,777				9,492
	Regulatory assets associated with asset retirement obligations	16,764				16,851
	Pensions and other benefits	23,769				33,756
	Regulatory assets associated with employee benefit obligations	33,127				68,717
	Regulatory assets associated with the Kemper IGCC	30,708				10,492
	Rate differential	56,074				27,270
	Federal effect of state deferred taxes	30,615				—
	Other	35,583				33,886
	Total	730,649				658,814
	Deferred tax assets —
	Federal effect of state deferred taxes	—				7,732
	Fuel clause over recovered	7,741				38,955
	Estimated loss on Kemper IGCC	472,000				31,200
	Pension and other benefits	57,999				87,416
	Property insurance	23,693				23,171
	Premium on long-term debt	23,736				26,778
	Unbilled fuel	12,136				11,642
	Long-term service agreement	—				5,544
	Asset retirement obligations	16,764				16,851
	Interest rate hedges	5,094				5,644
	ITC carryforward	—				170,938
	Kemper rate factor - regulatory liability retail	36,210				—
	Other	18,094				23,800
	Total	673,467				449,671
	Total deferred tax liabilities, net	57,182				209,143
	Portion included in (accrued) prepaid income taxes, net	15,626				35,815
	Accumulated deferred income taxes	$	72,808			$	244,958
	At December 31, 2013, the tax-related regulatory assets were $144.4 million. These assets are primarily attributable to tax benefits that flowed through to customers in prior years, to deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest.
	At December 31, 2013, the tax-related regulatory liabilities were $10.2 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 ITCs are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits for non-Kemper IGCC related deferred ITCs amortized in this manner amounted to $1.2 million, $1.2 million, and $1.3 million for 2013, 2012, and 2011, respectively. At December 31, 2013, all non-Kemper IGCC ITCs available to reduce federal income taxes payable had been utilized.
	In 2010, the Company began recognizing ITCs associated with the construction expenditures related to the Kemper IGCC. At December 31, 2013, the Company had $276.4 million in unamortized ITCs associated with the Kemper IGCC, which will be amortized over the life of the Kemper IGCC once placed in service and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO2 produced by the Kemper IGCC during operation in accordance with the Internal Revenue Code. A portion of the tax credits will be subject to recapture upon successful completion of SMEPA's purchase of an undivided interest in the Kemper IGCC.
	In 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term production-period projects placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term production-period projects placed in service in 2013).
	On January 2, 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014, including the Kemper IGCC, which is scheduled for completion in 2014).
	Effective Tax Rate
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	3.7			1.3			1.9
	Non-deductible book depreciation	(0.1	)		0.3			0.3
	AFUDC-equity	5			(18.6	)		(6.3	)
	Other	0.1			(1.2	)		(0.3	)
	Effective income tax rate	43.7	%		16.8	%		30.6	%
The Company's 2013 effective tax rate increased from 2012 primarily due to the increase in estimated losses associated with the Kemper IGCC.
Unrecognized Tax Benefits
Changes during the year in unrecognized tax benefits were as follows:
	2013				2012				2011
	(in thousands)
Unrecognized tax benefits at beginning of year	$	5,755			$	4,964			$	4,288
Tax positions from current periods	226				1,186				1,486
Tax positions from prior periods	(2,141		)		(26		)		(810		)
Settlements with taxing authorities	—				(369		)		—
Balance at end of year	$	3,840			$	5,755			$	4,964
The tax positions decrease from prior periods for 2013 relates to the uncertain tax position for the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" below for additional information.
The impact on the Company's effective tax rate, if recognized, was as follows:
	2013				2012				2011
	(in thousands)
Tax positions impacting the effective tax rate	$	3,840			$	3,656			$	4,144
Tax positions not impacting the effective tax rate	—				2,099				820
Balance of unrecognized tax benefits	$	3,840			$	5,755			$	4,964
The tax positions impacting the effective tax rate for 2013 primarily relate to the State of Mississippi ITC. The tax positions not impacting the effective tax rate for 2012 related to the timing difference associated with the tax accounting method change for repairs - generation assets. See "Tax Method of Accounting for Repairs" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognized tax benefits was as follows:
	2013				2012				2011
	(in thousands)
Interest accrued at beginning of year	$	772			$	680			$	413
Interest accrued during the year	399				92				267
Balance at end of year	$	1,171			$	772			$	680
The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2011. Southern Company has filed its 2012 federal income tax return and has received a full acceptance letter from the IRS; however, the IRS has not finalized its audit. For tax years 2012 and 2013, Southern Company was 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 2007.
Tax Method of Accounting for Repairs
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, on April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. On September 19, 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company is currently reviewing this new guidance. The ultimate outcome of this matter cannot be determined at this time; however, these regulations are not expected to have a material impact on the Company's financial statements.
Southern Power [Member]	'
Income Tax Disclosure [Line Items]	'
INCOME TAXES	'
	INCOME TAXES
	On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. In addition, the Company files separate company income tax returns for the States of Florida, New Mexico, South Carolina, and Tennessee. Unitary income tax returns are filed for the States of California, North Carolina, and Texas. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with Internal Revenue Service (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:
		2013				2012				2011
		(in millions)
	Federal —
	Current	$	(120.2	)		$	(133.1	)		$	61.6
	Deferred	158.7				210.4				12.4
		38.5				77.3				74
	State —
	Current	(5.2		)		(3.0		)		9.8
	Deferred	12.6				18.3				(7.9		)
		7.4				15.3				1.9
	Total	$	45.9			$	92.6			$	75.9
	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:
		2013				2012
		(in millions)
	Deferred tax liabilities —
	Accelerated depreciation and other property basis differences	$	829.5			$	632.9
	Basis difference on asset transfers	2.8				3.1
	Levelized capacity revenues	11.2				—
	Other	0.9				—
	Total	844.4				636
	Deferred tax assets —
	Federal effect of state deferred taxes	29.7				25.2
	Net basis difference on ITCs	58				28.6
	Basis difference on asset transfers	2.9				3.9
	Alternative minimum tax carryforward	1.1				1.1
	Unrealized loss on interest rate swaps	11.2				15.7
	Levelized capacity revenues	6				4.5
	State net operating loss	17				8.3
	Other	1.8				4.4
	Total	127.7				91.7
	Valuation Allowance	(7.5		)		(6.2		)
	Net deferred income tax assets	120.2				85.5
	Total deferred tax liabilities, net	724.2				550.5
	Portion included in current income taxes	0.2				0.2
	Accumulated deferred income taxes	$	724.4			$	550.7
	Deferred tax liabilities are the result of property related timing differences primarily due to bonus depreciation. The transfer of the Plant McIntosh construction project to Georgia Power in 2004 resulted in a deferred gain for federal income tax purposes. Georgia Power is reimbursing the Company for the related tax liability balance of $2.8 million. Of this total, $0.3 million is included in the balance sheets in "Receivables – Affiliated companies" and the remainder is included in "Other deferred charges and assets – affiliated."
	Deferred tax assets consist primarily of timing differences related to net basis differences on ITCs, the recognition of capacity revenues, and the unrealized loss on interest rate swaps reflected in AOCI. The transfer of Plants Dahlberg, Wansley, and Franklin to the Company from Georgia Power in 2001 also resulted in a deferred gain for federal income tax purposes. The Company will reimburse Georgia Power for the related tax asset of $2.6 million. Of this total, $1.0 million is included in the balance sheets in "Accounts payable – Affiliated" and the remainder is included in "Other deferred credits and liabilities – affiliated."
	At December 31, 2013 and December 31, 2012, the Company had state net operating loss (NOL) carryforwards of $240.8 million and $117.7 million, respectively. The NOL carryforwards resulted in deferred tax assets of $11.0 million as of December 31, 2013 and $5.4 million as of December 31, 2012. The Company has established a valuation allowance due to the remote likelihood that the full tax benefits will be realized. During 2013, the estimated amount of NOL utilization decreased resulting in an $18.6 million increase in the valuation allowance. Of the NOL balance at December 31, 2013, approximately $87.0 million expires in 2015, approximately $40.0 million expires in 2017, and approximately $107.0 million expires in 2018.
	In 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Tax Relief Act) was signed into law. Major tax incentives in the Tax Relief Act include 100% bonus depreciation for property placed in service after September 8, 2010 and through 2011 (and for certain long-term production period projects placed in service in 2012) and 50% bonus depreciation for property placed in service in 2012 (and for certain long-term production period projects placed in service in 2013).
	On January 2, 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014). The extension of 50% bonus depreciation had a positive impact of $98.9 million on the Company’s cash flows in 2013 and significantly increased deferred tax liabilities related to accelerated depreciation in 2012 and 2013.
	Effective Tax Rate
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	2.2			3.7			0.6
	Amortization of ITC	(1.7	)		(1.0	)		(0.4	)
	ITC basis difference	(14.5	)		(2.6	)		(3.1	)
	Other	0.3			(0.6	)		(0.3	)
	Effective income tax rate	21.3	%		34.5	%		31.8	%
	The Company's effective tax rate decreased in 2013 primarily as a result of ITCs recognized related to Plants Campo Verde and Spectrum. The Company's effective tax rate increased in 2012 primarily as a result of a decrease in the Alabama income tax deduction for federal income taxes paid.
	In 2009, President Obama signed into law the ARRA. Major tax incentives in the ARRA included renewable energy incentives. The ATRA retroactively extended several renewable energy incentives through 2013, including extending ITCs for biomass projects which begin construction before January 1, 2014. The Company received ITCs under the renewable energy incentives related to Plants Nacogdoches, Cimarron, Apex, Granville, Spectrum, and Campo Verde, which had a material impact on cash flows and net income.
	Cash ITCs received in 2013 for the construction of Plants Nacogdoches, Apex, Granville, Spectrum, and Campo Verde were $158.1 million. The tax benefit of the basis difference reduced income tax expense by $31.3 million in 2013.
	Cash ITCs received in 2012 for the construction of Plants Nacogdoches, Apex, and Granville were $45.0 million. The tax benefit of the basis difference reduced income tax expense by $6.9 million in 2012.
	Cash ITCs received in 2011 for the construction of Plants Nacogdoches and Cimarron were $84.7 million, which includes $42.9 million earned in 2010. The tax benefit of the basis difference reduced income tax expense by $7.3 million in 2011.
	See Note 1 under "Investment Tax Credits" for additional information.
	Unrecognized Tax Benefits
	Changes in unrecognized tax benefits were as follows:
		2013				2012				2011
		(in millions)
Unrecognized tax benefits at beginning of year	$	2.9			$	2.6			$	2.3
Tax positions from current periods	1.6				0.7				0.4
Tax positions from prior periods	(3.0		)		(0.2		)		(0.1		)
Reductions due to settlements	—				(0.2		)		—
Balance at end of year	$	1.5			$	2.9			$	2.6
The increase in unrecognized tax benefits from current periods for 2013 relates primarily to ITCs. The decrease in unrecognized tax benefits from prior periods for 2013 relates primarily to the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information.
The impact on the Company's effective tax rate, if recognized, was as follows:
	2013				2012				2011
	(in millions)
Tax positions impacting the effective tax rate	$	1.5			$	0.3			$	0.5
Tax positions not impacting the effective tax rate	—				2.6				2.1
Balance of unrecognized tax benefits	$	1.5			$	2.9			$	2.6
The tax positions impacting the effective tax rate for 2013 primarily relate to the ITCs realized in 2013. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognized tax benefits was immaterial for all years presented.
The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. 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 2011. For tax years 2012 and 2013, Southern Company is a participant in the Compliance Assurance Process of the IRS. Southern Company has filed its 2012 federal income tax return and has received a full acceptance letter from the IRS; however, the IRS has not finalized its audit. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2007.
Tax Method of Accounting for Repairs
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, on April 30, 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. On September 19, 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company is currently reviewing this new guidance. The ultimate outcome of this matter cannot be determined at this time; however, these regulations are not expected to materially impact the Company's financial statements.

Financing

Financing	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. Alabama Power considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At each of December 31, 2013 and 2012, 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:
		2013				2012
		(in millions)
	Senior notes	$	428			$	2,085
	Other long-term debt	12				227
	Capitalized leases	29				23
	Total	$	469			$	2,335
	Maturities through 2018 applicable to total long-term debt are as follows: $469 million in 2014; $2.97 billion in 2015; $1.83 billion in 2016; $1.14 billion in 2017; and $880 million in 2018.
	Bank Term Loans
	Certain of the traditional operating companies have entered into various floating rate bank term loan agreements for loans bearing interest based on one-month London Interbank Offered Rate (LIBOR). At December 31, 2013, Georgia Power had outstanding bank term loans totaling $400 million, which are reflected in notes payable on the balance sheets. Also at December 31, 2013, Mississippi Power had outstanding bank term loans totaling $525 million, which are reflected in the statements of capitalization as long-term debt. At December 31, 2012, Mississippi Power had outstanding bank term loans totaling $175 million.
	During 2013, the traditional operating companies repaid approximately $550 million of floating rate bank notes bearing interest based on one-month LIBOR.
	During 2012, Mississippi Power entered into a 366-day $100 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR. The first advance in the amount of $50 million was made in November 2012. In January 2013, the second advance in the amount of $50 million was made. In September 2013, Mississippi Power amended the bank loan, which extended the maturity date to 2015. The proceeds of this loan were used for working capital and for other general corporate purposes, including Mississippi Power's continuous construction program.
	In March 2013, Mississippi Power entered into four two-year floating rate bank loans bearing interest based on one-month LIBOR. These term loans were for an aggregate principal amount of $300 million and proceeds were used for working capital and other general corporate purposes, including Mississippi Power's continuous construction program.
	In September 2013, Mississippi Power entered into a two-year floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $125 million aggregate principal amount and proceeds were used to repay at maturity a two-year floating rate bank loan in the aggregate principal amount of $125 million.
	In November 2013, Georgia Power entered into three four-month floating rate bank loans for an aggregate principal amount of $400 million, bearing interest based on one-month LIBOR. The proceeds of these short-term loans were used for working capital and other general corporate purposes, including Georgia Power's continuous construction program. Subsequent to December 31, 2013, Georgia Power repaid these bank term loans.
	Subsequent to December 31, 2013, Mississippi Power entered into an 18-month floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $250 million aggregate principal amount and proceeds were used for working capital and other general corporate purposes, including Mississippi Power’s continuous construction program.
	These bank loans have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and other hybrid securities and, for Mississippi Power, securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2013, Georgia Power and Mississippi Power were in compliance with their respective debt limits.
	DOE Loan Guarantee Borrowings
	Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) on February 20, 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the Federal Financing Bank (FFB) and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB.
	Proceeds of advances made under the FFB Credit Facility will be used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion.
	All borrowings under the FFB Credit Facility are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE in the event the DOE is required to make any payments to FFB under the DOE guarantee. Georgia Power's reimbursement obligations to the DOE are secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 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 December 31, 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
	On February 20, 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to February 20, 2044 (the final maturity date) and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to February 20, 2029, and will be reset from time to time thereafter through the final maturity date. In connection with its entry into the Loan Guarantee Agreement, the FFB Note Purchase Agreement, and the FFB Promissory Note, Georgia Power incurred issuance costs of approximately $67 million, which will be amortized over the life of the borrowings under the FFB Credit Facility.
	Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, compliance with the Cargo Preference Act of 1954, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
	Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
	In the event certain mandatory prepayment events occur, the FFB’s commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
	In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power’s rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power’s ownership interest in Plant Vogtle Units 3 and 4.
	Senior Notes
	Southern Company and its subsidiaries issued a total of $2.1 billion of senior notes in 2013. Southern Company issued $500 million and its subsidiaries issued a total of $1.6 billion. The proceeds of these issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries' continuous construction programs.
	At December 31, 2013 and 2012, Southern Company and its subsidiaries had a total of $17.3 billion and $17.4 billion, respectively, of senior notes outstanding. At December 31, 2013 and 2012, Southern Company had a total of $1.8 billion and $1.3 billion, respectively, of senior notes outstanding.
	Since Southern Company is a holding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred and preference stockholders of such subsidiary.
	Pollution Control Revenue Bonds
	Pollution control obligations represent loans to the traditional operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of pollution control bonds issued by public authorities. The traditional operating companies had $3.2 billion and $3.4 billion of outstanding pollution control revenue bonds at December 31, 2013 and 2012, respectively. The traditional operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.
	Plant Daniel Revenue Bonds
	In 2011, in connection with Mississippi Power's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 21, 2021, issued for the benefit of the lessor. See "Assets Subject to Lien" herein for additional information.
	Other Revenue Bonds
	Other revenue bond obligations represent loans to Mississippi Power from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper IGCC and related facilities.
	In March 2013 and July 2013, the Mississippi Business Finance Corporation (MBFC) issued $15.8 million and $15.3 million, respectively, aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012A. The proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. In September 2013, the MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012A of $40.07 million, Series 2012B of $21.25 million, and Series 2012C of $21.25 million were paid at maturity.
	In November 2013, the MBFC entered into an agreement to issue up to $33.75 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013A (Mississippi Power Company Project) and up to $11.25 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013B (Mississippi Power Company Project) for the benefit of Mississippi Power. In November 2013, the MBFC issued $11.25 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013B for the benefit of Mississippi Power. The proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of the Series 2013A bonds will be used for this same purpose.
	Mississippi Power had $50.0 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2013 and 2012 and $11.3 million and $51.5 million of such obligations related to taxable revenue bonds outstanding at December 31, 2013 and 2012, respectively. Such amounts are reflected in the statements of capitalization as long-term senior notes and debt.
	Capital Leases
	In September 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at December 31, 2013 of approximately $83 million with an annual interest rate of 4.9%. Assets acquired under capital leases are recorded on the balance sheet as utility plant in service and the related obligations are classified as long-term debt.
	At December 31, 2013 and 2012, the capitalized lease obligations for Georgia Power were $45 million and $50 million, respectively, with an interest rate of 7.9% for both years.
	At December 31, 2013, Alabama Power had a capitalized lease obligation of $5 million for a natural gas pipeline with an annual interest rate of 6.9%.
	At December 31, 2013 and 2012, a subsidiary of Southern Company had capital lease obligations of approximately $30 million in each period for certain computer equipment including desktops, laptops, servers, printers, and storage devices with interest rates that range from 1.4% to 3.2%.
	Other Obligations
	In March 2012 and subsequent to December 31, 2013, Mississippi Power received $150 million and $75 million, respectively, interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the sale is closed, the deposits bear interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 9.932% per annum for 2013 and 9.967% per annum for 2012, and are refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that Mississippi Power is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies. On July 18, 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.
	Assets Subject to Lien
	Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. Alabama Power and Gulf Power have granted one or more liens on certain of their respective property in connection with the issuance of certain series of pollution control revenue bonds with an outstanding principal amount of $194 million as of December 31, 2013. 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.
	In 2011, Mississippi Power purchased Plant Daniel Units 3 and 4 for approximately $85 million in cash and the assumption of $270 million face value (with a fair value on the assumption date of $346 million) of debt obligations of the lessor related to Plant Daniel Units 3 and 4, which mature in 2021 and bear interest at a fixed stated interest rate of 7.13% per annum. These obligations are secured by Plant Daniel Units 3 and 4 and certain personal property.
	See "DOE Loan Guarantee Borrowings" for information regarding additional secured borrowings incurred by Georgia Power subsequent to December 31, 2013.
	Bank Credit Arrangements
	At December 31, 2013, committed credit arrangements with banks were as follows:
		Expires(a)																			Executable Term Loans						Due Within
																											One Year
	Company	2014				2015			2016			2018			Total			Unused			One			Two			Term Out		No Term Out
																					Year			Years
		(in millions)													(in millions)						(in millions)						(in millions)
	Southern Company	$	—			$	—		$	—		$	1,000		$	1,000		$	1,000		$	—		$	—		$	—	$	—
Alabama Power	238				35			—			1,030			1,303			1,303			53			—			53		185
Georgia Power	—				—			150			1,600			1,750			1,736			—			—			—		—
Gulf Power	110				—			165			—			275			275			45			—			45		65
Mississippi Power	135				—			165			—			300			300			25			40			65		70
Southern Power	—				—			—			500			500			500			—			—			—		—
Other	75				25			—			—			100			100			25			—			25		50
Total	$	558			$	60		$	480		$	4,130		$	5,228		$	5,214		$	148		$	40		$	188	$	370
(a)	No credit arrangements expire in 2017.
Most of the credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/4 of 1% for Southern Company, the traditional operating companies, and Southern Power. Compensating balances are not legally restricted from withdrawal.
Southern Company and its subsidiaries expect to renew their credit arrangements as needed, prior to expiration.
Most of the credit arrangements with banks have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements, other hybrid securities and, for Mississippi Power, securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2013, Southern Company, the traditional operating companies, and Southern Power were each in compliance with their respective debt limit covenants.
A portion of the $5.2 billion unused credit arrangements with banks is allocated to provide liquidity support to the traditional operating companies' variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2013 was approximately $1.8 billion. In addition, at December 31, 2013, the traditional operating companies had $442 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.
Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of committed bank credit arrangements. Southern Company, the traditional operating companies, and Southern Power 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(a)
	Amount Outstanding				Weighted Average Interest Rate
	(in millions)
December 31, 2013:
Commercial paper	$	1,082			0.2	%
Short-term bank debt	400				0.9	%
Total	$	1,482			0.4	%
December 31, 2012:
Commercial paper	$	820			0.3	%
Short-term bank debt	—				—	%
Total	$	820			0.3	%
(a)    Excludes notes payable related to other energy service contracts of $5 million at December 31, 2012.
Redeemable Preferred Stock of Subsidiaries
Each of the traditional operating companies has issued preferred and/or preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary's board of directors if 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 that would allow the holders to elect a majority of such subsidiary's board. 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 required to be shown as "noncontrolling interest," separately presented as a component of "Stockholders' Equity" on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity.
There were no changes for the years ended December 31, 2013 and 2012 in redeemable preferred stock of subsidiaries for Southern Company.
Alabama Power [Member]	'
Debt Disclosure [Line Items]	'
FINANCING	'
	FINANCING
	Long-Term Debt Payable to an Affiliated Trust
	The Company has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $206 million as of December 31, 2013 and 2012, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At each of December 31, 2013 and 2012, 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, 2013, the Company had no scheduled maturities of senior notes due within one year. At December 31, 2012, the Company had $250 million of senior notes due within one year.
	Maturities of senior notes and pollution control revenue bonds through 2018 applicable to total long-term debt are as follows: $454 million in 2015; $200 million in 2016; and $561 million in 2017. There are no scheduled maturities in 2014 and 2018.
	Pollution Control Revenue Bonds
	Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of pollution control and solid waste disposal facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company incurred no obligations related to the issuance of pollution control revenue bonds in 2013. The amount of tax-exempt pollution control revenue bonds outstanding at each of December 31, 2013 and 2012 was $1.2 billion, respectively.
	Senior Notes
	In December 2013, the Company issued $300 million aggregate principal amount of its Series 2013A 3.55% Senior Notes due December 1, 2023. The proceeds of these issuances were used for general corporate purposes, including the Company's continuous construction program.
	In November 2013, the Company's $250 million aggregate principal amount of its Series 2008B 5.80% Senior Notes due November 15, 2013 matured.
	At December 31, 2013 and 2012, the Company had $4.9 billion and $4.8 billion of senior notes outstanding, respectively. These senior notes are effectively subordinated to all secured debt of the Company which amounted to approximately $153 million at December 31, 2013.
	Outstanding Classes of Capital Stock
	The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized and outstanding. The Company's preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary and involuntary dissolution. The preferred stock and Class A preferred stock of the Company contain a feature that allows the holders to elect a majority of the Company's board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, the preferred stock and Class A preferred stock is presented as "Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The preference stock does not contain such a provision that would allow the holders to elect a majority of the Company's board. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution.
	The Company's preferred stock is subject to redemption at a price equal to the par value plus a premium. The Company's Class A preferred stock is subject to redemption at a price equal to the stated capital. Certain series of the Company's preference stock are subject to redemption at a price equal to the stated capital plus a make-whole premium based on the present value of the liquidation amount and future dividends to the first stated capital redemption date and the other series of preference stock are subject to redemption at a price equal to the stated capital. Certain series of the Company's preferred stock are subject to redemption at the option of the Company on or after a specified date. Information for each outstanding series is in the table below:
	Preferred/Preference Stock	Par Value/Stated Capital Per Share		Shares Outstanding			First Call Date	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			8/1/08	Stated Capital
	5.20% Class A Preferred Stock	$25		6,480,000			8/1/08	Stated Capital
	5.30% Class A Preferred Stock	$25		4,000,000			4/1/09	Stated Capital
	5.625% Preference Stock	$25		6,000,000			1/1/12	Stated Capital
	6.450% Preference Stock	$25		6,000,000			*	**
	6.500% Preference Stock	$25		2,000,000			*	**
	* Redemption permitted any time after issuance
	** Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital
	Dividend Restrictions
	The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
	Assets Subject to Lien
	The Company has granted liens on certain property in connection with the issuance of certain series of pollution control revenue bonds with an outstanding principal amount of $153 million as of December 31, 2013. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries.
	Bank Credit Arrangements
	At December 31, 2013, committed credit arrangements with banks were as follows:
	Expires(a)																Executable						Due Within One Year
																	Term-Loans
	2014				2015			2018			Total			Unused			One			Two			Term Out			No Term Out
																	Year			Years
											(in millions)
	$	238			$	35		$	1,030		$	1,303		$	1,303		$	53		$	—		$	53		$	185
	(a)	No credit arrangements expire in 2016 or 2017.
	The Company expects to renew its credit agreements as needed, prior to expiration. Most of the credit arrangements require payment of a commitment fee based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/4 of 1% for the Company. Compensating balances are not legally restricted from withdrawal.
	Most of the Company's credit arrangements with banks have covenants that limit the Company's debt to 65% of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 2013, the Company was in compliance with the debt limit covenants.
	A portion of the unused credit with banks is allocated to provide liquidity support to the Company's variable rate pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds requiring liquidity support was $793 million as of December 31, 2013. In addition, at December 31, 2013, the Company had $200 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.
	The Company borrows through commercial paper programs that have the liquidity support of committed bank credit arrangements. The Company may also make short-term borrowings through various other arrangements with banks. At December 31, 2013 and 2012, there was no short-term debt outstanding. At December 31, 2013, the Company had regulatory approval to have outstanding up to $2 billion of short-term borrowings.
Georgia Power [Member]	'
Debt Disclosure [Line Items]	'
FINANCING	'
	FINANCING
	Securities Due Within One Year
	A summary of scheduled maturities of long-term debt due within one year at December 31 was as follows:
		2013				2012
		(in millions)
	Senior notes	$	—			$	1,675
	Capital lease	5				5
	Total	$	5			$	1,680
	Maturities through 2018 applicable to total long-term debt are as follows: $5 million in 2014; $1.1 billion in 2015; $710 million in 2016; $457 million in 2017; and $277 million in 2018.
	Senior Notes
	The Company issued $850 million aggregate principal amount of unsecured senior notes in 2013. The proceeds of these issuances were used to fund a portion of the Company's repayment of $1.8 billion of unsecured senior notes and $300 million of an unsecured bank term loan, 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, 2013 and 2012, the Company had $6.9 billion and $7.9 billion of senior notes outstanding, respectively. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $45 million and $50 million at December 31, 2013 and 2012, respectively. As of December 31, 2013 and 2012, the Company's secured debt was related to capital lease obligations.
	See "DOE Loan Guarantee Borrowings" for information regarding additional secured borrowings incurred by the Company subsequent to December 31, 2013.
	Pollution Control Revenue Bonds
	Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2013 and 2012 was $1.7 billion and $1.8 billion, respectively. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.
	In 2013, the Company incurred obligations in connection with issuance by public authorities of an aggregate of $194 million of pollution control revenue bonds. The proceeds of these issuances were used to redeem $194 million of outstanding pollution control bonds. Also in November 2013, the Company purchased and now holds $104.6 million aggregate principal amount of pollution control revenue bonds issued for its benefit in 2013.
	Bank Term Loans
	In March 2013, the Company entered into three 60-day floating rate bank loans bearing interest based on one-month London Interbank Offered Rate (LIBOR). Each of these short-term loans was for $100 million aggregate principal amount, and the proceeds were used for working capital and other general corporate purposes, including the Company's continuous construction program. These bank loans were repaid at maturity.
	In November 2013, the Company entered into three four-month floating rate bank loans for an aggregate principal amount of $400 million, bearing interest based on one-month LIBOR. The proceeds of these short-term loans were used for working capital and other general corporate purposes, including the Company's continuous construction program. At December 31, 2013, these bank term loans are included in notes payable on the balance sheets. Subsequent to December 31, 2013, the Company repaid these bank term loans. There were no bank term loans outstanding at December 31, 2012.
	These bank loans have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes long-term debt payable to affiliated trusts and other hybrid securities. At December 31, 2013, the 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), the Company and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) on February 20, 2014, under which the DOE agreed to guarantee the obligations of the Company under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, the Company, and the Federal Financing Bank (FFB) and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which the Company may make term loan borrowings through the FFB.
	Proceeds of advances made under the FFB Credit Facility will be used to reimburse the Company for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion.
	All borrowings under the FFB Credit Facility are full recourse to the Company, and the Company is obligated to reimburse the DOE in the event the DOE is required to make any payments to FFB under the DOE guarantee. The Company's reimbursement obligations to the DOE are secured by a first priority lien on (i) the Company's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 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 December 31, 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
	On February 20, 2014, the Company made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to February 20, 2044 (the final maturity date) and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to February 20, 2029, and will be reset from time to time thereafter through the final maturity date. In connection with its entry into the Loan Guarantee Agreement, the FFB Note Purchase Agreement, and the FFB Promissory Note, the Company incurred issuance costs of approximately $67 million, which will be amortized over the life of the borrowings under the FFB Credit Facility.
	Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, compliance with the Cargo Preference Act of 1954, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
	Under the Loan Guarantee Agreement, the Company is subject to customary borrower affirmative and negative covenants and events of default. In addition, the Company is subject to project-related reporting requirements and other project-specific covenants and events of default.
	In the event certain mandatory prepayment events occur, the FFB’s commitment to make further advances under the FFB Credit Facility will terminate and the Company will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. The Company also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
	In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume the Company’s rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of the Company’s ownership interest in Plant Vogtle Units 3 and 4.
	Capital Leases
	Assets acquired under capital leases are recorded in the balance sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 2013 and 2012, the Company had a capital lease asset for its corporate headquarters building of $61 million, with accumulated depreciation at December 31, 2013 and 2012 of $16 million and $11 million, respectively. At December 31, 2013 and 2012, the capitalized lease obligation was $45 million and $50 million, respectively, with an interest rate of 7.9% for both years. For ratemaking purposes, the Georgia PSC has allowed only the lease payments in cost of service. The difference between the accrued expense and the lease payments allowed for ratemaking purposes has been deferred and is being amortized to expense as ordered by the Georgia PSC. The annual expense incurred for all capital leases was not material for any year presented. See Note 7 under "Fuel and Purchased Power Agreements" for additional information on capital lease PPAs that become effective in 2015.
	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, 2013, committed credit arrangements with banks were as follows:
	Expires(a)
	2016		2018		Total		Unused
	(in millions)
	$150		$1,600		$1,750		$1,736
	(a)	No credit arrangements expire in 2014, 2015, or 2017.
	The Company expects to renew its credit arrangements, as needed, prior to expiration. All the credit arrangements require payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1/4 of 1% for the Company.
	The credit arrangements have covenants that limit the Company's debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes certain hybrid securities.
	A portion of the $1.7 billion of unused credit arrangements with banks is allocated to provide liquidity support to the Company's variable rate pollution control revenue bonds and its commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2013 was $862 million. In addition, at December 31, 2013, the Company had $242 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.
	The Company makes short-term borrowings primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangements. The Company may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable on the balance sheets.
	The Company had $1.0 billion of short-term debt outstanding at December 31, 2013. The Company had no short-term debt outstanding at December 31, 2012, excluding $2 million of notes payable related to other energy service contracts. Details of short-term borrowings outstanding at December 31, 2013 were as follows:
		Short-term Debt at the End of the Period
		Amount Outstanding				Weighted Average Interest Rate
		(in millions)
	December 31, 2013:
	Commercial paper	$	647			0.2	%
	Short-term bank debt	400				0.9	%
	Total	$	1,047			0.5	%
Gulf Power [Member]	'
Debt Disclosure [Line Items]	'
FINANCING	'
	FINANCING
	Securities Due Within One Year
	Approximately $75 million will be required through December 31, 2014 to fund maturities of long-term debt.
	Maturities from 2015 through 2018 applicable to total long-term debt are as follows: $110 million in 2016 and $85 million in 2017. There are no scheduled maturities in 2015 and 2018.
	Senior Notes
	At each of December 31, 2013 and 2012, the Company had a total of $945 million of senior notes outstanding. These senior notes are effectively subordinate to all secured debt of the Company, which totals approximately $41 million at December 31, 2013.
	In June 2013, the Company issued $90 million aggregate principal amount of Series 2013A 5.00% Senior Notes due June 15, 2043. The proceeds from the issuance of the Series 2013A Senior Notes, together with the proceeds from the sale of Preference Stock described below, were used to repay at maturity $60 million aggregate principal amount of the Company's Series G 4.35% Senior Notes due July 15, 2013, to repay a portion of a 90-day floating rate bank loan in an aggregate principal amount outstanding of $125 million, for a portion of the redemption in July 2013 of $30 million aggregate principal amount outstanding of the Company’s Series H 5.25% Senior Notes due July 15, 2033, and for general corporate purposes, including the Company’s continuous construction program.
	Pollution Control Revenue Bonds
	Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2013 and 2012 was $296 million and $309 million, respectively.
	The Company purchased and held $42 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Gulf Power Company Plant Scherer Project), First Series 2002 (First Series 2002 Bonds) and $21 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Gulf Power Company Plant Scherer Project), First Series 2010 (First Series 2010 Bonds) in May 2013 and June 2013, respectively. In June 2013, the Company reoffered the First Series 2002 Bonds and the First Series 2010 Bonds to the public.
	In December 2013, the Company purchased and now holds $13 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 2012 (Gulf Power Company Project).
	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, 2013. 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 February 2013, the Company issued 400,000 shares of common stock to Southern Company and realized proceeds of $40 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.
	In June 2013, the Company issued 500,000 shares of Series 2013A 5.60% Preference Stock and realized proceeds of $50 million. The proceeds from the sale of the Preference Stock, together with the proceeds from the issuance of Series 2013A Senior Notes, were used to repay at maturity $60 million aggregate principal amount of the Company's Series G 4.35% Senior Notes due July 15, 2013, to repay a portion of a 90-day floating rate bank loan in an aggregate principal amount outstanding of $125 million, for a portion of the redemption in July 2013 of $30 million aggregate principal amount outstanding of the Company’s Series H 5.25% Senior Notes due July 15, 2033, and for general corporate purposes, including the Company’s continuous construction program.
	Subsequent to December 31, 2013, the Company issued 500,000 shares of common stock to Southern Company and realized proceeds of $50 million. The proceeds were used to repay a portion of the Company's short-term debt and for other general corporate purposes, including the Company's continuous construction program.
	Dividend Restrictions
	The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
	Assets Subject to Lien
	The Company has granted a lien on its property at Plant Daniel in connection with the issuance of two series of pollution control revenue bonds with an outstanding principal amount of $41 million. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its subsidiaries.
	Bank Credit Arrangements
	At December 31, 2013, committed credit arrangements with banks were as follows:
	Expires(a)													Executable						Due Within One Year
														Term-Loans
	2014				2016			Total			Unused			One			Two			Term Out			No Term Out
														Year			Years
								(in millions)
	$	110			$	165		$	275		$	275		$	45		$	—		$	45		$	65
	(a)	No credit arrangements expire in 2015, 2017, or 2018.
	The Company expects to renew its credit arrangements, as needed, prior to expiration. Most of the $275 million of unused credit arrangements with banks provide liquidity support to the Company's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds requiring liquidity support as of December 31, 2013 was $69 million and $206 million was available for liquidity support for the Company's commercial paper program and for other general corporate purposes. Most of the credit arrangements require payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1/4 of 1% for the Company.
	Most of those credit arrangements with banks 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, 2013, the Company was in compliance with these covenants.
	For short-term cash needs, the Company borrows primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangements. 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 commercial paper included in notes payable on the balance sheets were as follows:
		Commercial Paper at the
		End of the Period (a)
		Amount Outstanding				Weighted Average Interest Rate
		(in millions)
	December 31, 2013:
		$	136			0.20%
	December 31, 2012:
		$	124			0.30%
	(a)	Excludes notes payable related to other energy service contracts of $3.2 million for the period ended December 31, 2012.
Mississippi Power [Member]	'
Debt Disclosure [Line Items]	'
FINANCING	'
	FINANCING
	Bank Term Loans
	In November 2012, the Company entered into a 366-day $100 million aggregate principal amount floating rate bank loan bearing interest based on one-month London Interbank Offered Rate (LIBOR). The first advance in the amount of $50 million was made in November 2012. In January 2013, the second advance in the amount of $50 million was made. In September 2013, the Company amended the bank loan, which extended the maturity date to 2015. The proceeds of this loan were used for working capital and for other general corporate purposes, including the Company's continuous construction program.
	In March 2013, the Company entered into four two-year floating rate bank loans bearing interest based on one-month LIBOR. These term loans were for an aggregate principal amount of $300 million and proceeds were used for working capital and other general corporate purposes, including the Company's continuous construction program.
	In September 2013, the Company entered into a two-year floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $125 million aggregate principal amount and proceeds were used to repay at maturity a two-year floating rate bank loan in the aggregate principal amount of $125 million.
	Subsequent to December 31, 2013, the Company entered into an 18-month floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $250 million aggregate principal amount and proceeds were used for working capital and other general corporate purposes, including the Company’s continuous construction program.
	At December 31, 2013 and 2012, the Company had $525 million, which is reflected in the statements of capitalization as long-term debt, and $175 million of bank loans outstanding, respectively.
	These bank loans and the other revenue bonds described below have 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, other hybrid securities, and securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2013, the Company was in compliance with its debt limits.
	Senior Notes
	In November 2013, the Company's $50 million aggregate principal amount of Series 2008A 6.0% Senior Notes due November 15, 2013 matured. At December 31, 2013 and 2012, the Company had $1.1 billion of senior notes outstanding. These senior notes are effectively subordinated to all 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 as described in Note 1 under "Purchase of the Plant Daniel Combined Cycle Generating Units" herein. These bonds are secured by Plant Daniel Units 3 and 4 and certain personal property. The bonds were recorded at fair value as of the date of assumption, or $346.1 million, reflecting a premium of $76.1 million.
	Securities Due Within One Year
	A summary of scheduled maturities and redemptions of securities due within one year at December 31, 2013 and 2012 was as follows:
		2013				2012
		(in millions)
	Senior notes	$	—			$	50
	Bank term loans	—				175
	Revenue bonds	11.3				51.5
	Capitalized leases	2.5				—
	Outstanding at December 31	$	13.8			$	276.5
	Maturities through 2018 applicable to total long-term debt are as follows: $13.8 million in 2014, $527.7 million in 2015, $302.8 million in 2016, $37.9 million in 2017, and $3.1 million in 2018.
	Pollution Control Revenue Bonds
	Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2013 and 2012 was $82.7 million.
	Other Revenue Bonds
	Other revenue bond obligations represent loans to the Company from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper IGCC and related facilities.
	In March 2013 and July 2013, the Mississippi Business Finance Corporation (MBFC) issued $15.8 million and $15.3 million, respectively, aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012A. The proceeds were used to reimburse the Company for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC.
	In September 2013, the MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2012A of $40.07 million, Series 2012B of $21.25 million, and Series 2012C of $21.25 million were paid at maturity.
	In November 2013, the MBFC entered into an agreement to issue up to $33.75 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013A (Mississippi Power Company Project) and up to $11.25 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013B (Mississippi Power Company Project) for the benefit of the company. In November 2013, the MBFC issued $11.25 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013B for the benefit of the Company. The proceeds were used to reimburse the Company for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of the Series 2013A bonds will be used for this same purpose.
	The Company had $50.0 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2013 and 2012, and $11.3 million and $51.5 million of such obligations related to taxable revenue bonds outstanding at December 31, 2013 and 2012, respectively. Such amounts are reflected in the statements of capitalization as long-term senior notes and debt.
	Capital Leases
	In September 2013, the Company entered into an agreement to sell the air separation unit for the Kemper IGCC and also entered into a 20-year nitrogen supply agreement. The nitrogen supply agreement was determined to be a sale/leaseback agreement which resulted in a capital lease obligation for the Company at inception of $82.9 million with an annual interest rate of 4.9%. There are no contingent rentals in the contract and a portion of the monthly payment specified in the agreement is related to executory costs for the operation and maintenance of the air separation unit and excluded from the minimum lease payments. The minimum lease payments for 2013 were $1.8 million and will be $6.5 million each year thereafter. As of December 31, 2013, no amortization expense had been incurred associated with the capital lease due to the Kemper IGCC not yet being in service.
	Other Obligations
	In March 2012 and subsequent to December 31, 2013, the Company received $150 million and $75 million, respectively, interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the sale is closed, the deposits bear interest at the Company's AFUDC rate adjusted for income taxes, which was 9.932% per annum for 2013 and 9.967% per annum for 2012, and are refundable to SMEPA upon termination of the asset purchase agreement related to such purchase, within 60 days of a request by SMEPA for a full or partial refund, or within 15 days at SMEPA's discretion in the event that the Company is assigned a senior unsecured credit rating of BBB+ or lower by S&P or Baa1 or lower by Moody's or ceases to be rated by either of these rating agencies.
	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 personal property. See Note 1 under "Purchase of the Plant Daniel Combined Cycle Generating Units" and "Plant Daniel Revenue Bonds" for additional information. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy the obligations of Southern Company or another of its other subsidiaries.
	Outstanding Classes of Capital Stock
	The Company currently has preferred stock (including depositary shares which represent one-fourth of a share of preferred stock) and common stock authorized and outstanding. The preferred stock of the Company contains a feature that allows the holders to elect a majority of the Company's board of directors if dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, this preferred stock is presented as "Cumulative Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The Company's preferred stock and depositary preferred stock, without preference between classes, rank senior to the Company's common stock with respect to payment of dividends and voluntary or involuntary dissolution. The preferred stock and depositary preferred stock is subject to redemption at the option of the Company at a redemption price equal to 100% of the liquidation amount of the stock.
	Dividend Restrictions
	The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
	Bank Credit Arrangements
	At December 31, 2013, committed credit arrangements with banks were as follows:
	Expires(a)							Executable			Due Within One Year
								Term-Loans
	2014		2016		Total		Unused	One		Two	Term Out		No Term Out
								Year		Years
	(in millions)
	$135		$165		$300		$300	$25		$40	$65		$70
	(a)	No credit arrangements expire in 2015, 2017, or 2018.
	The Company expects to renew its credit arrangements, as needed, prior to expiration.
	Most of these 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 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 securitized debt relating to the securitization of certain costs of the Kemper IGCC.
	A portion of the $300 million unused credit arrangements with banks is allocated to provide liquidity support to the Company's variable rate pollution control revenue bonds and its commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2013 was $40.1 million.
	The Company makes short-term borrowings primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangements.
	At December 31, 2013 and 2012, there was no short-term debt outstanding.
Southern Power [Member]	'
Debt Disclosure [Line Items]	'
FINANCING	'
	FINANCING
	Other Long-Term Notes
	During 2013, the Company prepaid $9.3 million on a long-term debt payable to TRE and issued an aggregate $4.2 million due September 30, 2032 and $19.4 million due April 30, 2033 under promissory notes to TRE related to the financing of Plants Spectrum and Campo Verde, respectively.
	Senior Notes
	During 2013, Southern Power Company issued $300 million aggregate principal amount of its Series 2013A 5.25% Senior Notes due July 15, 2043. The net proceeds from the sale of the Series 2013A Senior Notes were used to repay a portion of its outstanding short-term indebtedness and for other general corporate purposes, including the Company’s continuous construction program.
	In 2011, Southern Power Company redeemed $575 million aggregate principal amount of its Series B 6.25% Senior Notes due July 15, 2012. The loss recognized for the early redemption was $19.8 million primarily related to the payment of a make whole premium.
	At December 31, 2013 and 2012, Southern Power Company had $1.6 billion and $1.3 billion, respectively, of senior notes outstanding.
	Bank Credit Arrangements
	In February 2013, Southern Power Company amended its $500 million committed credit facility (Facility), which extended the maturity date from 2016 to 2018. There were no borrowings outstanding under the Facility at December 31, 2013 and 2012. The Facility does not contain a material adverse change clause at the time of borrowing. The Company plans to renew the Facility prior to its expiration.
	Southern Power Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than 1/4 of 1%. The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65%. At December 31, 2013, the Company was in compliance with its debt limits.
	Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program.
	The Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. Commercial paper is included in notes payable in the balance sheets.
	Details of short-term borrowings were as follows:
		Commercial Paper at the
		End of the Period
		Amount Outstanding				Weighted Average Interest Rate
		(in millions)
	December 31, 2013:	$	—			N/A
	December 31, 2012:	$	71			0.5	%
	Dividend Restrictions
	Southern Power Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
	The indenture related to certain series of Southern Power Company's senior notes also contains certain limitations on the payment of common stock dividends. No dividends may be paid unless, as of the end of any calendar quarter, the Company's projected cash flows from fixed priced capacity PPAs are at least 80% of total projected cash flows for the next 12 months or the Company's debt to capitalization ratio is no greater than 60%. At December 31, 2013, Southern Power Company was in compliance with these ratios and had no other restrictions on its ability to pay dividends.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2013
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 2013, 2012, and 2011, the traditional operating companies and Southern Power incurred fuel expense of $5.5 billion, $5.1 billion, and $6.3 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 $157 million, $171 million, and $199 million for 2013, 2012, and 2011, respectively.
	Estimated total obligations under these commitments at December 31, 2013 were as follows:
		Capital Leases (4)		Operating Leases		Other
				(in millions)
	2014	$	—	$	201	$	21
	2015	20		244		13
	2016	26		260		11
	2017	27		263		8
	2018	27		266		7
	2019 and thereafter	541		2,104		58
	Total	$	641	$	3,338	$	118
	Less: amounts representing executory costs (1)	142
	Net minimum lease payments	499
	Less: amounts representing interest (2)	166
	Present value of net minimum lease payments (3)	$	333
	-1	Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments.
	-2	Calculated Georgia Power's incremental borrowing rate at the inception of the leases.
	-3	When the PPAs with non-affiliates begin in 2015, Georgia Power will recognize capital lease assets and capital lease obligations totaling $333 million, equal to the lesser of the present value of the net minimum lease payments or the estimated fair value of the leased property.
	-4	A total of $1.3 billion of biomass PPAs included under the non-affiliate capital and operating leases is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.
	Operating Leases
	The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $123 million, $155 million, and $176 million for 2013, 2012, and 2011, 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, 2013, estimated minimum lease payments under operating leases were as follows:
		Minimum Lease Payments
		Barges & Railcars		Other		Total
		(in millions)
	2014	$	56	$	45	$	101
	2015	35		40		75
	2016	30		35		65
	2017	12		32		44
	2018	6		25		31
	2019 and thereafter	15		120		135
	Total	$	154	$	297	$	451
	For the traditional operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases have terms expiring through 2023 with maximum obligations under these leases of $59 million. At the termination of the leases, the lessee may either 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
	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 2013, 2012, and 2011, the Company incurred fuel expense of $1.6 billion, $1.5 billion, and $1.7 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 $30 million, $33 million, and $33 million for 2013, 2012, and 2011, respectively. Total estimated minimum long-term obligations at December 31, 2013 were as follows:
		Operating Lease PPAs
		(in millions)
	2014	$	36
	2015	38
	2016	39
	2017	40
	2018	42
	2019 and thereafter	182
	Total commitments	$	377
	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 Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
	Operating Leases
	The Company has entered into rental agreements for coal railcars, vehicles, and other equipment with various terms and expiration dates. Total rent expense was $21 million in 2013, $24 million in 2012, and $23 million in 2011. Of these amounts, $18 million, $19 million, and $18 million for 2013, 2012, and 2011, respectively, relate to the railcar leases and are recoverable through the Company's Rate ECR. As of December 31, 2013, estimated minimum lease payments under operating leases were as follows:
		Minimum Lease Payments
		Railcars		Vehicles & Other		Total
		(in millions)
	2014	$	12	$	3	$	15
	2015	10		2		12
	2016	11		1		12
	2017	6		—		6
	2018	4		—		4
	2019 and thereafter	15		—		15
	Total	$	58	$	6	$	64
	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 $8 million in 2014, $5 million in 2015, $4 million in 2016, and $12 million in 2019 and thereafter. There are no maximum obligations under these leases in 2017 and 2018. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations.
	Guarantees
	The Company has guaranteed the obligation of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019, and also $100 million of senior notes issued in November 2013, which mature in December 2018. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to Georgia Power's then proportionate ownership of SEGCO's stock if the Company is called upon to make such payment under its guarantee. See Note 4 for additional information.
Georgia Power [Member]	'
Commitments [Line Items]	'
COMMITMENTS	'
	COMMITMENTS
	Fuel and Purchased Power Agreements
	To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2013, 2012, and 2011, the Company incurred fuel expense of $2.3 billion, $2.1 billion, and $2.8 billion, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.
	The Company has commitments regarding a portion of a 5% interest in the original cost of Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit's variable operating costs. Portions of the capacity payments relate to costs in excess of MEAG Power's Plant Vogtle Unit 1 and 2 allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity and energy is included in purchased power, non-affiliates in the statements of income. Capacity payments totaled $27 million, $50 million, and $52 million in 2013, 2012, and 2011, 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 $162 million, $169 million, and $216 million for 2013, 2012, and 2011, respectively. Estimated total long-term obligations at December 31, 2013 were as follows:
		Affiliate Capital Leases		Non-Affiliate Capital Leases (4)		Affiliate Operating Leases		Non-Affiliate Operating Leases (4)		Vogtle Units 1 and 2 Capacity Payments		Total ($)
		(in millions)
	2014	$	—	$	—	$	55	$	112	$	21	$	188
	2015	22		20		89		127		13		271
	2016	22		26		99		142		11		300
	2017	23		27		71		144		8		273
	2018	23		27		62		145		7		264
	2019 and thereafter	278		541		669		1,573		58		3,119
	Total	$	368	$	641	$	1,045	$	2,243	$	118	$	4,415
	Less: amounts representing executory costs(1)	55		142
	Net minimum lease payments	313		499
	Less: amounts representing interest(2)	85		166
	Present value of net minimum lease payments(3)	$	228	$	333
	-1	Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments.
	-2	Calculated at the Company's incremental borrowing rate at the inception of the leases.
	-3	When the PPAs begin in 2015, the Company will recognize capital lease assets and capital lease obligations totaling $482 million, equal to the lesser of the present value of the net minimum lease payments or the estimated fair value of the leased property.
	-4	A total of $1.3 billion of biomass PPAs included under the non-affiliate capital and operating leases is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.
	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 Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
	Operating Leases
	In addition to the PPA operating leases discussed above, the Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $32 million for 2013, $34 million for 2012, and $33 million for 2011. The Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments.
	As of December 31, 2013, estimated minimum lease payments under operating leases were as follows:
		Minimum Lease Payments
		Railcars		Other		Total
		(in millions)
	2014	$	20	$	6	$	26
	2015	14		6		20
	2016	8		5		13
	2017	5		4		9
	2018	2		4		6
	2019 and thereafter	—		11		11
	Total	$	49	$	36	$	85
	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 2018 with maximum obligations under these leases of $30 million. 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
	Alabama Power has guaranteed the obligations of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019 and also $100 million of senior notes issued in November 2013, which mature in December 2018. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company's then proportionate ownership of SEGCO's stock if Alabama Power is called upon to make such payment under its guarantee. See Note 4 for additional information.
	In addition, subsequent to December 31, 2013, the Company entered into an agreement that requires the Company to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2017. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million.
	As discussed earlier in this Note under "Operating Leases," the Company has entered into certain residual value guarantees related to railcar leases.
Gulf Power [Member]	'
Commitments [Line Items]	'
COMMITMENTS	'
	COMMITMENTS
	Fuel and Purchased Power Agreements
	To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil fuel which are not recognized on the balance sheets. In 2013, 2012, and 2011, the Company incurred fuel expense of $532.8 million, $544.9 million, and $662.3 million, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.
	In addition, the Company has entered into various long-term commitments for the purchase of capacity, energy, and transmission, some of which are accounted for as operating leases. The energy-related costs associated with PPAs are recovered through the fuel cost recovery clause. The capacity and transmission-related costs associated with PPAs are recovered through the purchased power capacity cost recovery clause. Capacity expense under purchased power agreements accounted for as operating leases was $21.3 million, $24.6 million, and $25.1 million for 2013, 2012, and 2011, respectively.
	Estimated total minimum long-term commitments at December 31, 2013 were as follows:
		Operating Lease PPAs
		(in millions)
	2014	$	52.9
	2015		78.6
	2016		78.7
	2017		78.8
	2018		78.9
	2019 and thereafter		349.2
	Total	$	717.1
	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 Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
	Operating Leases
	The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $18.0 million, $20.1 million, and $21.9 million for 2013, 2012, and 2011, respectively.
	Estimated total minimum lease payments under operating leases at December 31, 2013 were as follows:
		Minimum Lease Payments
		Barges &		Other		Total
		Railcars
		(in millions)
	2014	$	13.3	$	0.2	$	13.5
	2015	9.9		0.1		10
	2016	9.9		0.1		10
	2017	0.5		0.1		0.6
	Total	$	33.6	$	0.5	$	34.1
	The Company and Mississippi Power jointly entered into operating lease agreements for aluminum railcars for the transportation of coal to Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of each lease term. In early 2011, one operating lease expired and the Company elected not to exercise the option to purchase. The remaining operating lease has 229 aluminum railcars. The Company and Mississippi Power also have separate lease agreements for other railcars that do not include purchase options. The Company's share of the lease costs, charged to fuel inventory and recovered through the fuel cost recovery clause, was $3.1 million in 2013, $3.6 million in 2012, and $2.6 million in 2011. The Company's annual railcar lease payments for 2014 through 2017 will average approximately $1.4 million. The Company has no lease payment obligations for the period 2018 and thereafter.
Mississippi Power [Member]	'
Commitments [Line Items]	'
COMMITMENTS	'
	COMMITMENTS
	Fuel and Purchased Power Agreements
	To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil fuel which are not recognized on the balance sheets. In 2013, 2012, and 2011, the Company incurred fuel expense of $491.3 million, $411.2 million, and $490.4 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 due at December 31, 2013 of $38.7 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 Southern Company traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
	Operating Leases
	The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $10.1 million, $11.1 million, and $32.6 million for 2013, 2012, and 2011 respectively, which includes the Plant Daniel Units 3 and 4 operating lease that ended October 20, 2011.
	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. In early 2011, one operating lease expired and the Company elected not to exercise the option to purchase. The remaining operating lease has 229 aluminum railcars. The Company and Gulf Power also have separate lease agreements for other railcars that do not contain a purchase option.
	The Company's share (50%) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $3.1 million in 2013, $3.6 million in 2012, and $2.6 million in 2011. The Company's annual railcar lease payments for 2014 through 2017 will average approximately $1.4 million. The Company has no lease obligation for the period 2018 and thereafter.
	In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson and operating leases for barges and tow/shift boats for the transport of coal at Plant Watson. The Company's share (50% at Plant Daniel and 100% at Plant Watson) of the leases for fuel handling was charged to fuel handling expense in the amount of $0.2 million in 2013, $0.2 million in 2012, and $0.4 million in 2011. The Company's annual lease payment for 2014 is expected to be $0.2 million for fuel handling equipment. The Company charged to fuel stock and recovered through fuel cost recovery the barge transportation leases in the amount of $6.7 million in 2013, $7.3 million in 2012, and $7.5 million in 2011 related to barges and tow/shift boats. The Company's annual lease payment for 2014 with respect to these barge transportation leases is expected to be $7.6 million.
Southern Power [Member]	'
Commitments [Line Items]	'
COMMITMENTS	'
	COMMITMENTS
	Fuel Agreements
	SCS, as agent for the Company and the traditional operating companies, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities which are not recognized on the Company's balance sheets. In 2013, 2012, and 2011, the Company incurred fuel expense of $473.8 million, $426.3 million, and $454.8 million, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.
	SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and Southern Company's traditional operating companies. Under these agreements, each of the traditional operating companies and the Company may be jointly and severally liable. Southern Company has entered into keep-well agreements with each of the traditional operating companies to ensure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of the Company as a contracting party under these agreements.
	Operating Leases
	The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $1.9 million, $0.8 million, and $0.6 million for 2013, 2012, and 2011, respectively. These amounts include contingent rent expense related to the Plant Stanton Unit A land lease based on escalation in the Consumer Price Index for All Urban Consumers. The Company includes step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. As of December 31, 2013, estimated minimum lease payments under operating leases were $2.7 million in 2014, $2.5 million in 2015, $2.5 million in 2016, $2.5 million in 2017, $2.6 million in 2018, and $83.9 million in 2019 and thereafter. The majority of the committed future expenditures are land leases at solar facilities.
	Redeemable Noncontrolling Interest
	Pursuant to an agreement with TRE, on or after November 25, 2015, or earlier in the event of the death of the controlling member of TRE, TRE may require the Company to purchase its noncontrolling interest in STR at fair market value.

Common_Stock_and_Stock_Compens

Common Stock and Stock Compensation	12 Months Ended
	Dec. 31, 2013
COMMON STOCK	'
	COMMON STOCK
	Stock Issued
	During 2013, Southern Company issued approximately 6.9 million shares of common stock for $222.4 million through the employee and director stock plans, of which 0.7 million shares related to Southern Company's performance share plan.
	During the first seven months of 2013, all sales under the Southern Investment Plan and the employee savings plan were funded with shares acquired on the open market by the independent plan administrators. Beginning in August 2013 and continuing through the fourth quarter 2013, Southern Company began using shares held in treasury to satisfy the requirements under the Southern Investment Plan and the employee savings plan, issuing a total of approximately 4.4 million shares of common stock previously held in treasury for approximately $183.6 million.
	In addition, during the last six months of 2013, 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 $327.3 million, net of $2.8 million in fees and commissions.
	In 2012, Southern Company raised $397 million from the issuance of 12.1 million new common shares through the employee and director stock plans.
	Stock Repurchased
	In July 2012, Southern Company announced a program to repurchase shares to partially offset the incremental shares issued under its employee and director stock plans. There were no repurchases under this program in 2013 and no further repurchases under the program are anticipated.
	Shares Reserved
	At December 31, 2013, a total of 116 million shares were reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (which includes stock options and performance shares units as discussed below). Of the total 116 million shares reserved, there were 28 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 2013.
	Stock Options
	Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. As of December 31, 2013, there were 5,776 current and former employees participating in the stock option program. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control.
	The estimated fair values of stock options granted were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company's stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options.
	The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted:
	Year Ended December 31	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
	Southern Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject to Option			Weighted Average Exercise Price
	Outstanding at December 31, 2012	35,916,303			$	36.37
	Granted	9,152,716			44.17
	Exercised	(6,078,735	)		33.39
	Cancelled	(170,918	)		43.3
	Outstanding at December 31, 2013	38,819,366			$	38.64
	Exercisable at December 31, 2013	24,150,442			$	35.7
	The number of stock options vested, and expected to vest in the future, as of December 31, 2013 was not significantly different from the number of stock options outstanding at December 31, 2013 as stated above. As of December 31, 2013, 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 $147 million and $142 million, respectively.
	As of December 31, 2013, there was $9 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 11 months.
	For the years ended December 31, 2013, 2012, and 2011, total compensation cost for stock option awards recognized in income was $25 million, $23 million, and $22 million, respectively, with the related tax benefit also recognized in income of $10 million, $9 million, and $8 million, respectively.
	The total intrinsic value of options exercised during the years ended December 31, 2013, 2012, and 2011 was $77 million, $162 million, and $155 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $30 million, $62 million, and $60 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2013, 2012, and 2011 was $204 million, $397 million, and $528 million, respectively.
	Performance Shares
	Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount.
	The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period. Southern Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. The expected volatility was based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units.
	The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:
	Year Ended December 31	2013		2012		2011
	Expected volatility	12.00%		16.00%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97
	Total unvested performance share units outstanding as of December 31, 2012 were 1,633,156. During 2013, 929,653 performance share units were granted, 807,702 performance share units were vested, and 111,348 performance share units were forfeited, resulting in 1,643,759 unvested units outstanding at December 31, 2013. In January 2014, the vested performance share award units were converted into 240,980 shares outstanding at a share price of $41.27 for the three-year performance and vesting period ended December 31, 2013.
	For the years ended December 31, 2013, 2012, and 2011, total compensation cost for performance share units recognized in income was $31 million, $28 million, and $18 million, respectively, with the related tax benefit also recognized in income of $12 million, $11 million, and $7 million, respectively. As of December 31, 2013, there was $35 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 11 months.
	Diluted Earnings Per Share
	For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
		Average Common Stock Shares
		2013			2012		2011
		(in millions)
	As reported shares	877			871		857
	Effect of options and performance share award units	4			8		7
	Diluted shares	881			879		864
	Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were $16 million and were immaterial as of December 31, 2013 and 2012, respectively.
	Common Stock Dividend Restrictions
	The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2013, consolidated retained earnings included $6.1 billion of undistributed retained earnings of the subsidiaries.
Alabama Power [Member]	'
STOCK COMPENSATION	'
	STOCK COMPENSATION
	Stock Options
	Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2013, there were approximately 1,000 current and former employees of the Company participating in the stock option program, and there were 28 million shares of Southern Company common stock remaining available for awards under the Omnibus Incentive Compensation Plan. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control.
	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	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
	The Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject to Option			Weighted Average Exercise Price
	Outstanding at December 31, 2012	6,060,552			$	36.02
	Granted	1,319,038			44.07
	Exercised	(1,035,611	)		32.74
	Cancelled	(4,271	)		42.88
	Outstanding at December 31, 2013	6,339,708			$	38.23
	Exercisable at December 31, 2013	4,021,541			$	35.29
	The number of stock options vested, and expected to vest in the future, as of December 31, 2013 was not significantly different from the number of stock options outstanding at December 31, 2013 as stated above. As of December 31, 2013, 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 $26 million and $25 million, respectively.
	As of December 31, 2013, there was $1 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 11 months.
	For the years ended December 31, 2013, 2012, and 2011, total compensation cost for stock option awards recognized in income was $4 million, $4 million, and $3 million, respectively, with the related tax benefit also recognized in income of $2 million, $1 million, and $1 million, respectively.
	The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options 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.
	The total intrinsic value of options exercised during the years ended December 31, 2013, 2012, and 2011 was $11 million, $28 million, and $23 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $4 million, $11 million, and $9 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	Performance Shares
	Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount.
	The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. The expected volatility was based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units.
	The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:
	Year Ended December 31	2013		2012		2011
	Expected volatility	12.00%		16%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97
	Total unvested performance share units outstanding as of December 31, 2012 were 280,536. During 2013, 141,355 performance share units were granted, 131,581 performance share units were vested, and 5,484 performance share units were forfeited resulting in 284,826 unvested units outstanding at December 31, 2013. In January 2014, the vested performance share award units were converted into 39,258 shares outstanding at a share price of $41.27 for the three-year performance and vesting period ended December 31, 2013.
	For the years ended December 31, 2013, 2012, and 2011, total compensation cost for performance share units recognized in income was $5 million, $5 million, and $3 million, respectively, with the related tax benefit also recognized in income of $2 million, $2 million, and $1 million, respectively. As of December 31, 2013, there was $6 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 11 months.
Georgia Power [Member]	'
STOCK COMPENSATION	'
	STOCK COMPENSATION
	Stock Options
	Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2013, there were 1,265 current and former employees of the Company participating in the stock option program, and there were 28 million shares of Southern Company common stock remaining available for awards under the Omnibus Incentive Compensation Plan. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control.
	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	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
	The Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject to Option			Weighted Average Exercise Price
	Outstanding at December 31, 2012	6,547,498			$	36.18
	Granted	1,509,662			44.09
	Exercised	(1,196,585	)		33.38
	Cancelled	(11,421	)		40.99
	Outstanding at December 31, 2013	6,849,154			$	38.41
	Exercisable at December 31, 2013	4,321,853			$	35.51
	The number of stock options vested, and expected to vest in the future, as of December 31, 2013 was not significantly different from the number of stock options outstanding at December 31, 2013 as stated above. As of December 31, 2013, 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 $27 million and $26 million, respectively.
	As of December 31, 2013, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial.
	The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options 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. The amounts were not material for any year presented.
	The total intrinsic value of options exercised during the years ended December 31, 2013, 2012, and 2011 was $16 million, $34 million, and $32 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $6 million, $13 million, and $12 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	Performance Shares
	Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount.
	The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. The expected volatility was based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units.
	The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:
	Year Ended December 31	2013		2012		2011
	Expected volatility	12.00%		16.00%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97
	Total unvested performance share units outstanding as of December 31, 2012 were 280,000. During 2013, 161,240 performance share units were granted, 151,769 performance shares were vested, and 16,371 performance share units were forfeited, resulting in 273,100 unvested units outstanding at December 31, 2013. In January 2014, the vested performance share award units were converted into 45,239 shares outstanding at a share price of $41.27 for the three-year performance and vesting period ended December 31, 2013.
	For the years ended December 31, 2013, 2012, and 2011, total compensation cost for performance share units recognized in income was $6 million, $6 million, and $4 million, respectively, with the related tax benefit also recognized in income of $2 million, $2 million and $1 million, respectively. As of December 31, 2013, there was $6 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 11 months.
Gulf Power [Member]	'
STOCK COMPENSATION	'
	STOCK COMPENSATION
	Stock Options
	Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2013, there were 211 current and former employees of the Company participating in the stock option program, and there were 28 million shares of Southern Company common stock remaining available for awards under the Omnibus Incentive Compensation Plan. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control.
	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	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
	The Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject			Weighted Average
		to Option			Exercise Price
	Outstanding at December 31, 2012	1,388,915			$	36.08
	Granted	285,209			44.06
	Exercised	(281,377	)		33.62
	Cancelled	—			—
	Outstanding at December 31, 2013	1,392,747			$	38.21
	Exercisable at December 31, 2013	883,985			$	35.29
	The number of stock options vested, and expected to vest in the future, as of December 31, 2013, was not significantly different from the number of stock options outstanding at December 31, 2013 as stated above. As of December 31, 2013, 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 $5.7 million and $5.5 million, respectively.
	As of December 31, 2013, there was $0.4 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted average period of approximately 11 months.
	For each of the years ended December 31, 2013, 2012, and 2011, total compensation cost for stock option awards recognized in income was $0.7 million, with the related tax benefit also recognized in income of $0.3 million.
	The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options 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.
	The total intrinsic value of options exercised during the years ended December 31, 2013, 2012, and 2011 was $1.7 million, $3.8 million, and $3.2 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $0.6 million, $1.5 million, and $1.2 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	Performance Shares
	Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount.
	The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. The expected volatility was based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units.
	The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:
	Year Ended December 31	2013		2012		2011
	Expected volatility	12.00%		16.00%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97
	Total unvested performance share units outstanding as of December 31, 2012 were 68,805. During 2013, 30,627 performance share units were granted, 25,102 performance share units were vested, and 1,740 performance share units were forfeited resulting in 72,590 unvested units outstanding at December 31, 2013. In January 2014, the vested performance share award units were converted into 7,476 shares outstanding at a share price of $41.27 for the three-year performance and vesting period ended December 31, 2013.
	For the years ended December 31, 2013, 2012, and 2011, total compensation cost for performance share units recognized in income was $1.0 million, $1.0 million, and $0.7 million, respectively, with the related tax benefit also recognized in income of $0.4 million, $0.4 million, and $0.3 million, respectively. As of December 31, 2013, there was $1.2 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted average period of approximately 11 months.
Mississippi Power [Member]	'
STOCK COMPENSATION	'
	STOCK COMPENSATION
	Stock Options
	Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2013, there were 236 current and former employees of the Company participating in the stock option program and there were 28 million shares of Southern Company common stock remaining available for awards under the Omnibus Incentive Compensation Plan. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control.
	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	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
	The Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject to Option			Weighted Average Exercise Price
	Outstanding at December 31, 2012	1,373,566			$	36.34
	Granted	345,830			44.03
	Exercised	(379,933	)		33.59
	Cancelled	(5,870	)		44.94
	Outstanding at December 31, 2013	1,333,593			$	39.08
	Exercisable at December 31, 2013	898,518			$	37.02
	The number of stock options vested, and expected to vest in the future, as of December 31, 2013 was not significantly different from the number of stock options outstanding at December 31, 2013 as stated above. As of December 31, 2013, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and four years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $4.6 million and $4.4 million, respectively.
	As of December 31, 2013, there was $0.3 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 10 months.
	For the years ended December 31, 2013, 2012, and 2011, total compensation cost for stock option awards recognized in income was $1.0 million, $0.9 million, and $0.8 million, respectively, with the related tax benefit also recognized in income of $0.4 million, $0.3 million, and $0.3 million, respectively.
	The compensation cost and tax benefits related to the grant and exercise of Southern Company stock options 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.
	The total intrinsic value of options exercised during the years ended December 31, 2013, 2012, and 2011 was $2.7 million, $4.9 million, and $4.2 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $1.1 million, $1.9 million, and $1.6 million for the years ended December 31, 2013, 2012, and 2011, respectively.
	Performance Shares
	Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount.
	The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. The expected volatility was based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units.
	The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:
	Year Ended December 31	2013		2012		2011
	Expected volatility	12.00%		16.00%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97
	Total unvested performance share units outstanding as of December 31, 2012 were 68,486. During 2013, 36,769 performance share units were granted, 48,019 performance share units were vested, and 15,699 performance share units were forfeited resulting in 41,537 unvested units outstanding at December 31, 2013. In January 2014, the vested performance share award units were converted into 14,341 shares outstanding at a share price of $41.27 for the three-year performance and vesting period ended December 31, 2013.
	For the years ended December 31, 2013, 2012, and 2011, total compensation cost for performance share units recognized in income was $1.5 million, $1.2 million, and $0.7 million, respectively, with the related tax benefit also recognized in income of $0.6 million, $0.4 million, and $0.3 million, respectively. As of December 31, 2013, there was $1.7 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 11 months.

Nuclear_Insurance

Nuclear Insurance	12 Months Ended
	Dec. 31, 2013
NUCLEAR INSURANCE	'
	NUCLEAR INSURANCE
	Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $13.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $255 million and $252 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 to the financial statements herein for additional information on joint ownership agreements.
	Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million 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 $2.25 billion for nuclear losses in excess of the $500 million primary coverage. These policies have a sublimit of $1.7 billion for non-nuclear losses.
	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 replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period.
	A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion for accidental property damage occurring during construction.
	Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $43 million and $65 million, respectively.
	Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
	For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's financial condition and results of operations.
	All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
Alabama Power [Member]	'
NUCLEAR INSURANCE	'
	NUCLEAR INSURANCE
	Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $13.6 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $255 million per incident but not more than an aggregate of $38 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018.
	The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $500 million 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 $2.25 billion for nuclear losses in excess of the $500 million primary coverage. These policies have a sublimit of $1.7 billion for non-nuclear losses.
	NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases limits based on the projected full cost of replacement power and has elected a 12-week deductible waiting period.
	Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for the Company under the NEIL policies would be $43 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	'
	NUCLEAR INSURANCE
	Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Hatch and Plant Vogtle Units 1 and 2. The Act provides funds up to $13.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company, based on its ownership and buyback interests in all licensed reactors, is $252 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 to the financial statements herein 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 $500 million 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 $2.25 billion for nuclear losses in excess of the $500 million primary coverage. These policies have a sublimit of $1.7 billion for non-nuclear losses.
	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 replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period.
	A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion for accidental property damage occurring during construction.
	Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for the Company under the NEIL policies would be $65 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, 2013
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, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	24		$	—	$	24
	Interest rate derivatives	—			3			—		3
	Nuclear decommissioning trusts:(a)
	Domestic equity	589			75			—		664
	Foreign equity	35			196			—		231
	U.S. Treasury and government agency securities	—			103			—		103
	Municipal bonds	—			64			—		64
	Corporate bonds	—			229			—		229
	Mortgage and asset backed securities	—			132			—		132
	Other investments	—			37			3		40
	Cash equivalents	491			—			—		491
	Other investments	9			—			4		13
	Total	$	1,124		$	863		$	7	$	1,994
	Liabilities:
	Energy-related derivatives	$	—		$	56		$	—	$	56
	(a)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	26		$	—	$	26
	Interest rate derivatives	—			10			—		10
	Nuclear decommissioning trusts:(a)
	Domestic equity	453			65			—		518
	Foreign equity	28			172			—		200
	U.S. Treasury and government agency securities	—			134			—		134
	Municipal bonds	—			55			—		55
	Corporate bonds	—			234			—		234
	Mortgage and asset backed securities	—			141			—		141
	Other investments	—			20			—		20
	Cash equivalents	384			—			—		384
	Other investments	9			—			15		24
	Total	$	874		$	857		$	15	$	1,746
	Liabilities:
	Energy-related derivatives	$	—		$	111		$	—	$	111
	(a)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.
	Valuation Methodologies
	The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and Overnight Index Swap interest rates. Interest rate derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. See Note 11 for additional information on how these derivatives are used.
	For fair value measurements of investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts with each security discriminately assigned a primary pricing source, based on similar characteristics.
	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, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts' judgment are also obtained when available.
	"Other investments" include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.
	As of December 31, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair			Unfunded		Redemption	Redemption
		Value			Commitments		Frequency	Notice Period
	As of December 31, 2013:	(in millions)
	Nuclear decommissioning trusts:
	Foreign equity funds	$	131		None		Monthly	5 days
	Corporate bonds – commingled funds	8			None		Daily	Not applicable
	Equity – commingled funds	65			None		Daily/Monthly	Daily/7 days
Other – commingled funds	24			None		Daily	Not applicable
Trust-owned life insurance	110			None		Daily	15 days
Cash equivalents:
Money market funds	491			None		Daily	Not applicable
As of December 31, 2012:
Nuclear decommissioning trusts:
Foreign equity funds	$	117		None		Monthly	5 days
Corporate bonds – commingled funds	9			None		Daily	Not applicable
Equity – commingled funds	55			None		Daily/Monthly	Daily/7 days
Other – commingled funds	10			None		Daily	Not applicable
Trust-owned life insurance	96			None		Daily	15 days
Cash equivalents:
Money market funds	384			None		Daily	Not applicable
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have the Funds to comply with the NRC's regulations. The foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities and depositary receipts, including American depositary receipts, European depositary receipts and global depositary receipts, and rights and warrants to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.
The commingled funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, generally maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations with maturity shortening provisions. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The commingled funds included within corporate bonds represent the investment of cash collateral received under the Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. See Note 1 under "Nuclear Decommissioning" for additional information.
Alabama Power's nuclear decommissioning trust includes investments in TOLI. The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the Securities and Exchange Commission and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds.
As of December 31, 2013 and 2012, 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:
2013	$	21,650		$	22,197
2012	$	21,530		$	23,480
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.
Alabama Power [Member]	'
Fair Value Disclosures [Line Items]	'
FAIR VALUE MEASUREMENTS	'
	FAIR VALUE MEASUREMENTS
	Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
	•	Level 1 consists of observable market data in an active market for identical assets or liabilities.
	•	Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
	•	Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
	In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	7		$	—	$	7
	Nuclear decommissioning trusts:(a)
	Domestic equity	392			74			—		466
	Foreign equity	35			65			—		100
	U.S. Treasury and government agency securities	—			24			—		24
	Corporate bonds	—			89			—		89
	Mortgage and asset backed securities	—			18			—		18
	Other investments	—			13			3		16
	Cash equivalents	236			—			—		236
	Total	$	663		$	290		$	3	$	956
	Liabilities:
	Energy-related derivatives	$	—		$	8		$	—	$	8
	(a)	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information.
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	5		$	—	$	5
	Nuclear decommissioning trusts:(a)
	Domestic equity	291			64			—		355
	Foreign equity	28			55			—		83
	U.S. Treasury and government agency securities	—			29			—		29
	Corporate bonds	—			101			—		101
	Mortgage and asset backed securities	—			26			—		26
	Other investments	—			10			—		10
	Total	$	319		$	290		$	—	$	609
	Liabilities:
	Energy-related derivatives	$	—		$	18		$	—	$	18
	(a)	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.
	Valuation Methodologies
	The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and Overnight Index Swap interest rates. Interest rate derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. See Note 11 for additional information on how these derivatives are used.
	For fair value measurements of investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts with each security discriminately assigned a primary pricing source, based on similar characteristics. Other investments in private equity and real estate are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
	A market price secured from the primary source vendor is evaluated by management in its valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts' judgment are also obtained when available.
	As of December 31, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value		Unfunded	Redemption Frequency		Redemption
				Commitments			Notice Period
	As of December 31, 2013:	(in millions)
	Nuclear decommissioning trusts:
	Equity-commingled funds	$65		None	Daily/Monthly		Daily/7 Days
	Trust-owned life insurance	110		None	Daily		15 days
	Cash equivalents:
	Money market funds	236		None	Daily		Not applicable
	As of December 31, 2012:
	Nuclear decommissioning trusts:
	Equity-commingled funds	$55		None	Daily/Monthly		Daily/7 days
	Trust-owned life insurance	96		None	Daily		15 days
	The nuclear decommissioning trust includes investments in TOLI. The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trust does not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. The commingled funds primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and, to some degree, mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection.
	The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis, up to the full amount of the Company's investment in the money market funds.
	As of December 31, 2013 and 2012, 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:
2013	$	6,228		$	6,534
2012	$	6,179		$	6,899
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company.
Georgia Power [Member]	'
Fair Value Disclosures [Line Items]	'
FAIR VALUE MEASUREMENTS	'
	FAIR VALUE MEASUREMENTS
	Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
	•	Level 1 consists of observable market data in an active market for identical assets or liabilities.
	•	Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
	•	Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
	In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	5		$	—	$	5
	Nuclear decommissioning trusts:(a)
	Domestic equity	197			1			—		198
	Foreign equity	—			131			—		131
	U.S. Treasury and government agency securities	—			79			—		79
	Municipal bonds	—			64			—		64
	Corporate bonds	—			140			—		140
	Mortgage and asset backed securities	—			114			—		114
	Other investments	—			24			—		24
	Total	$	197		$	558		$	—	$	755
	Liabilities:
	Energy-related derivatives	$	—		$	21		$	—	$	21
	(a)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	11		$	—	$	11
	Nuclear decommissioning trusts:(a)
	Domestic equity	162			1			—		163
	Foreign equity	—			117			—		117
	U.S. Treasury and government agency securities	—			105			—		105
	Municipal bonds	—			55			—		55
	Corporate bonds	—			133			—		133
	Mortgage and asset backed securities	—			115			—		115
	Other investments	—			10			—		10
	Cash equivalents	15			—			—		15
	Total	$	177		$	547		$	—	$	724
	Liabilities:
	Energy-related derivatives	$	—		$	45		$	—	$	45
	(a)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.
	Valuation Methodologies
	The energy-related derivatives primarily consist of over-the-counter financial products for natural gas, 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. See Note 11 for additional information on how these derivatives are used.
	For fair value measurements of investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts with each security discriminately assigned a primary pricing source, based on similar characteristics.
	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, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts' judgment are also obtained when available.
	As of December 31, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value			Unfunded		Redemption	Redemption
					Commitments		Frequency	Notice Period
	As of December 31, 2013:	(in millions)
	Nuclear decommissioning trusts:
	Foreign equity fund	$	131		None		Daily	5 days
	Corporate bonds — commingled funds	8			None		Daily	Not applicable
	Other — commingled funds	24			None		Daily	Not applicable
	As of December 31, 2012:
	Nuclear decommissioning trusts:
	Foreign equity fund	$	117		None		Daily	5 days
	Corporate bonds — commingled funds	9			None		Daily	Not applicable
	Other — commingled funds	10			None		Daily	Not applicable
	Cash equivalents:
Money market funds	15			None		Daily	Not applicable
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The foreign equity fund in the nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities and depositary receipts, including American depositary receipts, European depositary receipts and global depositary receipts, and rights and warrants to buy common stocks. The Company may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.
The commingled funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, generally maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations with maturity shortening provisions. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. The commingled funds included within corporate bonds represent the investment of cash collateral received under the Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. See Note 1 under "Nuclear Decommissioning" for additional information.
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds.
As of December 31, 2013 and 2012, 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:
2013	$	8,593		$	8,782
2012	$	9,624		$	10,427
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on current rates offered to the Company.
Gulf Power [Member]	'
Fair Value Disclosures [Line Items]	'
FAIR VALUE MEASUREMENTS	'
	FAIR VALUE MEASUREMENTS
	Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
	•	Level 1 consists of observable market data in an active market for identical assets or liabilities.
	•	Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
	•	Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
	In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in thousands)
	Assets:
	Energy-related derivatives	$	—		$	6,962		$	—	$	6,962
	Cash equivalents	15,929			—			—		15,929
	Total	$	15,929		$	6,962		$	—	$	22,891
	Liabilities:
	Energy-related derivatives	$	—		$	17,043		$	—	$	17,043
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant			Significant
					Other			Unobservable
					Observable			Inputs
					Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in thousands)
	Assets:
	Energy-related derivatives	$	—		$	4,358		$	—	$	4,358
	Cash equivalents	15,231			—			—		15,231
	Total	$	15,231		$	4,358		$	—	$	19,589
	Liabilities:
	Energy-related derivatives	$	—		$	27,112		$	—	$	27,112
	Valuation Methodologies
	The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and Overnight Index Swap interest rates. See Note 10 for additional information on how these derivatives are used.
	As of December 31, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value		Unfunded	Redemption		Redemption
				Commitments	Frequency		Notice Period
	As of December 31, 2013:	(in thousands)
	Cash equivalents:
	Money market funds	$15,929		None	Daily		Not applicable
	As of December 31, 2012:
	Cash equivalents:
	Money market funds	$15,231		None	Daily		Not applicable
	The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds.
	As of December 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:
		Carrying Amount			Fair Value
		(in thousands)
	Long-term debt:
	2013	$	1,233,163		$	1,261,889
	2012	$	1,245,870		$	1,367,404
	The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company.
Mississippi Power [Member]	'
Fair Value Disclosures [Line Items]	'
FAIR VALUE MEASUREMENTS	'
	FAIR VALUE MEASUREMENTS
	Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
	•	Level 1 consists of observable market data in an active market for identical assets or liabilities.
	•	Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
	•	Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
	In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in thousands)
	Assets:
	Energy-related derivatives	$	—		$	4,803		$	—	$	4,803
	Cash equivalents	125,000			—			—		125,000
	Total	$	125,000		$	4,803		$	—	$	129,803
	Liabilities:
	Energy-related derivatives	$	—		$	10,281		$	—	$	10,281
	Foreign currency derivatives	—			1			—		1
	Total	$	—		$	10,282		$	—	$	10,282
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in thousands)
	Assets:
	Energy-related derivatives	$	—		$	2,519		$	—	$	2,519
	Cash equivalents	125,600			—			—		125,600
	Total	$	125,600		$	2,519		$	—	$	128,119
	Liabilities:
	Energy-related derivatives	$	—		$	19,446		$	—	$	19,446
	Foreign currency derivatives	—			37			—		37
	Total	$	—		$	19,483		$	—	$	19,483
	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 and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. 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, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value			Unfunded		Redemption	Redemption
					Commitments		Frequency	Notice Period
	As of December 31, 2013:	(in thousands)
	Cash equivalents:
	Money market funds	$	125,000		None		Daily	Not applicable
	As of December 31, 2012:
	Cash equivalents:
	Money market funds	$	125,600		None		Daily	Not applicable
	The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds.
	As of December 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:
		Carrying Amount			Fair Value
		(in thousands)
	Long-term debt:
	2013	$	2,098,639		$	2,045,519
	2012	$	1,840,933		$	1,956,799
	The fair values are determined using primarily 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. The need to use unobservable inputs would typically apply to long-term energy-related derivative contracts and generally results from the nature of the energy industry, as each participant forecasts its own power supply and demand and those of other participants, which directly impact the valuation of each unique contract.
	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, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	0.6		$	—	$	0.6
	Cash equivalents	68			—			—		68
	Total	$	68		$	0.6		$	—	$	68.6
	Liabilities:
	Energy-related derivatives	$	—		$	0.6		$	—	$	0.6
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	2.1		$	—	$	2.1
	Cash equivalents	26			—			—		26
	Total	$	26		$	2.1		$	—	$	28.1
	Liabilities:
	Energy-related derivatives	$	—		$	1.3		$	—	$	1.3
	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. See Note 9 for additional information on how these derivatives are used.
	As of December 31, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value			Unfunded		Redemption	Redemption
					Commitments		Frequency	Notice Period
	As of December 31, 2013:	(in millions)
	Cash equivalents:
	Money market funds	$	68		None		Daily	Not applicable
	As of December 31, 2012:
	Cash equivalents:
	Money market funds	$	26		None		Daily	Not applicable
	The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds.
	As of December 31, 2013 and 2012, 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:
	2013	$	1,620		$	1,660
	2012	$	1,306		$	1,444
	The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2013
Derivative [Line Items]	'
DERIVATIVES	'
	DERIVATIVES
	Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.
	Energy-Related Derivatives
	The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. Southern Power has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity.
	To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
	Energy-related derivative contracts are accounted for in one of three methods:
	•	Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
	•	Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
	•	Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
	Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
	At December 31, 2013, the net volume of energy-related derivative contracts for natural gas positions totaled 275 million mmBtu (million British thermal units) for the Southern Company system, with the longest hedge date of 2018 over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 2017 for derivatives not designated as hedges.
	In addition to the volumes discussed above, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 9 million mmBtu.
	For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to revenue and fuel expense for the next 12-month period ending December 31, 2014 are immaterial for Southern Company.
	Interest Rate Derivatives
	Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness.
	At December 31, 2013, the following interest rate derivatives were outstanding:
		Notional				Interest Rate		Weighted Average Interest		Hedge		Fair Value
		Amount				Received		Rate Paid		Maturity Date		Gain (Loss)
												December 31,
												2013
		(in millions)										(in millions)
	Fair value hedges of existing debt
		$	350			4.15%		3-month LIBOR + 1.96%		May-14		$	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, 2014 are immaterial. The Company has deferred gains and losses that are expected to be amortized into earnings through 2037.
	Foreign Currency Derivatives
	Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. At December 31, 2013, the fair value of the foreign currency derivative outstanding was immaterial.
	Derivative Financial Statement Presentation and Amounts
	At December 31, 2013 and 2012, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in millions)										(in millions)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	16			$	10			Liabilities from risk management activities		$	26			$	74
		Other deferred charges and assets		7				13				Other deferred credits and liabilities		29				35
	Total derivatives designated as hedging instruments for regulatory purposes			$	23			$	23					$	55			$	109
	Derivatives designated as hedging instruments in cash flow and fair value hedges
	Interest rate derivatives:	Other current assets		$	3			$	7			Liabilities from risk management activities		$	—			$	—
		Other deferred charges and assets		—				3				Other deferred credits and liabilities		—				—
	Total derivatives designated as hedging instruments in cash flow and fair value hedges			$	3			$	10					$	—			$	—
	Derivatives not designated as hedging instruments
	Energy-related derivatives:	Other current assets		$	—			$	1			Liabilities from risk management activities		$	1			$	1
		Other deferred charges and assets		1				2				Other deferred credits and liabilities		—				1
	Total derivatives not designated as hedging instruments			$	1			$	3					$	1			$	2
	Total			$	27			$	36					$	56			$	111
	All derivative instruments are measured at fair value. See Note 10 for additional information.
	The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2013 and 2012 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	24			$	26			Energy-related derivatives presented in the Balance Sheet (a)		$	56			$	111
	Gross amounts not offset in the Balance Sheet (b)		(22		)		(23		)		Gross amounts not offset in the Balance Sheet (b)		(22		)		(23		)
	Net-energy related derivative assets		$	2			$	3			Net-energy related derivative liabilities		$	34			$	88
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
	At December 31, 2013 and 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in millions)										(in millions)
	Energy-related derivatives:	Other regulatory assets, current		$	(26	)		$	(74	)		Other regulatory liabilities, current		$	16			$	10
		Other regulatory assets, deferred		(29		)		(35		)		Other regulatory liabilities, deferred		7				13
	Total energy-related derivative gains (losses)			$	(55	)		$	(109	)				$	23			$	23
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of interest rate and foreign currency derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for Southern Company. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on Southern Company's statements of income were offset by changes to the carrying value of long-term debt and the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Company's statements of income were offset by changes in the fair value of the purchase commitment related to equipment purchases.
For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recorded in OCI and reclassified into earnings were immaterial for Southern Company.
There was no material ineffectiveness recorded in earnings for any period presented.
For the Southern Company system's energy-related derivatives not designated as hedging instruments, a portion of the pre-tax realized and unrealized gains and losses is associated with hedging fuel price risk of certain PPA customers and has no impact on net income or on fuel expense as presented in the Company's statements of income. As a result, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the Company's statements of income were immaterial for any year presented. This third party hedging activity has been discontinued.
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2013, the fair value of derivative liabilities with contingent features was $9 million.
At December 31, 2013, Southern Company's collateral posted with its derivative counterparties was immaterial. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $9 million and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional operating companies, and Southern Power have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
Alabama Power [Member]	'
Derivative [Line Items]	'
DERIVATIVES	'
	DERIVATIVES
	The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
	Energy-Related Derivatives
	The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Alabama PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.
	To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
	Energy-related derivative contracts are accounted for in one of three methods:
	•	Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the energy cost recovery clause.
	•	Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
	•	Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
	Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
	At December 31, 2013, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:
	Net Purchased		Longest Hedge		Longest Non-Hedge
	mmBtu*		Date		Date
	(in millions)
	69		2017		—
	*	million British thermal units (mmBtu)
	For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to revenue and fuel expense for the 12-month period ending December 31, 2014 are immaterial.
	Interest Rate Derivatives
	The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings.
	At December 31, 2013, 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, 2014 are $3 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2035.
	Derivative Financial Statement Presentation and Amounts
	At December 31, 2013 and 2012, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in millions)										(in millions)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	5			$	2			Liabilities from risk management activities		$	3			$	14
		Other deferred charges and assets		2				3				Other deferred credits and liabilities		5				4
	Total derivatives designated as hedging instruments for regulatory purposes			$	7			$	5					$	8			$	18
	Total			$	7			$	5					$	8			$	18
	All derivative instruments are measured at fair value. See Note 10 for additional information.
	The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2013 and 2012 are presented in the following tables.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	7			$	5			Energy-related derivatives presented in the Balance Sheet (a)		$	8			$	18
	Gross amounts not offset in the Balance Sheet (b)		(5		)		(4		)		Gross amounts not offset in the Balance Sheet (b)		(5		)		(4		)
	Net-energy related derivative assets		$	2			$	1			Net-energy related derivative liabilities		$	3			$	14
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
	At December 31, 2013 and 2012, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in millions)										(in millions)
	Energy-related derivatives:	Other regulatory assets, current		$	(3	)		$	(14	)		Other current liabilities		$	5			$	2
		Other regulatory assets, deferred		(5		)		(4		)		Other regulatory liabilities, deferred		2				3
	Total energy-related derivative gains (losses)			$	(8	)		$	(18	)				$	7			$	5
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows:
	Derivatives in Cash Flow Hedging Relationships		Gain (Loss) Recognized in												Gain (Loss) Reclassified from Accumulated OCI into Income
			OCI on Derivative												(Effective Portion)
			(Effective Portion)														Amount
	Derivative Category		2013				2012				2011				Statements of Income		2013				2012				2011
															Location
			(in millions)														(in millions)
	Interest rate derivatives		$	—			$	(18	)		$	(14	)		Interest expense, net of amounts capitalized		$	(3	)		$	(3	)		$	3
	There was no material ineffectiveness recorded in earnings for any period presented.
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material.
	Contingent Features
	The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2013, the fair value of derivative liabilities with contingent features was $1 million.
	The Company's collateral posted with its derivative counterparties at December 31, 2013 was not material. However, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $9 million. 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.
	Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in 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.
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 Investors Services, Inc. and Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc. or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
Georgia Power [Member]	'
Derivative [Line Items]	'
DERIVATIVES	'
	DERIVATIVES
	The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
	Energy-Related Derivatives
	The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages a fuel-hedging program, implemented per the guidelines of the Georgia PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.
	To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
	Energy-related derivative contracts are accounted for in one of two methods:
	•	Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel-hedging program, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery mechanism.
	•	Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
	Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
	At December 31, 2013, the net volume of energy-related derivative contracts for natural gas positions totaled 60 million mmBtu (million British thermal units), all of which expire by 2017, which is the longest hedge date.
	In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 5 million mmBtu for the Company.
	Interest Rate Derivatives
	The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives’ fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to income.
	At December 31, 2013, 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, 2014 are immaterial. The Company has deferred gains and losses related to interest rate derivative settlements that are expected to be amortized into earnings through 2037.
	Derivative Financial Statement Presentation and Amounts
	At December 31, 2013 and 2012, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in millions)										(in millions)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	3			$	6			Liabilities from risk management activities		$	13			$	30
		Other deferred charges and assets		2				5				Other deferred credits and liabilities		8				15
	Total derivatives designated as hedging instruments for regulatory purposes			$	5			$	11					$	21			$	45
	All derivative instruments are measured at fair value. See Note 10 for additional information.
	The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2013 and 2012 are presented in the following tables.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	5			$	11			Energy-related derivatives presented in the Balance Sheet (a)		$	21			$	45
	Gross amounts not offset in the Balance Sheet (b)		(5		)		(11		)		Gross amounts not offset in the Balance Sheet (b)		(5		)		(11		)
	Net-energy related derivative assets		$	—			$	—			Net-energy related derivative liabilities		$	16			$	34
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
	At December 31, 2013 and 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in millions)										(in millions)
	Energy-related derivatives:	Other regulatory assets, current		$	(13	)		$	(30	)		Other regulatory liabilities, current		$	3			$	6
		Other regulatory assets, deferred		(8		)		(15		)		Other deferred credits and liabilities		2				5
	Total energy-related derivative gains (losses)			$	(21	)		$	(45	)				$	5			$	11
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into income were immaterial.
	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, 2013, the fair value of derivative liabilities with contingent features was $3 million.
	At December 31, 2013, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $9 million. 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.
	Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in 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.
	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 Investors Services, Inc. and Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc. or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
Gulf Power [Member]	'
Derivative [Line Items]	'
DERIVATIVES	'
	DERIVATIVES
	The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and may enter into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.
	Energy-Related Derivatives
	The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Florida PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.
	To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
	Energy-related derivative contracts are accounted for in one of two methods:
	•	Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clause.
	•	Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
	Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
	At December 31, 2013, the net volume of energy-related derivative contracts for natural gas positions totaled 88.62 million mmBtu (million British thermal units) for the Company, with the longest hedge date of 2018 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, 2013, 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, 2014 are $0.6 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2020.
	Derivative Financial Statement Presentation and Amounts
	At December 31, 2013 and 2012, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in thousands)										(in thousands)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	4,893			$	1,293			Liabilities from risk management activities		$	6,470			$	16,529
		Other deferred charges and assets		2,069				3,065				Other deferred credits and liabilities		10,573				10,583
	Total derivatives designated as hedging instruments for regulatory purposes			$	6,962			$	4,358					$	17,043			$	27,112
	All derivative instruments are measured at fair value. See Note 9 for additional information.
	The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2013 and 2012 are presented in the following tables.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	7			$	4			Energy-related derivatives presented in the Balance Sheet (a)		$	17			$	27
	Gross amounts not offset in the Balance Sheet (b)		(6		)		(4		)		Gross amounts not offset in the Balance Sheet (b)		(6		)		(4		)
	Net-energy related derivative assets		$	1			$	—			Net-energy related derivative liabilities		$	11			$	23
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
	At December 31, 2013 and 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in thousands)										(in thousands)
	Energy-related derivatives:	Other regulatory assets, current		$	(6,470	)		$	(16,529	)		Other regulatory liabilities, current		$	4,893			$	1,293
		Other regulatory assets, deferred		(10,573		)		(10,583		)		Other regulatory liabilities, deferred		2,069				3,065
	Total energy-related derivative gains (losses)			$	(17,043	)		$	(27,112	)				$	6,962			$	4,358
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
	Derivatives in Cash	Gain (Loss) Recognized in												Gain (Loss) Reclassified from Accumulated
	Flow Hedging Relationships	OCI on Derivative												OCI into Income (Effective Portion)
		(Effective Portion)														Amount
	Derivative Category	2013				2012				2011				Statements of Income Location		2013				2012				2011
		(in thousands)														(in thousands)
	Interest rate derivatives	$	—			$	—			$	—			Interest expense, net of amounts capitalized		$	(769	)		$	(933	)		$	(933	)
	There was no material ineffectiveness recorded in earnings for any period presented.
	For the years ended December 31, 2013, 2012, and 2011, 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, 2013, the fair value of derivative liabilities with contingent features was $3.7 million.
	At December 31, 2013, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $8.8 million. 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.
	Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in 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.
	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 Investors Services, Inc. and Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc. or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
Mississippi Power [Member]	'
Derivative [Line Items]	'
DERIVATIVES	'
	DERIVATIVES
	The Company is exposed to market risks, primarily commodity price risk and interest rate risk and occasionally foreign currency risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.
	Energy-Related Derivatives
	The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Mississippi PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.
	To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
	Energy-related derivative contracts are accounted for in one of three methods:
	•	Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
	•	Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of 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, 2013, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:
	Net Purchased		Longest Hedge		Longest Non-Hedge
	mmBtu*		Date		Date
	(in millions)
	56		2017		—
	*	mmBtu — million British thermal units
	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, 2013, 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, 2014 are $1.4 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2022.
	Foreign Currency Derivatives
	The Company may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is typically recorded directly to earnings; however, the Company has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. During 2011, certain fair value hedges were de-designated and subsequently settled in 2012. The ineffectiveness related to the de-designated hedges was recorded as a regulatory asset and was immaterial to the Company. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
	At December 31, 2013, the foreign currency derivatives outstanding were immaterial.
	Derivative Financial Statement Presentation and Amounts
	At December 31, 2013 and 2012, the fair value of energy-related derivatives, foreign currency derivatives, and interest rate derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet		2013				2012
												Location
				(in thousands)										(in thousands)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	3,352			$	638			Liabilities from risk management activities		$	3,652			$	13,116
		Other deferred charges and assets		1,451				1,881				Other deferred credits and liabilities		6,629				6,330
	Total derivatives designated as hedging instruments for regulatory purposes			$	4,803			$	2,519					$	10,281			$	19,446
	Derivatives designated as hedging instruments in cash flow and fair value hedges
	Foreign currency derivatives:	Other current assets		$	—			$	—			Liabilities from risk management activities		$	1			$	—
		Other deferred charges and assets		—				—				Other deferred credits and liabilities		—				37
	Total derivatives designated as hedging instruments in cash flow and fair value hedges			$	—			$	—					$	1			$	37
	Total			$	4,803			$	2,519					$	10,282			$	19,483
	All derivative instruments are measured at fair value. See Note 9 for additional information.
	The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2013 and 2012 are presented in the following tables.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in thousands)										(in thousands)
	Energy-related derivatives presented in the Balance Sheet (a)		$	4,803			$	2,519			Energy-related derivatives presented in the Balance Sheet (a)		$	10,281			$	19,446
	Gross amounts not offset in the Balance Sheet (b)		(3,856		)		(2,333		)		Gross amounts not offset in the Balance Sheet (b)		(3,856		)		(2,333		)
	Net-energy related derivative assets		$	947			$	186			Net-energy related derivative liabilities		$	6,425			$	17,113
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
	At December 31, 2013 and 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in thousands)										(in thousands)
	Energy-related derivatives:	Other regulatory assets, current		$	(3,652	)		$	(13,116	)		Other regulatory liabilities, current		$	3,352			$	638
		Other regulatory assets, deferred		(6,629		)		(6,330		)		Other regulatory liabilities, deferred		1,451				1,881
	Total energy-related derivative gains (losses)			$	(10,281	)		$	(19,446	)				$	4,803			$	2,519
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of income were as follows:
	Derivatives in Cash Flow	Gain (Loss) Recognized in												Gain (Loss) Reclassified from Accumulated
	Hedging Relationships	OCI on Derivative												OCI into Income
		(Effective Portion)												(Effective Portion)
																Amount
	Derivative Category	2013				2012				2011				Statements of Income Location		2013				2012				2011
		(in thousands)														(in thousands)
Energy-related derivatives	$	—			$	—			$	(3	)		Fuel		$	—			$	—			$	—
Interest rate derivatives	—				(774		)		(14,361		)		Interest Expense		(1,375		)		(1,073		)		48
Total	$	—			$	(774	)		$	(14,364	)				$	(1,375	)		$	(1,073	)		$	48
There was no material ineffectiveness recorded in earnings for any period presented.
For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial.
For the year ended December 31, 2013, the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on the Company's statements of income were immaterial. For the year ended December 31, 2012, the pre-tax effect of foreign currency derivatives designated as fair value hedging instruments, which include a pre-tax loss associated with the de-designated hedges prior to de-designation, was a $0.6 million gain. For the year ended December 31, 2011, the pre-tax loss was $3.6 million. These amounts were offset by changes in the fair value of the purchase commitment related to equipment purchases. Therefore, there is no impact on the Company's statements of income.
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, 2013, the fair value of derivative liabilities with contingent features was $1.5 million.
At December 31, 2013, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $8.8 million. 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.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. The Company participates in 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.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
Southern Power [Member]	'
Derivative [Line Items]	'
DERIVATIVES	'
	DERIVATIVES
	The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities
	Energy-Related Derivatives
	The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. The Company has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity.
	To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
	Energy-related derivative contracts are accounted for in one of two methods:
	•	Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are used to hedge anticipated purchases and sales and are initially deferred in other comprehensive income (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, 2013, the net volume of energy-related derivative contracts for natural gas positions totaled 1.6 million mmBtu (million British thermal units), all of which expire by 2017, which is the longest non-hedge date. At December 31, 2013, the net volume of energy-related derivative contracts for power positions was immaterial. In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 1.4 million mmBtu.
	Interest Rate Derivatives
	The Company may also enter into interest rate derivatives from time to time to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges, where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings.
	At December 31, 2013, there were no interest rate derivatives outstanding.
	The estimated pre-tax loss that will be reclassified from AOCI to interest expense for the 12-month period ending December 31, 2014 is $0.9 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2016.
	Derivative Financial Statement Presentation and Amounts
	At December 31, 2013 and 2012, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in millions)										(in millions)
	Derivatives not designated as hedging instruments
	Energy-related derivatives:	Assets from risk management activities		$	0.2			$	0.4			Other current liabilities		$	0.6			$	0.7
		Other deferred charges and assets – non-affiliated		0.4				1.7				Other deferred credits and liabilities – non-affiliated		—				0.6
	Total derivatives not designated as hedging instruments			$	0.6			$	2.1					$	0.6			$	1.3
	Total			$	0.6			$	2.1					$	0.6			$	1.3
	All derivative instruments are measured at fair value. See Note 8 for additional information.
	The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2013 and 2012 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	0.6			$	2.1			Energy-related derivatives presented in the Balance Sheet (a)		$	0.6			$	1.3
	Gross amounts not offset in the Balance Sheet (b)		(0.1		)		(1.0		)		Gross amounts not offset in the Balance Sheet (b)		(0.1		)		(1.0		)
	Net-energy related derivative assets		$	0.5			$	1.1			Net-energy related derivative liabilities		$	0.5			$	0.3
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
	Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in												Gain (Loss) Reclassified from AOCI into Income
		AOCI on Derivative												(Effective Portion)
		(Effective Portion)													Amount
	Derivative Category	2013				2012				2011				Statements of Income Location	2013				2012				2011
		(in millions)													(in millions)
	Energy-related derivatives	$	—			$	(0.2	)		$	0.1			Depreciation and amortization	$	0.4			$	0.4			$	0.4
	Interest rate derivatives	—				—				—				Interest expense, net of amounts capitalized	(6.5		)		(10.5		)		(11.4		)
														Other income (expense), net	—				—				(1.0		)
	Total	$	—			$	(0.2	)		$	0.1				$	(6.1	)		$	(10.1	)		$	(12.0	)
	There was no material ineffectiveness recorded in earnings for any period presented.
	For the Company's energy-related derivatives not designated as hedging instruments, a substantial portion of the pre-tax realized and unrealized gains and losses is associated with hedging fuel price risk of certain PPA customers and has no impact on net income or on fuel expense as presented in the Company's statements of income. As a result, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the Company's statements of income were immaterial for the years ended December 31, 2013, 2012, and 2011. This third party hedging activity has been discontinued.
	Contingent Features
	The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2013, the fair value of derivative liabilities with contingent features was immaterial.
	At December 31, 2013, the Company had no collateral posted with its derivative counterparties; however, because of the joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $8.8 million. 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.
	Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Southern Power Company participates in 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.
	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 Investors Services, Inc. and Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc. or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

Segment_and_Related_Informatio

Segment and Related Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
SEGMENT AND RELATED INFORMATION	'
	SEGMENT AND RELATED INFORMATION
	The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies – Alabama Power, Georgia Power, Gulf Power and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.
	Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $346 million, $425 million, and $359 million in 2013, 2012, and 2011, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2013, 2012, and 2011 was as follows:
		Electric Utilities
		Traditional			Southern			Eliminations			Total			All			Eliminations			Consolidated
		Operating			Power									Other
		Companies
		(in millions)
	2013
	Operating revenues	$	16,136		$	1,275		$	(376	)	$	17,035		$	139		$	(87	)	$	17,087
	Depreciation and amortization	1,711			175			—			1,886			15			—			1,901
	Interest income	17			1			—			18			2			(1		)	19
	Interest expense	714			74			—			788			36			—			824
	Income taxes	889			46			—			935			(85		)	(1		)	849
	Segment net income (loss)(a) (b)	1,486			166			—			1,652			(10		)	2			1,644
	Total assets	59,447			4,429			(101		)	63,775			1,077			(306		)	64,546
	Gross property additions	5,226			633			—			5,859			9			—			5,868
	2012
	Operating revenues	$	15,730		$	1,186		$	(438	)	$	16,478		$	141		$	(82	)	$	16,537
	Depreciation and amortization	1,629			143			—			1,772			15			—			1,787
	Interest income	21			1			—			22			19			(1		)	40
	Interest expense	757			63			—			820			39			—			859
	Income taxes	1,307			93			—			1,400			(66		)	—			1,334
	Segment net income (loss)(a)	2,145			175			1			2,321			33			(4		)	2,350
	Total assets	58,600			3,780			(129		)	62,251			1,116			(218		)	63,149
	Gross property additions	4,813			241			—			5,054			5			—			5,059
	2011
	Operating revenues	$	16,763		$	1,236		$	(412	)	$	17,587		$	149		$	(79	)	$	17,657
	Depreciation and amortization	1,576			124			—			1,700			16			1			1,717
	Interest income	18			1			—			19			3			(1		)	21
	Interest expense	726			77			—			803			54			—			857
	Income taxes	1,217			76			—			1,293			(74		)	—			1,219
	Segment net income (loss)(a)	2,052			162			—			2,214			(8		)	(3		)	2,203
	Total assets	54,622			3,581			(127		)	58,076			1,592			(401		)	59,267
	Gross property additions	4,589			255			—			4,844			9			—			4,853
	(a)    After dividends on preferred and preference stock of subsidiaries.
	(b)    Segment net income (loss) in 2013 includes $1.2 billion in pre-tax charges ($729 million after tax) for estimated probable losses on the Kemper IGCC.
	See Note (3) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Construction Schedule and Cost Estimate" for additional information.
	Products and Services
	Electric Utilities' Revenues
	Year		Retail			Wholesale			Other			Total
			(in millions)
	2013		$	14,541		$	1,855		$	639		$	17,035
	2012		14,187			1,675			616			16,478
	2011		15,071			1,905			611			17,587

Quarterly_Financial_Informatio

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information [Line Items]	'
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)	'
	QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
	Summarized quarterly financial information for 2013 and 2012 is as follows:
							Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries			Per Common Share
		Operating		Operating						Basic		Diluted Earnings				Trading
		Revenues		Income						Earnings						Price Range
	Quarter Ended													Dividends		High		Low
		(in millions)
	Mar-13	$	3,897	$	325		$	81		$	0.09	$	0.09	$	0.49	$	46.95	$	42.82
	Jun-13	4,246		640			297			0.34		0.34		0.5075		48.74		42.32
	Sep-13	5,017		1,491			852			0.97		0.97		0.5075		45.75		40.63
	Dec-13	3,927		799			414			0.47		0.47		0.5075		42.94		40.03
	Mar-12	$	3,604	$	766		$	368		$	0.42	$	0.42	$	0.4725	$	46.06	$	43.71
	Jun-12	4,181		1,143			623			0.71		0.71		0.49		48.45		44.22
	Sep-12	5,049		1,740			976			1.11		1.11		0.49		48.59		44.64
	Dec-12	3,703		814			383			0.44		0.44		0.49		47.09		41.75
	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 2013 and 2012 is as follows:
	Quarter Ended	Operating		Operating			Net Income After Dividends on Preferred and Preference Stock
		Revenues		Income
		(in millions)
	Mar-13	$	1,308	$	307		$	141
	Jun-13	1,392		357			173
	Sep-13	1,604		500			258
	Dec-13	1,314		312			140
	Mar-12	$	1,216	$	291		$	126
	Jun-12	1,377		390			185
	Sep-12	1,637		544			280
	Dec-12	1,290		271			113
	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 2013 and 2012 is as follows:
	Quarter Ended	Operating Revenues		Operating Income			Net Income After Dividends on Preferred and Preference Stock
		(in millions)
	Mar-13	$	1,882	$	412		$	197
	Jun-13	2,042		552			282
	Sep-13	2,484		872			487
	Dec-13	1,866		404			208
	Mar-12	$	1,745	$	344		$	167
	Jun-12	2,020		535			295
	Sep-12	2,498		924			525
	Dec-12	1,735		400			181
	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 2013 and 2012 is as follows:
	Quarter Ended	Operating		Operating			Net Income After Dividends on Preference Stock
		Revenues		Income
		(in thousands)
	Mar-13	$	326,274	$	51,640		$	21,792
	Jun-13	371,173		69,151			32,582
	Sep-13	399,361		87,776			44,754
	Dec-13	343,493		56,436			25,301
	Mar-12	$	316,245	$	49,098		$	20,666
	Jun-12	370,208		71,465			34,963
	Sep-12	421,819		93,813			47,754
	Dec-12	331,490		53,818			22,549
	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 2013 and 2012 is as follows:
	Quarter Ended	Operating		Operating			Net Income (Loss) After Dividends on Preferred Stock
		Revenues		Income (Loss)
		(in thousands)
	Mar-13	$	245,934	$	(429,148	)	$	(246,321	)
	Jun-13	306,435		(388,395		)	(219,110		)
	Sep-13	325,206		(79,890		)	(24,115		)
	Dec-13	267,582		(24,412		)	12,921
	Mar-12	$	228,714	$	30,213		$	25,255
	Jun-12	266,084		46,986			35,027
	Sep-12	305,419		66,151			54,625
	December 2012 (Restated)	235,779		(46,338		)	(14,965		)
	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 2013 and 2012 is as follows:
	Quarter Ended	Operating		Operating			Net
		Revenues		Income			Income
		(in thousands)
	Mar-13	$	302,947	$	64,673		$	29,192
	Jun-13	307,255		55,024			27,922
	Sep-13	364,767		116,497			85,153
	Dec-13	300,257		53,781			23,266
	Mar-12	$	253,681	$	56,343		$	29,316
	Jun-12	285,805		90,038			46,602
	Sep-12	354,971		119,234			68,376
	Dec-12	291,591		65,816			30,991
	The Company's business is influenced by seasonal weather conditions.

Valuation_and_Qualifying_Accou

Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2013
VALUATION AND QUALIFYING ACCOUNTS	'
	THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
	SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
	FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
	(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
	2013	$	16,984	$	36,788	$	—	$	35,917	$	17,855
	2012	26,155		35,305		—		44,476		16,984
	2011	24,919		66,641		—		65,405		26,155
	(Note)    Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
Alabama Power [Member]	'
VALUATION AND QUALIFYING ACCOUNTS	'
	ALABAMA POWER COMPANY
	SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
	FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
	(Stated in Thousands of Dollars)
				Additions
	Description	Balance at Beginning		Charged to		Charged to Other Accounts		Deductions		Balance at End of Period
		of Period		Income				(Note)
	Provision for uncollectible accounts
	2013	$	8,450	$	12,327	$	—	$	12,427	$	8,350
	2012	9,856		10,537		—		11,943		8,450
	2011	9,602		16,415		—		16,161		9,856
	(Note)    Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
Georgia Power [Member]	'
VALUATION AND QUALIFYING ACCOUNTS	'
	GEORGIA POWER COMPANY
	SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
	FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
	(Stated in Thousands of Dollars)
				Additions
	Description	Balance at Beginning		Charged to		Charged to Other		Deductions		Balance at End of Period
		of Period		Income		Accounts		(Note)
	Provision for uncollectible accounts
	2013	$	6,259	$	18,362	$	—	$	19,547	$	5,074
	2012	13,038		20,995		—		27,774		6,259
	2011	11,098		45,267		—		43,327		13,038
	(Note)    Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
Gulf Power [Member]	'
VALUATION AND QUALIFYING ACCOUNTS	'
	GULF POWER COMPANY
	SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
	FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
	(Stated in Thousands of Dollars)
				Additions
	Description	Balance at Beginning		Charged to		Charged to Other		Deductions		Balance at End of Period
		of Period		Income		Accounts		(Note)
	Provision for uncollectible accounts
	2013	$	1,490	$	1,900	$	—	$	2,259	$	1,131
	2012	1,962		2,611		—		3,083		1,490
	2011	2,014		3,332		—		3,384		1,962
	(Note)    Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
Mississippi Power [Member]	'
VALUATION AND QUALIFYING ACCOUNTS	'
	MISSISSIPPI POWER COMPANY
	SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
	FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
	(Stated in Thousands of Dollars)
				Additions
	Description	Balance at Beginning		Charged to		Charged to Other		Deductions		Balance at End of Period
		of Period		Income		Accounts		(Note)
	Provision for uncollectible accounts
	2013	$	373	$	3,757	$	—	$	1,112	$	3,018
	2012	547		628		—		802		373
	2011	638		1,235		—		1,326		547
	(Note)    Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Summary of Significant Accounting Policies [Line Items]

'

General

'

General

The Southern Company (Southern Company or the Company) is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants.

The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary. All material intercompany transactions have been eliminated in consolidation. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.

The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), and the traditional operating companies are also subject to regulation by their respective state public service commissions (PSC). The companies follow generally accepted accounting principles (GAAP) in the U.S. and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates.

Acquisition Accounting

'

Acquisitions

Southern Power acquires generation assets as part of its overall growth strategy. Southern Power accounts for business acquisitions from non-affiliates as business combinations. Accordingly, Southern Power has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition was allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business in accordance with GAAP are accounted for as asset acquisitions. The purchase price of each asset acquisition was allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by Southern Power for successful or potential acquisitions have been expensed as incurred.

Regulatory Assets and Liabilities

'

Regulatory Assets and Liabilities

The traditional operating companies are subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

2013

2012

Note

(in millions)

Deferred income tax charges

$

1,376

$

1,318

(a)

Deferred income tax charges — Medicare subsidy

65

72

(j)

Asset retirement obligations-asset

145

141

(a,h)

Asset retirement obligations-liability

(139

)

(71

)

(a,h)

Other cost of removal obligations

(1,289

)

(1,225

)

(a)

Deferred income tax credits

(203

)

(212

)

(a)

Loss on reacquired debt

293

309

(b)

Vacation pay

171

165

(c,h)

Under recovered regulatory clause revenues

70

38

(d)

Property damage reserves

(191

)

(193

)

(g)

Cancelled construction projects

70

65

(m)

Power purchase agreement charges

180

138

(h,n)

Fuel-hedging-asset

58

118

(h,o)

Other regulatory assets

337

276

(f)

Environmental remediation-asset

62

74

(g,h)

Other regulatory liabilities

(126

)

(100

)

(b,l,i)

Kemper IGCC* regulatory assets

76

36

(k)

Kemper regulatory deferral

(91

)

—

(k)

Retiree benefit plans

1,760

3,373

(e,h)

Total regulatory assets (liabilities), net

$

2,624

$

4,322

*

Integrated coal gasification combined cycle electric generating plant located in Kemper County, Mississippi (Kemper IGCC).

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 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period from January 2014 through December 2016 in accordance with Georgia Power's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP). See Note 3 under "Retail Regulatory Matters" for additional information.

(b)

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.

(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 appropriate state PSCs over periods generally not exceeding 10 years.

(e)

Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.

(f)

Comprised of numerous immaterial components including storm damage reserves, nuclear and generating plant outage costs, property taxes, post-retirement benefits, generation site selection/evaluation costs, power purchase agreement (PPA) capacity, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4 regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding, as applicable, 10 years or over the remaining life of the asset but not beyond 2031.

(g)

Recovered as storm restoration and potential reliability-related expenses or environmental remediation expenses are incurred as approved by the appropriate state PSCs.

(h)

Not earning a return as offset in rate base by a corresponding asset or liability.

(i)

Recovered and amortized as approved or accepted by the appropriate state PSC over the life of the contract.

(j)

Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years.

(k)

For additional information, See Note 3 under "Integrated Coal Gasification Combined Cycle."

(l)

Comprised of immaterial components including over recovered regulatory clause revenues, state income tax credits, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years, except for PPA credits that are recovered over the life of the PPA for periods up to 14 years.

(m)

Costs associated with construction of environmental controls that will not be completed as a result of unit retirements and amortized over nine years in accordance with the 2013 ARP.

(n)

Recovered over the life of the PPA for periods up to 14 years.

(o)

Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.

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 traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.

Southern Company's electric utility subsidiaries have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.

Fuel Costs

'

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under "Nuclear Fuel Disposal Costs" for additional information.

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 investment tax credits (ITCs) for the traditional operating companies are amortized over the lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $16 million in 2013, $23 million in 2012, and $19 million in 2011. At December 31, 2013, all ITCs available to reduce federal income taxes payable had not been utilized. The remaining ITCs will be carried forward and utilized in future years. Additionally, several subsidiaries have state ITCs, which are recognized in the period in which the credit is claimed on the state income tax return. A portion of the state ITCs available to reduce state income taxes payable was not utilized currently and will be carried forward and utilized in future years.

Under the American Recovery and Reinvestment Act of 2009, certain projects at Southern Power are eligible for ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit, and are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $5.5 million and $2.6 million in 2013 and 2012, respectively. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period.

In accordance with accounting standards related to the uncertainty in income taxes, Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.

Property, Plant, and Equipment

'

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.

The Southern Company system's property, plant, and equipment in service consisted of the following at December 31:

2013

2012

(in millions)

Generation

$

35,360

$

33,444

Transmission

9,289

8,747

Distribution

16,499

15,958

General

3,958

4,208

Plant acquisition adjustment

123

124

Utility plant in service

65,229

62,481

Information technology equipment and software

242

230

Communications equipment

437

430

Other

113

110

Other plant in service

792

770

Total plant in service

$

66,021

$

63,251

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 and Georgia Power range from 18 to 24 months for each unit. In accordance with a Georgia PSC order, Georgia Power deferred the costs of certain significant inspection costs for the combustion turbine units at Plant McIntosh and amortized such costs over 10 years, which approximated the expected maintenance cycle of the units. All inspection costs were fully amortized in 2013.

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,

2013

2012

(in millions)

Office building

$

61

$

61

Nitrogen plant

83

—

Computer-related equipment

62

58

Gas pipeline

6

—

Less: Accumulated amortization

(48

)

(39

)

Balance, net of amortization

$

164

$

80

The amount of non-cash property additions recognized for the years ended December 31, 2013, 2012, and 2011 was $411 million, $524 million, and $929 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, 2013, 2012, and 2011 were $107 million, $14 million, and $21 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 3.3% in 2013, 3.2% in 2012, and 3.2% in 2011. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and the FERC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $22.5 billion and $21.5 billion at December 31, 2013 and 2012, 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.

In 2009, the Georgia PSC approved an accounting order allowing Georgia Power to amortize a portion of its regulatory liability related to other cost of removal obligations. Under the terms of Georgia Power's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), Georgia Power amortized approximately $31 million annually of the remaining regulatory liability related to other cost of removal obligations over the three years ended December 31, 2013. Under the terms of the 2013 ARP, an additional $43 million will be amortized ratably over the three years ending December 31, 2016. See Note 3 under "Retail Regulatory Matters – Georgia Power – Rate Plans" for additional information.

Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 25 years. Accumulated depreciation for other plant in service totaled $513 million and $479 million at December 31, 2013 and 2012, respectively.

Asset Retirement Obligations and Other Costs of Removal

'

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Each traditional operating company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

The liability for asset retirement obligations primarily relates to the decommissioning of the Southern Company system's nuclear facilities, Plants Farley, Hatch, and Vogtle. In addition, the Southern Company system has retirement obligations related to various landfill sites, ash ponds, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these asset retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the asset retirement obligation. 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 asset retirement obligations included in the balance sheets are as follows:

2013

2012

(in millions)

Balance at beginning of year

$

1,757

$

1,344

Liabilities incurred

6

45

Liabilities settled

(16

)

(16

)

Accretion

97

112

Cash flow revisions

174

272

Balance at end of year

$

2,018

$

1,757

The increase in cash flow revisions in 2013 related to revisions to the nuclear decommissioning ARO based on Alabama Power's updated decommissioning study and Georgia Power's updated estimates for ash ponds in connection with the retirement of certain coal-fired generating units. The increase in cash flow revisions in 2012 related to updated estimates for some of the Southern Company system's ash ponds in connection with the retirement of certain coal-fired units and revisions to the nuclear decommissioning ARO based on Georgia Power's updated decommissioning study.

Nuclear Decommissioning

'

Nuclear Decommissioning

The U.S. Nuclear Regulatory Commission (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 Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds' managers to exercise the standard of care in investing that a "prudent investor" would use in the same circumstances. The FERC regulations also require that the Funds' managers may not invest in any securities of the utility for which it manages funds or its affiliates, except for investments tied to market indices or other mutual funds. While Southern Company is 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 asset retirement obligations 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 so loaned are fully collateralized by cash, letters of credit, and securities issued or guaranteed by the U.S. government, its agencies, and the instrumentalities. As of December 31, 2013 and 2012, approximately $32 million and $91 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 $33 million and $93 million at December 31, 2013 and 2012, 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, 2013, investment securities in the Funds totaled $1.5 billion, consisting of equity securities of $896 million, debt securities of $528 million, and $40 million of other securities. At December 31, 2012, investment securities in the Funds totaled $1.3 billion, consisting of equity securities of $718 million, debt securities of $564 million, and $20 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 $1.0 billion, $1.0 billion, and $2.2 billion in 2013, 2012, and 2011, respectively, all of which were reinvested. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $181 million, of which $5 million related to realized gains and $119 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $137 million, of which $4 million related to realized gains and $75 million related to unrealized gains related to securities held in the Funds at December 31, 2012. For 2011, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $29 million, of which $41 million related to realized gains and $60 million related to unrealized losses related to securities held in the Funds at December 31, 2011. 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 and purpose for which the securities were acquired.

For Alabama Power, amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.

At December 31, 2013 and 2012, the accumulated provisions for decommissioning were as follows:

External Trust Funds

Internal Reserves

Total

2013

2012

2013

2012

2013

2012

(in millions)

Plant Farley

$

713

$

604

$

21

$

22

$

734

$

626

Plant Hatch

469

435

—

—

469

435

Plant Vogtle Units 1 and 2

277

256

—

—

277

256

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, 2013 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2012 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2:

Plant Farley

Plant Hatch

Plant Vogtle

Units 1 and 2

Decommissioning periods:

Beginning year

2037

2034

2047

Completion year

2076

2068

2072

(in millions)

Site study costs:

Radiated structures

$

1,362

$

680

$

568

Non-radiated structures

80

51

76

Total site study costs

$

1,442

$

731

$

644

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study, and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. The Georgia PSC approved annual decommissioning cost for ratemaking of $2 million for Plant Hatch for 2011 through 2013. Under the 2013 ARP, the annual decommissioning cost through 2016 for ratemaking is $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively.

Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.

Allowance for Funds Used During Construction and Interest Capitalized

'

Allowance for Funds Used During Construction and Interest Capitalized

In accordance with regulatory treatment, the traditional operating companies record allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies' regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 15.0%, 8.2%, and 9.1% of net income for 2013, 2012, and 2011, respectively.

Cash payments for interest totaled $759 million, $803 million, and $832 million in 2013, 2012, and 2011, respectively, net of amounts capitalized of $92 million, $83 million, and $78 million, respectively.

Impairment of Long-Lived Assets and Intangibles

'

Impairment of Long-Lived Assets and Intangibles

Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

Reserves, Damages, and Recoveries

'

Storm Damage Reserves

Each traditional operating company maintains a reserve to cover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional operating companies accrued $28 million in 2013 and 2012. 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 2013 and 2012, there were no such additional accruals. See Note 3 under "Retail Regulatory Matters – Alabama Power – Natural Disaster Reserve" for additional information regarding Alabama Power's natural disaster reserve.

Leveraged Leases

'

Leveraged Leases

Southern Company has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. The Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows.

Cash and Cash Equivalents

'

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.

Materials and Supplies

'

Materials and Supplies

Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Fuel Inventory

'

Fuel Inventory

Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.

Financial Instruments

'

Financial Instruments

Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional operating companies' fuel-hedging programs. This results 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 are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2013, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial.

Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.

Comprehensive Income

'

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries.

Alabama Power [Member]

'

Summary of Significant Accounting Policies [Line Items]

'

General

'

General

Alabama Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which is the parent company of four traditional operating companies, Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – the Company, Georgia Power Company (Georgia Power), Gulf Power Company (Gulf Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Farley.

The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary.

The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Alabama Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.

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 $340 million, $340 million, and $347 million during 2013, 2012, and 2011, 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 U.S. Securities and Exchange Commission (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 $211 million, $218 million, and $215 million during 2013, 2012, and 2011, respectively.

The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which were $13 million in 2013, $12 million in 2012, and $12 million in 2011. Also, Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities, which were $27 million in 2013, $28 million in 2012, and $21 million in 2011. See Note 4 for additional information.

The Company has an agreement with Gulf Power under which the Company will make transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA. In 2009, Gulf Power entered into a PPA for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. The total cost committed by the Company related to the upgrades is approximately $22 million in 2013 and $31 million in 2014. The Company expects to recover a majority of these costs through a tariff with Gulf Power until 2023. The remainder of these costs will be recovered through normal rate mechanisms.

The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2013, 2012, or 2011.

Also, see Note 4 for information regarding the Company's ownership in, a PPA, and a gas pipeline ownership agreement with Southern Electric Generating Company (SEGCO).

The traditional operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.

Regulatory Assets and Liabilities

'

Regulatory Assets and Liabilities

The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

2013

2012

Note

(in millions)

Deferred income tax charges

$

519

$

525

(a,k)

Loss on reacquired debt

86

93

(b)

Vacation pay

63

61

(c,j)

Under/(over) recovered regulatory clause revenues

(18

)

34

(d)

Fuel-hedging (realized and unrealized) losses

8

18

(e)

Other regulatory assets

52

51

(f)

Asset retirement obligations

(132

)

(64

)

(a)

Other cost of removal obligations

(828

)

(759

)

(a)

Deferred income tax credits

(75

)

(79

)

(a)

Fuel-hedging (realized and unrealized) gains

(8

)

(5

)

(e)

Nuclear outage

51

33

(d)

Natural disaster reserve

(96

)

(103

)

(h)

Other regulatory liabilities

(11

)

(13

)

(d,g)

Retiree benefit plans

461

911

(i,j)

Regulatory deferrals

20

—

(l)

Total regulatory assets (liabilities), net

$

92

$

703

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:

(a)

Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.

(b)

Recovered over the remaining life of the original issue, which may range up to 50 years.

(c)

Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

(d)

Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding ten years.

(e)

Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.

(f)

Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable.

(g)

Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities.

(h)

Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC.

(i)

Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.

(j)

Not earning a return as offset in rate base by a corresponding asset or liability.

(k)

Included in the deferred income tax charges are $20 million for 2013 and $21 million for 2012 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 2015 through 2017.

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 other comprehensive income (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, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Energy Cost Recovery" and "Retail Regulatory Matters – Rate CNP" for additional information.

The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.

Fuel Costs

'

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under "Nuclear Fuel Disposal Costs" for additional information.

Income and Other Taxes

'

Income and Other Taxes

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Investment tax credits (ITCs) utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.

Property, Plant, and Equipment

'

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.

The Company's property, plant, and equipment in service consisted of the following at December 31:

2013

2012

(in millions)

Generation

$

11,314

$

11,110

Transmission

3,287

3,137

Distribution

5,934

5,714

General

1,545

1,434

Plant acquisition adjustment

12

12

Total plant in service

$

22,092

$

21,407

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.

In 2010, the Alabama PSC approved the Company's request to stop accruing for nuclear refueling outage costs in advance of the refueling outages when the most recent 18-month amortization cycle ended in December 2010 and to begin deferring nuclear outage expenses. The amortization will begin after each outage has occurred and the associated outage expenses are known.

During 2011, the Company deferred $38 million of nuclear outage expenses associated with the fall 2011 outage and began the first 18-month amortization cycle for expenses in January 2012. These expenses were fully amortized in June 2013. The Company deferred an additional $31 million of nuclear outage expenses associated with the spring 2012 outage and began the second amortization cycle in July 2012. These expenses were fully amortized in December 2013.

During 2013, the Company deferred $28 million of nuclear outage expenses associated with the spring 2013 outage and began the 18-month amortization cycle for expenses in July 2013. The Company deferred an additional $32 million of nuclear outage expenses associated with the fall 2013 outage and began the 18-month amortization cycle for expenses in January 2014.

The total unamortized deferred nuclear outage expense balance of $51 million is included in the 2013 balance sheet as a regulatory asset.

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 3.2% in 2013 and 2012, and 3.3% in 2011. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and the FERC. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

In 2011, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates beginning January 2012. The study was also provided to the Alabama PSC.

Asset Retirement Obligations and Other Costs of Removal

'

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

The liability for asset retirement obligations primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets are indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these asset retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the asset retirement obligation. 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 asset retirement obligations included in the balance sheets are as follows:

2013

2012

(in millions)

Balance at beginning of year

$

589

$

553

Liabilities incurred

—

—

Liabilities settled

(1

)

(1

)

Accretion

40

37

Cash flow revisions (a)

102

—

Balance at end of year

$

730

$

589

(a) Updated based on results from the 2013 nuclear decommissioning study

Nuclear Decommissioning

'

Nuclear Decommissioning

The U.S. Nuclear Regulatory Commission (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 Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds' managers to exercise the standard of care in investing that a "prudent investor" would use in the same circumstances. The FERC regulations also require that the Funds' managers may not invest in any securities of the utility for which it manages funds or its affiliates, except for investments tied to market indices or other mutual funds. 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 asset retirement obligations 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, 2013, investment securities in the Funds totaled $713 million, consisting of equity securities of $566 million, debt securities of $131 million, and $16 million of other securities. At December 31, 2012, investment securities in the Funds totaled $604 million, consisting of equity securities of $438 million, debt securities of $156 million, and $10 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 $279 million, $193 million, and $349 million in 2013, 2012, and 2011, respectively, all of which were reinvested. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $120 million, of which $5 million related to realized gains and $85 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $70 million, of which $4 million related to realized gains and $50 million related to unrealized gains related to securities held in the Funds at December 31, 2012. For 2011, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $6 million, of which $41 million related to realized gains and $51 million related to unrealized losses related to securities held in the Funds at December 31, 2011. 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 and purpose for which the securities were acquired.

Amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.

At December 31, the accumulated provisions for decommissioning were as follows:

2013

2012

(in millions)

External trust funds

$

713

$

604

Internal reserves

21

22

Total

$

734

$

626

Site study costs is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2013 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 the NRC and other applicable requirements.

Allowance for Funds Used During Construction and Interest Capitalized

'

Allowance for Funds Used During Construction

In accordance with regulatory treatment, the Company records allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The composite rate used to determine the amount of AFUDC was 9.1% in 2013, 9.4% in 2012, and 9.2% in 2011. AFUDC, net of income taxes, as a percent of net income after dividends on preferred and preference stock was 5.4% in 2013, 3.3% in 2012, and 3.9% in 2011.

Impairment of Long-Lived Assets and Intangibles

'

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

Reserves, Damages, and Recoveries

'

Natural Disaster Reserve

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 Natural Disaster Reserve (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 Natural Disaster Reserve (NDR) when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear.

As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. See Note 3 under "Retail Regulatory Matters – Natural Disaster Reserve" herein 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, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.

Financial Instruments

'

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel-hedging program. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. If any, immaterial ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations and had immaterial reclaim collateral arising from derivative instruments recognized at December 31, 2013.

The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.

Comprehensive Income

'

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.

Variable Interest Entities

'

Variable Interest Entities

The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiary of the trust. Therefore, the investment in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debt in the balance sheets.

Georgia Power [Member]

'

Summary of Significant Accounting Policies [Line Items]

'

General

'

General

Georgia Power Company (the Company) is a wholly-owned subsidiary of The Southern Company (Southern Company), which is the parent company of the Company and three other traditional operating companies, as well as Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power Company (Alabama Power), Gulf Power Company (Gulf Power), and Mississippi Power Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Hatch and Plant Vogtle.

The equity method is used for subsidiaries in which the Company has significant influence but does not control.

The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Georgia Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.

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 $504 million in 2013, $540 million in 2012, and $550 million in 2011. 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 U.S. Securities and Exchange Commission (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 $555 million in 2013, $574 million in 2012, and $537 million in 2011.

The Company has entered into several power purchase agreements (PPA) with Southern Power for capacity and energy. Expenses associated with these PPAs were $136 million, $147 million, and $171 million in 2013, 2012, and 2011, respectively. Additionally, the Company had $15 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2013 and 2012. 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 $10 million in 2013, $7 million in 2012, and $7 million in 2011. See Note 4 for additional information.

The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2013, 2012, or 2011.

See Note 4 for information regarding the Company's ownership in and a PPA with Southern Electric Generating Company (SEGCO). SEGCO plans to add natural gas as the primary fuel source for its generating units in 2015. SEGCO has entered into a joint ownership agreement with Alabama Power, which owns and operates a generating unit adjacent to the SEGCO units, for the ownership of the gas pipeline. SEGCO will own 86% of the pipeline with the remaining 14% owned by Alabama Power.

The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.

Regulatory Assets and Liabilities

'

Regulatory Assets and Liabilities

The Company is subject to the provisions of the FASB in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

2013

2012

Note

(in millions)

Retiree benefit plans

$

691

$

1,331

(a, k)

Deferred income tax charges

684

695

(b)

Deferred income tax charges — Medicare subsidy

38

43

(c)

Loss on reacquired debt

181

190

(d)

Asset retirement obligations

137

131

(b, k)

Fuel-hedging (realized and unrealized) losses

22

49

(e)

Vacation pay

88

85

(f, k)

Building leases

37

40

(g)

Cancelled construction projects

70

65

(h)

Remaining net book value of retired units

28

—

(i)

Other regulatory assets

86

100

(c)

Other cost of removal obligations

(58

)

(94

)

(b)

Deferred income tax credits

(112

)

(115

)

(b)

State income tax credits

—

(36

)

(j)

Other regulatory liabilities

(6

)

(13

)

(e)

Total regulatory assets (liabilities), net

$

1,886

$

2,471

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:

(a)

Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.

(b)

Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period of January 2014 through December 2016 in accordance with the Company's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP).

(c)

Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding nine years.

(d)

Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 39 years.

(e)

Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the Company's fuel cost recovery mechanism.

(f)

Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

(g)

See Note 6 under "Capital Leases." Recovered over the remaining lives of the buildings through 2026.

(h)

Costs associated with construction of environmental controls that will not be completed as a result of unit retirements and amortized over nine years in accordance with the 2013 ARP.

(i)

Amortization period over original remaining life beginning October 2013 through December 2022 as approved by the Georgia PSC in the 2013 ARP.

(j)

Additional tax benefits resulting from the Georgia state income tax credit settlement that were amortized over a 21-month period that began in April 2012 and ended in December 2013, in accordance with a Georgia PSC order. See Note 5 under "Current and Deferred Income Taxes" for additional information.

(k)

Not earning a return as 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 other comprehensive income (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. 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 includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. See Note 3 under "Nuclear Fuel Disposal Costs" for additional information.

Income and Other Taxes

'

Income and Other Taxes

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

Federal investment tax credits (ITCs) utilized are deferred and amortized to income as a credit to reduce depreciation over the average life of the related property. State ITCs are recognized in the period in which the credits are claimed on the state income tax return. A portion of the ITCs available to reduce income taxes payable was not utilized currently and will be carried forward and utilized in future years.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.

Property, Plant, and Equipment

'

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the cost of equity and debt funds used during construction.

The Company's property, plant, and equipment in service consisted of the following at December 31:

2013

2012

(in millions)

Generation

$

14,872

$

14,567

Transmission

4,859

4,581

Distribution

8,620

8,373

General

1,753

1,695

Plant acquisition adjustment

28

28

Total plant in service

$

30,132

$

29,244

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. Also, in accordance with a Georgia PSC order, the Company deferred the costs of certain significant inspection costs for the combustion turbine units at Plant McIntosh and amortized such costs over 10 years, which approximated the expected maintenance cycle of the units. All inspection costs were fully amortized in 2013.

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 2013, 2.9% in 2012, and 2.8% in 2011. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC and the FERC. Effective January 1, 2014, the Company's depreciation rates were revised by the Georgia PSC in connection with the 2013 ARP. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.

In 2009, the Georgia PSC approved an accounting order allowing the Company to amortize a portion of its regulatory liability related to other cost of removal obligations. Under the terms of the Company's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), the Company amortized approximately $31 million annually of the remaining regulatory liability related to other cost of removal obligations over the three years ended December 31, 2013. Under the terms of the 2013 ARP, an additional $43 million will be amortized ratably over the three years ending December 31, 2016.

Asset Retirement Obligations and Other Costs of Removal

'

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

The asset retirement obligation liability relates to the decommissioning of the Company's nuclear facilities, which include the Company's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, as well as various landfill sites, ash ponds, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with the Company's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these asset retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the asset retirement obligation. The Company will continue to recognize in the statements of income the allowed removal costs in accordance with its regulatory treatment. Any difference 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 asset retirement obligations included in the balance sheets are as follows:

2013

2012

(in millions)

Balance at beginning of year

$

1,105

$

757

Liabilities incurred

2

24

Liabilities settled

(13

)

(15

)

Accretion

55

72

Cash flow revisions

73

267

Balance at end of year

$

1,222

$

1,105

The increase in cash flow revisions is related to updated estimates for ash ponds in connection with the retirement of certain coal-fired generating units and revisions to the nuclear decommissioning asset retirement obligations based on the latest decommissioning study.

Nuclear Decommissioning

'

Nuclear Decommissioning

The U.S. Nuclear Regulatory Commission (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 Internal Revenue Service (IRS). The Funds are required to be held by one or more trustees with an individual net worth of at least $100 million. The FERC requires the Funds' managers to exercise the standard of care in investing that a "prudent investor" would use in the same circumstances. The FERC regulations also require that the Funds' managers may not invest in any securities of the utility for which it manages funds or its affiliates, except for investments tied to market indices or other mutual funds. 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 discussed 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 asset retirement obligations 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 so loaned are fully collateralized by cash, letters of credit, and securities issued or guaranteed by the U.S. government, its agencies, and the instrumentalities. As of December 31, 2013 and 2012, approximately $32 million and $91 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 $33 million and $93 million at December 31, 2013 and 2012, 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, 2013, investment securities in the Funds totaled $751 million, consisting of equity securities of $330 million, debt securities of $397 million, and $24 million of other securities. At December 31, 2012, investment securities in the Funds totaled $698 million, consisting of equity securities of $280 million, debt securities of $408 million, and $10 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 $705 million, $850 million, and $1.8 billion in 2013, 2012, and 2011, respectively, all of which were reinvested. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $61 million, of which $34 million related to unrealized gains on securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $67 million, of which $25 million related to unrealized gains on securities held in the Funds at December 31, 2012. For 2011, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $23 million, of which $9 million related to unrealized losses on securities held in the Funds at December 31, 2011. 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 and purpose for which the securities were acquired.

The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.

Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning are based on the most current study performed in 2012. The site study costs and external trust funds for decommissioning as of December 31, 2013 based on the Company's ownership interests were as follows:

Plant Hatch

Plant Vogtle

Units 1 and 2

Decommissioning periods:

Beginning year

2034

2047

Completion year

2068

2072

(in millions)

Site study costs:

Radiated structures

$

549

$

453

Spent fuel management

131

115

Non-radiated structures

51

76

Total site study costs

$

731

$

644

External trust funds

$

469

$

277

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. The Georgia PSC approved annual decommissioning costs for ratemaking of $2 million annually for Plant Hatch for 2011 through 2013. Under the 2013 ARP, the annual decommissioning cost through 2016 for ratemaking is $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4%. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs.

Allowance for Funds Used During Construction and Interest Capitalized

'

Allowance for Funds Used During Construction

In accordance with regulatory treatment, the Company records allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 2013, 2012, and 2011, the average AFUDC rates were 5.3%, 6.8%, and 7.5%, respectively, and AFUDC capitalized was $44 million, $75 million, and $134 million, respectively. AFUDC, net of income taxes, was 3.3%, 5.7%, and 10.4% of net income after dividends on preferred and preference stock for 2013, 2012, and 2011, respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information on the inclusion of construction costs related to the construction of two new nuclear generating units at Plant Vogtle (Plant Vogtle Units 3 and 4) in rate base effective January 1, 2011.

Impairment of Long-Lived Assets and Intangibles

'

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

Reserves, Damages, and Recoveries

'

Storm Damage Recovery

The Company defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Under the 2010 ARP, the Company accrued $18 million annually that was recoverable through base rates. At December 31, 2013, the Company's regulatory asset related to storm damage was $37 million, with approximately $30 million included in other regulatory assets, current and approximately $7 million included as other regulatory assets, deferred. Beginning January 1, 2014, the Company is accruing $30 million annually under the 2013 ARP. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs.

Environmental Remediation Recovery

The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. On December 17, 2013, the Georgia PSC approved the 2013 ARP including the recovery of approximately $2 million annually through the environmental compliance cost recovery (ECCR) tariff from 2014 through 2016. The Company recovered approximately $3 million annually through the ECCR tariff from 2011 through 2013 under the 2010 ARP. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and cost recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this regulatory treatment, environmental remediation liabilities generally are not expected to have a material impact on the Company's financial statements. As of December 31, 2013, the balance of the environmental remediation liability was $18 million, with approximately $2 million included in other regulatory assets, current and approximately $9 million included as other regulatory assets, deferred. See Note 3 under "Environmental Matters – Environmental Remediation" for additional information.

Cash and Cash Equivalents

'

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.

Materials and Supplies

'

Materials and Supplies

Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Fuel Inventory

'

Fuel Inventory

Fuel inventory includes the average cost of coal, natural gas, and oil, as well as transportation and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.

Financial Instruments

'

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel-hedging program. This results 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 are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2013.

The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.

Comprehensive Income

'

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.

Gulf Power [Member]

'

Summary of Significant Accounting Policies [Line Items]

'

General

'

General

Gulf Power Company (the Company) is a wholly-owned subsidiary of The Southern Company (Southern Company), which is the parent company of four traditional operating companies, as well as Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power Company (Alabama Power), Georgia Power Company (Georgia Power), and Mississippi Power Company (Mississippi Power) – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants.

The equity method is used for entities in which the Company has significant influence but does not control.

The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) and the Florida Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.

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 $78.4 million, $95.9 million, and $97.4 million during 2013, 2012, and 2011, 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 U.S. Securities and Exchange Commission (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 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 $10.2 million, $6.9 million, and $6.7 million and Mississippi Power $16.5 million, $21.1 million, and $23.4 million in 2013, 2012, and 2011, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information.

The Company entered into a power purchase agreement (PPA) with Southern Power for approximately 292 megawatts (MWs) annually from June 2009 through May 2014. Purchased power expenses associated with the PPA were $14.2 million, $14.7 million, and $14.3 million in 2013, 2012, and 2011, respectively, and fuel costs associated with the PPA were $0.8 million, $2.6 million, and $1.8 million in 2013, 2012, and 2011, respectively. These costs have been approved for recovery by the Florida PSC through the Company's fuel and purchased power capacity cost recovery clauses. Additionally, the Company had $4.2 million of deferred capacity expenses included in prepaid expenses and other regulatory liabilities, current in the balance sheets at December 31, 2013 and 2012, respectively. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.

The Company has an agreement with Georgia Power under the transmission facility cost allocation tariff for delivery of power from the Company's resources in the state of Georgia. The Company reimbursed Georgia Power $2.4 million in each of the years 2013, 2012, and 2011 for its share of related expenses.

The Company has an agreement with Alabama Power under which Alabama Power will make transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA, which was entered into in 2009 for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. Revenue requirement obligations to Alabama Power for these upgrades are estimated to be $135.0 million for the entire project. These costs began in July 2012 and will continue through 2023. The Company reimbursed Alabama Power $7.9 million and $3.0 million in 2013 and 2012, respectively, for the revenue requirements. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff.

The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2013 or 2012. In 2011, the Company provided storm restoration assistance to Alabama Power totaling $1.4 million.

The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.

Regulatory Assets and Liabilities

'

Regulatory Assets and Liabilities

The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

2013

2012

Note

(in thousands)

Deferred income tax charges

$

47,573

$

46,788

(a)

Deferred income tax charges — Medicare subsidy

3,351

3,678

(b)

Asset retirement obligations

(6,089

)

(5,793

)

(a,j)

Other cost of removal obligations

(228,148

)

(213,413

)

(a)

Deferred income tax credits

(5,238

)

(6,515

)

(a)

Loss on reacquired debt

16,565

16,400

(c)

Vacation pay

9,521

9,238

(d,j)

Under recovered regulatory clause revenues

45,191

3,523

(e)

Over recovered regulatory clause revenues

—

(17,092

)

(e)

Property damage reserve

(35,380

)

(31,956

)

(f)

Fuel-hedging (realized and unrealized) losses

17,043

29,038

(g,j)

Fuel-hedging (realized and unrealized) gains

(6,962

)

(4,358

)

(g,j)

PPA charges

180,149

137,568

(j,k)

Other regulatory assets

12,772

11,034

(l)

Environmental remediation

50,384

60,452

(h,j)

PPA credits

(7,496

)

(7,502

)

(j,k)

Other regulatory liabilities

(1,308

)

(534

)

(f)

Retiree benefit plans, net

68,296

141,429

(i,j)

Total regulatory assets (liabilities), net

$

160,224

$

171,985

Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:

(a)

Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.

(b)

Recovered and amortized over periods not exceeding 14 years.

(c)

Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years.

(d)

Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

(e)

Recorded and recovered or amortized as approved by the Florida PSC, generally within one year.

(f)

Recorded and recovered or amortized as approved by the Florida PSC.

(g)

Fuel-hedging assets and liabilities are recognized over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, costs are recovered through the fuel cost recovery clause.

(h)

Recovered through the environmental cost recovery clause when the remediation is performed.

(i)

Recovered and amortized over the average remaining service period which may range up to 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)

Recovered over the life of the PPA for periods up to 14 years.

(l)

Comprised primarily of net book value of retired meters, deferred rate case expenses, and generation site evaluation costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years, or deferred pursuant to Florida statute while the Company continues to evaluate certain potential new generating projects.

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 other comprehensive income (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's wholesale business consists of two types of agreements. The first type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where a portion of that unit is reserved for the customer. These agreements are associated with the Company's co-ownership of a unit with Georgia Power Company (Georgia Power) at Plant Scherer and consist of both capacity and energy sales. Capacity revenues represent the majority of the Company’s wholesale earnings. The Company currently has long-term sales agreements for 100% of the Company's ownership of that unit for the next two years and 57% for the next five years. The second type, referred to as requirements service, provides that the Company serves the customer's capacity and energy requirements from other Company resources.

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. Investment tax credits (ITCs) utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.

Property, Plant, and Equipment

'

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.

The Company's property, plant, and equipment in service consisted of the following at December 31:

2013

2012

(in thousands)

Generation

$

2,607,166

$

2,598,773

Transmission

473,378

429,341

Distribution

1,117,024

1,069,065

General

164,065

161,379

Plant acquisition adjustment

2,031

2,286

Total plant in service

$

4,363,664

$

4,260,844

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 3.6% in both 2013 and 2012 and 3.5% in 2011. 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.

Asset Retirement Obligations and Other Costs of Removal

'

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

The liability for asset retirement obligations primarily relates to the Company's combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, ash ponds, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these asset retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the asset retirement obligation. 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.

Allowance for Funds Used During Construction and Interest Capitalized

'

Allowance for Funds Used During Construction

In accordance with regulatory treatment, the Company records allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 6.26% for 2013, 6.72% for 2012, and 7.65% for 2011. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 6.87%, 5.36%, and 11.75% for 2013, 2012, and 2011, respectively.

Impairment of Long-Lived Assets and Intangibles

'

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

Reserves, Damages, and Recoveries

'

Property Damage Reserve

The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The costs of such damage are charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $48.0 million and $55.0 million. The Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company's discretion. The Company accrued total expenses of $3.5 million in each of 2013, 2012, and 2011. As of December 31, 2013 and 2012, the balance in the Company's property damage reserve totaled approximately $35.4 million and $32.0 million, respectively, which is included in deferred liabilities in the balance sheets.

When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. In 2013, the Florida PSC approved a settlement agreement (Settlement Agreement) that, among other things, provides for recovery of costs associated with any tropical systems named by the National Hurricane Center through the initiation of a storm surcharge. The storm surcharge will begin, on an interim basis, 60 days following the filing of a cost recovery petition. The storm surcharge generally may not exceed $4.00/1,000 kilowatt hours (KWHs) on monthly residential bills in aggregate for a calendar year. This limitation does not apply if the Company incurs in excess of $100 million in storm recovery costs that qualify for recovery in a given calendar year. This threshold amount is inclusive of the amount necessary to replenish the storm reserve to the level that existed as of December 31, 2013. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case" for details of the Settlement Agreement.

Injuries and Damages Reserve

The Company is subject to claims and lawsuits arising in the ordinary course of business. As permitted by the Florida PSC, the Company accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the reserve does not exceed $2.0 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. The injuries and damages reserve was $3.6 million and $3.1 million at December 31, 2013 and 2012, respectively. For 2013, $1.6 million and $2.0 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. For 2012, $1.6 million and $1.5 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. There were no liabilities in excess of the reserve balance at December 31, 2013 or 2012.

Cash and Cash Equivalents

'

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.

Materials and Supplies

'

Materials and Supplies

Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Fuel Inventory

'

Fuel Inventory

Fuel inventory includes the average cost of oil, natural gas, coal, transportation and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.

Financial Instruments

'

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC approved fuel-hedging program. This results 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 are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 10 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2013.

The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.

Comprehensive Income

'

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.

Mississippi Power [Member]

'

Summary of Significant Accounting Policies [Line Items]

'

General

'

General

Mississippi Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which is the parent company of the Company and three other traditional operating companies, as well as Southern Power Company (Southern Power), Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company (Alabama Power), Georgia Power Company, Gulf Power Company (Gulf Power), and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants.

The equity method is used for entities 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 Federal Energy Regulatory Commission (FERC) and the Mississippi Public Service Commission (PSC). The Company follows generally accepted accounting principles (GAAP) in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.

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 $205.0 million, $212.7 million, and $185.5 million during 2013, 2012, and 2011, 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 U.S. Securities and Exchange Commission (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 $12.5 million, $11.7 million, and $12.2 million in 2013, 2012, and 2011, respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility, which were $27.1 million, $28.1 million, and $20.9 million in 2013, 2012, and 2011, 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 $16.5 million, $21.2 million, and $23.3 million in 2013, 2012, and 2011, respectively. See Note 4 for additional information.

The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2013 or 2011. The Company received storm assistance from other Southern Company subsidiaries totaling $2.0 million in 2012.

The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.

Regulatory Assets and Liabilities

'

Regulatory Assets and Liabilities

The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:

2013

2012

Note

(in thousands)

Retiree benefit plans – regulatory assets

$

82,799

$

162,293

(a,g)

Retiree benefit plans – regulatory liabilities

(3,111

)

—

(a,g)

Property damage

(60,092

)

(58,789

)

(i)

Deferred income tax charges

140,185

68,175

(c)

Property tax

31,206

27,882

(d)

Vacation pay

10,214

9,635

(e,g)

Loss on reacquired debt

9,178

9,815

(k)

Plant Daniel Units 3 and 4 regulatory assets

18,821

12,386

(j)

Other regulatory assets

1,201

2,035

(b)

Fuel-hedging (realized and unrealized) losses

10,340

20,906

(f,g)

Asset retirement obligations

8,918

9,353

(c)

Deferred income tax credits

(10,191

)

(11,157

)

(c)

Other cost of removal obligations

(156,683

)

(143,461

)

(c)

Fuel-hedging (realized and unrealized) gains

(5,335

)

(2,519

)

(f,g)

Kemper IGCC* regulatory assets

75,873

36,047

(h)

Kemper regulatory deferral

(90,524

)

—

(h)

Other regulatory liabilities

(409

)

—

(b)

Deferred income tax charges – Medicare subsidy

4,214

4,868

(l)

Total regulatory assets (liabilities), net

$

66,604

$

147,469

*    Integrated coal gasification combined cycle electric generating plant located in Kemper County, Mississippi (Kemper IGCC).

Note:    The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:

(a)

Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.

(b)

Recorded and recovered as approved by the Mississippi PSC.

(c)

Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.

(d)

Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information.

(e)

Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

(f)

Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the Energy Cost Management clause (ECM).

(g)

Not earning a return as offset in rate base by a corresponding asset or liability.

(h)

For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle."

(i)

For additional information, see Note 1 under "Provision for Property Damage" and Note 3 under "Retail Regulatory Matters – System Restoration Rider."

(j)

Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term.

(k)

Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.

(l)

Recovered and amortized over a 10-year period beginning in 2012, as approved by the Mississippi PSC for the retail portion and a five-year period for the wholesale portion, as approved by FERC.

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 other comprehensive income (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 2008, the Company requested that the U.S. Department of Energy (DOE) transfer the remaining funds previously granted under the Clean Coal Power Initiative Round 2 (DOE Grants) from a cancelled integrated coal gasification combined cycle project of one of Southern Company's subsidiaries that would have been located in Orlando, Florida. In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270.0 million of the Kemper IGCC through the DOE Grants funds. Through December 31, 2013, the Company has received grant funds of $245.3 million, used for the construction of the Kemper IGCC, which is reflected in the Company's financial statements as a reduction to the Kemper IGCC capital costs. An additional $25 million is expected to be received for its initial operation.

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 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 electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 22.2% of the Company's total operating revenues in 2013 and are largely subject to rolling 10-year cancellation notices.

The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.

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. Investment tax credits (ITCs) utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.

Property, Plant, and Equipment

'

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction for projects where recovery of construction work in progress (CWIP) is not allowed in rates.

The Company's property, plant, and equipment in service consisted of the following at December 31:

2013

2012

(in thousands)

Generation

$

1,475,264

$

1,363,269

Transmission

633,903

563,037

Distribution

828,470

802,718

General

439,721

225,723

Plant acquisition adjustment

81,412

81,412

Total plant in service

$

3,458,770

$

3,036,159

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 lignite mine for the Kemper IGCC and a portion of the railway track maintenance costs, which are charged to fuel stock and recovered through the Company's fuel clause.

Purchase of Plant Under Lease Obligation

'

Purchase of the Plant Daniel Combined Cycle Generating Units

In 2011, the Company purchased the combined cycle generating Units 3 and 4 at Plant Daniel (Plant Daniel Units 3 and 4) for $84.8 million in cash and the assumption of $270.0 million face value of debt obligations of the lessor related to Plant Daniel Units 3 and 4, which mature in 2021, bear interest at a fixed stated interest rate of 7.13% per annum, and had a fair value at the time of purchase of $346.1 million. These obligations are secured by Plant Daniel Units 3 and 4 and certain personal property. The fair value of the debt was determined using a discounted cash flow model based on the Company's borrowing rate at the closing date. The fair value is considered a Level 2 disclosure for financial reporting purposes. Accordingly, Plant Daniel Units 3 and 4 were reflected in the Company's financial statements as follows:

(in thousands)

Assumption of debt obligations

$

270,000

Fair value adjustment at date of purchase

76,051

Total debt

346,051

Cash payment for the purchase

84,803

Total value of Plant Daniel Units 3 and 4

$

430,854

See Note 3 under "Retail Regulatory Matters – Performance Evaluation Plan" for additional information.

Depreciation and Amortization

'

Depreciation, Depletion, and Amortization

Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.4% in 2013, 3.5% in 2012, and 3.9% in 2011. Depreciation studies are conducted periodically to update the composite rates. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities.

The Company, in compliance with FERC guidance, classified $81.4 million as a plant acquisition adjustment on the purchase of Plant Daniel Units 3 and 4. This includes $76.1 million recorded in conjunction with the premium on long-term debt and is being amortized over 10 years beginning October 2011. See "Purchase of the Plant Daniel Combined Cycle Generating Units" herein for additional information.

In January 2012, the Mississippi PSC issued an order allowing the Company to defer in a regulatory asset the difference between the revenue requirement under the purchase option of Plant Daniel Units 3 and 4 and the revenue requirement assuming operating lease accounting treatment for the extended term. The regulatory asset will be deferred for a 10-year period ending October 2021. At the conclusion of the deferral period, the unamortized deferral balance will be amortized into rates over the remaining life of the units.

The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation on June 5, 2013. Depreciation associated with fixed assets, amortization associated with rolling stock, and depletion associated with minerals and minerals rights will be recognized and charged to fuel stock and recovered through the Company’s fuel clause.

Asset Retirement Obligations and Other Costs of Removal

'

Asset Retirement Obligations and Other Costs of Removal

Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.

The Company has AROs related to various landfill sites, ash ponds, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified AROs related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the AROs related to these assets is indeterminable and, therefore, the fair value of the AROs cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of 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 Mississippi PSC, and are reflected in the balance sheets.

Details of the ARO included in the balance sheets are as follows:

2013

2012

(in thousands)

Balance at beginning of year

$

42,115

$

19,148

Liabilities incurred

—

20,989

Liabilities settled

(24

)

(282

)

Accretion

1,840

1,874

Cash flow revisions

(2,021

)

386

Balance at end of year

$

41,910

$

42,115

Allowance for Funds Used During Construction and Interest Capitalized

'

Allowance for Funds Used During Construction

In accordance with regulatory treatment, the Company records allowance for funds used during construction (AFUDC), which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 6.89%, 7.04%, and 7.06% for the years ended December 31, 2013, 2012, and 2011, respectively.

Impairment of Long-Lived Assets and Intangibles

'

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

Reserves, Damages, and Recoveries

'

Provision for Property Damage

The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. In 2009, the Mississippi PSC approved the System Restoration Rider (SRR) stipulation between the Company and the Mississippi Public Utilities Staff (MPUS). In accordance with the stipulation, every three years the Mississippi PSC, MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. Each year the Company will set rates to collect the approved SRR revenues. 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 2013, 2012, and 2011, the Company made retail accruals of $3.2 million, $3.5 million, and $3.8 million, respectively, per the annual SRR rate filings. 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. See Note 3 under "Retail Regulatory Matters – System Restoration Rider" for additional information. The Company accrued $0.3 million annually in 2013, 2012, and 2011 for the wholesale jurisdiction.

Cash and Cash Equivalents

'

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.

Materials and Supplies

'

Materials and Supplies

Generally, materials and supplies include the average cost of transmission, distribution, mining, and generating plant materials. Materials are charged to inventory when purchased and then expensed, capitalized to plant, or charged to fuel stock, as appropriate, at weighted-average cost when utilized.

Fuel Inventory

'

Fuel Inventory

Fuel inventory includes the average cost of coal, lignite, natural gas, oil, transportation and emissions allowances. Fuel is charged to inventory when purchased, except for the cost of owning and operating the lignite mine related to the Kemper IGCC which is charged to inventory as incurred, and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates. The retail rate is approved by the Mississippi PSC and the wholesale rates are approved by the FERC. Emissions allowances granted by the U.S. Environmental Protection Agency (EPA) are included in inventory at zero cost.

Financial Instruments

'

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information. 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. This results in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Foreign currency exchange rate hedges are designated as fair value hedges. Settled foreign currency exchange hedges are recorded in CWIP. Any ineffectiveness arising from these would be recognized currently in net income; however, the Company has regulatory approval allowing it to defer any ineffectiveness arising from hedging instruments relating to the Kemper IGCC to a regulatory asset. Other derivative contracts are marked to market through current period income and are recorded on a net basis in the statements of income. The amounts related to derivatives on the cash flow statement are classified in the same category as the items being hedged. See Note 10 for additional information.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2013.

The Company has an ECM clause which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company's jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC.

The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.

Comprehensive Income

'

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.

Variable Interest Entities

'

Variable Interest Entities

The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

The Company is required to provide financing for all costs associated with the mine development and operation under a contract with Liberty Fuels Company, LLC, a subsidiary of North American Coal Corporation (Liberty Fuels), in conjunction with the construction of the Kemper IGCC. Liberty Fuels qualifies as a VIE for which the Company is the primary beneficiary. For the year ended December 31, 2013, the VIE consolidation resulted in an ARO and an associated liability in the amounts of $21.0 million and $22.7 million, respectively. For the year ended December 31, 2012, the VIE consolidation resulted in an ARO and an associated liability in the amounts of $21.0 million and $21.8 million, respectively. For the year ended 2011, Liberty Fuels did not have a material impact on the financial position and results of operations of the Company. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information.

Southern Power [Member]

'

Summary of Significant Accounting Policies [Line Items]

'

General

'

General

Southern Power Company is a wholly-owned subsidiary of The Southern Company (Southern Company), which is also the parent company of four traditional operating companies, Southern Company Services, Inc. (SCS), Southern Communications Services, Inc. (SouthernLINC Wireless), Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear Operating Company, Inc. (Southern Nuclear), and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power Company, Georgia Power Company (Georgia Power), Gulf Power Company, and Mississippi Power Company – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) construct, acquire, own, and manage generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants.

Southern Power Company and certain of its generation subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC). The Company follows generally accepted accounting principles (GAAP). The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.

The financial statements include the accounts of Southern Power Company and its wholly-owned subsidiaries, Southern Company - Florida LLC, Oleander Power Project, LP, and Nacogdoches Power LLC, which own, operate, and maintain the Company's ownership interests in Plants Stanton Unit A, Oleander, and Nacogdoches, respectively. The financial statements also include the accounts of Southern Power Company's wholly-owned subsidiary, Southern Renewable Energy, Inc. (SRE). SRE was formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. Through Southern Turner Renewable Energy LLC (STR), a jointly-owned subsidiary owned 90% by SRE and 10% by Turner Renewable Energy, LLC (TRE), SRE and its subsidiaries own, operate, and maintain Plants Cimarron, Apex, Granville, Spectrum, and Campo Verde. All intercompany accounts and transactions have been eliminated in consolidation.

Affiliate Transactions

'

Affiliate Transactions

Southern Power Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations, construction management, and transactions associated with the Southern Company system's fleet of generating units. Because the Company has no employees, all employee-related charges are rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for these services from SCS amounted to approximately $117.6 million in 2013, $125.4 million in 2012, and $112.7 million in 2011. Approximately $114.3 million in 2013, $107.7 million in 2012, and $87.9 million in 2011 were operations and maintenance expenses; the remainder was recorded to plant in service. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the U.S. Securities and Exchange Commission (SEC). Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.

The Company has several agreements with SCS for transmission services. Transmission purchased from affiliates totaled $8.3 million in 2013, $6.6 million in 2012, and $7.1 million in 2011. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC.

Total billings for all power purchase agreements (PPAs) with affiliates totaled $148.4 million, $159.9 million, and $175.9 million in 2013, 2012, and 2011, respectively. The deferred amounts outstanding were $17.6 million and $19.0 million as of December 31, 2013 and 2012, respectively, which are recorded as "Deferred capacity revenues – affiliated" on the balance sheets. Revenue recognized under affiliate PPAs accounted for as operating leases totaled $69.0 million, $76.2 million, and $75.6 million in 2013, 2012, and 2011, respectively. The Company and the traditional operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information.

The Company and the traditional operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.

Acquisition Accounting

'

Acquisition Accounting

The Company acquires generation assets as part of its overall growth strategy. The Company accounts for business acquisitions from non-affiliates as business combinations. Accordingly, the Company has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition was allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business in accordance with GAAP are accounted for as asset acquisitions. The purchase price of each asset acquisition was allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions have been expensed as incurred.

Revenues

'

Revenues

The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements.

The Company may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 for further information.

Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. All revenues under solar PPAs are accounted for as contingent revenues and recognized as services are performed. Transmission revenues and other fees are recognized as earned as other operating revenues. Revenues are recorded on a gross basis for all full requirements PPAs. See "Financial Instruments" herein for additional information.

Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. For the year ended December 31, 2013, Florida Power & Light Company (FPL) accounted for 11.8% of total revenues, Georgia Power accounted for 10.7% of total revenues, and Duke Energy Corporation (resulting from a merger between Duke Energy Corporation and Progress Energy, Inc.) accounted for 10.3% of total revenues. For the year ended December 31, 2012, FPL accounted for 12.8% of total revenues, Georgia Power accounted for 12.5% of total revenues, and Progress Energy Florida, Inc. accounted for 5.9% of total revenues. For the year ended December 31, 2011, FPL accounted for 14.7% of total revenues, Georgia Power accounted for 14% of total revenues, and Progress Energy Carolinas, Inc. accounted for 8.3% of total revenues.

Fuel Costs

'

Fuel Costs

Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur.

Income and Other Taxes

'

Income and Other Taxes

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.

Under the American Recovery and Reinvestment Act of 2009 (ARRA), certain projects are eligible for investment tax credits (ITCs) or cash grants. The Company has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Credits amortized in this manner amount to $5.5 million and $2.6 million in 2013 and 2012, respectively. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense as costs are incurred during the construction period. At December 31, 2013, all ITCs available to reduce federal income taxes payable have been utilized. Additionally, state ITCs are recognized at the time the credit is claimed on the state income tax return. A portion of the state ITCs available to reduce state income taxes payable were not utilized currently and will be carried forward and utilized in future years.

In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.

Property, Plant, and Equipment

'

Property, Plant, and Equipment

The Company's depreciable property, plant, and equipment consists entirely of generation assets.

Property, plant, and equipment is stated at original cost. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, minor items of property, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred.

Depreciation and Amortization

'

Depreciation

Depreciation of the original cost of assets is computed under the straight-line method and applies a composite depreciation rate based on the assets' estimated useful lives determined by the Company. The primary assets in property, plant, and equipment are power plants, which have estimated composite depreciable lives ranging from 18 to 34 years. These lives reflect a composite of the significant components (retirement units) that make up the plants. 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.

When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.

Beginning in 2014, the Company changed to component depreciation. Certain generation assets will be depreciated on a units-of-production basis to better match outage and maintenance costs to the usage of and revenues from these assets.

Impairment of Long-Lived Assets and Intangibles

'

Impairment of Long-Lived Assets and Intangibles

The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist of acquired PPAs that are amortized over the term of the PPA and goodwill resulting from acquisitions. The average term of these PPAs is 20 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.

The amortization expense for the acquired PPAs is as follows:

Amortization

Expense

(in millions)

2013

$

2.5

2014

2.5

2015

2.5

2016

2.5

2017

2.5

2018 and beyond

33.5

Total

$

46

Deferred Project Development Costs

'

Deferred Project Development Costs

The Company capitalizes project development costs once it is determined that it is probable that a specific site will be acquired and a plant constructed. These costs include professional services, permits, and other costs directly related to the construction of a project. In addition, the Company has acquired emission reduction credits necessary for future unspecified construction in areas designated by the U.S. Environmental Protection Agency (EPA) as non-attainment areas for nitrogen oxide or volatile organic compound emissions. These credits are reflected on the balance sheets at historical cost. Deferred project development costs, including the cost of emission reduction offsets to be surrendered, are generally transferred to construction work in progress (CWIP) upon commencement of construction. The total deferred project development costs were $11.2 million at December 31, 2013 and 2012.

Cash and Cash Equivalents

'

Cash and Cash Equivalents

For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.

Materials and Supplies

'

Materials and Supplies

Generally, materials and supplies include the average cost of generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Fuel Inventory

'

Fuel Inventory

Fuel inventory includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost.

Financial Instruments

'

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 8 for additional information. 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. Other derivative contracts qualify as cash flow hedges of anticipated transactions. This results in the deferral of related gains and losses in accumulated other comprehensive income (AOCI) until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. See Note 9 for additional information. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item.

The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2013.

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.

Other Income and (Expense)

'

Other Income and (Expense)

Other income and (expense) includes non-operating revenues and expenses. Revenues are recognized when earned and expenses are recognized when incurred.

Comprehensive Income

'

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications of amounts included in net income.

Variable Interest Entities

'

Variable Interest Entities

The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

The Company has certain wholly-owned subsidiaries that are determined to be VIEs. The Company is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
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:
		2013				2012			Note
		(in millions)
	Deferred income tax charges	$	1,376			$	1,318		(a)
	Deferred income tax charges — Medicare subsidy	65				72			(j)
	Asset retirement obligations-asset	145				141			(a,h)
	Asset retirement obligations-liability	(139		)		(71		)	(a,h)
	Other cost of removal obligations	(1,289		)		(1,225		)	(a)
	Deferred income tax credits	(203		)		(212		)	(a)
	Loss on reacquired debt	293				309			(b)
	Vacation pay	171				165			(c,h)
	Under recovered regulatory clause revenues	70				38			(d)
	Property damage reserves	(191		)		(193		)	(g)
	Cancelled construction projects	70				65			(m)
	Power purchase agreement charges	180				138			(h,n)
	Fuel-hedging-asset	58				118			(h,o)
	Other regulatory assets	337				276			(f)
	Environmental remediation-asset	62				74			(g,h)
	Other regulatory liabilities	(126		)		(100		)	(b,l,i)
	Kemper IGCC* regulatory assets	76				36			(k)
	Kemper regulatory deferral	(91		)		—			(k)
	Retiree benefit plans	1,760				3,373			(e,h)
	Total regulatory assets (liabilities), net	$	2,624			$	4,322
	*	Integrated coal gasification combined cycle electric generating plant located in Kemper County, Mississippi (Kemper IGCC).
	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 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period from January 2014 through December 2016 in accordance with Georgia Power's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP). See Note 3 under "Retail Regulatory Matters" for additional information.
	(b)	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.
	(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 appropriate state PSCs over periods generally not exceeding 10 years.
	(e)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.
	(f)	Comprised of numerous immaterial components including storm damage reserves, nuclear and generating plant outage costs, property taxes, post-retirement benefits, generation site selection/evaluation costs, power purchase agreement (PPA) capacity, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4 regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding, as applicable, 10 years or over the remaining life of the asset but not beyond 2031.
	(g)	Recovered as storm restoration and potential reliability-related expenses or environmental remediation expenses are incurred as approved by the appropriate state PSCs.
	(h)	Not earning a return as offset in rate base by a corresponding asset or liability.
	(i)	Recovered and amortized as approved or accepted by the appropriate state PSC over the life of the contract.
	(j)	Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years.
	(k)	For additional information, See Note 3 under "Integrated Coal Gasification Combined Cycle."
	(l)	Comprised of immaterial components including over recovered regulatory clause revenues, state income tax credits, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years, except for PPA credits that are recovered over the life of the PPA for periods up to 14 years.
	(m)	Costs associated with construction of environmental controls that will not be completed as a result of unit retirements and amortized over nine years in accordance with the 2013 ARP.
	(n)	Recovered over the life of the PPA for periods up to 14 years.
	(o)	Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.
Property Plant and Equipment	'
	The Southern Company system's property, plant, and equipment in service consisted of the following at December 31:
		2013				2012
		(in millions)
	Generation	$	35,360			$	33,444
	Transmission	9,289				8,747
	Distribution	16,499				15,958
	General	3,958				4,208
	Plant acquisition adjustment	123				124
	Utility plant in service	65,229				62,481
	Information technology equipment and software	242				230
	Communications equipment	437				430
	Other	113				110
	Other plant in service	792				770
	Total plant in service	$	66,021			$	63,251
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,
		2013				2012
		(in millions)
	Office building	$	61			$	61
	Nitrogen plant	83				—
	Computer-related equipment	62				58
	Gas pipeline	6				—
	Less: Accumulated amortization	(48		)		(39		)
	Balance, net of amortization	$	164			$	80
Acquisitions	'
	Acquisitions entered into or made by Southern Power and Turner Renewable Energy through Southern Turner Renewable Energy, LLC during 2013 and 2012 are detailed in the table below:
		MW Capacity*		Year of Operation	Party Under PPA Contract for Plant Output	PPA Contract Period	Purchase Price
							(millions)
	Adobe Solar, LLC (a)	20		2014	Southern California Edison Company	20 years	$100.00
	Campo Verde Solar, LLC (b)	139		2013	San Diego Gas & Electric Company	20 years	$136.60
	Spectrum Nevada Solar, LLC (c)	30		2013	Nevada Power Company	25 years	$17.60
	Apex Nevada Solar, LLC	20		2012	Nevada Power Company	25 years	$102.00
	* megawatt (MW)
	(a) This acquisition is expected to occur in spring 2014, and the purchase price is expected to be $100 million.
	(b) Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar Inc. to complete the construction of the solar facility.
	(c) Under an engineering, procurement, and construction agreement, an additional $104 million was paid to a subsidiary of Sun Edison, LLC to complete the construction of the solar facility.
Asset Retirement Obligations and Other Costs of Removal	'
	Details of the asset retirement obligations included in the balance sheets are as follows:
		2013				2012
		(in millions)
	Balance at beginning of year	$	1,757			$	1,344
	Liabilities incurred	6				45
	Liabilities settled	(16		)		(16		)
	Accretion	97				112
	Cash flow revisions	174				272
	Balance at end of year	$	2,018			$	1,757
Accumulated Provisions for Decommissioning	'
	At December 31, 2013 and 2012, the accumulated provisions for decommissioning were as follows:
		External Trust Funds							Internal Reserves							Total
		2013				2012			2013			2012				2013		2012
		(in millions)
	Plant Farley	$	713			$	604		$	21		$	22			$	734	$	626
	Plant Hatch	469				435			—			—				469		435
	Plant Vogtle Units 1 and 2	277				256			—			—				277		256
Estimated Cost of Decommissioning	'
	The estimated costs of decommissioning as of December 31, 2013 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2012 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2:
		Plant Farley				Plant Hatch			Plant Vogtle
									Units 1 and 2
	Decommissioning periods:
	Beginning year	2037				2034			2047
	Completion year	2076				2068			2072
		(in millions)
	Site study costs:
	Radiated structures	$	1,362			$	680		$	568
	Non-radiated structures	80				51			76
	Total site study costs	$	1,442			$	731		$	644
Net Investments in Leveraged Leases	'
	Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31:
		2013				2012
		(in millions)
	Net rentals receivable	$	1,440			$	1,214
	Unearned income	(775		)		(544		)
	Investment in leveraged leases	665				670
	Deferred taxes from leveraged leases	(287		)		(278		)
	Net investment in leveraged leases	$	378			$	392
Components of Income from Leveraged Leases	'
	A summary of the components of income from the leveraged leases follows:
		2013				2012			2011
		(in millions)
	Pretax leveraged lease income (loss)	$	(5	)		$	21		$	25
	Income tax expense	2				(8		)	(9		)
	Net leveraged lease income (loss)	$	(3	)		$	13		$	16
Accumulated Other Comprehensive Income (Loss) Balances, Net of Tax Effects	'
	Accumulated OCI (loss) balances, net of tax effects, were as follows:
		Qualifying				Marketable			Pension and Other				Accumulated Other
		Hedges				Securities			Postretirement				Comprehensive
									Benefit Plans				Income (Loss)
		(in millions)
	Balance at December 31, 2012	$	(45	)		$	3		$	(81	)		$	(123	)
	Current period change	9				(3		)	42				48
	Balance at December 31, 2013	$	(36	)		$	—		$	(39	)		$	(75	)
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:
		2013				2012			Note
		(in millions)
	Deferred income tax charges	$	519			$	525		(a,k)
	Loss on reacquired debt	86				93			(b)
	Vacation pay	63				61			(c,j)
	Under/(over) recovered regulatory clause revenues	(18		)		34			(d)
	Fuel-hedging (realized and unrealized) losses	8				18			(e)
	Other regulatory assets	52				51			(f)
	Asset retirement obligations	(132		)		(64		)	(a)
	Other cost of removal obligations	(828		)		(759		)	(a)
	Deferred income tax credits	(75		)		(79		)	(a)
	Fuel-hedging (realized and unrealized) gains	(8		)		(5		)	(e)
	Nuclear outage	51				33			(d)
	Natural disaster reserve	(96		)		(103		)	(h)
	Other regulatory liabilities	(11		)		(13		)	(d,g)
	Retiree benefit plans	461				911			(i,j)
	Regulatory deferrals	20				—			(l)
	Total regulatory assets (liabilities), net	$	92			$	703
	Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
	(a)	Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.
	(b)	Recovered over the remaining life of the original issue, which may range up to 50 years.
	(c)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.
	(d)	Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding ten years.
	(e)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.
	(f)	Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable.
	(g)	Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities.
	(h)	Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC.
	(i)	Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information.
	(j)	Not earning a return as offset in rate base by a corresponding asset or liability.
	(k)	Included in the deferred income tax charges are $20 million for 2013 and $21 million for 2012 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 2015 through 2017.
Property Plant and Equipment	'
	The Company's property, plant, and equipment in service consisted of the following at December 31:
		2013				2012
		(in millions)
	Generation	$	11,314			$	11,110
	Transmission	3,287				3,137
	Distribution	5,934				5,714
	General	1,545				1,434
	Plant acquisition adjustment	12				12
	Total plant in service	$	22,092			$	21,407
Asset Retirement Obligations and Other Costs of Removal	'
	Details of the asset retirement obligations included in the balance sheets are as follows:
		2013				2012
		(in millions)
	Balance at beginning of year	$	589			$	553
	Liabilities incurred	—				—
	Liabilities settled	(1		)		(1		)
	Accretion	40				37
	Cash flow revisions (a)	102				—
	Balance at end of year	$	730			$	589
	(a) Updated based on results from the 2013 nuclear decommissioning study
Accumulated Provisions for Decommissioning	'
	At December 31, the accumulated provisions for decommissioning were as follows:
		2013				2012
		(in millions)
	External trust funds	$	713			$	604
	Internal reserves	21				22
	Total	$	734			$	626
Estimated Cost of Decommissioning	'
	The estimated costs of decommissioning as of December 31, 2013 based on the most current study performed in 2013 for Plant Farley are as follows:
	Decommissioning periods:
	Beginning year	2037
	Completion year	2076
		(in millions)
	Site study costs:
	Radiated structures	$	1,362
	Non-radiated structures	80
	Total site study costs	$	1,442
Gulf Power [Member]	'
Summary of Significant Accounting Policies [Line Items]	'
Regulatory Assets and Liabilities	'
	Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
		2013				2012			Note
		(in thousands)
	Deferred income tax charges	$	47,573			$	46,788		(a)
	Deferred income tax charges — Medicare subsidy	3,351				3,678			(b)
	Asset retirement obligations	(6,089		)		(5,793		)	(a,j)
	Other cost of removal obligations	(228,148		)		(213,413		)	(a)
	Deferred income tax credits	(5,238		)		(6,515		)	(a)
	Loss on reacquired debt	16,565				16,400			(c)
	Vacation pay	9,521				9,238			(d,j)
	Under recovered regulatory clause revenues	45,191				3,523			(e)
	Over recovered regulatory clause revenues	—				(17,092		)	(e)
	Property damage reserve	(35,380		)		(31,956		)	(f)
	Fuel-hedging (realized and unrealized) losses	17,043				29,038			(g,j)
	Fuel-hedging (realized and unrealized) gains	(6,962		)		(4,358		)	(g,j)
	PPA charges	180,149				137,568			(j,k)
	Other regulatory assets	12,772				11,034			(l)
	Environmental remediation	50,384				60,452			(h,j)
	PPA credits	(7,496		)		(7,502		)	(j,k)
	Other regulatory liabilities	(1,308		)		(534		)	(f)
	Retiree benefit plans, net	68,296				141,429			(i,j)
	Total regulatory assets (liabilities), net	$	160,224			$	171,985
	Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
	(a)	Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.
	(b)	Recovered and amortized over periods not exceeding 14 years.
	(c)	Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years.
	(d)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.
	(e)	Recorded and recovered or amortized as approved by the Florida PSC, generally within one year.
	(f)	Recorded and recovered or amortized as approved by the Florida PSC.
	(g)	Fuel-hedging assets and liabilities are recognized over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, costs are recovered through the fuel cost recovery clause.
	(h)	Recovered through the environmental cost recovery clause when the remediation is performed.
	(i)	Recovered and amortized over the average remaining service period which may range up to 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)	Recovered over the life of the PPA for periods up to 14 years.
	(l)	Comprised primarily of net book value of retired meters, deferred rate case expenses, and generation site evaluation costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years, or deferred pursuant to Florida statute while the Company continues to evaluate certain potential new generating projects.
Property Plant and Equipment	'
	The Company's property, plant, and equipment in service consisted of the following at December 31:
		2013				2012
		(in thousands)
	Generation	$	2,607,166			$	2,598,773
	Transmission	473,378				429,341
	Distribution	1,117,024				1,069,065
	General	164,065				161,379
	Plant acquisition adjustment	2,031				2,286
	Total plant in service	$	4,363,664			$	4,260,844
Asset Retirement Obligations and Other Costs of Removal	'
	Details of the asset retirement obligations included in the balance sheets are as follows:
		2013				2012
		(in thousands)
	Balance at beginning of year	$	16,055			$	10,729
	Liabilities incurred	518				—
	Liabilities settled	(1,913		)		(107		)
	Accretion	751				507
	Cash flow revisions	773				4,926
	Balance at end of year	$	16,184			$	16,055
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:
		2013				2012			Note
		(in millions)
	Retiree benefit plans	$	691			$	1,331		(a, k)
	Deferred income tax charges	684				695			(b)
	Deferred income tax charges — Medicare subsidy	38				43			(c)
	Loss on reacquired debt	181				190			(d)
	Asset retirement obligations	137				131			(b, k)
	Fuel-hedging (realized and unrealized) losses	22				49			(e)
	Vacation pay	88				85			(f, k)
	Building leases	37				40			(g)
	Cancelled construction projects	70				65			(h)
	Remaining net book value of retired units	28				—			(i)
	Other regulatory assets	86				100			(c)
	Other cost of removal obligations	(58		)		(94		)	(b)
	Deferred income tax credits	(112		)		(115		)	(b)
	State income tax credits	—				(36		)	(j)
	Other regulatory liabilities	(6		)		(13		)	(e)
	Total regulatory assets (liabilities), net	$	1,886			$	2,471
	Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
	(a)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.
	(b)	Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period of January 2014 through December 2016 in accordance with the Company's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP).
	(c)	Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding nine years.
	(d)	Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 39 years.
	(e)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the Company's fuel cost recovery mechanism.
	(f)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.
	(g)	See Note 6 under "Capital Leases." Recovered over the remaining lives of the buildings through 2026.
	(h)	Costs associated with construction of environmental controls that will not be completed as a result of unit retirements and amortized over nine years in accordance with the 2013 ARP.
	(i)	Amortization period over original remaining life beginning October 2013 through December 2022 as approved by the Georgia PSC in the 2013 ARP.
	(j)	Additional tax benefits resulting from the Georgia state income tax credit settlement that were amortized over a 21-month period that began in April 2012 and ended in December 2013, in accordance with a Georgia PSC order. See Note 5 under "Current and Deferred Income Taxes" for additional information.
	(k)	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:
		2013				2012
		(in millions)
	Generation	$	14,872			$	14,567
	Transmission	4,859				4,581
	Distribution	8,620				8,373
	General	1,753				1,695
	Plant acquisition adjustment	28				28
	Total plant in service	$	30,132			$	29,244
Asset Retirement Obligations and Other Costs of Removal	'
	Details of the asset retirement obligations included in the balance sheets are as follows:
		2013				2012
		(in millions)
	Balance at beginning of year	$	1,105			$	757
	Liabilities incurred	2				24
	Liabilities settled	(13		)		(15		)
	Accretion	55				72
	Cash flow revisions	73				267
	Balance at end of year	$	1,222			$	1,105
Accumulated Provisions for Decommissioning	'
	The site study costs and external trust funds for decommissioning as of December 31, 2013 based on the Company's ownership interests were as follows:
		Plant Hatch				Plant Vogtle
						Units 1 and 2
	Decommissioning periods:
	Beginning year	2034				2047
	Completion year	2068				2072
		(in millions)
	Site study costs:
	Radiated structures	$	549			$	453
	Spent fuel management	131				115
	Non-radiated structures	51				76
	Total site study costs	$	731			$	644
	External trust funds	$	469			$	277
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:
		2013				2012			Note
		(in thousands)
	Retiree benefit plans – regulatory assets	$	82,799			$	162,293		(a,g)
	Retiree benefit plans – regulatory liabilities	(3,111		)		—			(a,g)
	Property damage	(60,092		)		(58,789		)	(i)
	Deferred income tax charges	140,185				68,175			(c)
	Property tax	31,206				27,882			(d)
	Vacation pay	10,214				9,635			(e,g)
	Loss on reacquired debt	9,178				9,815			(k)
	Plant Daniel Units 3 and 4 regulatory assets	18,821				12,386			(j)
	Other regulatory assets	1,201				2,035			(b)
	Fuel-hedging (realized and unrealized) losses	10,340				20,906			(f,g)
	Asset retirement obligations	8,918				9,353			(c)
	Deferred income tax credits	(10,191		)		(11,157		)	(c)
	Other cost of removal obligations	(156,683		)		(143,461		)	(c)
	Fuel-hedging (realized and unrealized) gains	(5,335		)		(2,519		)	(f,g)
	Kemper IGCC* regulatory assets	75,873				36,047			(h)
	Kemper regulatory deferral	(90,524		)		—			(h)
	Other regulatory liabilities	(409		)		—			(b)
	Deferred income tax charges – Medicare subsidy	4,214				4,868			(l)
	Total regulatory assets (liabilities), net	$	66,604			$	147,469
	*    Integrated coal gasification combined cycle electric generating plant located in Kemper County, Mississippi (Kemper IGCC).
	Note:    The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
	(a)	Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.
	(b)	Recorded and recovered as approved by the Mississippi PSC.
	(c)	Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.
	(d)	Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information.
	(e)	Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.
	(f)	Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the Energy Cost Management clause (ECM).
	(g)	Not earning a return as offset in rate base by a corresponding asset or liability.
	(h)	For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle."
	(i)	For additional information, see Note 1 under "Provision for Property Damage" and Note 3 under "Retail Regulatory Matters – System Restoration Rider."
	(j)	Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term.
	(k)	Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.
	(l)	Recovered and amortized over a 10-year period beginning in 2012, as approved by the Mississippi PSC for the retail portion and a five-year period for the wholesale portion, as approved by FERC.
Property Plant and Equipment	'
	The Company's property, plant, and equipment in service consisted of the following at December 31:
		2013				2012
		(in thousands)
	Generation	$	1,475,264			$	1,363,269
	Transmission	633,903				563,037
	Distribution	828,470				802,718
	General	439,721				225,723
	Plant acquisition adjustment	81,412				81,412
	Total plant in service	$	3,458,770			$	3,036,159
Purchase of the Plant Daniel Combined Cycle Generating Units	'
	The fair value is considered a Level 2 disclosure for financial reporting purposes. Accordingly, Plant Daniel Units 3 and 4 were reflected in the Company's financial statements as follows:
		(in thousands)
	Assumption of debt obligations	$	270,000
	Fair value adjustment at date of purchase	76,051
	Total debt	346,051
	Cash payment for the purchase	84,803
	Total value of Plant Daniel Units 3 and 4	$	430,854
Asset Retirement Obligations and Other Costs of Removal	'
	Details of the ARO included in the balance sheets are as follows:
		2013				2012
		(in thousands)
	Balance at beginning of year	$	42,115			$	19,148
	Liabilities incurred	—				20,989
	Liabilities settled	(24		)		(282		)
	Accretion	1,840				1,874
	Cash flow revisions	(2,021		)		386
	Balance at end of year	$	41,910			$	42,115
Southern Power [Member]	'
Summary of Significant Accounting Policies [Line Items]	'
Future Amortization Expense for PPAs	'
	The amortization expense for the acquired PPAs is as follows:
		Amortization
		Expense
		(in millions)
	2013	$	2.5
	2014	2.5
	2015	2.5
	2016	2.5
	2017	2.5
	2018 and beyond	33.5
	Total	$	46

Retirement_Benefits_Tables

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]	'
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans	'
	Actuarial Assumptions
	The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.52% and 5.40%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.02	%		4.26	%		4.98	%
	Other postretirement benefit plans	4.85			4.05			4.88
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	7.13			7.29			7.39
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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in millions)
	Benefit obligation	$	103			$	(88	)
	Service and interest costs	5				(4		)
Changes in projected benefit obligations and fair value of plan assets	'
	Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2013 and 2012 were as follows:
		2013				2012
		(in millions)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	9,302			$	8,079
	Service cost	232				198
	Interest cost	389				393
	Benefits paid	(357		)		(336		)
	Actuarial (gain) loss	(703		)		968
	Balance at end of year	8,863				9,302
	Change in plan assets
	Fair value of plan assets at beginning of year	7,953				6,800
	Actual return on plan assets	1,098				1,010
	Employer contributions	39				479
	Benefits paid	(357		)		(336		)
	Fair value of plan assets at end of year	8,733				7,953
	Accrued liability	$	(130	)		$	(1,349	)
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, 2013 and 2012 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 2014.
		Prior Service Cost				Net (Gain) Loss
		(in millions)
	Balance at December 31, 2013:
	Accumulated OCI	$	5			$	59
	Regulatory assets	75				1,575
	Total	$	80			$	1,634
	Balance at December 31, 2012:
	Accumulated OCI	$	7			$	118
	Regulatory assets	100				2,913
	Total	$	107			$	3,031
	Estimated amortization in net periodic pension cost in 2014:
	Accumulated OCI	$	1			$	4
	Regulatory assets	25				106
	Total	$	26			$	110
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, 2013 and 2012 are presented in the following table:
		Accumulated				Regulatory Assets
		OCI
		(in millions)
	Balance at December 31, 2011	$	109			$	2,614
	Net loss	21				519
	Reclassification adjustments:
	Amortization of prior service costs	(1		)		(29		)
	Amortization of net gain (loss)	(4		)		(91		)
	Total reclassification adjustments	(5		)		(120		)
	Total change	16				399
	Balance at December 31, 2012	$	125			$	3,013
	Net gain	(52		)		(1,145		)
	Change in prior service costs	—				1
	Reclassification adjustments:
	Amortization of prior service costs	(1		)		(26		)
	Amortization of net gain (loss)	(8		)		(192		)
	Total reclassification adjustments	(9		)		(218		)
	Total change	(61		)		(1,362		)
	Balance at December 31, 2013	$	64			$	1,651
Estimated pension benefit payments	'
	At December 31, 2013, estimated benefit payments were as follows:
		Benefit Payments
		(in millions)
	2014	$	399
	2015	422
	2016	446
	2017	471
	2018	492
	2019 to 2023	2,795
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, 2013 and 2012 were as follows:
		2013				2012
		(in millions)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	1,872			$	1,787
	Service cost	24				21
	Interest cost	74				85
	Benefits paid	(94		)		(99		)
	Actuarial (gain) loss	(200		)		71
	Retiree drug subsidy	6				7
	Balance at end of year	1,682				1,872
	Change in plan assets
	Fair value of plan assets at beginning of year	821				765
	Actual return on plan assets	129				93
	Employer contributions	39				55
	Benefits paid	(88		)		(92		)
	Fair value of plan assets at end of year	901				821
	Accrued liability	$	(781	)		$	(1,051	)
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, 2013 and 2012 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 2014.
		Prior Service				Net (Gain)				Transition
		Cost				Loss				Obligation
						(in millions)
	Balance at December 31, 2013:
	Accumulated OCI	$	—			$	1			$	—
	Net regulatory assets (liabilities)	9				64				—
	Total	$	9			$	65			$	—
	Balance at December 31, 2012:
	Accumulated OCI	$	—			$	7			$	—
	Net regulatory assets (liabilities)	13				342				5
	Total	$	13			$	349			$	5
	Estimated amortization as net periodic postretirement benefit cost in 2014:
	Accumulated OCI	$	—			$	—			$	—
	Net regulatory assets (liabilities)	4				2				—
	Total	$	4			$	2			$	—
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans	'
	The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2013 and 2012 are presented in the following table:
		Accumulated				Net Regulatory
		OCI				Assets (Liabilities)
		(in millions)
	Balance at December 31, 2011	$	6			$	345
	Net loss	1				35
	Reclassification adjustments:
	Amortization of transition obligation	—				(10		)
	Amortization of prior service costs	—				(4		)
	Amortization of net gain (loss)	—				(6		)
	Total reclassification adjustments	—				(20		)
	Total change	1				15
	Balance at December 31, 2012	$	7			$	360
	Net gain	(6		)		(266		)
	Reclassification adjustments:
	Amortization of transition obligation	—				(5		)
	Amortization of prior service costs	—				(4		)
	Amortization of net gain (loss)	—				(12		)
	Total reclassification adjustments	—				(21		)
	Total change	(6		)		(287		)
	Balance at December 31, 2013	$	1			$	73
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)
	2014	$	110			$	(9	)		$	101
	2015	115				(10		)		105
	2016	120				(11		)		109
	2017	124				(13		)		111
	2018	130				(14		)		116
	2019 to 2023	654				(75		)		579
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, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
		Target			2013			2012
	Pension plan assets:
	Domestic equity	26	%		31	%		28	%
	International equity	25			25			24
	Fixed income	23			23			27
	Special situations	3			1			1
	Real estate investments	14			14			13
	Private equity	9			6			7
	Total	100	%		100	%		100	%
	Other postretirement benefit plan assets:
	Domestic equity	40	%		40	%		38	%
	International equity	21			25			24
	Domestic fixed income	25			24			28
	Global fixed income	4			4			3
	Special situations	1			—			—
	Real estate investments	6			5			5
	Private equity	3			2			2
	Total	100	%		100	%		100	%
Pension Plans [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Amounts recognized in balance sheets related to benefit plans	'
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in millions)
	Prepaid pension costs	$	419			$	—
	Other regulatory assets, deferred	1,651				3,013
	Other current liabilities	(40		)		(37		)
	Employee benefit obligations	(509		)		(1,312		)
	Accumulated OCI	64				125
Components of net periodic benefit cost	'
	Components of net periodic pension cost were as follows:
		2013				2012				2011
		(in millions)
	Service cost	$	232			$	198			$	184
	Interest cost	389				393				389
	Expected return on plan assets	(603		)		(581		)		(607		)
	Recognized net loss	200				95				21
	Net amortization	27				30				32
	Net periodic pension cost	$	245			$	135			$	19
Fair values of benefit plan assets	'
	The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant				Significant
						Other				Unobservable
						Observable				Inputs
						Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	1,433			$	839			$	—		$	2,272
	International equity*	1,101				1,018				—			2,119
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				599				—			599
	Mortgage- and asset-backed securities	—				156				—			156
	Corporate bonds	—				978				—			978
	Pooled funds	—				471				—			471
	Cash equivalents and other	1				223				—			224
	Real estate investments	260				—				1,000			1,260
	Private equity	—				—				571			571
	Total	$	2,795			$	4,284			$	1,571		$	8,650
	Liabilities:
	Derivatives	—				(3		)		—			(3		)
	Total	$	2,795			$	4,281			$	1,571		$	8,647
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant				Significant
						Other				Unobservable
						Observable				Inputs
						Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	1,163			$	670			$	—		$	1,833
	International equity*	912				979				—			1,891
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				516				—			516
	Mortgage- and asset-backed securities	—				127				—			127
	Corporate bonds	—				876				3			879
	Pooled funds	—				399				—			399
	Cash equivalents and other	5				548				—			553
	Real estate investments	258				—				841			1,099
	Private equity	—				—				593			593
	Total	$	2,338			$	4,115			$	1,437		$	7,890
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in fair value measurement of the level 3 items in benefit plan assets	'
	Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
		(in millions)
	Beginning balance	$	841			$	593			$	782		$	582
	Actual return on investments:
	Related to investments held at year end	74				8				56			1
	Related to investments sold during the year	30				51				3			41
	Total return on investments	104				59				59			42
	Purchases, sales, and settlements	55				(81		)		—			(31		)
	Ending balance	$	1,000			$	571			$	841		$	593
Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Amounts recognized in balance sheets related to benefit plans	'
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
		2013				2012
		(in millions)
	Other regulatory assets, deferred	$	109			$	360
	Other current liabilities	(4		)		(3		)
	Employee benefit obligations	(777		)		(1,048		)
	Other regulatory liabilities, deferred	(36		)		—
	Accumulated OCI	1				7
Components of net periodic benefit cost	'
	Components of the other postretirement benefit plans' net periodic cost were as follows:
		2013				2012				2011
		(in millions)
	Service cost	$	24			$	21			$	21
	Interest cost	74				85				92
	Expected return on plan assets	(56		)		(60		)		(64		)
	Net amortization	21				20				20
	Net periodic postretirement benefit cost	$	63			$	66			$	69
Fair values of benefit plan assets	'
	Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant				Significant			Total
						Other				Unobservable
						Observable				Inputs
						Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)
		(in millions)
	Assets:
	Domestic equity*	$	157			$	45			$	—		$	202
	International equity*	39				82				—			121
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				34				—			34
	Mortgage- and asset-backed securities	—				6				—			6
	Corporate bonds	—				35				—			35
	Pooled funds	—				46				—			46
	Cash equivalents and other	—				19				—			19
	Trust-owned life insurance	—				369				—			369
	Real estate investments	10				—				36			46
	Private equity	—				—				20			20
	Total	$	206			$	636			$	56		$	898
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant				Significant
						Other				Unobservable
						Observable				Inputs
						Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	140			$	43			$	—		$	183
	International equity*	33				75				—			108
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				24				—			24
	Mortgage- and asset-backed securities	—				4				—			4
	Corporate bonds	—				31				—			31
	Pooled funds	—				42				—			42
	Cash equivalents and other	—				44				—			44
	Trust-owned life insurance	—				320				—			320
	Real estate investments	10				—				30			40
	Private equity	—				—				21			21
	Total	$	183			$	583			$	51		$	817
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in fair value measurement of the level 3 items in benefit plan assets	'
	Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
		(in millions)
	Beginning balance	$	30			$	21			$	30		$	23
	Actual return on investments:
	Related to investments held at year end	3				—				—			—
	Related to investments sold during the year	1				2				—			1
	Total return on investments	4				2				—			1
	Purchases, sales, and settlements	2				(3		)		—			(3		)
	Ending balance	$	36			$	20			$	30		$	21
Alabama Power [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans	'
	Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.52% and 5.41%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.02	%		4.27	%		4.98	%
	Other postretirement benefit plans	4.86			4.06			4.88
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	7.36			7.19			7.39
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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in millions)
	Benefit obligation	$	26			$	(22	)
	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, 2013 and 2012 were as follows:
		2013				2012
		(in millions)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	2,218			$	1,932
	Service cost	52				44
	Interest cost	93				94
	Benefits paid	(93		)		(90		)
	Actuarial (gain) loss	(158		)		238
	Balance at end of year	2,112				2,218
	Change in plan assets
	Fair value of plan assets at beginning of year	2,077				1,885
	Actual return on plan assets	285				274
	Employer contributions	9				8
	Benefits paid	(93		)		(90		)
	Fair value of plan assets at end of year	2,278				2,077
	Prepaid pension costs (accrued liability)	$	166			$	(141	)
Amounts recognized in balance sheets related to benefit plans	'
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
		2013				2012
		(in millions)
	Other regulatory assets, deferred	$	6			$	89
	Other regulatory liabilities, deferred	(21		)		—
	Employee benefit obligations	(42		)		(147		)
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in millions)
	Prepaid pension costs	$	276			$	—
	Other regulatory assets, deferred	476				822
	Other current liabilities	(9		)		(8		)
	Employee benefit obligations	(101		)		(133		)
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, 2013 and 2012 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 2014.
		2013				2012				Estimated
										Amortization
										in 2014
		(in millions)
	Prior service cost	$	19			$	22			$	4
	Net (gain) loss	(34		)		67				—
	Net regulatory assets (liabilities)	$	(15	)		$	89
	Presented below are the amounts included in regulatory assets at December 31, 2013 and 2012 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 2014.
		2013				2012				Estimated
										Amortization
										in 2014
						(in millions)
	Prior service cost	$	19			$	26			$	7
	Net (gain) loss	457				796				31
	Regulatory assets	$	476			$	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 regulatory assets related to the defined benefit pension plans for the years ended December 31, 2013 and 2012 are presented in the following table:
		2013			2012
		(in millions)
	Regulatory assets:
	Beginning balance	$	822		$	727
	Net (gain) loss	(287		)	125
	Reclassification adjustments:
	Amortization of prior service costs	(7		)	(7		)
	Amortization of net gain (loss)	(52		)	(23		)
	Total reclassification adjustments	(59		)	(30		)
	Total change	(346		)	95
	Ending balance	$	476		$	822
	The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2013 and 2012 are presented in the following table:
		2013			2012
		(in millions)
	Net regulatory assets (liabilities):
	Beginning balance	$	89		$	96
	Net gain	(99		)	(1		)
	Reclassification adjustments:
	Amortization of transition obligation	—			(2		)
	Amortization of prior service costs	(3		)	(4		)
	Amortization of net gain (loss)	(2		)	—
	Total reclassification adjustments	(5		)	(6		)
	Total change	(104		)	(7		)
	Ending balance	$	(15	)	$	89
Components of net periodic benefit cost	'
	Components of net periodic pension cost (income) were as follows:
		2013				2012				2011
		(in millions)
	Service cost	$	52			$	44			$	43
	Interest cost	93				94				96
	Expected return on plan assets	(157		)		(162		)		(173		)
	Recognized net (gain) loss	52				23				4
	Net amortization	7				7				9
	Net periodic pension cost (income)	$	47			$	6			$	(21	)
	Components of the other postretirement benefit plans' net periodic cost were as follows:
		2013				2012				2011
		(in millions)
	Service cost	$	6			$	5			$	5
	Interest cost	19				22				24
	Expected return on plan assets	(23		)		(23		)		(25		)
	Net amortization	5				6				7
	Net periodic postretirement benefit cost	$	7			$	10			$	11
Estimated pension benefit payments	'
	At December 31, 2013, estimated benefit payments were as follows:
		Benefit Payments
		(in millions)
	2014	$	104
	2015	108
	2016	113
	2017	118
	2018	122
	2019 to 2023	669
	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)
	2014	$	30			$	(3	)		$	27
	2015	31				(3		)		28
	2016	31				(3		)		28
	2017	33				(4		)		29
	2018	33				(4		)		29
	2019 to 2023	164				(22		)		142
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, 2013 and 2012 were as follows:
		2013				2012
		(in millions)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	490			$	470
	Service cost	6				5
	Interest cost	19				22
	Benefits paid	(24		)		(24		)
	Actuarial (gain) loss	(62		)		15
	Retiree drug subsidy	2				2
	Balance at end of year	431				490
	Change in plan assets
	Fair value of plan assets at beginning of year	343				315
	Actual return on plan assets	61				39
	Employer contributions	7				11
	Benefits paid	(22		)		(22		)
	Fair value of plan assets at end of year	389				343
	Accrued liability	$	(42	)		$	(147	)
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, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
		Target			2013			2012
	Pension plan assets:
	Domestic equity	26	%		31	%		28	%
	International equity	25			25			24
	Fixed income	23			23			27
	Special situations	3			1			1
	Real estate investments	14			14			13
	Private equity	9			6			7
	Total	100	%		100	%		100	%
	Other postretirement benefit plan assets:
	Domestic equity	44	%		47	%		46	%
	International equity	20			20			20
	Domestic fixed income	24			27			28
	Special situations	1			—			—
	Real estate investments	8			4			4
	Private equity	3			2			2
	Total	100	%		100	%		100	%
Fair values of benefit plan assets	'
	Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	67			$	11			$	—		$	78
	International equity*	14				13				—			27
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				17				—			17
	Mortgage- and asset-backed securities	—				2				—			2
	Corporate bonds	—				12				—			12
	Pooled funds	—				6				—			6
	Cash equivalents and other	—				10				—			10
	Trust-owned life insurance	—				211				—			211
	Real estate investments	4				—				13			17
	Private equity	—				—				7			7
	Total	$	85			$	282			$	20		$	387
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	62			$	9			$	—		$	71
	International equity*	12				13				—			25
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				7				—			7
	Mortgage- and asset-backed securities	—				2				—			2
	Corporate bonds	—				11				—			11
	Pooled funds	—				5				—			5
	Cash equivalents and other	—				19				—			19
	Trust-owned life insurance	—				178				—			178
	Real estate investments	4				—				11			15
	Private equity	—				—				8			8
	Total	$	78			$	244			$	19		$	341
	*	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, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	374			$	219			$	—		$	593
	International equity*	287				265				—			552
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				156				—			156
	Mortgage- and asset-backed securities	—				41				—			41
	Corporate bonds	—				255				—			255
	Pooled funds	—				123				—			123
	Cash equivalents and other	—				58				—			58
	Real estate investments	68				—				261			329
	Private equity	—				—				149			149
	Total	$	729			$	1,117			$	410		$	2,256
	Liabilities:
	Derivatives	—				(1		)		—			(1		)
	Total	$	729			$	1,116			$	410		$	2,255
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
Domestic equity*	$	304			$	175			$	—		$	479
International equity*	238				256				—			494
Fixed income:
U.S. Treasury, government, and agency bonds	—				135				—			135
Mortgage- and asset-backed securities	—				33				—			33
Corporate bonds	—				230				1			231
Pooled funds	—				104				—			104
Cash equivalents and other	1				143				—			144
Real estate investments	67				—				220			287
Private equity	—				—				155			155
Total	$	610			$	1,076			$	376		$	2,062
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in fair value measurement of the level 3 items in benefit plan assets	'
	Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
		(in millions)
	Beginning balance	$	220			$	155			$	217		$	161
	Actual return on investments:
	Related to investments held at year end	19				2				2			—
	Related to investments sold during the year	8				13				1			2
	Total return on investments	27				15				3			2
	Purchases, sales, and settlements	14				(21		)		—			(8		)
	Ending balance	$	261			$	149			$	220		$	155
	Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
		(in millions)
	Beginning balance	$	11			$	8			$	11		$	8
	Actual return on investments:
	Related to investments held at year end	1				—				—			—
	Related to investments sold during the year	—				—				—			—
	Total return on investments	1				—				—			—
	Purchases, sales, and settlements	1				(1		)		—			—
	Ending balance	$	13			$	7			$	11		$	8
Georgia Power [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans	'
	Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.52% and 5.40%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.02	%		4.27	%		4.98	%
	Other postretirement benefit plans	4.85			4.04			4.87
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	6.74			7.24			7.25
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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in millions)
	Benefit obligation	$	51			$	(43	)
	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, 2013 and 2012 were as follows:
		2013				2012
		(in millions)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	3,312			$	2,909
	Service cost	69				60
	Interest cost	138				141
	Benefits paid	(141		)		(136		)
	Actuarial (gain) loss	(262		)		338
	Balance at end of year	3,116				3,312
	Change in plan assets
	Fair value of plan assets at beginning of year	2,827				2,575
	Actual return on plan assets	387				377
	Employer contributions	12				11
	Benefits paid	(141		)		(136		)
	Fair value of plan assets at end of year	3,085				2,827
	Accrued liability	$	(31	)		$	(485	)
Amounts recognized in balance sheets related to benefit plans	'
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in millions)
	Prepaid pension costs	$	118			$	—
	Other regulatory assets, deferred	610				1,132
	Current liabilities, other	(12		)		(11		)
	Employee benefit obligations	(137		)		(474		)
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
		2013				2012
		(in millions)
	Other regulatory assets, deferred	$	69			$	187
	Employee benefit obligations	(316		)		(418		)
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, 2013 and 2012 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 2014.
		2013				2012				Estimated
										Amortization
										in 2014
		(in millions)
	Prior service cost	$	(4	)		$	(4	)		$	—
	Net (gain) loss	73				186				2
	Transition obligation	—				5				—
	Regulatory assets	$	69			$	187
	Presented below are the amounts included in regulatory assets at December 31, 2013 and 2012 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 2014.
		2013				2012				Estimated
										Amortization
										in 2014
		(in millions)
	Prior service cost	$	26			$	37			$	10
	Net (gain) loss	584				1,095				41
	Regulatory assets	$	610			$	1,132
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, 2013 and 2012 are presented in the following table:
		2013			2012
		(in millions)
	Regulatory assets:
	Beginning balance	$	1,132		$	995
	Net (gain) loss	(438		)	182
	Reclassification adjustments:
	Amortization of prior service costs	(10		)	(12		)
	Amortization of net gain (loss)	(74		)	(33		)
	Total reclassification adjustments	(84		)	(45		)
	Total change	(522		)	137
	Ending balance	$	610		$	1,132
Components of net periodic benefit cost	'
	Components of net periodic pension cost (income) were as follows:
		2013				2012				2011
		(in millions)
	Service cost	$	69			$	60			$	57
	Interest cost	138				141				144
	Expected return on plan assets	(212		)		(221		)		(234		)
	Recognized net loss	74				33				6
	Net amortization	10				12				12
	Net periodic pension cost (income)	$	79			$	25			$	(15	)
	Components of the other postretirement benefit plans' net periodic cost were as follows:
		2013				2012				2011
		(in millions)
	Service cost	$	7			$	7			$	7
	Interest cost	31				37				41
	Expected return on plan assets	(24		)		(29		)		(30		)
	Net amortization	12				10				11
	Net periodic postretirement benefit cost	$	26			$	25			$	29
Estimated pension benefit payments	'
	At December 31, 2013, estimated benefit payments were as follows:
		Benefit Payments
		(in millions)
	2014	$	154
	2015	161
	2016	167
	2017	175
	2018	181
	2019 to 2023	995
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, 2013 and 2012 were as follows:
		2013				2012
		(in millions)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	800			$	774
	Service cost	7				7
	Interest cost	31				37
	Benefits paid	(45		)		(46		)
	Actuarial (gain) loss	(73		)		25
	Retiree drug subsidy	3				3
	Balance at end of year	723				800
	Change in plan assets
	Fair value of plan assets at beginning of year	382				365
	Actual return on plan assets	56				43
	Employer contributions	11				17
	Benefits paid	(42		)		(43		)
	Fair value of plan assets at end of year	407				382
	Accrued liability	$	(316	)		$	(418	)
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans	'
	The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2013 and 2012 are presented in the following table:
		2013			2012
		(in millions)
	Regulatory assets:
	Beginning balance	$	187		$	186
	Net (gain) loss	(106		)	11
	Reclassification adjustments:
	Amortization of transition obligation	(4		)	(6		)
	Amortization of prior service costs	—			—
	Amortization of net gain (loss)	(8		)	(4		)
	Total reclassification adjustments	(12		)	(10		)
	Total change	(118		)	1
	Ending balance	$	69		$	187
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)
	2014	$	49			$	(4	)		$	45
	2015	50				(4		)		46
	2016	53				(5		)		48
	2017	54				(5		)		49
	2018	58				(6		)		52
	2019 to 2023	287				(30		)		257
Composition of benefit plan assets along with targeted mix of assets	'
	The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
		Target			2013			2012
	Pension plan assets:
	Domestic equity	26	%		31	%		28	%
	International equity	25			25			24
	Fixed income	23			23			27
	Special situations	3			1			1
	Real estate investments	14			14			13
	Private equity	9			6			7
	Total	100	%		100	%		100	%
	Other postretirement benefit plan assets:
	Domestic equity	41	%		36	%		34	%
	International equity	21			30			27
	Domestic fixed income	24			21			27
	Global fixed income	8			8			7
	Special situations	1			—			—
	Real estate investments	3			3			3
	Private equity	2			2			2
	Total	100	%		100	%		100	%
Fair values of benefit plan assets	'
	The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	506			$	296			$	—		$	802
	International equity*	389				359				—			748
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				212				—			212
	Mortgage- and asset-backed securities	—				55				—			55
	Corporate bonds	—				346				—			346
	Pooled funds	—				166				—			166
	Cash equivalents and other	—				79				—			79
	Real estate investments	92				—				353			445
	Private equity	—				—				202			202
	Total	$	987			$	1,513			$	555		$	3,055
	Liabilities:
	Derivatives	—				(1		)		—			(1		)
	Total	$	987			$	1,512			$	555		$	3,054
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	413			$	238			$	—		$	651
	International equity*	324				348				—			672
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				183				—			183
	Mortgage- and asset-backed securities	—				45				—			45
	Corporate bonds	—				312				1			313
	Pooled funds	—				142				—			142
	Cash equivalents and other	2				195				—			197
	Real estate investments	92				—				299			391
	Private equity	—				—				211			211
	Total	$	831			$	1,463			$	511		$	2,805
	*	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, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	74			$	25			$	—		$	99
	International equity*	12				57				—			69
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				7				—			7
	Mortgage- and asset-backed securities	—				2				—			2
	Corporate bonds	—				11				—			11
	Pooled funds	—				34				—			34
	Cash equivalents and other	—				6				—			6
	Trust-owned life insurance	—				158				—			158
	Real estate investments	3				—				11			14
	Private equity	—				—				6			6
	Total	$	89			$	300			$	17		$	406
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in millions)
	Assets:
	Domestic equity*	$	65			$	27			$	—		$	92
International equity*	10				51				—			61
Fixed income:
U.S. Treasury, government, and agency bonds	—				6				—			6
Mortgage- and asset-backed securities	—				1				—			1
Corporate bonds	—				10				—			10
Pooled funds	—				32				—			32
Cash equivalents and other	—				18				—			18
Trust-owned life insurance	—				142				—			142
Real estate investments	3				—				10			13
Private equity	—				—				7			7
Total	$	78			$	287			$	17		$	382
*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in fair value measurement of the level 3 items in benefit plan assets	'
	Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
		(in millions)
	Beginning balance	$	10			$	7			$	9		$	7
	Actual return on investments:
	Related to investments held at year end	1				—				1			—
	Related to investments sold during the year	—				—				—			—
	Total return on investments	1				—				1			—
	Purchases, sales, and settlements	—				(1		)		—			—
	Ending balance	$	11			$	6			$	10		$	7
	Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
		(in millions)
	Beginning balance	$	299			$	211			$	296		$	220
	Actual return on investments:
	Related to investments held at year end	25				3				2			—
	Related to investments sold during the year	10				17				1			2
	Total return on investments	35				20				3			2
	Purchases, sales, and settlements	19				(29		)		—			(11		)
	Ending balance	$	353			$	202			$	299		$	211
Gulf Power [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans	'
	The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.53% and 5.41%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.02	%		4.27	%		4.98	%
	Other postretirement benefit plans	4.86			4.06			4.88
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	8.04			8.02			8.11
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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in thousands)
	Benefit obligation	$	2,884			$	(2,479	)
	Service and interest costs	138				(119		)
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, 2013 and 2012 were as follows:
		2013				2012
		(in thousands)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	413,501			$	352,834
	Service cost	11,128				9,101
	Interest cost	17,321				17,199
	Benefits paid	(14,831		)		(14,046		)
	Plan amendments	—				426
	Actuarial (gain) loss	(31,791		)		47,987
	Balance at end of year	395,328				413,501
	Change in plan assets
	Fair value of plan assets at beginning of year	350,260				304,324
	Actual return on plan assets	49,076				45,762
	Employer contributions	1,134				14,220
	Benefits paid	(14,831		)		(14,046		)
	Fair value of plan assets at end of year	385,639				350,260
	Accrued liability	$	(9,689	)		$	(63,241	)
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, 2013 and 2012 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 2014.
		2013				2012				Estimated Amortization in 2014
		(in thousands)
	Prior service cost	$	4,401			$	5,565			$	1,115
	Net (gain) loss	70,879				133,696				4,559
	Regulatory assets	$	75,280			$	139,261
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, 2013 and 2012 are presented in the following table:
		2013			2012
		(in thousands)
	Regulatory assets:
	Beginning balance	$	139,261		$	115,853
	Net (gain) loss	(54,432		)	28,157
	Change in prior service costs	—			426
	Reclassification adjustments:
	Amortization of prior service costs	(1,164		)	(1,262		)
	Amortization of net gain (loss)	(8,385		)	(3,913		)
	Total reclassification adjustments	(9,549		)	(5,175		)
	Total change	(63,981		)	23,408
	Ending balance	$	75,280		$	139,261
Estimated pension benefit payments	'
	At December 31, 2013, estimated benefit payments were as follows:
		Benefit Payments
		(in thousands)
	2014	$	16,548
	2015	17,440
	2016	18,405
	2017	19,649
	2018	20,681
	2019 to 2023	121,864
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, 2013 and 2012 were as follows:
		2013				2012
		(in thousands)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	75,395			$	70,923
	Service cost	1,355				1,167
	Interest cost	2,982				3,367
	Benefits paid	(3,583		)		(3,854		)
	Actuarial (gain) loss	(7,900		)		3,468
	Retiree drug subsidy	330				324
	Balance at end of year	68,579				75,395
	Change in plan assets
	Fair value of plan assets at beginning of year	16,227				14,978
	Actual return on plan assets	2,119				2,131
	Employer contributions	2,381				2,648
	Benefits paid	(3,253		)		(3,530		)
	Fair value of plan assets at end of year	17,474				16,227
	Accrued liability	$	(51,105	)		$	(59,168	)
Amounts included in accumulated other comprehensive income and regulatory assets related to other postretirement benefit plans	'
	Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2013 and 2012 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 2014.
		2013				2012				Estimated Amortization in 2014
		(in thousands)
	Prior service cost	$	138			$	324			$	186
	Net (gain) loss	(7,122		)		1,845				(24		)
	Net regulatory assets (liabilities)	$	(6,984	)		$	2,169
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans	'
	The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2013 and 2012 are presented in the following table:
		2013			2012
		(in thousands)
	Net regulatory assets (liabilities):
	Beginning balance	$	2,169		$	239
	Net (gain) loss	(8,967		)	2,309
	Reclassification adjustments:
	Amortization of transition obligation	—			(193		)
	Amortization of prior service costs	(186		)	(186		)
	Amortization of net gain (loss)	—			—
	Total reclassification adjustments	(186		)	(379		)
	Total change	(9,153		)	1,930
	Ending balance	$	(6,984	)	$	2,169
Summary of estimation of future benefit payments and subsidy receipts based on assumptions used to measure accumulated benefit obligation for postretirement plans	'
	Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
		Benefit				Subsidy				Total
		Payments				Receipts
		(in thousands)
	2014	$	4,447			$	(409	)		$	4,038
	2015	4,630				(456		)		4,174
	2016	4,856				(504		)		4,352
	2017	4,994				(557		)		4,437
	2018	5,168				(611		)		4,557
	2019 to 2023	26,272				(3,251		)		23,021
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, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
		Target			2013			2012
	Pension plan assets:
	Domestic equity	26	%		31	%		28	%
	International equity	25			25			24
	Fixed income	23			23			27
	Special situations	3			1			1
	Real estate investments	14			14			13
	Private equity	9			6			7
	Total	100	%		100	%		100	%
	Other postretirement benefit plan assets:
	Domestic equity	25	%		30	%		27	%
	International equity	24			24			23
	Domestic fixed income	25			25			29
	Special situations	3			1			1
	Real estate investments	14			14			13
	Private equity	9			6			7
	Total	100	%		100	%		100	%
Gulf Power [Member] | Pension Plans [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Amounts recognized in balance sheets related to benefit plans	'
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in thousands)
	Prepaid pension costs	$	11,533			$	—
	Other regulatory assets, deferred	75,280				139,261
	Current liabilities, other	(1,183		)		(855		)
	Employee benefit obligations	(20,039		)		(62,386		)
Components of net periodic benefit cost	'
	Components of net periodic pension cost were as follows:
		2013				2012				2011
		(in thousands)
	Service cost	$	11,128			$	9,101			$	8,431
	Interest cost	17,321				17,199				17,074
	Expected return on plan assets	(26,435		)		(25,932		)		(27,232		)
	Recognized net (gain) loss	8,385				3,913				512
	Net amortization	1,164				1,262				1,262
	Net periodic pension cost	$	11,563			$	5,543			$	47
Fair values of benefit plan assets	'
	The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
		(in thousands)
	Assets:
	Domestic equity*	$	63,269			$	37,037			$	—		$	100,306
	International equity*	48,606				44,941				—			93,547
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				26,461				—			26,461
	Mortgage- and asset-backed securities	—				6,873				—			6,873
	Corporate bonds	—				43,222				—			43,222
	Pooled funds	—				20,810				—			20,810
	Cash equivalents and other	38				9,851				—			9,889
	Real estate investments	11,493				—				44,139			55,632
	Private equity	—				—				25,201			25,201
	Total	$	123,406			$	189,195			$	69,340		$	381,941
	Liabilities:
	Derivatives	—				(115		)		—			(115		)
	Total	$	123,406			$	189,080			$	69,340		$	381,826
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in thousands)
	Assets:
	Domestic equity*	$	51,215			$	29,499			$	—		$	80,714
	International equity*	40,166				43,120				—			83,286
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				22,724				—			22,724
	Mortgage- and asset-backed securities	—				5,594				—			5,594
	Corporate bonds	—				38,534				139			38,673
	Pooled funds	—				17,581				—			17,581
	Cash equivalents and other	208				24,148				—			24,356
	Real estate investments	11,362				—				37,039			48,401
	Private equity	—				—				26,129			26,129
	Total	$	102,951			$	181,200			$	63,307		$	347,458
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in fair value measurement of the level 3 items in benefit plan assets	'
	Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
		(in thousands)
	Beginning balance	$	37,039			$	26,129			$	34,989		$	26,053
	Actual return on investments:
	Related to investments held at year end	3,357				376				1,918			44
	Related to investments sold during the year	1,310				2,282				132			1,396
	Total return on investments	4,667				2,658				2,050			1,440
	Purchases, sales, and settlements	2,433				(3,586		)		—			(1,364		)
	Ending balance	$	44,139			$	25,201			$	37,039		$	26,129
Gulf Power [Member] | Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Amounts recognized in balance sheets related to benefit plans	'
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
		2013				2012
		(in thousands)
	Other regulatory assets, deferred	$	—			$	2,169
	Current liabilities, other	(687		)		(661		)
	Other regulatory liabilities, deferred	(6,984		)		—
	Employee benefit obligations	(50,418		)		(58,507		)
Components of net periodic benefit cost	'
	Components of the other postretirement benefit plans' net periodic cost were as follows:
		2013				2012				2011
		(in thousands)
	Service cost	$	1,355			$	1,167			$	1,132
	Interest cost	2,982				3,367				3,658
	Expected return on plan assets	(1,238		)		(1,311		)		(1,445		)
	Net amortization	186				379				396
	Net periodic postretirement benefit cost	$	3,285			$	3,602			$	3,741
Fair values of benefit plan assets	'
	The fair values of other postretirement benefit plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
		(in thousands)
	Assets:
	Domestic equity*	$	2,778			$	1,628			$	—		$	4,406
	International equity*	2,136				1,973				—			4,109
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				1,161				—			1,161
	Mortgage- and asset-backed securities	—				303				—			303
	Corporate bonds	—				1,897				—			1,897
	Pooled funds	—				1,417				—			1,417
	Cash equivalents and other	1				433				—			434
	Real estate investments	504				—				1,939			2,443
	Private equity	—				—				1,108			1,108
	Total	$	5,419			$	8,812			$	3,047		$	17,278
	Liabilities:
	Derivatives	—				(5		)		—			(5		)
	Total	$	5,419			$	8,807			$	3,047		$	17,273
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in thousands)
	Assets:
	Domestic equity*	$	2,290			$	1,319			$	—		$	3,609
	International equity*	1,795				1,928				—			3,723
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				1,016				—			1,016
	Mortgage- and asset-backed securities	—				250				—			250
	Corporate bonds	—				1,722				6			1,728
	Pooled funds	—				1,298				—			1,298
	Cash equivalents and other	9				1,078				—			1,087
	Real estate investments	508				—				1,667			2,175
	Private equity	—				15				1,155			1,170
	Total	$	4,602			$	8,626			$	2,828		$	16,056
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in fair value measurement of the level 3 items in benefit plan assets	'
	Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate				Private				Real Estate			Private
		Investments				Equity				Investments			Equity
		(in thousands)
	Beginning balance	$	1,667			$	1,155			$	1,657		$	1,232
	Actual return on investments:
	Related to investments held at year end	108				16				107			(1		)
	Related to investments sold during the year	57				104				6			80
	Total return on investments	165				120				113			79
	Purchases, sales, and settlements	107				(167		)		(103		)	(156		)
	Ending balance	$	1,939			$	1,108			$	1,667		$	1,155
Mississippi Power [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans	'
	The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2010 for the 2011 plan year using discount rates for the pension plans and the other postretirement benefit plans of 5.51% and 5.39%, respectively, and an annual salary increase of 3.84%.
		2013			2012			2011
	Discount rate:
	Pension plans	5.01	%		4.26	%		4.98	%
	Other postretirement benefit plans	4.85			4.04			4.87
	Annual salary increase	3.59			3.59			3.84
	Long-term return on plan assets:
	Pension plans	8.2			8.2			8.45
	Other postretirement benefit plans	7.04			6.96			7.53
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, 2013 as follows:
		1 Percent				1 Percent
		Increase				Decrease
		(in thousands)
	Benefit obligation	$	4,665			$	(4,004	)
	Service and interest costs	224				(192		)
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, 2013 and 2012 were as follows:
		2013				2012
		(in thousands)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	432,553			$	369,680
	Service cost	11,067				9,416
	Interest cost	18,062				18,019
	Benefits paid	(16,207		)		(14,949		)
	Actuarial (gain) loss	(36,080		)		50,387
	Balance at end of year	409,395				432,553
	Change in plan assets
	Fair value of plan assets at beginning of year	351,749				282,100
	Actual return on plan assets	49,431				39,668
	Employer contributions	2,430				44,930
	Benefits paid	(16,207		)		(14,949		)
	Fair value of plan assets at end of year	387,403				351,749
	Accrued liability	$	(21,992	)		$	(80,804	)
Amounts recognized in balance sheets related to benefit plans	'
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's other postretirement benefit plans consist of the following:
		2013				2012
		(in thousands)
	Other regulatory assets, deferred	$	5,227			$	15,454
	Other regulatory liabilities, deferred	(3,111		)		—
	Employee benefit obligations	(57,663		)		(69,793		)
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, 2013 and 2012 are presented in the following table:
		2013			2012
		(in thousands)
	Regulatory assets:
	Beginning balance	$	146,838		$	117,354
	Net (gain) loss	(58,662		)	34,893
	Reclassification adjustments:
	Amortization of prior service costs	(1,143		)	(1,309		)
	Amortization of net gain (loss)	(9,461		)	(4,100		)
	Total reclassification adjustments	(10,604		)	(5,409		)
	Total change	(69,266		)	29,484
	Ending balance	$	77,572		$	146,838
Estimated pension benefit payments	'
	At December 31, 2013, estimated benefit payments were as follows:
		Benefit
		Payments
		(in thousands)
	2014	$	17,245
	2015	18,076
	2016	18,993
	2017	20,172
	2018	21,237
	2019 to 2023	124,728
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, 2013 and 2012 were as follows:
		2013				2012
		(in thousands)
	Change in benefit obligation
	Benefit obligation at beginning of year	$	91,783			$	87,447
	Service cost	1,151				1,038
	Interest cost	3,619				4,155
	Benefits paid	(4,080		)		(4,432		)
	Actuarial (gain) loss	(11,959		)		3,166
	Retiree drug subsidy	426				409
	Balance at end of year	80,940				91,783
	Change in plan assets
	Fair value of plan assets at beginning of year	21,990				20,534
	Actual return on plan assets	2,379				2,427
	Employer contributions	2,562				3,052
	Benefits paid	(3,654		)		(4,023		)
	Fair value of plan assets at end of year	23,277				21,990
	Accrued liability	$	(57,663	)		$	(69,793	)
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans	'
	The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2013 and 2012 are presented in the following table:
		2013			2012
		(in thousands)
	Net regulatory assets (liabilities):
	Beginning balance	$	15,454		$	13,324
	Net (gain) loss	(12,867		)	2,600
	Reclassification adjustments:
	Amortization of transition obligation	—			(171		)
	Amortization of prior service costs	188			188
	Amortization of net gain (loss)	(659		)	(487		)
	Total reclassification adjustments	(471		)	(470		)
	Total change	(13,338		)	2,130
	Ending balance	$	2,116		$	15,454
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 thousands)
	2014	$	5,051			$	(526	)		$	4,525
	2015	5,335				(577		)		4,758
	2016	5,569				(632		)		4,937
	2017	5,849				(689		)		5,160
	2018	6,091				(748		)		5,343
	2019 to 2023	32,600				(3,793		)		28,807
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, 2013 and 2012, along with the targeted mix of assets for each plan, is presented below:
		Target			2013			2012
	Pension plan assets:
	Domestic equity	26	%		31	%		28	%
	International equity	25			25			24
	Fixed income	23			23			27
	Special situations	3			1			1
	Real estate investments	14			14			13
	Private equity	9			6			7
	Total	100	%		100	%		100	%
	Other postretirement benefit plan assets:
	Domestic equity	21	%		25	%		22	%
	International equity	20			20			19
	Fixed income	38			38			42
	Special situations	3			1			1
	Real estate investments	11			11			10
	Private equity	7			5			6
	Total	100	%		100	%		100	%
Mississippi Power [Member] | Pension Plans [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Amounts recognized in balance sheets related to benefit plans	'
	Amounts recognized in the balance sheets at December 31, 2013 and 2012 related to the Company's pension plans consist of the following:
		2013				2012
		(in thousands)
	Prepaid pension costs	$	5,698			$	—
	Other regulatory assets, deferred	77,572				146,838
	Other current liabilities	(2,134		)		(2,087		)
	Employee benefit obligations	(25,556		)		(78,717		)
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, 2013 and 2012 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 2014.
		2013				2012				Estimated Amortization in 2014
		(in thousands)
	Prior service cost	$	4,118			$	5,261			$	1,088
	Net (gain) loss	73,454				141,577				4,937
	Regulatory assets	$	77,572			$	146,838
Components of net periodic benefit cost	'
	Components of net periodic pension cost were as follows:
		2013				2012				2011
		(in thousands)
	Service cost	$	11,067			$	9,416			$	8,838
	Interest cost	18,062				18,019				17,827
	Expected return on plan assets	(26,849		)		(24,121		)		(25,166		)
	Recognized net (gain) loss	9,461				4,100				1,114
	Net amortization	1,143				1,309				1,309
	Net periodic pension cost	$	12,884			$	8,723			$	3,922
Fair values of benefit plan assets	'
	The fair values of pension plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
		(in thousands)
	Assets:
	Domestic equity*	$	63,558			$	37,206			$	—		$	100,764
	International equity*	48,829				45,146				—			93,975
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				26,582				—			26,582
	Mortgage- and asset-backed securities	—				6,904				—			6,904
	Corporate bonds	—				43,420				—			43,420
	Pooled funds	—				20,905				—			20,905
	Cash equivalents and other	38				9,896				—			9,934
	Real estate investments	11,546				—				44,341			55,887
	Private equity	—				—				25,316			25,316
	Total	$	123,971			$	190,059			$	69,657		$	383,687
	Liabilities:
	Derivatives	—				(115		)		—			(115		)
	Total	$	123,971			$	189,944			$	69,657		$	383,572
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in thousands)
	Assets:
	Domestic equity*	$	51,433			$	29,624			$	—		$	81,057
	International equity*	40,337				43,303				—			83,640
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				22,820				—			22,820
	Mortgage- and asset-backed securities	—				5,618				—			5,618
	Corporate bonds	—				38,696				140			38,836
	Pooled funds	—				17,656				—			17,656
	Cash equivalents and other	209				24,251				—			24,460
	Real estate investments	11,410				—				37,196			48,606
	Private equity	—				—				26,240			26,240
	Total	$	103,389			$	181,968			$	63,576		$	348,933
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in fair value measurement of the level 3 items in benefit plan assets	'
	Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate				Private Equity				Real Estate			Private Equity
		Investments								Investments
		(in thousands)
	Beginning balance	$	37,196			$	26,240			$	32,434		$	24,151
	Actual return on investments:
	Related to investments held at year end	3,385				378				4,629			44
	Related to investments sold during the year	1,316				2,300				133			3,415
	Total return on investments	4,701				2,678				4,762			3,459
	Purchases, sales, and settlements	2,444				(3,602		)		—			(1,370		)
	Ending balance	$	44,341			$	25,316			$	37,196		$	26,240
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'
Defined Benefit Plan Disclosure [Line Items]	'
Amounts related to defined benefit pension plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'
	Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2013 and 2012 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 2014.
		2013				2012				Estimated Amortization in 2014
		(in thousands)
	Prior service cost	$	(2,311	)		$	(2,498	)		$	(188	)
	Net (gain) loss	4,427				17,952				—
	Net regulatory assets (liabilities)	$	2,116			$	15,454
Components of net periodic benefit cost	'
	Components of the other postretirement benefit plans' net periodic cost were as follows:
		2013				2012				2011
		(in thousands)
	Service cost	$	1,151			$	1,038			$	1,012
	Interest cost	3,619				4,155				4,292
	Expected return on plan assets	(1,472		)		(1,552		)		(1,763		)
	Net amortization	471				470				274
	Net periodic postretirement benefit cost	$	3,769			$	4,111			$	3,815
Fair values of benefit plan assets	'
	The fair values of other postretirement benefit plan assets as of December 31, 2013 and 2012 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)				(Level 2)				(Level 3)			Total
		(in thousands)
	Assets:
	Domestic equity*	$	3,089			$	1,809			$	—		$	4,898
	International equity*	2,375				2,193				—			4,568
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				5,213				—			5,213
	Mortgage- and asset-backed securities	—				337				—			337
	Corporate bonds	—				2,109				—			2,109
	Pooled funds	—				1,016				—			1,016
	Cash equivalents and other	1				968				—			969
	Real estate investments	560				—				2,156			2,716
	Private equity	—				—				1,231			1,231
	Total	$	6,025			$	13,645			$	3,387		$	23,057
	Liabilities:
	Derivatives	—				(5		)		—			(5		)
	Total	$	6,025			$	13,640			$	3,387		$	23,052
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)				(Level 2)				(Level 3)			Total
		(in thousands)
	Assets:
	Domestic equity*	$	2,561			$	1,475			$	—		$	4,036
	International equity*	2,008				2,156				—			4,164
	Fixed income:
	U.S. Treasury, government, and agency bonds	—				5,187				—			5,187
	Mortgage- and asset-backed securities	—				280				—			280
	Corporate bonds	—				1,925				7			1,932
	Pooled funds	—				879				—			879
	Cash equivalents and other	11				1,612				—			1,623
	Real estate investments	569				—				1,865			2,434
	Private equity	—				14				1,293			1,307
	Total	$	5,149			$	13,528			$	3,165		$	21,842
	*	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
Changes in fair value measurement of the level 3 items in benefit plan assets	'
	Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2013 and 2012 were as follows:
		2013								2012
		Real Estate Investments				Private Equity				Real Estate Investments			Private Equity
		(in thousands)
	Beginning balance	$	1,865			$	1,293			$	1,851		$	1,377
	Actual return on investments:
	Related to investments held at year end	158				18				119			(1		)
	Related to investments sold during the year	64				110				7			90
	Total return on investments	222				128				126			89
	Purchases, sales, and settlements	69				(190		)		(112		)	(173		)
	Ending balance	$	2,156			$	1,231			$	1,865		$	1,293

Contingencies_and_Regulatory_M1

Contingencies and Regulatory Matters Current And Actual Cost Estimates (Tables)	12 Months Ended
	Dec. 31, 2013
Loss Contingencies [Line Items]	'
Current cost estimate and actual costs incurred	'
	Mississippi Power’s 2010 project estimate, current cost estimate, and actual costs incurred as of December 31, 2013 for the Kemper IGCC are as follows:
	Cost Category	2010 Project Estimate(d)		Current Estimate		Actual Costs at 12/31/2013
		(in billions)
	Plant Subject to Cost Cap(a)	$	2.4	$	4.06	$	3.25
	Lignite Mine and Equipment	0.21		0.23		0.23
	CO2 Pipeline Facilities	0.14		0.11		0.09
	AFUDC(b)	0.17		0.45		0.28
	General Exceptions	0.05		0.1		0.07
	Regulatory Asset(c)	—		0.09		0.07
	Total Kemper IGCC(a)	$	2.97	$	5.04	$	3.99
	(a)	The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions.
	(b)	Mississippi Power’s original estimate included recovery of financing costs during construction which was not approved by the Mississippi PSC in June 2012 as described in "Rate Recovery of Kemper IGCC Costs."
	(c)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets."
	(d)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
Mississippi Power [Member]	'
Loss Contingencies [Line Items]	'
Current cost estimate and actual costs incurred	'
	The Company's 2010 project estimate, current cost estimate, and actual costs incurred as of December 31, 2013 for the Kemper IGCC are as follows:
	Cost Category	2010 Project Estimate(d)		Current Estimate		Actual Costs at 12/31/2013
		(in billions)
	Plant Subject to Cost Cap(a)	$	2.4	$	4.06	$	3.25
	Lignite Mine and Equipment	0.21		0.23		0.23
	CO2 Pipeline Facilities	0.14		0.11		0.09
	AFUDC(b)	0.17		0.45		0.28
	General Exceptions	0.05		0.1		0.07
	Regulatory Asset(c)	—		0.09		0.07
	Total Kemper IGCC(a)	$	2.97	$	5.04	$	3.99
	(a)	The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions.
	(b)	The Company’s original estimate included recovery of financing costs during construction which was not approved by the Mississippi PSC in June 2012 as described in "Rate Recovery of Kemper IGCC Costs."
	(c)	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets."
	(d)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.

Joint_Ownership_Agreements_Tab

Joint Ownership Agreements (Tables)	12 Months Ended
	Dec. 31, 2013
Jointly Owned Utility Plant Interests [Line Items]	'
Schedule of percentage ownership and investment in jointly-owned facilities	'
	At December 31, 2013, Alabama Power's, Georgia Power's, and Southern Power's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:
	Facility (Type)	Percent			Plant in Service				Accumulated				CWIP
		Ownership							Depreciation
					(in millions)
	Plant Vogtle (nuclear) Units 1 and 2	45.7	%		$	3,375			$	2,028			$	53
	Plant Hatch (nuclear)	50.1			1,092				551				52
	Plant Miller (coal) Units 1 and 2	91.8			1,410				575				89
	Plant Scherer (coal) Units 1 and 2	8.4			209				80				24
	Plant Wansley (coal)	53.5			800				260				36
	Rocky Mountain (pumped storage)	25.4			182				120				—
	Intercession City (combustion turbine)	33.3			14				4				—
	Plant Stanton (combined cycle) Unit A	65			156				42				—
Alabama Power [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Schedule of percentage ownership and investment in jointly-owned facilities	'
	In addition to the Company's ownership of SEGCO and joint ownership of the natural gas pipeline, the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2013 were as follows:
	Facility	Total Megawatt Capacity			Company Ownership				Plant in Service				Accumulated Depreciation		Construction Work in Progress
									(in millions)
	Greene County	500			60	%	(1)		$	157			$	91	$	5
	Plant Miller
	Units 1 and 2	1,320			91.84	%	(2)		1,410				575		89
	-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, 2013, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:
	Facility (Type)	Company Ownership		Plant in Service				Accumulated Depreciation			CWIP
		(in millions)
	Plant Vogtle (nuclear)
	Units 1 and 2	45.70%		$	3,375			$	2,028		$	53
	Plant Hatch (nuclear)	50.1		1,092				551			52
	Plant Wansley (coal)	53.5		800				260			36
	Plant Scherer (coal)
	Units 1 and 2	8.4		209				80			24
	Unit 3	75		1,155				398			19
	Rocky Mountain (pumped storage)	25.4		182				120			—
	Intercession City (combustion-turbine)	33.3		14				4			—
Gulf Power [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Schedule of percentage ownership and investment in jointly-owned facilities	'
	At December 31, 2013, the Company's percentage ownership and investment in these jointly-owned facilities were as follows:
		Plant Scherer				Plant Daniel Units 1 & 2 (coal)
		Unit 3 (coal)
		(in thousands)
	Plant in service	$	382,374		(a)	$	282,370
	Accumulated depreciation	123,862				172,365
	Construction work in progress	6,303				169,085
	Company Ownership	25		%		50		%
	(a)	Includes net plant acquisition adjustment of $2.0 million.
Mississippi Power [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Schedule of percentage ownership and investment in jointly-owned facilities	'
	At December 31, 2013, the Company's percentage ownership and investment in these jointly-owned facilities in commercial operation were as follows:
	Generating	Company			Plant in Service				Accumulated			Construction Work in Progress
	Plant	Ownership							Depreciation
					(in thousands)
	Greene County
	Units 1 and 2	40	%		$	96,153			$	49,731		$	3,017
	Daniel
	Units 1 and 2	50	%		$	299,179			$	152,952		$	168,539

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Line Items]	'
Details of income tax provisions	'
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in millions)
	Federal —
	Current	$	363			$	177			$	57
	Deferred	386				1,011				1,035
		749				1,188				1,092
	State —
	Current	(10		)		61				8
	Deferred	110				85				119
		100				146				127
	Total	$	849			$	1,334			$	1,219
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:
		2013				2012
		(in millions)
	Deferred tax liabilities —
	Accelerated depreciation	$	9,710			$	9,022
	Property basis differences	1,515				1,254
	Leveraged lease basis differences	287				278
	Employee benefit obligations	491				536
	Premium on reacquired debt	113				84
	Regulatory assets associated with employee benefit obligations	705				988
	Regulatory assets associated with asset retirement obligations	824				1,108
	Other	350				349
	Total	13,995				13,619
	Deferred tax assets —
	Federal effect of state deferred taxes	421				394
	Employee benefit obligations	1,048				1,678
	Over recovered fuel clause	30				135
	Other property basis differences	157				134
	Deferred costs	84				39
	ITC carryforward	121				256
	Unbilled revenue	116				101
	Other comprehensive losses	54				84
	Asset retirement obligations	824				720
	Estimated Loss on Kemper IGCC	472				—
	Deferred state tax assets	77				68
	Other	220				363
	Total	3,624				3,972
	Valuation allowance	(49		)		(54		)
	Total deferred tax assets	3,575				3,918
	Total deferred tax liabilities, net	10,420				9,701
	Portion included in prepaid expenses (accrued income taxes), net	143				237
	Accumulated deferred income taxes	$	10,563			$	9,938
Reconciliation of federal statutory income tax rate to effective income tax rate	'
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	2.5			2.5			2.4
	Employee stock plans dividend deduction	(1.6	)		(1.0	)		(1.1	)
	Non-deductible book depreciation	1.5			0.9			0.7
	AFUDC-Equity	(2.6	)		(1.3	)		(1.5	)
	ITC basis difference	(1.2	)		(0.3	)		(0.2	)
	Other	(0.5	)		(0.2	)		(0.3	)
	Effective income tax rate	33.1	%		35.6	%		35	%
Changes in unrecognized tax benefits	'
	Changes during the year in unrecognized tax benefits were as follows:
		2013				2012				2011
		(in millions)
	Unrecognized tax benefits at beginning of year	$	70			$	120			$	296
	Tax positions from current periods	3				13				46
	Tax positions increase from prior periods	—				7				1
	Tax positions decrease from prior periods	(66		)		(56		)		(111		)
	Reductions due to settlements	—				(10		)		(112		)
	Reductions due to expired statute of limitations	—				(4		)		—
	Balance at end of year	$	7			$	70			$	120
Impact on effective tax rate	'
	The impact on Southern Company's effective tax rate, if recognized, is as follows:
		2013				2012				2011
		(in millions)
	Tax positions impacting the effective tax rate	$	7			$	5			$	69
	Tax positions not impacting the effective tax rate	—				65				51
	Balance of unrecognized tax benefits	$	7			$	70			$	120
Accrued interest for unrecognized tax benefits	'
	Accrued interest for unrecognized tax benefits was as follows:
		2013				2012				2011
		(in millions)
	Interest accrued at beginning of year	$	1			$	10			$	29
	Interest reclassified due to settlements	—				(9		)		(24		)
	Interest accrued during the year	—				—				5
	Balance at end of year	$	1			$	1			$	10
Alabama Power [Member]	'
Income Tax Disclosure [Line Items]	'
Details of income tax provisions	'
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in millions)
	Federal —
	Current	$	243			$	262			$	20
	Deferred	160				137				377
		403				399				397
	State —
	Current	36				51				(1		)
	Deferred	39				27				82
		75				78				81
	Total	$	478			$	477			$	478
Tax effects between the carrying amounts of assets and liabilities	'
	The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
		2013				2012
		(in millions)
	Deferred tax liabilities —
	Accelerated depreciation	$	3,187			$	2,989
	Property basis differences	458				420
	Premium on reacquired debt	33				36
	Employee benefit obligations	209				218
	Under recovered energy clause	—				16
	Regulatory assets associated with employee benefit obligations	198				378
	Asset retirement obligations	38				—
	Regulatory assets associated with asset retirement obligations	265				248
	Other	128				114
	Total	4,516				4,419
	Deferred tax assets —
	Federal effect of state deferred taxes	205				194
	Unbilled fuel revenue	41				39
	Storm reserve	32				34
	Employee benefit obligations	231				408
	Other comprehensive losses	18				19
	Asset retirement obligations	303				248
	Other	108				98
	Total	938				1,040
	Total deferred tax liabilities, net	3,578				3,379
	Portion included in prepaid expenses (accrued income taxes)	25				25
	Accumulated deferred income taxes	$	3,603			$	3,404
Reconciliation of federal statutory income tax rate to effective income tax rate	'
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	4			4.1			4.3
	Non-deductible book depreciation	1			0.9			0.8
	Differences in prior years' deferred and current tax rates	(0.1	)		(0.1	)		(0.1	)
	AFUDC equity	(0.9	)		(0.5	)		(0.6	)
	Other	(0.1	)		(0.3	)		(0.4	)
	Effective income tax rate	38.9	%		39.1	%		39	%
Changes in unrecognized tax benefits	'
	Changes during the year in unrecognized tax benefits were as follows:
		2013				2012				2011
						(in millions)
	Unrecognized tax benefits at beginning of year	$	31			$	32			$	43
	Tax positions from current periods	—				5				6
	Tax positions from prior periods	(31		)		(4		)		(17		)
	Reductions due to settlements	—				(2		)		—
	Balance at end of year	$	—			$	31			$	32
Impact on effective tax rate	'
	The impact on the Company's effective tax rate, if recognized, is as follows:
		2013				2012				2011
						(in millions)
	Tax positions impacting the effective tax rate	$	—			$	—			$	5
	Tax positions not impacting the effective tax rate	—				31				27
	Balance of unrecognized tax benefits	$	—			$	31			$	32
Accrued interest for unrecognized tax benefits	'
	Accrued interest for unrecognized tax benefits is as follows:
		2013				2012				2011
						(in millions)
	Interest accrued at beginning of year	$	—			$	1.9			$	1.5
	Interest reclassified due to settlements	—				(1.9		)		—
	Interest accrued during the year	—				—				0.4
	Balance at end of year	$	—			$	—			$	1.9
Georgia Power [Member]	'
Income Tax Disclosure [Line Items]	'
Details of income tax provisions	'
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in millions)
	Federal –
	Current	$	277			$	273			$	106
	Deferred	374				370				479
		651				643				585
	State –
	Current	(30		)		38				19
	Deferred	102				7				21
		72				45				40
	Total	$	723			$	688			$	625
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:
		2013				2012
		(in millions)
	Deferred tax liabilities –
	Accelerated depreciation	$	4,479			$	4,201
	Property basis differences	873				757
	Employee benefit obligations	232				255
	Premium on reacquired debt	73				77
	Regulatory assets associated with employee benefit obligations	276				536
	Asset retirement obligations	495				446
	Other	168				93
	Total	6,596				6,365
	Deferred tax assets –
	Federal effect of state deferred taxes	159				142
	Employee benefit obligations	388				644
	Other property basis differences	93				100
	Other deferred costs	84				39
	Cost of removal obligations	17				29
	State tax credit carry forward	118				86
	Federal tax credit carry forward	3				—
	Over-recovered fuel costs	22				89
	Unbilled fuel revenue	53				39
	Asset retirement obligations	495				446
	Other	32				42
	Total	1,464				1,656
	Total deferred tax liabilities, net	5,132				4,709
	Portion included in current assets/(liabilities), net	68				152
	Accumulated deferred income taxes	$	5,200			$	4,861
Reconciliation of federal statutory income tax rate to effective income tax rate	'
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	2.5			1.6			1.5
	Non-deductible book depreciation	1.3			1.2			0.8
	AFUDC equity	(0.6	)		(1.0	)		(1.9	)
	Other	(0.4	)		(0.1	)		(0.5	)
	Effective income tax rate	37.8	%		36.7	%		34.9	%
Changes in unrecognized tax benefits	'
	Changes during the year in unrecognized tax benefits were as follows:
		2013				2012				2011
		(in millions)
	Unrecognized tax benefits at beginning of year	$	23			$	47			$	237
	Tax positions from current periods	—				3				9
	Tax positions increase from prior periods	—				3				—
	Tax positions decrease from prior periods	(23		)		(19		)		(87		)
	Reductions due to settlements	—				(8		)		(112		)
	Reductions due to expired statute of limitations	—				(3		)		—
	Balance at end of year	$	—			$	23			$	47
Impact on effective tax rate	'
	The impact on the Company's effective tax rate, if recognized, is as follows:
		2013				2012				2011
		(in millions)
	Tax positions impacting the effective tax rate	$	—			$	—			$	28
	Tax positions not impacting the effective tax rate	—				23				19
	Balance of unrecognized tax benefits	$	—			$	23			$	47
Accrued interest for unrecognized tax benefits	'
	Accrued interest for unrecognized tax benefits was as follows:
		2013				2012				2011
		(in millions)
	Interest accrued at beginning of year	$	—			$	6			$	27
	Interest reclassified due to settlements	—				(6		)		(24		)
	Interest accrued during the year	—				—				3
	Balance at end of year	$	—			$	—			$	6
Gulf Power [Member]	'
Income Tax Disclosure [Line Items]	'
Details of income tax provisions	'
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in thousands)
	Federal -
	Current	$	5,009			$	(92,610	)		$	(1,548	)
	Deferred	63,134				161,096				56,087
		68,143				68,486				54,539
	State -
	Current	(2,410		)		(2,484		)		(412		)
	Deferred	13,935				13,209				7,141
		11,525				10,725				6,729
	Total	$	79,668			$	79,211			$	61,268
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:
		2013				2012
		(in thousands)
	Deferred tax liabilities-
	Accelerated depreciation	$	721,087			$	696,502
	Property basis differences	45,960				—
	Fuel recovery clause	7,972				—
	Pension and other employee benefits	25,800				28,579
	Regulatory assets associated with employee benefit obligations	27,660				57,279
	Regulatory assets associated with asset retirement obligations	6,554				6,502
	Other	23,947				16,019
	Total	858,980				804,881
	Deferred tax assets-
	Federal effect of state deferred taxes	24,277				20,656
	Postretirement benefits	17,816				17,905
	Fuel recovery clause	—				6,922
	Pension and other employee benefits	33,015				61,939
	Other basis differences	—				23,549
	Property reserve	15,144				13,773
	Other comprehensive loss	696				993
	Asset retirement obligations	6,554				6,502
	Alternative minimum tax carryforward	18,420				938
	Other	17,084				4,724
	Total	133,006				157,901
	Net deferred tax liabilities	725,974				646,980
	Portion included in current assets (liabilities), net	8,381				1,972
	Accumulated deferred income taxes	$	734,355			$	648,952
Reconciliation of federal statutory income tax rate to effective income tax rate	'
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	3.5			3.3			2.5
	Non-deductible book depreciation	0.5			0.5			0.5
	Differences in prior years' deferred and current tax rates	(0.2	)		(0.2	)		(0.3	)
	AFUDC equity	(1.1	)		(0.9	)		(2.0	)
	Other, net	(0.1	)		(0.2	)		(0.2	)
	Effective income tax rate	37.6	%		37.5	%		35.5	%
Changes in unrecognized tax benefits	'
	Changes during the year in unrecognized tax benefits were as follows:
		2013				2012				2011
		(in thousands)
	Unrecognized tax benefits at beginning of year	$	5,007			$	2,892			$	3,870
	Tax positions from current periods	45				2,630				540
	Tax positions from prior periods	(5,007		)		515				(1,518		)
	Reductions due to settlements	—				(1,030		)		—
	Balance at end of year	$	45			$	5,007			$	2,892
Impact on effective tax rate	'
	The impact on the Company's effective tax rate, if recognized, was as follows:
		2013				2012				2011
		(in thousands)
	Tax positions impacting the effective tax rate	$	45			$	45			$	1,804
	Tax positions not impacting the effective tax rate	—				4,962				1,088
	Balance of unrecognized tax benefits	$	45			$	5,007			$	2,892
Mississippi Power [Member]	'
Income Tax Disclosure [Line Items]	'
Details of income tax provisions	'
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in thousands)
	Federal —
	Current	$	23,345			$	1,212			$	(27,099	)
	Deferred	(342,870		)		16,994				65,206
		(319,525		)		18,206				38,107
	State —
	Current	5,219				1,656				(2,473		)
	Deferred	(53,529		)		694				6,559
		(48,310		)		2,350				4,086
	Total	$	(367,835	)		$	20,556			$	42,193
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:
		2013				2012
		(in thousands)
	Deferred tax liabilities —
	Accelerated depreciation	$	371,553			$	385,899
	Property basis differences	130,679				72,451
	Energy cost management clause under recovered	1,777				9,492
	Regulatory assets associated with asset retirement obligations	16,764				16,851
	Pensions and other benefits	23,769				33,756
	Regulatory assets associated with employee benefit obligations	33,127				68,717
	Regulatory assets associated with the Kemper IGCC	30,708				10,492
	Rate differential	56,074				27,270
	Federal effect of state deferred taxes	30,615				—
	Other	35,583				33,886
	Total	730,649				658,814
	Deferred tax assets —
	Federal effect of state deferred taxes	—				7,732
	Fuel clause over recovered	7,741				38,955
	Estimated loss on Kemper IGCC	472,000				31,200
	Pension and other benefits	57,999				87,416
	Property insurance	23,693				23,171
	Premium on long-term debt	23,736				26,778
	Unbilled fuel	12,136				11,642
	Long-term service agreement	—				5,544
	Asset retirement obligations	16,764				16,851
	Interest rate hedges	5,094				5,644
	ITC carryforward	—				170,938
	Kemper rate factor - regulatory liability retail	36,210				—
	Other	18,094				23,800
	Total	673,467				449,671
	Total deferred tax liabilities, net	57,182				209,143
	Portion included in (accrued) prepaid income taxes, net	15,626				35,815
	Accumulated deferred income taxes	$	72,808			$	244,958
Reconciliation of federal statutory income tax rate to effective income tax rate	'
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	3.7			1.3			1.9
	Non-deductible book depreciation	(0.1	)		0.3			0.3
	AFUDC-equity	5			(18.6	)		(6.3	)
	Other	0.1			(1.2	)		(0.3	)
	Effective income tax rate	43.7	%		16.8	%		30.6	%
Changes in unrecognized tax benefits	'
	Changes during the year in unrecognized tax benefits were as follows:
		2013				2012				2011
		(in thousands)
	Unrecognized tax benefits at beginning of year	$	5,755			$	4,964			$	4,288
	Tax positions from current periods	226				1,186				1,486
	Tax positions from prior periods	(2,141		)		(26		)		(810		)
	Settlements with taxing authorities	—				(369		)		—
	Balance at end of year	$	3,840			$	5,755			$	4,964
Impact on effective tax rate	'
	The impact on the Company's effective tax rate, if recognized, was as follows:
		2013				2012				2011
		(in thousands)
	Tax positions impacting the effective tax rate	$	3,840			$	3,656			$	4,144
	Tax positions not impacting the effective tax rate	—				2,099				820
	Balance of unrecognized tax benefits	$	3,840			$	5,755			$	4,964
Accrued interest for unrecognized tax benefits	'
	Accrued interest for unrecognized tax benefits was as follows:
		2013				2012				2011
		(in thousands)
	Interest accrued at beginning of year	$	772			$	680			$	413
	Interest accrued during the year	399				92				267
	Balance at end of year	$	1,171			$	772			$	680
Southern Power [Member]	'
Income Tax Disclosure [Line Items]	'
Details of income tax provisions	'
	Details of income tax provisions are as follows:
		2013				2012				2011
		(in millions)
	Federal —
	Current	$	(120.2	)		$	(133.1	)		$	61.6
	Deferred	158.7				210.4				12.4
		38.5				77.3				74
	State —
	Current	(5.2		)		(3.0		)		9.8
	Deferred	12.6				18.3				(7.9		)
		7.4				15.3				1.9
	Total	$	45.9			$	92.6			$	75.9
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:
		2013				2012
		(in millions)
	Deferred tax liabilities —
	Accelerated depreciation and other property basis differences	$	829.5			$	632.9
	Basis difference on asset transfers	2.8				3.1
	Levelized capacity revenues	11.2				—
	Other	0.9				—
	Total	844.4				636
	Deferred tax assets —
	Federal effect of state deferred taxes	29.7				25.2
	Net basis difference on ITCs	58				28.6
	Basis difference on asset transfers	2.9				3.9
	Alternative minimum tax carryforward	1.1				1.1
	Unrealized loss on interest rate swaps	11.2				15.7
	Levelized capacity revenues	6				4.5
	State net operating loss	17				8.3
	Other	1.8				4.4
	Total	127.7				91.7
	Valuation Allowance	(7.5		)		(6.2		)
	Net deferred income tax assets	120.2				85.5
	Total deferred tax liabilities, net	724.2				550.5
	Portion included in current income taxes	0.2				0.2
	Accumulated deferred income taxes	$	724.4			$	550.7
Reconciliation of federal statutory income tax rate to effective income tax rate	'
	A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State income tax, net of federal deduction	2.2			3.7			0.6
	Amortization of ITC	(1.7	)		(1.0	)		(0.4	)
	ITC basis difference	(14.5	)		(2.6	)		(3.1	)
	Other	0.3			(0.6	)		(0.3	)
	Effective income tax rate	21.3	%		34.5	%		31.8	%
Changes in unrecognized tax benefits	'
	Changes in unrecognized tax benefits were as follows:
		2013				2012				2011
		(in millions)
	Unrecognized tax benefits at beginning of year	$	2.9			$	2.6			$	2.3
	Tax positions from current periods	1.6				0.7				0.4
	Tax positions from prior periods	(3.0		)		(0.2		)		(0.1		)
	Reductions due to settlements	—				(0.2		)		—
	Balance at end of year	$	1.5			$	2.9			$	2.6
Impact on effective tax rate	'
	The impact on the Company's effective tax rate, if recognized, was as follows:
		2013				2012				2011
		(in millions)
	Tax positions impacting the effective tax rate	$	1.5			$	0.3			$	0.5
	Tax positions not impacting the effective tax rate	—				2.6				2.1
	Balance of unrecognized tax benefits	$	1.5			$	2.9			$	2.6

Financing_Tables

Financing (Tables)	12 Months Ended
	Dec. 31, 2013
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:
		2013				2012
		(in millions)
	Senior notes	$	428			$	2,085
	Other long-term debt	12				227
	Capitalized leases	29				23
	Total	$	469			$	2,335
Credit arrangements with banks	'
	At December 31, 2013, committed credit arrangements with banks were as follows:
		Expires(a)																			Executable Term Loans						Due Within
																											One Year
	Company	2014				2015			2016			2018			Total			Unused			One			Two			Term Out		No Term Out
																					Year			Years
		(in millions)													(in millions)						(in millions)						(in millions)
	Southern Company	$	—			$	—		$	—		$	1,000		$	1,000		$	1,000		$	—		$	—		$	—	$	—
	Alabama Power	238				35			—			1,030			1,303			1,303			53			—			53		185
	Georgia Power	—				—			150			1,600			1,750			1,736			—			—			—		—
	Gulf Power	110				—			165			—			275			275			45			—			45		65
	Mississippi Power	135				—			165			—			300			300			25			40			65		70
	Southern Power	—				—			—			500			500			500			—			—			—		—
	Other	75				25			—			—			100			100			25			—			25		50
	Total	$	558			$	60		$	480		$	4,130		$	5,228		$	5,214		$	148		$	40		$	188	$	370
	(a)	No credit arrangements expire in 2017.
Short-term borrowings	'
	Details of short-term borrowings were as follows:
		Short-term Debt at the End of the Period(a)
		Amount Outstanding				Weighted Average Interest Rate
		(in millions)
	December 31, 2013:
	Commercial paper	$	1,082			0.2	%
	Short-term bank debt	400				0.9	%
	Total	$	1,482			0.4	%
	December 31, 2012:
	Commercial paper	$	820			0.3	%
	Short-term bank debt	—				—	%
	Total	$	820			0.3	%
	(a)    Excludes notes payable related to other energy service contracts of $5 million at December 31, 2012.
Alabama Power [Member]	'
Debt Disclosure [Line Items]	'
Credit arrangements with banks	'
	At December 31, 2013, committed credit arrangements with banks were as follows:
	Expires(a)																Executable						Due Within One Year
																	Term-Loans
	2014				2015			2018			Total			Unused			One			Two			Term Out			No Term Out
																	Year			Years
											(in millions)
	$	238			$	35		$	1,030		$	1,303		$	1,303		$	53		$	—		$	53		$	185
	(a)	No credit arrangements expire in 2016 or 2017.
Georgia Power [Member]	'
Debt Disclosure [Line Items]	'
Scheduled maturities and redemptions of securities due within one year	'
	A summary of scheduled maturities of long-term debt due within one year at December 31 was as follows:
		2013				2012
		(in millions)
	Senior notes	$	—			$	1,675
	Capital lease	5				5
	Total	$	5			$	1,680
Credit arrangements with banks	'
	At December 31, 2013, committed credit arrangements with banks were as follows:
	Expires(a)
	2016		2018		Total		Unused
	(in millions)
	$150		$1,600		$1,750		$1,736
	(a)	No credit arrangements expire in 2014, 2015, or 2017.
Short-term borrowings	'
	Details of short-term borrowings outstanding at December 31, 2013 were as follows:
		Short-term Debt at the End of the Period
		Amount Outstanding				Weighted Average Interest Rate
		(in millions)
	December 31, 2013:
	Commercial paper	$	647			0.2	%
	Short-term bank debt	400				0.9	%
	Total	$	1,047			0.5	%
Gulf Power [Member]	'
Debt Disclosure [Line Items]	'
Credit arrangements with banks	'
	At December 31, 2013, committed credit arrangements with banks were as follows:
	Expires(a)													Executable						Due Within One Year
														Term-Loans
	2014				2016			Total			Unused			One			Two			Term Out			No Term Out
														Year			Years
								(in millions)
	$	110			$	165		$	275		$	275		$	45		$	—		$	45		$	65
	(a)	No credit arrangements expire in 2015, 2017, or 2018.
Short-term borrowings	'
	Details of commercial paper included in notes payable on the balance sheets were as follows:
		Commercial Paper at the
		End of the Period (a)
		Amount Outstanding				Weighted Average Interest Rate
		(in millions)
	December 31, 2013:
		$	136			0.20%
	December 31, 2012:
		$	124			0.30%
	(a)	Excludes notes payable related to other energy service contracts of $3.2 million for the period ended December 31, 2012.
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, 2013 and 2012 was as follows:
		2013				2012
		(in millions)
	Senior notes	$	—			$	50
	Bank term loans	—				175
	Revenue bonds	11.3				51.5
	Capitalized leases	2.5				—
	Outstanding at December 31	$	13.8			$	276.5
Credit arrangements with banks	'
	At December 31, 2013, committed credit arrangements with banks were as follows:
	Expires(a)							Executable			Due Within One Year
								Term-Loans
	2014		2016		Total		Unused	One		Two	Term Out		No Term Out
								Year		Years
	(in millions)
	$135		$165		$300		$300	$25		$40	$65		$70
	(a)	No credit arrangements expire in 2015, 2017, or 2018.
Southern Power [Member]	'
Debt Disclosure [Line Items]	'
Short-term borrowings	'
	Details of short-term borrowings were as follows:
		Commercial Paper at the
		End of the Period
		Amount Outstanding				Weighted Average Interest Rate
		(in millions)
	December 31, 2013:	$	—			N/A
	December 31, 2012:	$	71			0.5	%
Redeemable Preferred Stock [Member] | Alabama Power [Member]	'
Debt Disclosure [Line Items]	'
Redeemable preferred stock	'
	Information for each outstanding series is in the table below:
	Preferred/Preference Stock	Par Value/Stated Capital Per Share		Shares Outstanding			First Call Date	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			8/1/08	Stated Capital
	5.20% Class A Preferred Stock	$25		6,480,000			8/1/08	Stated Capital
	5.30% Class A Preferred Stock	$25		4,000,000			4/1/09	Stated Capital
	5.625% Preference Stock	$25		6,000,000			1/1/12	Stated Capital
	6.450% Preference Stock	$25		6,000,000			*	**
	6.500% Preference Stock	$25		2,000,000			*	**
	* Redemption permitted any time after issuance
	** Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital

Commitments_Tables

Commitments (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments [Line Items]	'
Estimated minimum long-term purchase commitments	'
	Estimated total obligations under these commitments at December 31, 2013 were as follows:
		Capital Leases (4)		Operating Leases		Other
				(in millions)
	2014	$	—	$	201	$	21
	2015	20		244		13
	2016	26		260		11
	2017	27		263		8
	2018	27		266		7
	2019 and thereafter	541		2,104		58
	Total	$	641	$	3,338	$	118
	Less: amounts representing executory costs (1)	142
	Net minimum lease payments	499
	Less: amounts representing interest (2)	166
	Present value of net minimum lease payments (3)	$	333
	-1	Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments.
	-2	Calculated Georgia Power's incremental borrowing rate at the inception of the leases.
	-3	When the PPAs with non-affiliates begin in 2015, Georgia Power will recognize capital lease assets and capital lease obligations totaling $333 million, equal to the lesser of the present value of the net minimum lease payments or the estimated fair value of the leased property.
	-4	A total of $1.3 billion of biomass PPAs included under the non-affiliate capital and operating leases is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.
Estimated minimum lease payments under operating leases	'
	As of December 31, 2013, estimated minimum lease payments under operating leases were as follows:
		Minimum Lease Payments
		Barges & Railcars		Other		Total
		(in millions)
	2014	$	56	$	45	$	101
	2015	35		40		75
	2016	30		35		65
	2017	12		32		44
	2018	6		25		31
	2019 and thereafter	15		120		135
	Total	$	154	$	297	$	451
Alabama Power [Member]	'
Commitments [Line Items]	'
Estimated minimum long-term purchase commitments	'
	Total estimated minimum long-term obligations at December 31, 2013 were as follows:
		Operating Lease PPAs
		(in millions)
	2014	$	36
	2015	38
	2016	39
	2017	40
	2018	42
	2019 and thereafter	182
	Total commitments	$	377
Estimated minimum lease payments under operating leases	'
	As of December 31, 2013, estimated minimum lease payments under operating leases were as follows:
		Minimum Lease Payments
		Railcars		Vehicles & Other		Total
		(in millions)
	2014	$	12	$	3	$	15
	2015	10		2		12
	2016	11		1		12
	2017	6		—		6
	2018	4		—		4
	2019 and thereafter	15		—		15
	Total	$	58	$	6	$	64
Georgia Power [Member]	'
Commitments [Line Items]	'
Estimated long-term obligations	'
	Estimated total long-term obligations at December 31, 2013 were as follows:
		Affiliate Capital Leases		Non-Affiliate Capital Leases (4)		Affiliate Operating Leases		Non-Affiliate Operating Leases (4)		Vogtle Units 1 and 2 Capacity Payments		Total ($)
		(in millions)
	2014	$	—	$	—	$	55	$	112	$	21	$	188
	2015	22		20		89		127		13		271
	2016	22		26		99		142		11		300
	2017	23		27		71		144		8		273
	2018	23		27		62		145		7		264
	2019 and thereafter	278		541		669		1,573		58		3,119
	Total	$	368	$	641	$	1,045	$	2,243	$	118	$	4,415
	Less: amounts representing executory costs(1)	55		142
	Net minimum lease payments	313		499
	Less: amounts representing interest(2)	85		166
	Present value of net minimum lease payments(3)	$	228	$	333
	-1	Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments.
	-2	Calculated at the Company's incremental borrowing rate at the inception of the leases.
	-3	When the PPAs begin in 2015, the Company will recognize capital lease assets and capital lease obligations totaling $482 million, equal to the lesser of the present value of the net minimum lease payments or the estimated fair value of the leased property.
	-4	A total of $1.3 billion of biomass PPAs included under the non-affiliate capital and operating leases is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.
Estimated minimum lease payments under operating leases	'
	As of December 31, 2013, estimated minimum lease payments under operating leases were as follows:
		Minimum Lease Payments
		Railcars		Other		Total
		(in millions)
	2014	$	20	$	6	$	26
	2015	14		6		20
	2016	8		5		13
	2017	5		4		9
	2018	2		4		6
	2019 and thereafter	—		11		11
	Total	$	49	$	36	$	85
Gulf Power [Member]	'
Commitments [Line Items]	'
Estimated minimum long-term purchase commitments	'
	Estimated total minimum long-term commitments at December 31, 2013 were as follows:
		Operating Lease PPAs
		(in millions)
	2014	$	52.9
	2015		78.6
	2016		78.7
	2017		78.8
	2018		78.9
	2019 and thereafter		349.2
	Total	$	717.1
Estimated minimum lease payments under operating leases	'
	Estimated total minimum lease payments under operating leases at December 31, 2013 were as follows:
		Minimum Lease Payments
		Barges &		Other		Total
		Railcars
		(in millions)
	2014	$	13.3	$	0.2	$	13.5
	2015	9.9		0.1		10
	2016	9.9		0.1		10
	2017	0.5		0.1		0.6
	Total	$	33.6	$	0.5	$	34.1

Common_Stock_and_Stock_Compens1

Common Stock and Stock Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
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	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
Summary of stock option activity	'
	Southern Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject to Option			Weighted Average Exercise Price
	Outstanding at December 31, 2012	35,916,303			$	36.37
	Granted	9,152,716			44.17
	Exercised	(6,078,735	)		33.39
	Cancelled	(170,918	)		43.3
	Outstanding at December 31, 2013	38,819,366			$	38.64
	Exercisable at December 31, 2013	24,150,442			$	35.7
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	2013		2012		2011
	Expected volatility	12.00%		16.00%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97
Earnings per share	'
	Shares used to compute diluted earnings per share were as follows:
		Average Common Stock Shares
		2013			2012		2011
		(in millions)
	As reported shares	877			871		857
	Effect of options and performance share award units	4			8		7
	Diluted shares	881			879		864
Gulf Power [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
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	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
Summary of stock option activity	'
	The Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject			Weighted Average
		to Option			Exercise Price
	Outstanding at December 31, 2012	1,388,915			$	36.08
	Granted	285,209			44.06
	Exercised	(281,377	)		33.62
	Cancelled	—			—
	Outstanding at December 31, 2013	1,392,747			$	38.21
	Exercisable at December 31, 2013	883,985			$	35.29
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	2013		2012		2011
	Expected volatility	12.00%		16.00%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97
Alabama Power [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
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	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
Summary of stock option activity	'
	The Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject to Option			Weighted Average Exercise Price
	Outstanding at December 31, 2012	6,060,552			$	36.02
	Granted	1,319,038			44.07
	Exercised	(1,035,611	)		32.74
	Cancelled	(4,271	)		42.88
	Outstanding at December 31, 2013	6,339,708			$	38.23
	Exercisable at December 31, 2013	4,021,541			$	35.29
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	2013		2012		2011
	Expected volatility	12.00%		16%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97
Georgia Power [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
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	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
Summary of stock option activity	'
	The Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject to Option			Weighted Average Exercise Price
	Outstanding at December 31, 2012	6,547,498			$	36.18
	Granted	1,509,662			44.09
	Exercised	(1,196,585	)		33.38
	Cancelled	(11,421	)		40.99
	Outstanding at December 31, 2013	6,849,154			$	38.41
	Exercisable at December 31, 2013	4,321,853			$	35.51
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	2013		2012		2011
	Expected volatility	12.00%		16.00%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97
Mississippi Power [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
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	2013		2012		2011
	Expected volatility	16.60%		17.70%		17.50%
	Expected term (in years)	5		5		5
	Interest rate	0.90%		0.90%		2.30%
	Dividend yield	4.40%		4.20%		4.80%
	Weighted average grant-date fair value	$2.93		$3.39		$3.23
Summary of stock option activity	'
	The Company's activity in the stock option program for 2013 is summarized below:
		Shares Subject to Option			Weighted Average Exercise Price
	Outstanding at December 31, 2012	1,373,566			$	36.34
	Granted	345,830			44.03
	Exercised	(379,933	)		33.59
	Cancelled	(5,870	)		44.94
	Outstanding at December 31, 2013	1,333,593			$	39.08
	Exercisable at December 31, 2013	898,518			$	37.02
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	2013		2012		2011
	Expected volatility	12.00%		16.00%		19.20%
	Expected term (in years)	3		3		3
	Interest rate	0.40%		0.40%		1.40%
	Annualized dividend rate	$1.96		$1.89		$1.82
	Weighted average grant-date fair value	$40.50		$41.99		$35.97

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Line Items]	'
Assets and liabilities measured at fair value on a recurring basis	'
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	24		$	—	$	24
	Interest rate derivatives	—			3			—		3
	Nuclear decommissioning trusts:(a)
	Domestic equity	589			75			—		664
	Foreign equity	35			196			—		231
	U.S. Treasury and government agency securities	—			103			—		103
	Municipal bonds	—			64			—		64
	Corporate bonds	—			229			—		229
	Mortgage and asset backed securities	—			132			—		132
	Other investments	—			37			3		40
	Cash equivalents	491			—			—		491
	Other investments	9			—			4		13
	Total	$	1,124		$	863		$	7	$	1,994
	Liabilities:
	Energy-related derivatives	$	—		$	56		$	—	$	56
	(a)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	26		$	—	$	26
	Interest rate derivatives	—			10			—		10
	Nuclear decommissioning trusts:(a)
	Domestic equity	453			65			—		518
	Foreign equity	28			172			—		200
	U.S. Treasury and government agency securities	—			134			—		134
	Municipal bonds	—			55			—		55
	Corporate bonds	—			234			—		234
	Mortgage and asset backed securities	—			141			—		141
	Other investments	—			20			—		20
	Cash equivalents	384			—			—		384
	Other investments	9			—			15		24
	Total	$	874		$	857		$	15	$	1,746
	Liabilities:
	Energy-related derivatives	$	—		$	111		$	—	$	111
	(a)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'
	As of December 31, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair			Unfunded		Redemption	Redemption
		Value			Commitments		Frequency	Notice Period
	As of December 31, 2013:	(in millions)
	Nuclear decommissioning trusts:
	Foreign equity funds	$	131		None		Monthly	5 days
	Corporate bonds – commingled funds	8			None		Daily	Not applicable
	Equity – commingled funds	65			None		Daily/Monthly	Daily/7 days
	Other – commingled funds	24			None		Daily	Not applicable
	Trust-owned life insurance	110			None		Daily	15 days
	Cash equivalents:
	Money market funds	491			None		Daily	Not applicable
	As of December 31, 2012:
	Nuclear decommissioning trusts:
	Foreign equity funds	$	117		None		Monthly	5 days
	Corporate bonds – commingled funds	9			None		Daily	Not applicable
	Equity – commingled funds	55			None		Daily/Monthly	Daily/7 days
	Other – commingled funds	10			None		Daily	Not applicable
	Trust-owned life insurance	96			None		Daily	15 days
	Cash equivalents:
	Money market funds	384			None		Daily	Not applicable
Financial instruments not having carrying amount equal to fair value	'
	As of December 31, 2013 and 2012, 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:
	2013	$	21,650		$	22,197
	2012	$	21,530		$	23,480
Alabama Power [Member]	'
Fair Value Disclosures [Line Items]	'
Assets and liabilities measured at fair value on a recurring basis	'
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	7		$	—	$	7
	Nuclear decommissioning trusts:(a)
	Domestic equity	392			74			—		466
	Foreign equity	35			65			—		100
	U.S. Treasury and government agency securities	—			24			—		24
	Corporate bonds	—			89			—		89
	Mortgage and asset backed securities	—			18			—		18
	Other investments	—			13			3		16
	Cash equivalents	236			—			—		236
	Total	$	663		$	290		$	3	$	956
	Liabilities:
	Energy-related derivatives	$	—		$	8		$	—	$	8
	(a)	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information.
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	5		$	—	$	5
	Nuclear decommissioning trusts:(a)
	Domestic equity	291			64			—		355
	Foreign equity	28			55			—		83
	U.S. Treasury and government agency securities	—			29			—		29
	Corporate bonds	—			101			—		101
	Mortgage and asset backed securities	—			26			—		26
	Other investments	—			10			—		10
	Total	$	319		$	290		$	—	$	609
	Liabilities:
	Energy-related derivatives	$	—		$	18		$	—	$	18
	(a)	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'
	As of December 31, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value		Unfunded	Redemption Frequency		Redemption
				Commitments			Notice Period
	As of December 31, 2013:	(in millions)
	Nuclear decommissioning trusts:
	Equity-commingled funds	$65		None	Daily/Monthly		Daily/7 Days
	Trust-owned life insurance	110		None	Daily		15 days
	Cash equivalents:
	Money market funds	236		None	Daily		Not applicable
	As of December 31, 2012:
	Nuclear decommissioning trusts:
	Equity-commingled funds	$55		None	Daily/Monthly		Daily/7 days
	Trust-owned life insurance	96		None	Daily		15 days
Financial instruments not having carrying amount equal to fair value	'
	As of December 31, 2013 and 2012, 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:
	2013	$	6,228		$	6,534
	2012	$	6,179		$	6,899
Georgia Power [Member]	'
Fair Value Disclosures [Line Items]	'
Assets and liabilities measured at fair value on a recurring basis	'
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	5		$	—	$	5
	Nuclear decommissioning trusts:(a)
	Domestic equity	197			1			—		198
	Foreign equity	—			131			—		131
	U.S. Treasury and government agency securities	—			79			—		79
	Municipal bonds	—			64			—		64
	Corporate bonds	—			140			—		140
	Mortgage and asset backed securities	—			114			—		114
	Other investments	—			24			—		24
	Total	$	197		$	558		$	—	$	755
	Liabilities:
	Energy-related derivatives	$	—		$	21		$	—	$	21
	(a)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	11		$	—	$	11
	Nuclear decommissioning trusts:(a)
	Domestic equity	162			1			—		163
	Foreign equity	—			117			—		117
	U.S. Treasury and government agency securities	—			105			—		105
	Municipal bonds	—			55			—		55
	Corporate bonds	—			133			—		133
	Mortgage and asset backed securities	—			115			—		115
	Other investments	—			10			—		10
	Cash equivalents	15			—			—		15
	Total	$	177		$	547		$	—	$	724
	Liabilities:
	Energy-related derivatives	$	—		$	45		$	—	$	45
	(a)	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'
	As of December 31, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value			Unfunded		Redemption	Redemption
					Commitments		Frequency	Notice Period
	As of December 31, 2013:	(in millions)
	Nuclear decommissioning trusts:
	Foreign equity fund	$	131		None		Daily	5 days
	Corporate bonds — commingled funds	8			None		Daily	Not applicable
	Other — commingled funds	24			None		Daily	Not applicable
	As of December 31, 2012:
	Nuclear decommissioning trusts:
	Foreign equity fund	$	117		None		Daily	5 days
	Corporate bonds — commingled funds	9			None		Daily	Not applicable
	Other — commingled funds	10			None		Daily	Not applicable
	Cash equivalents:
	Money market funds	15			None		Daily	Not applicable
Financial instruments not having carrying amount equal to fair value	'
	As of December 31, 2013 and 2012, 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:
	2013	$	8,593		$	8,782
	2012	$	9,624		$	10,427
Gulf Power [Member]	'
Fair Value Disclosures [Line Items]	'
Assets and liabilities measured at fair value on a recurring basis	'
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in thousands)
	Assets:
	Energy-related derivatives	$	—		$	6,962		$	—	$	6,962
	Cash equivalents	15,929			—			—		15,929
	Total	$	15,929		$	6,962		$	—	$	22,891
	Liabilities:
	Energy-related derivatives	$	—		$	17,043		$	—	$	17,043
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant			Significant
					Other			Unobservable
					Observable			Inputs
					Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in thousands)
	Assets:
	Energy-related derivatives	$	—		$	4,358		$	—	$	4,358
	Cash equivalents	15,231			—			—		15,231
	Total	$	15,231		$	4,358		$	—	$	19,589
	Liabilities:
	Energy-related derivatives	$	—		$	27,112		$	—	$	27,112
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, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value		Unfunded	Redemption		Redemption
				Commitments	Frequency		Notice Period
	As of December 31, 2013:	(in thousands)
	Cash equivalents:
	Money market funds	$15,929		None	Daily		Not applicable
	As of December 31, 2012:
	Cash equivalents:
	Money market funds	$15,231		None	Daily		Not applicable
Financial instruments not having carrying amount equal to fair value	'
	As of December 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:
		Carrying Amount			Fair Value
		(in thousands)
	Long-term debt:
	2013	$	1,233,163		$	1,261,889
	2012	$	1,245,870		$	1,367,404
Mississippi Power [Member]	'
Fair Value Disclosures [Line Items]	'
Assets and liabilities measured at fair value on a recurring basis	'
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in thousands)
	Assets:
	Energy-related derivatives	$	—		$	4,803		$	—	$	4,803
	Cash equivalents	125,000			—			—		125,000
	Total	$	125,000		$	4,803		$	—	$	129,803
	Liabilities:
	Energy-related derivatives	$	—		$	10,281		$	—	$	10,281
	Foreign currency derivatives	—			1			—		1
	Total	$	—		$	10,282		$	—	$	10,282
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in thousands)
	Assets:
	Energy-related derivatives	$	—		$	2,519		$	—	$	2,519
	Cash equivalents	125,600			—			—		125,600
	Total	$	125,600		$	2,519		$	—	$	128,119
	Liabilities:
	Energy-related derivatives	$	—		$	19,446		$	—	$	19,446
	Foreign currency derivatives	—			37			—		37
	Total	$	—		$	19,483		$	—	$	19,483
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, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value			Unfunded		Redemption	Redemption
					Commitments		Frequency	Notice Period
	As of December 31, 2013:	(in thousands)
	Cash equivalents:
	Money market funds	$	125,000		None		Daily	Not applicable
	As of December 31, 2012:
	Cash equivalents:
	Money market funds	$	125,600		None		Daily	Not applicable
Financial instruments not having carrying amount equal to fair value	'
	As of December 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:
		Carrying Amount			Fair Value
		(in thousands)
	Long-term debt:
	2013	$	2,098,639		$	2,045,519
	2012	$	1,840,933		$	1,956,799
Southern Power [Member]	'
Fair Value Disclosures [Line Items]	'
Assets and liabilities measured at fair value on a recurring basis	'
	As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2013:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	0.6		$	—	$	0.6
	Cash equivalents	68			—			—		68
	Total	$	68		$	0.6		$	—	$	68.6
	Liabilities:
	Energy-related derivatives	$	—		$	0.6		$	—	$	0.6
	As of December 31, 2012, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:
		Fair Value Measurements Using
		Quoted Prices in Active Markets for Identical Assets			Significant Other Observable Inputs			Significant Unobservable Inputs
	As of December 31, 2012:	(Level 1)			(Level 2)			(Level 3)		Total
		(in millions)
	Assets:
	Energy-related derivatives	$	—		$	2.1		$	—	$	2.1
	Cash equivalents	26			—			—		26
	Total	$	26		$	2.1		$	—	$	28.1
	Liabilities:
	Energy-related derivatives	$	—		$	1.3		$	—	$	1.3
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, 2013 and 2012, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:
		Fair Value			Unfunded		Redemption	Redemption
					Commitments		Frequency	Notice Period
	As of December 31, 2013:	(in millions)
	Cash equivalents:
	Money market funds	$	68		None		Daily	Not applicable
	As of December 31, 2012:
	Cash equivalents:
	Money market funds	$	26		None		Daily	Not applicable
Financial instruments not having carrying amount equal to fair value	'
	As of December 31, 2013 and 2012, 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:
	2013	$	1,620		$	1,660
	2012	$	1,306		$	1,444

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative [Line Items]	'
Notional amount of interest rate derivatives	'
	At December 31, 2013, the following interest rate derivatives were outstanding:
		Notional				Interest Rate		Weighted Average Interest		Hedge		Fair Value
		Amount				Received		Rate Paid		Maturity Date		Gain (Loss)
												December 31,
												2013
		(in millions)										(in millions)
	Fair value hedges of existing debt
		$	350			4.15%		3-month LIBOR + 1.96%		May-14		$	3
Fair value of energy-related derivatives and interest rate derivatives	'
	At December 31, 2013 and 2012, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in millions)										(in millions)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	16			$	10			Liabilities from risk management activities		$	26			$	74
		Other deferred charges and assets		7				13				Other deferred credits and liabilities		29				35
	Total derivatives designated as hedging instruments for regulatory purposes			$	23			$	23					$	55			$	109
	Derivatives designated as hedging instruments in cash flow and fair value hedges
	Interest rate derivatives:	Other current assets		$	3			$	7			Liabilities from risk management activities		$	—			$	—
		Other deferred charges and assets		—				3				Other deferred credits and liabilities		—				—
	Total derivatives designated as hedging instruments in cash flow and fair value hedges			$	3			$	10					$	—			$	—
	Derivatives not designated as hedging instruments
	Energy-related derivatives:	Other current assets		$	—			$	1			Liabilities from risk management activities		$	1			$	1
		Other deferred charges and assets		1				2				Other deferred credits and liabilities		—				1
	Total derivatives not designated as hedging instruments			$	1			$	3					$	1			$	2
	Total			$	27			$	36					$	56			$	111
Balance sheet offsetting	'
	Amounts related to energy-related derivative contracts at December 31, 2013 and 2012 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	24			$	26			Energy-related derivatives presented in the Balance Sheet (a)		$	56			$	111
	Gross amounts not offset in the Balance Sheet (b)		(22		)		(23		)		Gross amounts not offset in the Balance Sheet (b)		(22		)		(23		)
	Net-energy related derivative assets		$	2			$	3			Net-energy related derivative liabilities		$	34			$	88
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
Pre-tax effects on the balance sheets	'
	At December 31, 2013 and 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in millions)										(in millions)
	Energy-related derivatives:	Other regulatory assets, current		$	(26	)		$	(74	)		Other regulatory liabilities, current		$	16			$	10
		Other regulatory assets, deferred		(29		)		(35		)		Other regulatory liabilities, deferred		7				13
	Total energy-related derivative gains (losses)			$	(55	)		$	(109	)				$	23			$	23
Alabama Power [Member]	'
Derivative [Line Items]	'
Energy-related derivative contracts	'
	At December 31, 2013, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:
	Net Purchased		Longest Hedge		Longest Non-Hedge
	mmBtu*		Date		Date
	(in millions)
	69		2017		—
	*	million British thermal units (mmBtu)
Fair value of energy-related derivatives and interest rate derivatives	'
	At December 31, 2013 and 2012, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in millions)										(in millions)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	5			$	2			Liabilities from risk management activities		$	3			$	14
		Other deferred charges and assets		2				3				Other deferred credits and liabilities		5				4
	Total derivatives designated as hedging instruments for regulatory purposes			$	7			$	5					$	8			$	18
	Total			$	7			$	5					$	8			$	18
Balance sheet offsetting	'
	Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2013 and 2012 are presented in the following tables.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	7			$	5			Energy-related derivatives presented in the Balance Sheet (a)		$	8			$	18
	Gross amounts not offset in the Balance Sheet (b)		(5		)		(4		)		Gross amounts not offset in the Balance Sheet (b)		(5		)		(4		)
	Net-energy related derivative assets		$	2			$	1			Net-energy related derivative liabilities		$	3			$	14
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
Pre-tax effects on the balance sheets	'
	At December 31, 2013 and 2012, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in millions)										(in millions)
	Energy-related derivatives:	Other regulatory assets, current		$	(3	)		$	(14	)		Other current liabilities		$	5			$	2
		Other regulatory assets, deferred		(5		)		(4		)		Other regulatory liabilities, deferred		2				3
	Total energy-related derivative gains (losses)			$	(8	)		$	(18	)				$	7			$	5
Pre-tax effects on the statements of income	'
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows:
	Derivatives in Cash Flow Hedging Relationships		Gain (Loss) Recognized in												Gain (Loss) Reclassified from Accumulated OCI into Income
			OCI on Derivative												(Effective Portion)
			(Effective Portion)														Amount
	Derivative Category		2013				2012				2011				Statements of Income		2013				2012				2011
															Location
			(in millions)														(in millions)
	Interest rate derivatives		$	—			$	(18	)		$	(14	)		Interest expense, net of amounts capitalized		$	(3	)		$	(3	)		$	3
Georgia Power [Member]	'
Derivative [Line Items]	'
Fair value of energy-related derivatives and interest rate derivatives	'
	At December 31, 2013 and 2012, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in millions)										(in millions)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	3			$	6			Liabilities from risk management activities		$	13			$	30
		Other deferred charges and assets		2				5				Other deferred credits and liabilities		8				15
	Total derivatives designated as hedging instruments for regulatory purposes			$	5			$	11					$	21			$	45
Balance sheet offsetting	'
	Some of these energy-related contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2013 and 2012 are presented in the following tables.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	5			$	11			Energy-related derivatives presented in the Balance Sheet (a)		$	21			$	45
	Gross amounts not offset in the Balance Sheet (b)		(5		)		(11		)		Gross amounts not offset in the Balance Sheet (b)		(5		)		(11		)
	Net-energy related derivative assets		$	—			$	—			Net-energy related derivative liabilities		$	16			$	34
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
Pre-tax effects on the balance sheets	'
	At December 31, 2013 and 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in millions)										(in millions)
	Energy-related derivatives:	Other regulatory assets, current		$	(13	)		$	(30	)		Other regulatory liabilities, current		$	3			$	6
		Other regulatory assets, deferred		(8		)		(15		)		Other deferred credits and liabilities		2				5
	Total energy-related derivative gains (losses)			$	(21	)		$	(45	)				$	5			$	11
Gulf Power [Member]	'
Derivative [Line Items]	'
Fair value of energy-related derivatives and interest rate derivatives	'
	At December 31, 2013 and 2012, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet Location		2013				2012
				(in thousands)										(in thousands)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	4,893			$	1,293			Liabilities from risk management activities		$	6,470			$	16,529
		Other deferred charges and assets		2,069				3,065				Other deferred credits and liabilities		10,573				10,583
	Total derivatives designated as hedging instruments for regulatory purposes			$	6,962			$	4,358					$	17,043			$	27,112
Balance sheet offsetting	'
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	7			$	4			Energy-related derivatives presented in the Balance Sheet (a)		$	17			$	27
	Gross amounts not offset in the Balance Sheet (b)		(6		)		(4		)		Gross amounts not offset in the Balance Sheet (b)		(6		)		(4		)
	Net-energy related derivative assets		$	1			$	—			Net-energy related derivative liabilities		$	11			$	23
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
Pre-tax effects on the balance sheets	'
	At December 31, 2013 and 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in thousands)										(in thousands)
	Energy-related derivatives:	Other regulatory assets, current		$	(6,470	)		$	(16,529	)		Other regulatory liabilities, current		$	4,893			$	1,293
		Other regulatory assets, deferred		(10,573		)		(10,583		)		Other regulatory liabilities, deferred		2,069				3,065
	Total energy-related derivative gains (losses)			$	(17,043	)		$	(27,112	)				$	6,962			$	4,358
Pre-tax effects on the statements of income	'
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
	Derivatives in Cash	Gain (Loss) Recognized in												Gain (Loss) Reclassified from Accumulated
	Flow Hedging Relationships	OCI on Derivative												OCI into Income (Effective Portion)
		(Effective Portion)														Amount
	Derivative Category	2013				2012				2011				Statements of Income Location		2013				2012				2011
		(in thousands)														(in thousands)
	Interest rate derivatives	$	—			$	—			$	—			Interest expense, net of amounts capitalized		$	(769	)		$	(933	)		$	(933	)
Mississippi Power [Member]	'
Derivative [Line Items]	'
Energy-related derivative contracts	'
	At December 31, 2013, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows:
	Net Purchased		Longest Hedge		Longest Non-Hedge
	mmBtu*		Date		Date
	(in millions)
	56		2017		—
	*	mmBtu — million British thermal units
Fair value of energy-related derivatives and interest rate derivatives	'
	At December 31, 2013 and 2012, the fair value of energy-related derivatives, foreign currency derivatives, and interest rate derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet Location		2013				2012				Balance Sheet		2013				2012
												Location
				(in thousands)										(in thousands)
	Derivatives designated as hedging instruments for regulatory purposes
	Energy-related derivatives:	Other current assets		$	3,352			$	638			Liabilities from risk management activities		$	3,652			$	13,116
		Other deferred charges and assets		1,451				1,881				Other deferred credits and liabilities		6,629				6,330
	Total derivatives designated as hedging instruments for regulatory purposes			$	4,803			$	2,519					$	10,281			$	19,446
	Derivatives designated as hedging instruments in cash flow and fair value hedges
	Foreign currency derivatives:	Other current assets		$	—			$	—			Liabilities from risk management activities		$	1			$	—
		Other deferred charges and assets		—				—				Other deferred credits and liabilities		—				37
	Total derivatives designated as hedging instruments in cash flow and fair value hedges			$	—			$	—					$	1			$	37
	Total			$	4,803			$	2,519					$	10,282			$	19,483
Balance sheet offsetting	'
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in thousands)										(in thousands)
	Energy-related derivatives presented in the Balance Sheet (a)		$	4,803			$	2,519			Energy-related derivatives presented in the Balance Sheet (a)		$	10,281			$	19,446
	Gross amounts not offset in the Balance Sheet (b)		(3,856		)		(2,333		)		Gross amounts not offset in the Balance Sheet (b)		(3,856		)		(2,333		)
	Net-energy related derivative assets		$	947			$	186			Net-energy related derivative liabilities		$	6,425			$	17,113
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
Pre-tax effects on the balance sheets	'
	At December 31, 2013 and 2012, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
		Unrealized Losses										Unrealized Gains
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in thousands)										(in thousands)
	Energy-related derivatives:	Other regulatory assets, current		$	(3,652	)		$	(13,116	)		Other regulatory liabilities, current		$	3,352			$	638
		Other regulatory assets, deferred		(6,629		)		(6,330		)		Other regulatory liabilities, deferred		1,451				1,881
	Total energy-related derivative gains (losses)			$	(10,281	)		$	(19,446	)				$	4,803			$	2,519
Pre-tax effects on the statements of income	'
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of income were as follows:
	Derivatives in Cash Flow	Gain (Loss) Recognized in												Gain (Loss) Reclassified from Accumulated
	Hedging Relationships	OCI on Derivative												OCI into Income
		(Effective Portion)												(Effective Portion)
																Amount
	Derivative Category	2013				2012				2011				Statements of Income Location		2013				2012				2011
		(in thousands)														(in thousands)
	Energy-related derivatives	$	—			$	—			$	(3	)		Fuel		$	—			$	—			$	—
	Interest rate derivatives	—				(774		)		(14,361		)		Interest Expense		(1,375		)		(1,073		)		48
	Total	$	—			$	(774	)		$	(14,364	)				$	(1,375	)		$	(1,073	)		$	48
Southern Power [Member]	'
Derivative [Line Items]	'
Fair value of energy-related derivatives and interest rate derivatives	'
	At December 31, 2013 and 2012, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
		Asset Derivatives										Liability Derivatives
	Derivative Category	Balance Sheet		2013				2012				Balance Sheet		2013				2012
		Location										Location
				(in millions)										(in millions)
	Derivatives not designated as hedging instruments
	Energy-related derivatives:	Assets from risk management activities		$	0.2			$	0.4			Other current liabilities		$	0.6			$	0.7
		Other deferred charges and assets – non-affiliated		0.4				1.7				Other deferred credits and liabilities – non-affiliated		—				0.6
	Total derivatives not designated as hedging instruments			$	0.6			$	2.1					$	0.6			$	1.3
	Total			$	0.6			$	2.1					$	0.6			$	1.3
Balance sheet offsetting	'
	Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.
	Fair Value
	Assets		2013				2012				Liabilities		2013				2012
			(in millions)										(in millions)
	Energy-related derivatives presented in the Balance Sheet (a)		$	0.6			$	2.1			Energy-related derivatives presented in the Balance Sheet (a)		$	0.6			$	1.3
	Gross amounts not offset in the Balance Sheet (b)		(0.1		)		(1.0		)		Gross amounts not offset in the Balance Sheet (b)		(0.1		)		(1.0		)
	Net-energy related derivative assets		$	0.5			$	1.1			Net-energy related derivative liabilities		$	0.5			$	0.3
	(a) The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
Pre-tax effects on the statements of income	'
	For the years ended December 31, 2013, 2012, and 2011, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
	Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in												Gain (Loss) Reclassified from AOCI into Income
		AOCI on Derivative												(Effective Portion)
		(Effective Portion)													Amount
	Derivative Category	2013				2012				2011				Statements of Income Location	2013				2012				2011
		(in millions)													(in millions)
	Energy-related derivatives	$	—			$	(0.2	)		$	0.1			Depreciation and amortization	$	0.4			$	0.4			$	0.4
	Interest rate derivatives	—				—				—				Interest expense, net of amounts capitalized	(6.5		)		(10.5		)		(11.4		)
														Other income (expense), net	—				—				(1.0		)
	Total	$	—			$	(0.2	)		$	0.1				$	(6.1	)		$	(10.1	)		$	(12.0	)

Segment_and_Related_Informatio1

Segment and Related Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Financial data for business segments	'
	Financial data for business segments and products and services for the years ended December 31, 2013, 2012, and 2011 was as follows:
		Electric Utilities
		Traditional			Southern			Eliminations			Total			All			Eliminations			Consolidated
		Operating			Power									Other
		Companies
		(in millions)
	2013
	Operating revenues	$	16,136		$	1,275		$	(376	)	$	17,035		$	139		$	(87	)	$	17,087
	Depreciation and amortization	1,711			175			—			1,886			15			—			1,901
	Interest income	17			1			—			18			2			(1		)	19
	Interest expense	714			74			—			788			36			—			824
	Income taxes	889			46			—			935			(85		)	(1		)	849
	Segment net income (loss)(a) (b)	1,486			166			—			1,652			(10		)	2			1,644
	Total assets	59,447			4,429			(101		)	63,775			1,077			(306		)	64,546
	Gross property additions	5,226			633			—			5,859			9			—			5,868
	2012
	Operating revenues	$	15,730		$	1,186		$	(438	)	$	16,478		$	141		$	(82	)	$	16,537
	Depreciation and amortization	1,629			143			—			1,772			15			—			1,787
	Interest income	21			1			—			22			19			(1		)	40
	Interest expense	757			63			—			820			39			—			859
	Income taxes	1,307			93			—			1,400			(66		)	—			1,334
	Segment net income (loss)(a)	2,145			175			1			2,321			33			(4		)	2,350
	Total assets	58,600			3,780			(129		)	62,251			1,116			(218		)	63,149
	Gross property additions	4,813			241			—			5,054			5			—			5,059
	2011
	Operating revenues	$	16,763		$	1,236		$	(412	)	$	17,587		$	149		$	(79	)	$	17,657
	Depreciation and amortization	1,576			124			—			1,700			16			1			1,717
	Interest income	18			1			—			19			3			(1		)	21
	Interest expense	726			77			—			803			54			—			857
	Income taxes	1,217			76			—			1,293			(74		)	—			1,219
	Segment net income (loss)(a)	2,052			162			—			2,214			(8		)	(3		)	2,203
	Total assets	54,622			3,581			(127		)	58,076			1,592			(401		)	59,267
	Gross property additions	4,589			255			—			4,844			9			—			4,853
	(a)    After dividends on preferred and preference stock of subsidiaries.
	(b)    Segment net income (loss) in 2013 includes $1.2 billion in pre-tax charges ($729 million after tax) for estimated probable losses on the Kemper IGCC.
	See Note (3) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Construction Schedule and Cost Estimate" for additional information.
Financial data for products and services	'
	Products and Services
	Electric Utilities' Revenues
	Year		Retail			Wholesale			Other			Total
			(in millions)
	2013		$	14,541		$	1,855		$	639		$	17,035
	2012		14,187			1,675			616			16,478
	2011		15,071			1,905			611			17,587

Quarterly_Financial_Informatio1

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information [Line Items]	'
Summarized quarterly financial data	'
	Summarized quarterly financial information for 2013 and 2012 is as follows:
							Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries			Per Common Share
		Operating		Operating						Basic		Diluted Earnings				Trading
		Revenues		Income						Earnings						Price Range
	Quarter Ended													Dividends		High		Low
		(in millions)
	Mar-13	$	3,897	$	325		$	81		$	0.09	$	0.09	$	0.49	$	46.95	$	42.82
	Jun-13	4,246		640			297			0.34		0.34		0.5075		48.74		42.32
	Sep-13	5,017		1,491			852			0.97		0.97		0.5075		45.75		40.63
	Dec-13	3,927		799			414			0.47		0.47		0.5075		42.94		40.03
	Mar-12	$	3,604	$	766		$	368		$	0.42	$	0.42	$	0.4725	$	46.06	$	43.71
	Jun-12	4,181		1,143			623			0.71		0.71		0.49		48.45		44.22
	Sep-12	5,049		1,740			976			1.11		1.11		0.49		48.59		44.64
	Dec-12	3,703		814			383			0.44		0.44		0.49		47.09		41.75
Alabama Power [Member]	'
Quarterly Financial Information [Line Items]	'
Summarized quarterly financial data	'
	Summarized quarterly financial information for 2013 and 2012 is as follows:
	Quarter Ended	Operating		Operating			Net Income After Dividends on Preferred and Preference Stock
		Revenues		Income
		(in millions)
	Mar-13	$	1,308	$	307		$	141
	Jun-13	1,392		357			173
	Sep-13	1,604		500			258
	Dec-13	1,314		312			140
	Mar-12	$	1,216	$	291		$	126
	Jun-12	1,377		390			185
	Sep-12	1,637		544			280
	Dec-12	1,290		271			113
Georgia Power [Member]	'
Quarterly Financial Information [Line Items]	'
Summarized quarterly financial data	'
	Summarized quarterly financial information for 2013 and 2012 is as follows:
	Quarter Ended	Operating Revenues		Operating Income			Net Income After Dividends on Preferred and Preference Stock
		(in millions)
	Mar-13	$	1,882	$	412		$	197
	Jun-13	2,042		552			282
	Sep-13	2,484		872			487
	Dec-13	1,866		404			208
	Mar-12	$	1,745	$	344		$	167
	Jun-12	2,020		535			295
	Sep-12	2,498		924			525
	Dec-12	1,735		400			181
Gulf Power [Member]	'
Quarterly Financial Information [Line Items]	'
Summarized quarterly financial data	'
	Summarized quarterly financial information for 2013 and 2012 is as follows:
	Quarter Ended	Operating		Operating			Net Income After Dividends on Preference Stock
		Revenues		Income
		(in thousands)
	Mar-13	$	326,274	$	51,640		$	21,792
	Jun-13	371,173		69,151			32,582
	Sep-13	399,361		87,776			44,754
	Dec-13	343,493		56,436			25,301
	Mar-12	$	316,245	$	49,098		$	20,666
	Jun-12	370,208		71,465			34,963
	Sep-12	421,819		93,813			47,754
	Dec-12	331,490		53,818			22,549
Mississippi Power [Member]	'
Quarterly Financial Information [Line Items]	'
Summarized quarterly financial data	'
	Summarized quarterly financial information for 2013 and 2012 is as follows:
	Quarter Ended	Operating		Operating			Net Income (Loss) After Dividends on Preferred Stock
		Revenues		Income (Loss)
		(in thousands)
	Mar-13	$	245,934	$	(429,148	)	$	(246,321	)
	Jun-13	306,435		(388,395		)	(219,110		)
	Sep-13	325,206		(79,890		)	(24,115		)
	Dec-13	267,582		(24,412		)	12,921
	Mar-12	$	228,714	$	30,213		$	25,255
	Jun-12	266,084		46,986			35,027
	Sep-12	305,419		66,151			54,625
	December 2012 (Restated)	235,779		(46,338		)	(14,965		)
Southern Power [Member]	'
Quarterly Financial Information [Line Items]	'
Summarized quarterly financial data	'
	Summarized quarterly financial information for 2013 and 2012 is as follows:
	Quarter Ended	Operating		Operating			Net
		Revenues		Income			Income
		(in thousands)
	Mar-13	$	302,947	$	64,673		$	29,192
	Jun-13	307,255		55,024			27,922
	Sep-13	364,767		116,497			85,153
	Dec-13	300,257		53,781			23,266
	Mar-12	$	253,681	$	56,343		$	29,316
	Jun-12	285,805		90,038			46,602
	Sep-12	354,971		119,234			68,376
	Dec-12	291,591		65,816			30,991

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) (USD $)

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Asset retirement obligations-liability [Member]

Asset retirement obligations-liability [Member]

Other cost of removal obligations [Member]

Other cost of removal obligations [Member]

Deferred income tax credits [Member]

Deferred income tax credits [Member]

Property damage reserves [Member]

Property damage reserves [Member]

Other regulatory liabilities [Member]

Other regulatory liabilities [Member]

Kemper Regulatory Deferral [Member]

Kemper Regulatory Deferral [Member]

Deferred income tax charges [Member]

Deferred income tax charges [Member]

Deferred income tax charges - Medicare subsidy [Member]

Deferred income tax charges - Medicare subsidy [Member]

Asset retirement obligations-asset [Member]

Asset retirement obligations-asset [Member]

Loss on reacquired debt [Member]

Loss on reacquired debt [Member]

Vacation pay [Member]

Vacation pay [Member]

Under recovered regulatory clause revenues [Member]

Under recovered regulatory clause revenues [Member]

Canceled construction projects [Member]

Canceled construction projects [Member]

PPA charges [Member]

PPA charges [Member]

Fuel hedging-asset [Member]

Fuel hedging-asset [Member]

Other regulatory assets [Member]

Other regulatory assets [Member]

Environmental remediation-asset [Member]

Environmental remediation-asset [Member]

Regulatory assets associated with Kemper IGCC [Member]

Regulatory assets associated with Kemper IGCC [Member]

Retiree benefit plans [Member]

Retiree benefit plans [Member]

Maximum [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Adobe Solar LLC [Member]

Adobe Solar LLC [Member]

Asset retirement obligations-liability [Member]

Asset retirement obligations-liability [Member]

Other cost of removal obligations [Member]

Other cost of removal obligations [Member]

Deferred income tax credits [Member]

Deferred income tax credits [Member]

Other regulatory liabilities [Member]

Other regulatory liabilities [Member]

Fuel hedging-liability [Member]

Fuel hedging-liability [Member]

Nuclear outage [Member]

Nuclear outage [Member]

Nuclear disaster reserve [Member]

Nuclear disaster reserve [Member]

Retiree benefit plans [Member]

Retiree benefit plans [Member]

Regulatory Deferrals [Member]

Regulatory Deferrals [Member]

Deferred income tax charges [Member]

Deferred income tax charges [Member]

Loss on reacquired debt [Member]

Loss on reacquired debt [Member]

Vacation pay [Member]

Vacation pay [Member]

Under recovered regulatory clause revenues [Member]

Under recovered regulatory clause revenues [Member]

Fuel hedging-asset [Member]

Fuel hedging-asset [Member]

Other regulatory assets [Member]

Other regulatory assets [Member]

Maximum [Member]

Other cost of removal obligations [Member]

Other cost of removal obligations [Member]

Deferred income tax credits [Member]

Deferred income tax credits [Member]

Other regulatory liabilities [Member]

Other regulatory liabilities [Member]

State income tax credits [Member]

State income tax credits [Member]

Deferred income tax charges [Member]

Deferred income tax charges [Member]

Deferred income tax charges - Medicare subsidy [Member]

Deferred income tax charges - Medicare subsidy [Member]

Asset retirement obligations-asset [Member]

Asset retirement obligations-asset [Member]

Loss on reacquired debt [Member]

Loss on reacquired debt [Member]

Vacation pay [Member]

Vacation pay [Member]

Canceled construction projects [Member]

Canceled construction projects [Member]

Fuel hedging-asset [Member]

Fuel hedging-asset [Member]

Other regulatory assets [Member]

Other regulatory assets [Member]

Retiree benefit plans [Member]

Retiree benefit plans [Member]

Remaining Net Book Value Of Retired Units [Member]

Remaining Net Book Value Of Retired Units [Member]

Building Leases [Member]

Building Leases [Member]

Maximum [Member]

Asset retirement obligations-liability [Member]

Asset retirement obligations-liability [Member]

Other cost of removal obligations [Member]

Other cost of removal obligations [Member]

Deferred income tax credits [Member]

Deferred income tax credits [Member]

Property damage reserves [Member]

Property damage reserves [Member]

Other regulatory liabilities [Member]

Other regulatory liabilities [Member]

Over recovered regulatory clause revenues [Member]

Over recovered regulatory clause revenues [Member]

Fuel hedging-liability [Member]

Fuel hedging-liability [Member]

PPA credits [Member]

PPA credits [Member]

Deferred income tax charges [Member]

Deferred income tax charges [Member]

Deferred income tax charges - Medicare subsidy [Member]

Deferred income tax charges - Medicare subsidy [Member]

Loss on reacquired debt [Member]

Loss on reacquired debt [Member]

Vacation pay [Member]

Vacation pay [Member]

Under recovered regulatory clause revenues [Member]

Under recovered regulatory clause revenues [Member]

PPA charges [Member]

PPA charges [Member]

Fuel hedging-asset [Member]

Fuel hedging-asset [Member]

Other regulatory assets [Member]

Other regulatory assets [Member]

Environmental remediation-asset [Member]

Environmental remediation-asset [Member]

Retiree benefit plans [Member]

Retiree benefit plans [Member]

Maximum [Member]

Maximum [Member]

Other cost of removal obligations [Member]

Other cost of removal obligations [Member]

Deferred income tax credits [Member]

Deferred income tax credits [Member]

Property damage reserves [Member]

Property damage reserves [Member]

Other regulatory liabilities [Member]

Other regulatory liabilities [Member]

Fuel hedging-liability [Member]

Fuel hedging-liability [Member]

Retiree Benefit Plans - Regulatory Liabilities [Member]

Retiree Benefit Plans - Regulatory Liabilities [Member]

Deferred income tax charges [Member]

Deferred income tax charges [Member]

Deferred income tax charges - Medicare subsidy [Member]

Deferred income tax charges - Medicare subsidy [Member]

Asset retirement obligations-asset [Member]

Asset retirement obligations-asset [Member]

Loss on reacquired debt [Member]

Loss on reacquired debt [Member]

Vacation pay [Member]

Vacation pay [Member]

Fuel hedging-asset [Member]

Fuel hedging-asset [Member]

Other regulatory assets [Member]

Other regulatory assets [Member]

Kemper IGCC [Member]

Kemper IGCC [Member]

Kemper Regulatory Deferral [Member]

Kemper Regulatory Deferral [Member]

Property tax [Member]

Property tax [Member]

Retiree Benefit Plans - Regulatory Assets [Member]

Retiree Benefit Plans - Regulatory Assets [Member]

Plant Daniel Units 3 and 4 [Member]

Plant Daniel Units 3 and 4 [Member]

Plant Daniel Units 3 and 4 [Member]

Southern Power [Member]

Southern Power [Member]

Generation Site Selection Evaluation Costs [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

'

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'

'

Payments to Acquire Businesses, Gross

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'

'

$100,000,000

$100,000,000

[1]

Total assets (liabilities), net

2,624,000,000

4,322,000,000

-139,000,000

[2],[3]

-71,000,000

[2],[3]

-1,289,000,000

[2]

-1,225,000,000

[2]

-203,000,000

[2]

-212,000,000

[2]

-191,000,000

[4]

-193,000,000

[4]

-126,000,000

[5],[6],[7]

-100,000,000

[5],[6],[7]

-91,000,000

[8]

0

[8]

1,376,000,000

[2]

1,318,000,000

[2]

65,000,000

[9]

72,000,000

[9]

145,000,000

[2],[3]

141,000,000

[2],[3]

293,000,000

[6]

309,000,000

[6]

171,000,000

[10],[3]

165,000,000

[10],[3]

70,000,000

[11]

38,000,000

[11]

70,000,000

[12]

65,000,000

[12]

180,000,000

[13],[3]

138,000,000

[13],[3]

58,000,000

[14],[3]

118,000,000

[14],[3]

337,000,000

[15]

276,000,000

[15]

62,000,000

[3],[4]

74,000,000

[3],[4]

76,000,000

[16],[8]

36,000,000

[16],[8]

1,760,000,000

[17],[3]

3,373,000,000

[17],[3]

'

92,000,000

703,000,000

-132,000,000

[18]

-64,000,000

[18]

-828,000,000

[18]

-759,000,000

[18]

-75,000,000

[18]

-79,000,000

[18]

-11,000,000

[19],[20]

-13,000,000

[19],[20]

-8,000,000

[21]

-5,000,000

[21]

51,000,000

[19]

33,000,000

[19]

-96,000,000

[22]

-103,000,000

[22]

461,000,000

[17],[3]

911,000,000

[17],[3]

20,000,000

[23]

0

[23]

519,000,000

[18],[24]

525,000,000

[18],[24]

86,000,000

[25]

93,000,000

[25]

63,000,000

[10],[3]

61,000,000

[10],[3]

-18,000,000

[19]

34,000,000

[19]

8,000,000

[21]

18,000,000

[21]

52,000,000

[26]

51,000,000

[26]

'

1,886,000,000

2,471,000,000

-58,000,000

[27]

-94,000,000

[27]

-112,000,000

[27]

-115,000,000

[27]

-6,000,000

[28]

-13,000,000

0

[28]

-36,000,000

684,000,000

[27]

695,000,000

[27]

38,000,000

[29]

43,000,000

[29]

137,000,000

[27],[3]

131,000,000

[27],[3]

181,000,000

[30]

190,000,000

[30]

88,000,000

[10],[3]

85,000,000

[10],[3]

70,000,000

[12]

65,000,000

[12]

22,000,000

[31]

49,000,000

[31]

86,000,000

[29]

100,000,000

[29]

691,000,000

[3],[32]

1,331,000,000

[3],[32]

28,000,000

[28]

0

[28]

37,000,000

[33]

40,000,000

[33]

'

160,224,000

171,985,000

-6,089,000

[3],[34]

-5,793,000

[3],[34]

-228,148,000

[34]

-213,413,000

[34]

-5,238,000

[34]

-6,515,000

[34]

-35,380,000

[35]

-31,956,000

[35]

-1,308,000

[35]

-534,000

[35]

0

[36]

-17,092,000

[36]

-6,962,000

[3],[33]

-4,358,000

[3],[33]

-7,496,000

[13],[3]

-7,502,000

[13],[3]

47,573,000

[34]

46,788,000

[34]

3,351,000

[37]

3,678,000

[37]

16,565,000

[38]

16,400,000

[38]

9,521,000

[10],[3]

9,238,000

[10],[3]

45,191,000

[36]

3,523,000

[36]

180,149,000

[13],[3]

137,568,000

[13],[3]

17,043,000

[3],[33]

29,038,000

[3],[33]

12,772,000

[39]

11,034,000

[39]

50,384,000

[3],[40]

60,452,000

[3],[40]

68,296,000

[17],[3]

141,429,000

[17],[3]

'

'

66,604,000

147,469,000

-156,683,000

[41]

-143,461,000

[41]

-10,191,000

[41]

-11,157,000

[41]

-60,092,000

[42]

-58,789,000

[42]

-409,000

[43]

0

[43]

-5,335,000

[3],[44]

-2,519,000

[3],[44]

-3,111,000

[3],[32]

0

[3],[32]

140,185,000

[41]

68,175,000

[41]

4,214,000

[45]

4,868,000

[45]

8,918,000

[41]

9,353,000

[41]

9,178,000

[46]

9,815,000

[46]

10,214,000

[10],[3]

9,635,000

[10],[3]

10,340,000

[3],[44]

20,906,000

[3],[44]

1,201,000

[43]

2,035,000

[43]

75,873,000

[16],[47]

36,047,000

[16],[47]

-90,524,000

[47]

0

[47]

31,206,000

[48]

27,882,000

[48]

82,799,000

[3],[32]

162,293,000

[3],[32]

'

18,821,000

[49]

12,386,000

[49]

'

'

Schedule of Regulatory Assets and Liabilities - Other Information [Abstract]

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'

Life of Related Property Over which Deferred Income Tax Liabilities are Amortized

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'

'

'

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'

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'

'

'

'

'

'

'50 years

'

'

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'

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'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'70 years

'

'

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'

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'

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'

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'

'

'

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'

'

'

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'

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'

'

'

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'

'

'65 years

'

'

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'

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'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

Other Cost of Removal Obligations Related to Subsidiary

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

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'

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'

'

'

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'

'

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'

'

43,000,000

'

'

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'

'

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'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization Period of Other Cost of Removal Obligations

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'

'3 years

'

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'

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'

'

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'

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'

Life of New Issue

'

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'

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'

'

'

'

'

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'

'

'

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'

'

'50 years

'

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'

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'

'

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'

'50 years

'

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'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'39 years

'40 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization of Regulatory Asset, Vacation Pay

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovery and Amortization Periods for Regulatory Assets Liabilities Approved by PSCs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 years

'14 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 years

'

'14 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization Period For Other Regulatory Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization Period of Regulatory Assets and Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'50 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'12 months

'

'

'

'10 years

'

'

'

'

Medicare Drug Subsidy Obligation Related To Subsidiary

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$20,000,000

$21,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovered and Amortized as Approved by Appropriate State PSCs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 years

'9 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'14 years

'8 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization Period For Other Regulatory Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fuel Hedging Assets and Liabilities, Amortization Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'4 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Refueling Cycles Maximum Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'24 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period for Environmental Construction

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'9 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Power Purchase Agreement Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'14 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovered and Amortization Periods as Approved by Appropriate State Public Service Commission

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'14 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recovery and Amortization Periods for Regulatory Assets Liabilities Approved by FERC

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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[1]

This acquisition is expected to occur in spring 2014, and the purchase price is expected to be $100 million.

[2]

Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At DecemberB 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period from January 2014 through December 2016 in accordance with Georgia Power's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP). See Note 3 under "Retail Regulatory Matters" for additional information.

[3]

Not earning a return as offset in rate base by a corresponding asset or liability.

[4]

Recovered as storm restoration and potential reliability-related expenses or environmental remediation expenses are incurred as approved by the appropriate state PSCs.

[5]

Recovered and amortized as approved or accepted by the appropriate state PSC over the life of the contract.

[6]

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.

[7]

Comprised of immaterial components including over recovered regulatory clause revenues, state income tax credits, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years, except for PPA credits that are recovered over the life of the PPA for periods up to 14 years.

[8]

For additional information, See Note 3 under "Integrated Coal Gasification Combined Cycle."

[9]

Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years.

[10]

Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

[11]

Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding 10 years.

[12]

Costs associated with construction of environmental controls that will not be completed as a result of unit retirements and amortized over nine years in accordance with the 2013 ARP.

[13]

Recovered over the life of the PPA for periods up to 14 years.

[14]

Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.

[15]

Comprised of numerous immaterial components including storm damage reserves, nuclear and generating plant outage costs, property taxes, post-retirement benefits, generation site selection/evaluation costs, power purchase agreement (PPA) capacity, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4 regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding, as applicable, 10 years or over the remaining life of the asset but not beyond 2031.

[16]

Integrated coal gasification combined cycle electric generating plant located in Kemper County, Mississippi (Kemper IGCC).

[17]

Recovered and amortized over the average remaining service period which may range up to 15 years. See NoteB 2 for additional information.

[18]

Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.

[19]

Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding ten years.

[20]

Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities.

[21]

Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.

[22]

Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC.

[23]

Recorded and amortized as approved by the Alabama PSC for 2015 through 2017.

[24]

Included in the deferred income tax charges are $20 million for 2013 and $21 million for 2012 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.

[25]

Recovered over the remaining life of the original issue, which may range up to 50 years.

[26]

Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable.

[27]

Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2013, other cost of removal obligations included $43 million that will be amortized over the three-year period of January 2014 through December 2016 in accordance with the Company's Alternate Rate Plan for the years 2014 through 2016 (2013 ARP).

[28]

Amortization period over original remaining life beginning October 2013 through December 2022 as approved by the Georgia PSC in the 2013 ARP.

[29]

Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding nine years.

[30]

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 39 years.

[31]

Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the Company's fuel cost recovery mechanism.

[32]

Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.

[33]

See Note 6 under "Capital Leases." Recovered over the remaining lives of the buildings through 2026.

[34]

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.

[35]

Recorded and recovered or amortized as approved by the Florida PSC.

[36]

Recorded and recovered or amortized as approved by the Florida PSC, generally within one year.

[37]

Recovered and amortized over periods not exceeding 14 years.

[38]

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.

[39]

Comprised primarily of net book value of retired meters, deferred rate case expenses, and generation site evaluation costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years, or deferred pursuant to Florida statute while the Company continues to evaluate certain potential new generating projects.

[40]

Recovered through the environmental cost recovery clause when the remediation is performed.

[41]

Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.

[42]

For additional information, see Note 1 under "Provision for Property Damage" and Note 3 under "Retail Regulatory Matters b System Restoration Rider."

[43]

Recorded and recovered as approved by the Mississippi PSC.

[44]

Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the Energy Cost Management clauseB (ECM).

[45]

Recovered and amortized over a 10-year period beginning in 2012, as approved by the Mississippi PSC for the retail portion and a five-year period for the wholesale portion, as approved by FERC.

[46]

Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years.

[47]

For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle."

[48]

Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information.

[49]

Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term.

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Property, Plant, and Equipment (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Oct. 20, 2011
			Alabama Power [Member]	Alabama Power [Member]	Georgia Power [Member]	Georgia Power [Member]	Gulf Power [Member]	Gulf Power [Member]	Mississippi Power [Member]	Mississippi Power [Member]	Plant Daniel Units 3 and 4 [Member]
											Mississippi Power [Member]
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Generation	$35,360,000,000	$33,444,000,000	$11,314,000,000	$11,110,000,000	$14,872,000,000	$14,567,000,000	$2,607,166,000	$2,598,773,000	$1,475,264,000	$1,363,269,000	'
Transmission	9,289,000,000	8,747,000,000	3,287,000,000	3,137,000,000	4,859,000,000	4,581,000,000	473,378,000	429,341,000	633,903,000	563,037,000	'
Distribution	16,499,000,000	15,958,000,000	5,934,000,000	5,714,000,000	8,620,000,000	8,373,000,000	1,117,024,000	1,069,065,000	828,470,000	802,718,000	'
General	3,958,000,000	4,208,000,000	1,545,000,000	1,434,000,000	1,753,000,000	1,695,000,000	164,065,000	161,379,000	439,721,000	225,723,000	'
Plant acquisition adjustment	123,000,000	124,000,000	12,000,000	12,000,000	28,000,000	28,000,000	2,031,000	2,286,000	81,412,000	81,412,000	81,400,000
Utility plant in service	65,229,000,000	62,481,000,000	'	'	'	'	'	'	'	'	'
Information technology equipment and software	242,000,000	230,000,000	'	'	'	'	'	'	'	'	'
Communications equipment	437,000,000	430,000,000	'	'	'	'	'	'	'	'	'
Other	113,000,000	110,000,000	'	'	'	'	'	'	'	'	'
Other plant in service	792,000,000	770,000,000	'	'	'	'	'	'	'	'	'
Total plant in service	$66,021,000,000	$63,251,000,000	$22,092,000,000	$21,407,000,000	$30,132,000,000	$29,244,000,000	$4,363,664,000	$4,260,844,000	$3,458,770,000	$3,036,159,000	'

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Purchase of the Plant Daniel Combined Cycle Generating Units (Details) (Mississippi Power [Member], Plant Daniel Units 3 and 4 [Member], USD $)	Dec. 31, 2011	Oct. 20, 2011
In Thousands, unless otherwise specified
Mississippi Power [Member] | Plant Daniel Units 3 and 4 [Member]	'	'
Significant Acquisitions and Disposals [Line Items]	'	'
Assumptions of debt obligations	'	$270,000
Fair value adjustment at date of purchase	76,100	76,051
Total debt	346,100	346,051
Cash payment for the purchase	'	84,803
Total value of Plant Daniel Units 3 and 4	'	$430,854

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Capital Leased Assets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Capital Leased Assets [Line Items]	'	'
Capital Leased Assets, Accumulated Amortization	($48)	($39)
Capital Leased Assets, Net of Amortization	164	80
Office Building [Member]	'	'
Capital Leased Assets [Line Items]	'	'
Capital Leased Assets, Gross	61	61
Nitrogen Plant [Member]	'	'
Capital Leased Assets [Line Items]	'	'
Capital Leased Assets, Gross	83	0
Computer-Related Equipment [Member]	'	'
Capital Leased Assets [Line Items]	'	'
Capital Leased Assets, Gross	62	58
Gas Pipeline [Member]	'	'
Capital Leased Assets [Line Items]	'	'
Capital Leased Assets, Gross	$6	$0

Summary_of_Significant_Account7

Summary of Significant Accounting Policies - Business Acquisitions (Details) (Southern Power [Member], USD $)

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Aug. 27, 2013

Dec. 31, 2013

Apr. 23, 2013

Dec. 31, 2013

Dec. 31, 2013

Sep. 28, 2012

Jun. 29, 2012

Dec. 31, 2013

Adobe Solar LLC [Member]

Adobe Solar LLC [Member]

Campo Verde Solar LLC [Member]

Campo Verde Solar LLC [Member]

Spectrum Nevada Solar Llc [Member]

Spectrum Nevada Solar Llc [Member]

Apex Nevada Solar Llc [Member]

Apex Nevada Solar Llc [Member]

MW

MW

MW

MW

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

MW Capacity

'

20

[1],[2]

'

139

[1],[3]

30

[1],[4]

'

'

20

[1]

Year of Operation

'

'2014

[2]

'

'2013

[3]

'2013

[4]

'

'

'2012

PPA Contract Period

'

'20 years

[2]

'

'20 years

[3]

'25 years

[4]

'

'25 years

'25 years

Payments to Acquire Businesses, Gross

$100

$100

[2]

$136.60

$136.60

[3]

$17.60

[4]

'

'

$102

Business Acquisition Cost of Acquired Entity Purchase Consideration Cash Will Be Paid

'

'

$355.50

'

'

$104

'

'

[1]

megawatt (MW)

[2]

This acquisition is expected to occur in spring 2014, and the purchase price is expected to be $100 million.

[3]

Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar Inc. to complete the construction of the solar facility.

[4]

Under an engineering, procurement, and construction agreement, an additional $104 million was paid to a subsidiary of Sun Edison, LLC to complete the construction of the solar facility.

Summary_of_Significant_Account8

Summary of Significant Accounting Policies - Intangible Assets (Details) (Southern Power [Member], USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Southern Power [Member]	'
Acquired Finite-Lived Intangible Assets [Line Items]	'
2013	$2.50
2014	2.5
2015	2.5
2016	2.5
2017	2.5
2018 and beyond	33.5
Total	$46

Summary_of_Significant_Account9

Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Balance at beginning of year	$1,757,000		$1,344,000
Liabilities incurred	6,000		45,000
Liabilities settled	-16,000		-16,000
Accretion	97,000		112,000
Cash flow revisions	174,000		272,000
Balance at end of year	2,018,000		1,757,000
Alabama Power [Member]	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Balance at beginning of year	589,000		553,000
Liabilities incurred	0		0
Liabilities settled	-1,000		-1,000
Accretion	40,000		37,000
Cash flow revisions	102,000	[1]	0	[1]
Balance at end of year	730,000		589,000
Georgia Power [Member]	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Balance at beginning of year	1,105,000		757,000
Liabilities incurred	2,000		24,000
Liabilities settled	-13,000		-15,000
Accretion	55,000		72,000
Cash flow revisions	73,000		267,000
Balance at end of year	1,222,000		1,105,000
Gulf Power [Member]	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Balance at beginning of year	16,055		10,729
Liabilities incurred	518		0
Liabilities settled	-1,913		-107
Accretion	751		507
Cash flow revisions	773		4,926
Balance at end of year	16,184		16,055
Mississippi Power [Member]	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Balance at beginning of year	42,115		19,148
Liabilities incurred	0		20,989
Liabilities settled	-24		-282
Accretion	1,840		1,874
Cash flow revisions	-2,021		386
Balance at end of year	$41,910		$42,115
[1]	(a) Updated based on results from the 2013 nuclear decommissioning study

Recovered_Sheet1

Summary of Significant Accounting Policies - Accumulated Provisions and Estimated Costs For Decommissioning (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Alabama Power [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	$734	$626
Decommissioning	'	'
Total site study costs	1,442	'
Alabama Power [Member] | Plant Farley [Member]	'	'
Decommissioning	'	'
Beginning Year	'2037	'
Completion Year	'2076	'
Alabama Power [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	713	604
Alabama Power [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	21	22
Alabama Power [Member] | Site Study Cost Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	1,362	'
Alabama Power [Member] | Site Study Cost Non-Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	80	'
Plant Farley [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	734	626
Decommissioning	'	'
Beginning Year	'2037	'
Completion Year	'2076	'
Total site study costs	1,442	'
Plant Farley [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	713	604
Plant Farley [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	21	22
Plant Farley [Member] | Site Study Cost Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	1,362	'
Plant Farley [Member] | Site Study Cost Non-Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	80	'
Plant Hatch [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	469	435
Decommissioning	'	'
Beginning Year	'2034	'
Completion Year	'2068	'
Total site study costs	731	'
Plant Hatch [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	469	435
Plant Hatch [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	0	0
Plant Hatch [Member] | Site Study Cost Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	680	'
Plant Hatch [Member] | Site Study Cost Non-Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	51	'
Plant Hatch [Member] | Georgia Power [Member]	'	'
Decommissioning	'	'
Beginning Year	'2034	'
Completion Year	'2068	'
Total site study costs	731	'
External trust funds	469	'
Plant Hatch [Member] | Georgia Power [Member] | Site Study Cost Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	549	'
Plant Hatch [Member] | Georgia Power [Member] | Spent Fuel Management [Member]	'	'
Decommissioning	'	'
Total site study costs	131	'
Plant Hatch [Member] | Georgia Power [Member] | Site Study Cost Non-Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	51	'
Plant Vogtle [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	277	256
Decommissioning	'	'
Beginning Year	'2047	'
Completion Year	'2072	'
Total site study costs	644	'
Plant Vogtle [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	277	256
Plant Vogtle [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member]	'	'
Accumulated Provisions for Decommissioning	'	'
Total	0	0
Plant Vogtle [Member] | Site Study Cost Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	568	'
Plant Vogtle [Member] | Site Study Cost Non-Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	76	'
Plant Vogtle [Member] | Georgia Power [Member]	'	'
Decommissioning	'	'
Beginning Year	'2047	'
Completion Year	'2072	'
Total site study costs	644	'
External trust funds	277	'
Plant Vogtle [Member] | Georgia Power [Member] | Site Study Cost Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	453	'
Plant Vogtle [Member] | Georgia Power [Member] | Spent Fuel Management [Member]	'	'
Decommissioning	'	'
Total site study costs	115	'
Plant Vogtle [Member] | Georgia Power [Member] | Site Study Cost Non-Radiated Structures [Member]	'	'
Decommissioning	'	'
Total site study costs	$76	'

Recovered_Sheet2

Summary of Significant Accounting Policies - Leveraged Leases (Details) (Domestic And International Leveraged Lease [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Domestic And International Leveraged Lease [Member]	'	'	'
Net Investments from Leveraged Lease	'	'	'
Net rentals receivable	$1,440	$1,214	'
Unearned income	-775	-544	'
Investment in leveraged leases	665	670	'
Deferred taxes from leveraged leases	-287	-278	'
Net investment in leveraged leases	378	392	'
Components of Income from Leveraged Lease	'	'	'
Pretax leveraged lease income	-5	21	25
Income tax expense	2	-8	-9
Net leveraged lease income	($3)	$13	$16

Recovered_Sheet3

Summary of Significant Accounting Policies - Comprehensive Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in Accumulated OCI (loss) balances [Roll Forward]	'	'	'
Beginning Balance	($123,000)	'	'
Current period change	48,000	-12,000	-41,000
Ending Balance	-75,000	-123,000	'
Qualifying Hedges [Member]	'	'	'
Change in Accumulated OCI (loss) balances [Roll Forward]	'	'	'
Beginning Balance	-45,000	'	'
Current period change	9,000	'	'
Ending Balance	-36,000	'	'
Marketable Securities [Member]	'	'	'
Change in Accumulated OCI (loss) balances [Roll Forward]	'	'	'
Beginning Balance	3,000	'	'
Current period change	-3,000	'	'
Ending Balance	0	'	'
Pension and Other Postretirement Benefit Plans [Member]	'	'	'
Change in Accumulated OCI (loss) balances [Roll Forward]	'	'	'
Beginning Balance	-81,000	'	'
Current period change	42,000	'	'
Ending Balance	($39,000)	'	'

Recovered_Sheet4

Summary of Significant Accounting Policies - Textual (Details) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2013

Mar. 31, 2013

Mar. 31, 2012

Sep. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 04, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Oct. 20, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Maximum [Member]

Plant Hatch [Member]

Plant Vogtle [Member]

Equity Securities [Member]

Equity Securities [Member]

Debt Securities [Member]

Debt Securities [Member]

Other Securities [Member]

Other Securities [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Utility Plant in Service [Member]

Utility Plant in Service [Member]

Utility Plant in Service [Member]

Other Plant in Service [Member]

Other Plant in Service [Member]

Other Plant in Service [Member]

Other Plant in Service [Member]

Recoverable Vacation Pay [Member]

Recoverable Vacation Pay [Member]

Retiree benefit plans [Member]

Retiree benefit plans [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Alabama Power and Georgia Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Traditional Operating Companies [Member]

Traditional Operating Companies [Member]

Capital Lease Obligations [Member]

Capital Lease Obligations [Member]

Capital Lease Obligations [Member]

Capital Lease Obligations [Member]

Capital Lease Obligations [Member]

Capital Lease Obligations [Member]

Realized Gain [Member]

Realized Gain [Member]

Realized Gain [Member]

Unrealized Gain [Member]

Unrealized Losses [Member]

Unrealized Losses [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Southern Renewable Energy, Inc. [Member]

Turner Renewable Energy [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Operations and Maintenance Expense [Member]

Operations and Maintenance Expense [Member]

Operations and Maintenance Expense [Member]

Deferred capacity revenues affiliated [Member]

Deferred capacity revenues affiliated [Member]

Electric Transmission [Member]

Electric Transmission [Member]

Electric Transmission [Member]

Florida Power and Light [Member]

Florida Power and Light [Member]

Florida Power and Light [Member]

Progress Energy Carolina [Member]

Progress Energy Florida [Member]

Progress Energy Florida [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Operating Lease PPA [Member]

Operating Lease PPA [Member]

Operating Lease PPA [Member]

Minimum [Member]

Maximum [Member]

Plant Scherer Unit 3 [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Southern Power [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Prepaid expenses and other regulatory liabilities [Member]

Current Liabilities [Member]

Current Liabilities [Member]

Deferred Credits and Other Liabilities [Member]

Deferred Credits and Other Liabilities [Member]

Recoverable Vacation Pay [Member]

Recoverable Vacation Pay [Member]

Retiree benefit plans [Member]

Retiree benefit plans [Member]

Fuel Expense [Member]

Fuel Expense [Member]

Fuel Expense [Member]

Purchased Power [Member]

Purchased Power [Member]

Purchased Power [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Plant Scherer [Member]

Plant Scherer [Member]

Plant Scherer [Member]

SEGCO [Member]

Equity Securities [Member]

Equity Securities [Member]

Debt Securities [Member]

Debt Securities [Member]

Other Securities [Member]

Other Securities [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Securities Held in Funds [Member]

Utility Plant in Service [Member]

Utility Plant in Service [Member]

Utility Plant in Service [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Nuclear Operating Company, Inc. [Member]

Southern Nuclear Operating Company, Inc. [Member]

Southern Nuclear Operating Company, Inc. [Member]

Gulf Power [Member]

Recoverable Vacation Pay [Member]

Recoverable Vacation Pay [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Plant Farley [Member]

Fuel Purchases [Member]

Fuel Purchases [Member]

Fuel Purchases [Member]

Non-Fuel Expense [Member]

Non-Fuel Expense [Member]

Non-Fuel Expense [Member]

Unrealized Losses [Member]

Unrealized Losses [Member]

Unrealized Losses [Member]

Plant Scherer Unit 3 [Member]

Plant McIntosh [Member]

Plant Hatch [Member]

Plant Hatch [Member]

Plant Vogtle [Member]

Securities Investment [Member]

Securities Investment [Member]

Securities Investment [Member]

Equity Securities [Member]

Equity Securities [Member]

Debt Securities [Member]

Debt Securities [Member]

Other Securities [Member]

Other Securities [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Nuclear Operating Company, Inc. [Member]

Southern Nuclear Operating Company, Inc. [Member]

Southern Nuclear Operating Company, Inc. [Member]

Gulf Power [Member]

Other regulatory assets current [Member]

Other regulatory assets deferred [Member]

Recoverable Vacation Pay [Member]

Recoverable Vacation Pay [Member]

Retiree benefit plans [Member]

Retiree benefit plans [Member]

Storm damage [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Storm reserve [Member]

Environmental remediation reserve [Member]

Environmental remediation reserve [Member]

Non-Fuel Expense [Member]

Non-Fuel Expense [Member]

Non-Fuel Expense [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Property tax [Member]

Property tax [Member]

Recoverable Vacation Pay [Member]

Recoverable Vacation Pay [Member]

Other Postretirement Benefits [Member]

Other Postretirement Benefits [Member]

Plant Daniel Units 3 and 4 [Member]

Plant Daniel Units 3 and 4 [Member]

Plant Daniel Units 3 and 4 [Member]

Plant Daniel Units 3 and 4 [Member]

Kemper IGCC [Member]

Kemper IGCC [Member]

Fuel Purchases [Member]

Fuel Purchases [Member]

Fuel Purchases [Member]

Non-Fuel Expense [Member]

Non-Fuel Expense [Member]

Non-Fuel Expense [Member]

Storm Assistance [Member]

Georgia Power [Member]

Georgia Power [Member]

Mississippi Power [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Southern Company Services, Inc. [Member]

Sales Revenue, Goods, Net [Member]

Sales Revenue, Goods, Net [Member]

Sales Revenue, Goods, Net [Member]

Sales Revenue, Goods, Net [Member]

Sales Revenue, Goods, Net [Member]

Sales Revenue, Goods, Net [Member]

Sales Revenue, Goods, Net [Member]

Sales Revenue, Goods, Net [Member]

Sales Revenue, Goods, Net [Member]

kWh

MW

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Sales Agreement From Year Two Thousand Fifteen Till Two Thousand Twenty [Member]

Georgia Power [Member]

Realized Gain [Member]

Realized Gain [Member]

Realized Gain [Member]

Unrealized Gain [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Plant Scherer Unit 3 [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Traditional Operating Companies [Member]

Customer Concentration Risk [Member]

Customer Concentration Risk [Member]

Customer Concentration Risk [Member]

Customer Concentration Risk [Member]

Customer Concentration Risk [Member]

Customer Concentration Risk [Member]

Customer Concentration Risk [Member]

Customer Concentration Risk [Member]

Customer Concentration Risk [Member]

Plant Scherer Unit 3 [Member]

Plant Scherer Unit 3 [Member]

Plant Scherer Unit 3 [Member]

Jointly Owned Utility Plant Interests [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

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'

'

Jointly Owned Utility Plant, Proportionate Ownership Share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

90.00%

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14.00%

'

'

86.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

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'

'

'

'

'

'

'

'

'

'

Affiliate Transactions [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

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'

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'

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'

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'

'

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'

'

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'

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'

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'

'

'

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'

'

'

'

'

'

'

'

'

'

Affiliate transaction amount

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$148,400,000

$159,900,000

$175,900,000

'

'

'

'

$117,600,000

$125,400,000

$112,700,000

$114,300,000

$107,700,000

$87,900,000

$17,600,000

$19,000,000

$8,300,000

$6,600,000

$7,100,000

'

'

'

'

'

'

'

'

'

$69,000,000

$76,200,000

$75,600,000

'

'

'

'

'

'

$10,200,000

$6,900,000

$6,700,000

'

'

'

'

$78,400,000

$95,900,000

$97,400,000

$16,500,000

$21,100,000

$23,400,000

'

'

'

'

'

'

'

'

'

$800,000

$2,600,000

$1,800,000

$14,200,000

$14,700,000

$14,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$340,000,000

$340,000,000

$347,000,000

$211,000,000

$218,000,000

$215,000,000

'

'

'

'

'

'

$27,000,000

$28,000,000

$21,000,000

$13,000,000

$12,000,000

$12,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$136,000,000

$147,000,000

$171,000,000

$504,000,000

$540,000,000

$550,000,000

$555,000,000

$574,000,000

$537,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$205,000,000

$212,700,000

$185,500,000

$16,500,000

$21,200,000

$23,300,000

'

'

'

'

'

'

'

'

'

'

'

'

$27,100,000

$28,100,000

$20,900,000

$12,500,000

$11,700,000

$12,200,000

$2,000,000

'

'

'

'

'

'

'

'

Long-term Purchase Commitment, Period Over Which Costs Are Expected to Be Recovered

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2023

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Purchase Commitment, Minimum Power Required

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

292

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gulf Power agreement, commitment amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-Term Purchase Commitment Amount In Year Two

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Prepaid capacity expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gulf Power agreement, percentage reimbursement of non-fuel expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred capacity expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

180,149,000

137,568,000

'

'

'

'

'

'

'

'

'

'

4,200,000

'

'

'

'

'

'

4,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

162,000,000

169,000,000

216,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gulf Power agreement, reimbursement of non-fuel expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,400,000

2,400,000

2,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,000,000

7,000,000

7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue Requirement Obligations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

135,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue Requirements Reimbursement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,900,000

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Strom restoration cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Government Grants [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Grants expected to be received from Department of Energy

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000,000

270,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Grants received from Department of Energy

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

245,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenues [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage Of Wholesale Customers To Operating Revenue

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22.20%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period Of Contract Cancellation Notices Of Wholesale Customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent Of Long-Term Sales Agreements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

57.00%

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period For Long-Term Sales Agreement Two

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period For Long-Term Sales Agreement One

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum revenue from a single customer or industry

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11.80%

12.80%

14.70%

8.30%

10.30%

5.90%

10.70%

12.50%

14.00%

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum percentage of uncollectible accounts

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Property, Plant and Equipment [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Refueling cycles for Alabama Power and Georgia Power, minimum months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'18 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'18 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'18 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Refueling cycles for Alabama Power and Georgia Power, maximum months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'24 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'24 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization period of defer inspection costs for the combustion turbines

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization Period of Defer Costs of Certain Significant Inspection Costs for Combustion Turbines

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Non-cash property additions recognized

411,000,000

524,000,000

929,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

107,000,000

14,000,000

21,000,000

'

'

'

Nuclear outage expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

32,000,000

28,000,000

31,000,000

38,000,000

31,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized Nuclear Outage Expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue bond obligations fair value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

346,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash payment to be made in conjunction with purchase of facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

84,800,000

'

'

85,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Face value of debt obligations assumed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

270,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fixed stated interest rate of debt obligation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.93%

9.97%

7.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

7.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.90%

7.90%

4.90%

Income Tax Matters [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization of deferred investment tax credits

16,000,000

23,000,000

19,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,400,000

1,400,000

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,000,000

8,000,000

8,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,000,000

13,000,000

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000

1,200,000

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Credits amortized to income tax expense

5,500,000

2,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,500,000

2,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reduction in tax basis of assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Depreciation and Amortization

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Depreciation of cost of utility plant in service, composite straight-line rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.30%

3.20%

3.20%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.60%

3.60%

3.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.20%

3.20%

3.30%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.00%

2.90%

2.80%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.40%

3.50%

3.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

23,059,000,000

21,964,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22,500,000,000

21,500,000,000

'

513,000,000

479,000,000

'

'

'

'

'

'

'

'

871,963,000

786,620,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,211,336,000

1,168,055,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,114,000,000

7,761,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,970,000,000

10,431,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,095,352,000

1,065,474,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory liabilities amortized

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,000,000

'

31,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization period of other cost of removal obligations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional Regulatory Liability Amortization

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

43,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Plant in service, estimated useful lives

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'25 years

'

'

'

'

'

'

'

'

'

'18 years

'34 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Plant acquisition adjustment

123,000,000

124,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,031,000

2,286,000

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,000,000

12,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

28,000,000

28,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

81,412,000

81,412,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

81,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value adjustment at date of purchase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

76,051,000

'

'

76,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value adjustment at date of purchase, amortization term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization period of regulatory assets and liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'50 years

'

'

'

'

'

'

'

'

'

'12 months

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment of Long-Lived Assets and Intangibles

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Average term of PPAs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred Project Development Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred project development costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,200,000

11,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decommissioning

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated cost of decommissioning completion year

'

'

'

'

'2068

'2072

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2076

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2068

'

'2072

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum net worth requirement by a one or more persons to hold external trust funds

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair market value of fund's securities on loan under the Funds' managers' securities lending program

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

32,000,000

91,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of collateral received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

33,000,000

93,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decommissioning Fund Investments Net Of Foreign Currency

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

713,000,000

604,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

751,000,000

698,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investment securities in the Funds

1,465,000,000

1,303,000,000

'

'

'

'

896,000,000

718,000,000

528,000,000

564,000,000

40,000,000

20,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

714,000,000

605,000,000

'

'

566,000,000

438,000,000

131,000,000

156,000,000

16,000,000

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

751,000,000

698,000,000

'

'

'

'

'

'

'

'

'

705,000,000

850,000,000

1,800,000,000

330,000,000

280,000,000

397,000,000

408,000,000

24,000,000

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sale of securities held in external trust funds

1,000,000,000

1,000,000,000

2,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

279,000,000

193,000,000

349,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in fair value of securities related to nuclear decommissioning

181,000,000

137,000,000

29,000,000

'

'

'

'

'

'

'

'

'

5,000,000

4,000,000

41,000,000

119,000,000

75,000,000

60,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

120,000,000

70,000,000

6,000,000

'

'

'

'

'

'

'

50,000,000

51,000,000

5,000,000

4,000,000

41,000,000

85,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

61,000,000

67,000,000

23,000,000

34,000,000

25,000,000

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount expensed for rate making purpose

'

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,000,000

2,000,000

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Significant assumption of inflation rate used to determine the costs for rate making

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Significant assumption of trust earnings rate used to determine the costs for rate making

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowance for Funds Used During Construction and Interest Capitalized

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Composite rate used to determine allowance for funds used during construction

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.26%

6.72%

7.65%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.10%

9.40%

9.20%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.30%

6.80%

7.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.89%

7.04%

7.06%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

AFUDC capitalized

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

44,000,000

75,000,000

134,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

AFUDC, net of income taxes

15.00%

8.20%

9.10%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.87%

5.36%

11.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.40%

3.30%

3.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.30%

5.70%

10.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash payments for interest totaled

759,000,000

803,000,000

832,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60,396,000

50,248,000

74,989,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

53,401,000

58,255,000

55,486,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

243,000,000

273,000,000

286,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

344,000,000

337,000,000

346,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,285,000

32,589,000

14,814,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net of amounts capitalized

92,000,000

83,000,000

78,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,178,000

19,092,000

18,001,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,421,000

2,500,000

3,951,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,000,000

7,000,000

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14,000,000

21,000,000

37,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

54,118,000

32,816,000

10,065,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reserves and Recoveries

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrued reserves

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35,400,000

32,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

28,000,000

28,000,000

'

'

'

'

'

'

Recovery Period For Natural Disaster Reserve Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'24 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Customer Surcharge Storm Recovery Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Customer Surcharge Storm Recovery Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum total rate NDR charge per month, non-residential customer account

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum total rate NDR charge per month, residential customer account

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Old Natural Disaster Reserve Authorized Limit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Costs recovered annually under rate plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,000,000

2,000,000

3,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Environmental Regulatory Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,000,000

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

PSC Approved Annual Property Damage Reserve Accrual

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

PSC approved target level for property damage reserve

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

48,000,000

55,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Threshold above which additional property damage reserves are authorized by PSC

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in accrued property damage costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,500,000

3,500,000

3,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cumulative damage costs limit under PSC order

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

PSC approved annual uninsured injuries and damages accrual

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,600,000

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Threshold above which additional uninsured injuries and damages accruals are authorized by PSC

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reserve for losses and loss adjustment expenses

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,600,000

3,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,600,000

1,600,000

2,000,000

1,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Regulatory Assets

2,624,000,000

4,322,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

171,000,000

[1],[2]

165,000,000

[1],[2]

1,760,000,000

[1],[3]

3,373,000,000

[1],[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

160,224,000

171,985,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,521,000

[1],[2]

9,238,000

[1],[2]

68,296,000

[1],[3]

141,429,000

[1],[3]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

92,000,000

703,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

63,000,000

[1],[2]

61,000,000

[1],[2]

'

'

'

'

'

'

'

'

'

1,886,000,000

2,471,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

88,000,000

[1],[2]

85,000,000

[1],[2]

691,000,000

[1],[4]

1,331,000,000

[1],[4]

'

'

'

'

'

'

'

'

'

'

66,604,000

147,469,000

'

'

'

'

'

'

'

'

31,206,000

[5]

27,882,000

[5]

10,214,000

[1],[2]

9,635,000

[1],[2]

2,116,000

15,454,000

'

18,821,000

[6]

12,386,000

[6]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Threshold above which actual damages are charged to the reserve

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Retail accrual per annual SRR rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,200,000

3,500,000

3,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Wholesale accrual per annual SRR rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000

300,000

300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory asset

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Regulatory Assets Current

124,000,000

163,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,536,000

30,576,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

24,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

66,000,000

72,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30,000,000

'

'

'

'

'

'

'

'

'

52,496,000

55,302,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Regulatory Assets Deferred

2,557,000,000

4,032,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

109,000,000

360,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

340,415,000

372,294,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

2,169,000

'

'

'

'

'

'

'

692,000,000

1,083,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,000,000

89,000,000

'

'

'

'

'

'

'

1,152,000,000

1,798,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

69,000,000

187,000,000

'

'

'

'

'

'

'

200,620,000

236,225,000

'

'

'

'

'

'

'

'

'

'

'

'

5,227,000

15,454,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrual Under Alternate Rate Plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leveraged Leases [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leveraged lease agreement term

'

'

'

'45 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash and Cash Equivalents [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Original Maturities of Temporary Cash Investments

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Variable Interest Entities [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Variable Interest Entity, Consolidated, Carrying Amount, Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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21,000,000

21,000,000

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Variable Interest Entity, Consolidated, Carrying Amount, Liabilities

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$22,700,000

$21,800,000

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[1]

Not earning a return as offset in rate base by a corresponding asset or liability.

[2]

Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay.

[3]

Recovered and amortized over the average remaining service period which may range up to 15 years. See NoteB 2 for additional information.

[4]

Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information.

[5]

Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information.

[6]

Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term.

Retirement_Benefits_Actuarial_

Retirement Benefits - Actuarial Assumptions 1 (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Discount rate:	'	'	'	'
Annual salary increase	3.59%	3.59%	3.84%	3.84%
Pension Plans [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	5.02%	4.26%	4.98%	5.52%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	8.20%	8.20%	8.45%	'
Other Postretirement Benefits [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	4.85%	4.05%	4.88%	5.40%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	7.13%	7.29%	7.39%	'
Alabama Power [Member]	'	'	'	'
Discount rate:	'	'	'	'
Annual salary increase	3.59%	3.59%	3.84%	3.84%
Alabama Power [Member] | Pension Plans [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	5.02%	4.27%	4.98%	5.52%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	8.20%	8.20%	8.45%	'
Alabama Power [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	4.86%	4.06%	4.88%	5.41%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	7.36%	7.19%	7.39%	'
Georgia Power [Member]	'	'	'	'
Discount rate:	'	'	'	'
Annual salary increase	3.59%	3.59%	3.84%	3.84%
Georgia Power [Member] | Pension Plans [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	5.02%	4.27%	4.98%	5.52%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	8.20%	8.20%	8.45%	'
Georgia Power [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	4.85%	4.04%	4.87%	5.40%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	6.74%	7.24%	7.25%	'
Gulf Power [Member]	'	'	'	'
Discount rate:	'	'	'	'
Annual salary increase	3.59%	3.59%	3.84%	3.84%
Gulf Power [Member] | Pension Plans [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	5.02%	4.27%	4.98%	5.53%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	8.20%	8.20%	8.45%	'
Gulf Power [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	4.86%	4.06%	4.88%	5.41%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	8.04%	8.02%	8.11%	'
Mississippi Power [Member]	'	'	'	'
Discount rate:	'	'	'	'
Annual salary increase	3.59%	3.59%	3.84%	3.84%
Mississippi Power [Member] | Pension Plans [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	5.01%	4.26%	4.98%	5.51%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	8.20%	8.20%	8.45%	'
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Discount rate:	'	'	'	'
Discount rate on net periodic benefit costs	4.85%	4.04%	4.87%	5.39%
Long-term return on plan assets:	'	'	'	'
Long-term return on plan assets on net periodic benefit costs	7.04%	6.96%	7.53%	'

Retirement_Benefits_Actuarial_1

Retirement Benefits - Actuarial Assumptions 2 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components	'
1 Percent increase on benefit obligation	$103,000
1 Percent decrease on benefit obligation	-88,000
1 Percent increase on service and interest costs	5,000
1 Percent decrease on service and interest costs	-4,000
Alabama Power [Member]	'
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components	'
1 Percent increase on benefit obligation	26,000
1 Percent decrease on benefit obligation	-22,000
1 Percent increase on service and interest costs	1,000
1 Percent decrease on service and interest costs	-1,000
Georgia Power [Member]	'
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components	'
1 Percent increase on benefit obligation	51,000
1 Percent decrease on benefit obligation	-43,000
1 Percent increase on service and interest costs	2,000
1 Percent decrease on service and interest costs	-2,000
Gulf Power [Member]	'
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components	'
1 Percent increase on benefit obligation	2,884
1 Percent decrease on benefit obligation	-2,479
1 Percent increase on service and interest costs	138
1 Percent decrease on service and interest costs	-119
Mississippi Power [Member]	'
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components	'
1 Percent increase on benefit obligation	4,665
1 Percent decrease on benefit obligation	-4,004
1 Percent increase on service and interest costs	224
1 Percent decrease on service and interest costs	($192)

Retirement_Benefits_Changes_in

Retirement Benefits - Changes in Projected Benefit Obligations and Fair Value of Plan Assets (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	$9,302,000	$8,079,000	'
Service cost	232,000	198,000	184,000
Interest cost	389,000	393,000	389,000
Benefits paid	-357,000	-336,000	'
Actuarial loss (gain)	-703,000	968,000	'
Balance at end of year	8,863,000	9,302,000	8,079,000
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	7,953,000	6,800,000	'
Actual return (loss) on plan assets	1,098,000	1,010,000	'
Employer contributions	39,000	479,000	'
Fair value of plan assets at end of year	8,733,000	7,953,000	6,800,000
Accrued liability	-130,000	-1,349,000	'
Other Postretirement Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	1,872,000	1,787,000	'
Service cost	24,000	21,000	21,000
Interest cost	74,000	85,000	92,000
Benefits paid	-94,000	-99,000	'
Actuarial loss (gain)	200,000	-71,000	'
Retiree drug subsidy	6,000	7,000	'
Balance at end of year	1,682,000	1,872,000	1,787,000
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	821,000	765,000	'
Actual return (loss) on plan assets	129,000	93,000	'
Employer contributions	39,000	55,000	'
Benefits paid, net of drug subsidy	-88,000	-92,000	'
Fair value of plan assets at end of year	901,000	821,000	765,000
Accrued liability	-781,000	-1,051,000	'
Alabama Power [Member] | Pension Plans [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	2,218,000	1,932,000	'
Service cost	52,000	44,000	43,000
Interest cost	93,000	94,000	96,000
Benefits paid	-93,000	-90,000	'
Actuarial loss (gain)	-158,000	238,000	'
Balance at end of year	2,112,000	2,218,000	1,932,000
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	2,077,000	1,885,000	'
Actual return (loss) on plan assets	285,000	274,000	'
Employer contributions	9,000	8,000	'
Fair value of plan assets at end of year	2,278,000	2,077,000	1,885,000
Accrued liability	166,000	-141,000	'
Alabama Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	490,000	470,000	'
Service cost	6,000	5,000	5,000
Interest cost	19,000	22,000	24,000
Benefits paid	-24,000	-24,000	'
Actuarial loss (gain)	-62,000	15,000	'
Retiree drug subsidy	2,000	2,000	'
Balance at end of year	431,000	490,000	470,000
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	343,000	315,000	'
Actual return (loss) on plan assets	61,000	39,000	'
Employer contributions	7,000	11,000	'
Benefits paid, net of drug subsidy	-22,000	-22,000	'
Fair value of plan assets at end of year	389,000	343,000	315,000
Accrued liability	-42,000	-147,000	'
Georgia Power [Member] | Pension Plans [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	3,312,000	2,909,000	'
Service cost	69,000	60,000	57,000
Interest cost	138,000	141,000	144,000
Benefits paid	-141,000	-136,000	'
Actuarial loss (gain)	-262,000	338,000	'
Balance at end of year	3,116,000	3,312,000	2,909,000
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	2,827,000	2,575,000	'
Actual return (loss) on plan assets	387,000	377,000	'
Employer contributions	12,000	11,000	'
Fair value of plan assets at end of year	3,085,000	2,827,000	2,575,000
Accrued liability	-31,000	-485,000	'
Georgia Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	800,000	774,000	'
Service cost	7,000	7,000	7,000
Interest cost	31,000	37,000	41,000
Benefits paid	-45,000	-46,000	'
Actuarial loss (gain)	73,000	-25,000	'
Retiree drug subsidy	3,000	3,000	'
Balance at end of year	723,000	800,000	774,000
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	382,000	365,000	'
Actual return (loss) on plan assets	56,000	43,000	'
Employer contributions	11,000	17,000	'
Benefits paid, net of drug subsidy	-42,000	-43,000	'
Fair value of plan assets at end of year	407,000	382,000	365,000
Accrued liability	-316,000	-418,000	'
Gulf Power [Member]	'	'	'
Change in benefit obligation	'	'	'
Service cost	11,128	9,101	8,431
Interest cost	17,321	17,199	17,074
Gulf Power [Member] | Pension Plans [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	413,501	352,834	'
Service cost	11,128	9,101	'
Interest cost	17,321	17,199	'
Benefits paid	-14,831	-14,046	'
Plan amendments	0	426	'
Actuarial loss (gain)	-31,791	47,987	'
Balance at end of year	395,328	413,501	'
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	350,260	304,324	'
Actual return (loss) on plan assets	49,076	45,762	'
Employer contributions	1,134	14,220	'
Fair value of plan assets at end of year	385,639	350,260	'
Accrued liability	-9,689	-63,241	'
Gulf Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	75,395	70,923	'
Service cost	1,355	1,167	1,132
Interest cost	2,982	3,367	3,658
Benefits paid	-3,583	-3,854	'
Actuarial loss (gain)	7,900	-3,468	'
Retiree drug subsidy	330	324	'
Balance at end of year	68,579	75,395	70,923
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	16,227	14,978	'
Actual return (loss) on plan assets	2,119	2,131	'
Employer contributions	2,381	2,648	'
Benefits paid, net of drug subsidy	-3,253	-3,530	'
Fair value of plan assets at end of year	17,474	16,227	14,978
Accrued liability	-51,105	-59,168	'
Mississippi Power [Member]	'	'	'
Change in benefit obligation	'	'	'
Service cost	11,067	9,416	8,838
Interest cost	18,062	18,019	17,827
Change in plan assets	'	'	'
Employer contributions	4,100	3,900	3,800
Mississippi Power [Member] | Pension Plans [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	432,553	369,680	'
Service cost	11,067	9,416	'
Interest cost	18,062	18,019	'
Benefits paid	-16,207	-14,949	'
Actuarial loss (gain)	-36,080	50,387	'
Balance at end of year	409,395	432,553	'
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	351,749	282,100	'
Actual return (loss) on plan assets	49,431	39,668	'
Employer contributions	2,430	44,930	'
Fair value of plan assets at end of year	387,403	351,749	'
Accrued liability	-21,992	-80,804	'
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Change in benefit obligation	'	'	'
Benefit obligation at beginning of year	91,783	87,447	'
Service cost	1,151	1,038	1,012
Interest cost	3,619	4,155	4,292
Benefits paid	-4,080	-4,432	'
Actuarial loss (gain)	11,959	-3,166	'
Retiree drug subsidy	426	409	'
Balance at end of year	80,940	91,783	87,447
Change in plan assets	'	'	'
Fair value of plan assets at beginning of year	21,990	20,534	'
Actual return (loss) on plan assets	2,379	2,427	'
Employer contributions	2,562	3,052	'
Benefits paid, net of drug subsidy	-3,654	-4,023	'
Fair value of plan assets at end of year	23,277	21,990	20,534
Accrued liability	($57,663)	($69,793)	'

Retirement_Benefits_Amounts_Re

Retirement Benefits - Amounts Recognized in Balance Sheets and Amounts in AOCI (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Prepaid pension costs	$419,000,000	$0
Other regulatory assets, deferred	2,557,000,000	4,032,000,000
Other current liabilities	-347,000,000	-557,000,000
Other regulatory liabilities, deferred	-475,000,000	-289,000,000
Employee benefit obligations	-1,461,000,000	-2,540,000,000
Accumulated OCI	-75,000,000	-123,000,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Net Regulatory Assets	2,624,000,000	4,322,000,000
Pension Plans [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Prepaid pension costs	419,000,000	0
Other regulatory assets, deferred	1,651,000,000	3,013,000,000
Other current liabilities	-40,000,000	-37,000,000
Employee benefit obligations	-509,000,000	-1,312,000,000
Accumulated OCI	64,000,000	125,000,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	80,000,000	107,000,000
Net (Gain) Loss	1,634,000,000	3,031,000,000
Prior Service Cost, Estimated	26,000,000	'
Net (Gain) Loss, Estimated	110,000,000	'
Pension Plans [Member] | Accumulated Other Comprehensive Income (Loss)	'	'
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	5,000,000	7,000,000
Net (Gain) Loss	59,000,000	118,000,000
Prior Service Cost, Estimated	1,000,000	'
Net (Gain) Loss, Estimated	4,000,000	'
Pension Plans [Member] | Regulatory Assets [Member]	'	'
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	75,000,000	100,000,000
Net (Gain) Loss	1,575,000,000	2,913,000,000
Prior Service Cost, Estimated	25,000,000	'
Net (Gain) Loss, Estimated	106,000,000	'
Other Postretirement Benefits [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Other regulatory assets, deferred	109,000,000	360,000,000
Other current liabilities	-4,000,000	-3,000,000
Other regulatory liabilities, deferred	-36,000,000	0
Employee benefit obligations	-777,000,000	-1,048,000,000
Accumulated OCI	1,000,000	7,000,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	9,000,000	13,000,000
Net (Gain) Loss	65,000,000	349,000,000
Transition Obligation	0	5,000,000
Prior Service Cost, Estimated	4,000,000	'
Net (Gain) Loss, Estimated	2,000,000	'
Transition Obligation, Estimated	0	'
Other Postretirement Benefits [Member] | Accumulated Other Comprehensive Income (Loss)	'	'
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	1,000,000	7,000,000
Transition Obligation	0	0
Prior Service Cost, Estimated	0	'
Net (Gain) Loss, Estimated	0	'
Transition Obligation, Estimated	0	'
Other Postretirement Benefits [Member] | Regulatory Assets [Member]	'	'
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	9,000,000	13,000,000
Net (Gain) Loss	64,000,000	342,000,000
Transition Obligation	0	5,000,000
Prior Service Cost, Estimated	4,000,000	'
Net (Gain) Loss, Estimated	2,000,000	'
Transition Obligation, Estimated	0	'
Alabama Power [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Prepaid pension costs	276,000,000	0
Other regulatory assets, deferred	692,000,000	1,083,000,000
Other current liabilities	-41,000,000	-52,000,000
Other regulatory liabilities, deferred	-259,000,000	-183,000,000
Employee benefit obligations	-195,000,000	-321,000,000
Accumulated OCI	-26,000,000	-27,000,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Net Regulatory Assets	92,000,000	703,000,000
Alabama Power [Member] | Pension Plans [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Prepaid pension costs	276,000,000	0
Other regulatory assets, deferred	476,000,000	822,000,000
Other current liabilities	-9,000,000	-8,000,000
Employee benefit obligations	-101,000,000	-133,000,000
Alabama Power [Member] | Pension Plans [Member] | Regulatory Assets [Member]	'	'
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	19,000,000	26,000,000
Net (Gain) Loss	457,000,000	796,000,000
Prior Service Cost, Estimated	7,000,000	'
Net (Gain) Loss, Estimated	-31,000,000	'
Alabama Power [Member] | Other Postretirement Benefits [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Other regulatory assets, deferred	6,000,000	89,000,000
Other regulatory liabilities, deferred	-21,000,000	0
Employee benefit obligations	-42,000,000	-147,000,000
Alabama Power [Member] | Other Postretirement Benefits [Member] | Regulatory Assets [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Other regulatory assets, deferred	-15,000,000	89,000,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	19,000,000	22,000,000
Net (Gain) Loss	-34,000,000	67,000,000
Prior Service Cost, Estimated	4,000,000	'
Net (Gain) Loss, Estimated	0	'
Georgia Power [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Prepaid pension costs	118,000,000	0
Other regulatory assets, deferred	1,152,000,000	1,798,000,000
Other current liabilities	-122,000,000	-146,000,000
Employee benefit obligations	-542,000,000	-950,000,000
Accumulated OCI	-5,000,000	-7,000,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Net Regulatory Assets	1,886,000,000	2,471,000,000
Georgia Power [Member] | Pension Plans [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Prepaid pension costs	118,000,000	0
Other regulatory assets, deferred	610,000,000	1,132,000,000
Other current liabilities	-12,000,000	-11,000,000
Employee benefit obligations	-137,000,000	-474,000,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	26,000,000	37,000,000
Net (Gain) Loss	584,000,000	1,095,000,000
Prior Service Cost, Estimated	10,000,000	'
Net (Gain) Loss, Estimated	41,000,000	'
Georgia Power [Member] | Other Postretirement Benefits [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Other regulatory assets, deferred	69,000,000	187,000,000
Employee benefit obligations	-316,000,000	-418,000,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	-4,000,000	-4,000,000
Net (Gain) Loss	73,000,000	186,000,000
Transition Obligation	0	5,000,000
Prior Service Cost, Estimated	0	'
Net (Gain) Loss, Estimated	2,000,000	'
Transition Obligation, Estimated	0	'
Gulf Power [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Prepaid pension costs	11,533,000	0
Other regulatory assets, deferred	340,415,000	372,294,000
Other current liabilities	-22,972,000	-19,930,000
Other regulatory liabilities, deferred	-56,051,000	-47,863,000
Employee benefit obligations	-76,338,000	-126,871,000
Accumulated OCI	-1,109,000	-1,581,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Net Regulatory Assets	160,224,000	171,985,000
Gulf Power [Member] | Pension Plans [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Prepaid pension costs	11,533,000	0
Other regulatory assets, deferred	75,280,000	139,261,000
Other current liabilities	-1,183,000	-855,000
Employee benefit obligations	-20,039,000	-62,386,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	4,401,000	5,565,000
Net (Gain) Loss	70,879,000	133,696,000
Prior Service Cost, Estimated	1,115,000	'
Net (Gain) Loss, Estimated	4,559,000	'
Gulf Power [Member] | Other Postretirement Benefits [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Other regulatory assets, deferred	0	2,169,000
Other current liabilities	-687,000	-661,000
Other regulatory liabilities, deferred	-6,984,000	0
Employee benefit obligations	-50,418,000	-58,507,000
Gulf Power [Member] | Other Postretirement Benefits [Member] | Regulatory Assets [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Other regulatory assets, deferred	-6,984,000	2,169,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	138,000	324,000
Net (Gain) Loss	-7,122,000	1,845,000
Prior Service Cost, Estimated	186,000	'
Net (Gain) Loss, Estimated	-24,000	'
Mississippi Power [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Other regulatory assets, deferred	200,620,000	236,225,000
Other current liabilities	-21,413,000	-31,882,000
Other regulatory liabilities, deferred	-140,880,000	-56,984,000
Employee benefit obligations	-94,430,000	-157,421,000
Accumulated OCI	-7,864,000	-8,713,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Net Regulatory Assets	66,604,000	147,469,000
Mississippi Power [Member] | Pension Plans [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Prepaid pension costs	5,698,000	0
Other regulatory assets, deferred	77,572,000	146,838,000
Other current liabilities	-2,134,000	-2,087,000
Employee benefit obligations	-25,556,000	-78,717,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	4,118,000	5,261,000
Net (Gain) Loss	73,454,000	141,577,000
Prior Service Cost, Estimated	1,088,000	'
Net (Gain) Loss, Estimated	4,937,000	'
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'	'
Amounts recognized in the consolidated balance sheets related to company's pension plans	'	'
Other regulatory assets, deferred	5,227,000	15,454,000
Other regulatory liabilities, deferred	-3,111,000	0
Employee benefit obligations	-57,663,000	-69,793,000
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization	'	'
Prior Service Cost	-2,311,000	-2,498,000
Net (Gain) Loss	4,427,000	17,952,000
Prior Service Cost, Estimated	-188,000	'
Net (Gain) Loss, Estimated	0	'
Net Regulatory Assets	$2,116,000	$15,454,000

Retirement_Benefits_Components

Retirement Benefits - Components of Accumulated OCI and Changes in Regulatory Assets (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans, Defined Benefit [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	$27,000	$30,000	$32,000
Net periodic benefit cost	245,000	135,000	19,000
Pension Plans, Defined Benefit [Member] | Accumulated Other Comprehensive Income (Loss)	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	125,000	109,000	'
Net (gain) loss	-52,000	21,000	'
Change in prior service costs	0	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	-1,000	-1,000	'
Amortization of net gain (loss)	-8,000	-4,000	'
Total reclassification adjustments	-9,000	-5,000	'
Net periodic benefit cost	-61,000	16,000	'
Ending Balance	64,000	125,000	'
Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	3,013,000	2,614,000	'
Net (gain) loss	-1,145,000	519,000	'
Change in prior service costs	1,000	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	-26,000	-29,000	'
Amortization of net gain (loss)	-192,000	-91,000	'
Total reclassification adjustments	-218,000	-120,000	'
Net periodic benefit cost	-1,362,000	399,000	'
Ending Balance	1,651,000	3,013,000	'
Other Postretirement Benefits [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	21,000	20,000	20,000
Net periodic benefit cost	63,000	66,000	69,000
Other Postretirement Benefits [Member] | Accumulated Other Comprehensive Income (Loss)	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	7,000	6,000	'
Net (gain) loss	-6,000	1,000	'
Reclassification adjustments	'	'	'
Amortization of transition obligation	0	0	'
Amortization of prior service costs	0	0	'
Amortization of net gain (loss)	0	0	'
Total reclassification adjustments	0	0	'
Net periodic benefit cost	-6,000	1,000	'
Ending Balance	1,000	7,000	'
Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	360,000	345,000	'
Net (gain) loss	-266,000	35,000	'
Reclassification adjustments	'	'	'
Amortization of transition obligation	-5,000	-10,000	'
Amortization of prior service costs	-4,000	-4,000	'
Amortization of net gain (loss)	-12,000	-6,000	'
Total reclassification adjustments	-21,000	-20,000	'
Net periodic benefit cost	-287,000	15,000	'
Ending Balance	73,000	360,000	'
Alabama Power [Member] | Pension Plans, Defined Benefit [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	7,000	7,000	9,000
Net periodic benefit cost	47,000	6,000	-21,000
Alabama Power [Member] | Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	822,000	727,000	'
Net (gain) loss	-287,000	125,000	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	-7,000	-7,000	'
Amortization of net gain (loss)	-52,000	-23,000	'
Total reclassification adjustments	-59,000	-30,000	'
Net periodic benefit cost	-346,000	95,000	'
Ending Balance	476,000	822,000	'
Alabama Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	5,000	6,000	7,000
Net periodic benefit cost	7,000	10,000	11,000
Alabama Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	89,000	96,000	'
Net (gain) loss	-99,000	-1,000	'
Reclassification adjustments	'	'	'
Amortization of transition obligation	0	-2,000	'
Amortization of prior service costs	-3,000	-4,000	'
Amortization of net gain (loss)	-2,000	0	'
Total reclassification adjustments	-5,000	-6,000	'
Net periodic benefit cost	-104,000	-7,000	'
Ending Balance	-15,000	89,000	'
Georgia Power [Member] | Pension Plans, Defined Benefit [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	10,000	12,000	12,000
Net periodic benefit cost	79,000	25,000	-15,000
Georgia Power [Member] | Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	1,132,000	995,000	'
Net (gain) loss	-438,000	182,000	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	-10,000	-12,000	'
Amortization of net gain (loss)	-74,000	-33,000	'
Total reclassification adjustments	-84,000	-45,000	'
Net periodic benefit cost	-522,000	137,000	'
Ending Balance	610,000	1,132,000	'
Georgia Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	12,000	10,000	11,000
Net periodic benefit cost	26,000	25,000	29,000
Georgia Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	187,000	186,000	'
Net (gain) loss	-106,000	11,000	'
Reclassification adjustments	'	'	'
Amortization of transition obligation	-4,000	-6,000	'
Amortization of prior service costs	0	0	'
Amortization of net gain (loss)	-8,000	-4,000	'
Total reclassification adjustments	-12,000	-10,000	'
Net periodic benefit cost	-118,000	1,000	'
Ending Balance	69,000	187,000	'
Gulf Power [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	1,164	1,262	1,262
Net periodic benefit cost	11,563	5,543	47
Gulf Power [Member] | Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	139,261	115,853	'
Net (gain) loss	-54,432	28,157	'
Change in prior service costs	0	426	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	-1,164	-1,262	'
Amortization of net gain (loss)	-8,385	-3,913	'
Total reclassification adjustments	-9,549	-5,175	'
Net periodic benefit cost	-63,981	23,408	'
Ending Balance	75,280	139,261	'
Gulf Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	186	379	396
Net periodic benefit cost	3,285	3,602	3,741
Gulf Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	2,169	239	'
Net (gain) loss	-8,967	2,309	'
Reclassification adjustments	'	'	'
Amortization of transition obligation	0	-193	'
Amortization of prior service costs	-186	-186	'
Amortization of net gain (loss)	0	0	'
Total reclassification adjustments	-186	-379	'
Net periodic benefit cost	-9,153	1,930	'
Ending Balance	-6,984	2,169	'
Mississippi Power [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	1,143	1,309	1,309
Net periodic benefit cost	12,884	8,723	3,922
Mississippi Power [Member] | Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	146,838	117,354	'
Net (gain) loss	-58,662	34,893	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	-1,143	-1,309	'
Amortization of net gain (loss)	-9,461	-4,100	'
Total reclassification adjustments	-10,604	-5,409	'
Net periodic benefit cost	-69,266	29,484	'
Ending Balance	77,572	146,838	'
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Reclassification adjustments	'	'	'
Amortization of prior service costs	471	470	274
Net periodic benefit cost	3,769	4,111	3,815
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member]	'	'	'
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward]	'	'	'
Beginning Balance	15,454	13,324	'
Net (gain) loss	-12,867	2,600	'
Reclassification adjustments	'	'	'
Amortization of transition obligation	0	-171	'
Amortization of prior service costs	188	188	'
Amortization of net gain (loss)	-659	-487	'
Total reclassification adjustments	-471	-470	'
Net periodic benefit cost	-13,338	2,130	'
Ending Balance	$2,116	$15,454	'

Retirement_Benefits_Components1

Retirement Benefits - Components of Net Periodic Benefit Cost and Estimated Future Benefit Payments (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Postretirement Benefits [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	$24,000	$21,000	$21,000
Interest cost	74,000	85,000	92,000
Expected return on plan assets	-56,000	-60,000	-64,000
Net amortization	21,000	20,000	20,000
Net periodic benefit cost	63,000	66,000	69,000
Benefit Payments	'	'	'
Benefit Payments, 2014	110,000	'	'
Benefit Payments, 2015	115,000	'	'
Benefit Payments, 2016	120,000	'	'
Benefit Payments, 2017	124,000	'	'
Benefit Payments, 2018	130,000	'	'
Benefit Payments, 2019 to 2023	654,000	'	'
Subsidy Receipts	'	'	'
Subsidy Receipts, 2014	-9,000	'	'
Subsidy Receipts, 2015	-10,000	'	'
Subsidy Receipts, 2016	-11,000	'	'
Subsidy Receipts, 2017	-13,000	'	'
Subsidy Receipts, 2018	-14,000	'	'
Subsidy Receipts, 2019 to 2023	-75,000	'	'
Benefit Payments and Subsidy Receipts, Total	'	'	'
Benefit Payments and Subsidy Receipts, 2014	101,000	'	'
Benefit Payments and Subsidy Receipts, 2015	105,000	'	'
Benefit Payments and Subsidy Receipts, 2016	109,000	'	'
Benefit Payments and Subsidy Receipts, 2017	111,000	'	'
Benefit Payments and Subsidy Receipts, 2018	116,000	'	'
Benefit Payments and Subsidy Receipts, 2019 to 2023	579,000	'	'
Pension Plans [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	232,000	198,000	184,000
Interest cost	389,000	393,000	389,000
Expected return on plan assets	-603,000	-581,000	-607,000
Recognized net (gain) loss	200,000	95,000	21,000
Net amortization	27,000	30,000	32,000
Net periodic benefit cost	245,000	135,000	19,000
Benefit Payments	'	'	'
Benefit Payments, 2014	399,000	'	'
Benefit Payments, 2015	422,000	'	'
Benefit Payments, 2016	446,000	'	'
Benefit Payments, 2017	471,000	'	'
Benefit Payments, 2018	492,000	'	'
Benefit Payments, 2019 to 2023	2,795,000	'	'
Alabama Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	6,000	5,000	5,000
Interest cost	19,000	22,000	24,000
Expected return on plan assets	-23,000	-23,000	-25,000
Net amortization	5,000	6,000	7,000
Net periodic benefit cost	7,000	10,000	11,000
Benefit Payments	'	'	'
Benefit Payments, 2014	30,000	'	'
Benefit Payments, 2015	31,000	'	'
Benefit Payments, 2016	31,000	'	'
Benefit Payments, 2017	33,000	'	'
Benefit Payments, 2018	33,000	'	'
Benefit Payments, 2019 to 2023	164,000	'	'
Subsidy Receipts	'	'	'
Subsidy Receipts, 2014	-3,000	'	'
Subsidy Receipts, 2015	-3,000	'	'
Subsidy Receipts, 2016	-3,000	'	'
Subsidy Receipts, 2017	-4,000	'	'
Subsidy Receipts, 2018	-4,000	'	'
Subsidy Receipts, 2019 to 2023	-22,000	'	'
Benefit Payments and Subsidy Receipts, Total	'	'	'
Benefit Payments and Subsidy Receipts, 2014	27,000	'	'
Benefit Payments and Subsidy Receipts, 2015	28,000	'	'
Benefit Payments and Subsidy Receipts, 2016	28,000	'	'
Benefit Payments and Subsidy Receipts, 2017	29,000	'	'
Benefit Payments and Subsidy Receipts, 2018	29,000	'	'
Benefit Payments and Subsidy Receipts, 2019 to 2023	142,000	'	'
Alabama Power [Member] | Pension Plans [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	52,000	44,000	43,000
Interest cost	93,000	94,000	96,000
Expected return on plan assets	-157,000	-162,000	-173,000
Recognized net (gain) loss	52,000	23,000	4,000
Net amortization	7,000	7,000	9,000
Net periodic benefit cost	47,000	6,000	-21,000
Benefit Payments	'	'	'
Benefit Payments, 2014	104,000	'	'
Benefit Payments, 2015	108,000	'	'
Benefit Payments, 2016	113,000	'	'
Benefit Payments, 2017	118,000	'	'
Benefit Payments, 2018	122,000	'	'
Benefit Payments, 2019 to 2023	669,000	'	'
Georgia Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	7,000	7,000	7,000
Interest cost	31,000	37,000	41,000
Expected return on plan assets	-24,000	-29,000	-30,000
Net amortization	12,000	10,000	11,000
Net periodic benefit cost	26,000	25,000	29,000
Benefit Payments	'	'	'
Benefit Payments, 2014	49,000	'	'
Benefit Payments, 2015	50,000	'	'
Benefit Payments, 2016	53,000	'	'
Benefit Payments, 2017	54,000	'	'
Benefit Payments, 2018	58,000	'	'
Benefit Payments, 2019 to 2023	287,000	'	'
Subsidy Receipts	'	'	'
Subsidy Receipts, 2014	-4,000	'	'
Subsidy Receipts, 2015	-4,000	'	'
Subsidy Receipts, 2016	-5,000	'	'
Subsidy Receipts, 2017	-5,000	'	'
Subsidy Receipts, 2018	-6,000	'	'
Subsidy Receipts, 2019 to 2023	-30,000	'	'
Benefit Payments and Subsidy Receipts, Total	'	'	'
Benefit Payments and Subsidy Receipts, 2014	45,000	'	'
Benefit Payments and Subsidy Receipts, 2015	46,000	'	'
Benefit Payments and Subsidy Receipts, 2016	48,000	'	'
Benefit Payments and Subsidy Receipts, 2017	49,000	'	'
Benefit Payments and Subsidy Receipts, 2018	52,000	'	'
Benefit Payments and Subsidy Receipts, 2019 to 2023	257,000	'	'
Georgia Power [Member] | Pension Plans [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	69,000	60,000	57,000
Interest cost	138,000	141,000	144,000
Expected return on plan assets	-212,000	-221,000	-234,000
Recognized net (gain) loss	74,000	33,000	6,000
Net amortization	10,000	12,000	12,000
Net periodic benefit cost	79,000	25,000	-15,000
Benefit Payments	'	'	'
Benefit Payments, 2014	154,000	'	'
Benefit Payments, 2015	161,000	'	'
Benefit Payments, 2016	167,000	'	'
Benefit Payments, 2017	175,000	'	'
Benefit Payments, 2018	181,000	'	'
Benefit Payments, 2019 to 2023	995,000	'	'
Gulf Power [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	11,128	9,101	8,431
Interest cost	17,321	17,199	17,074
Expected return on plan assets	-26,435	-25,932	-27,232
Recognized net (gain) loss	8,385	3,913	512
Net amortization	1,164	1,262	1,262
Net periodic benefit cost	11,563	5,543	47
Gulf Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	1,355	1,167	1,132
Interest cost	2,982	3,367	3,658
Expected return on plan assets	-1,238	-1,311	-1,445
Net amortization	186	379	396
Net periodic benefit cost	3,285	3,602	3,741
Benefit Payments	'	'	'
Benefit Payments, 2014	4,447	'	'
Benefit Payments, 2015	4,630	'	'
Benefit Payments, 2016	4,856	'	'
Benefit Payments, 2017	4,994	'	'
Benefit Payments, 2018	5,168	'	'
Benefit Payments, 2019 to 2023	26,272	'	'
Subsidy Receipts	'	'	'
Subsidy Receipts, 2014	-409	'	'
Subsidy Receipts, 2015	-456	'	'
Subsidy Receipts, 2016	-504	'	'
Subsidy Receipts, 2017	-557	'	'
Subsidy Receipts, 2018	-611	'	'
Subsidy Receipts, 2019 to 2023	-3,251	'	'
Benefit Payments and Subsidy Receipts, Total	'	'	'
Benefit Payments and Subsidy Receipts, 2014	4,038	'	'
Benefit Payments and Subsidy Receipts, 2015	4,174	'	'
Benefit Payments and Subsidy Receipts, 2016	4,352	'	'
Benefit Payments and Subsidy Receipts, 2017	4,437	'	'
Benefit Payments and Subsidy Receipts, 2018	4,557	'	'
Benefit Payments and Subsidy Receipts, 2019 to 2023	23,021	'	'
Gulf Power [Member] | Pension Plans [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	11,128	9,101	'
Interest cost	17,321	17,199	'
Benefit Payments	'	'	'
Benefit Payments, 2014	16,548	'	'
Benefit Payments, 2015	17,440	'	'
Benefit Payments, 2016	18,405	'	'
Benefit Payments, 2017	19,649	'	'
Benefit Payments, 2018	20,681	'	'
Benefit Payments, 2019 to 2023	121,864	'	'
Mississippi Power [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	11,067	9,416	8,838
Interest cost	18,062	18,019	17,827
Expected return on plan assets	-26,849	-24,121	-25,166
Recognized net (gain) loss	9,461	4,100	1,114
Net amortization	1,143	1,309	1,309
Net periodic benefit cost	12,884	8,723	3,922
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	1,151	1,038	1,012
Interest cost	3,619	4,155	4,292
Expected return on plan assets	-1,472	-1,552	-1,763
Net amortization	471	470	274
Net periodic benefit cost	3,769	4,111	3,815
Benefit Payments	'	'	'
Benefit Payments, 2014	5,051	'	'
Benefit Payments, 2015	5,335	'	'
Benefit Payments, 2016	5,569	'	'
Benefit Payments, 2017	5,849	'	'
Benefit Payments, 2018	6,091	'	'
Benefit Payments, 2019 to 2023	32,600	'	'
Subsidy Receipts	'	'	'
Subsidy Receipts, 2014	-526	'	'
Subsidy Receipts, 2015	-577	'	'
Subsidy Receipts, 2016	-632	'	'
Subsidy Receipts, 2017	-689	'	'
Subsidy Receipts, 2018	-748	'	'
Subsidy Receipts, 2019 to 2023	-3,793	'	'
Benefit Payments and Subsidy Receipts, Total	'	'	'
Benefit Payments and Subsidy Receipts, 2014	4,525	'	'
Benefit Payments and Subsidy Receipts, 2015	4,758	'	'
Benefit Payments and Subsidy Receipts, 2016	4,937	'	'
Benefit Payments and Subsidy Receipts, 2017	5,160	'	'
Benefit Payments and Subsidy Receipts, 2018	5,343	'	'
Benefit Payments and Subsidy Receipts, 2019 to 2023	28,807	'	'
Mississippi Power [Member] | Pension Plans [Member]	'	'	'
Components of net periodic	'	'	'
Service cost	11,067	9,416	'
Interest cost	18,062	18,019	'
Benefit Payments	'	'	'
Benefit Payments, 2014	17,245	'	'
Benefit Payments, 2015	18,076	'	'
Benefit Payments, 2016	18,993	'	'
Benefit Payments, 2017	20,172	'	'
Benefit Payments, 2018	21,237	'	'
Benefit Payments, 2019 to 2023	$124,728	'	'

Retirement_Benefits_Pension_Pl

Retirement Benefits - Pension Plan and Other Postretirement Benefit Plan Assets (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plans [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Pension Plans [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	26.00%	'
Defined Benefit Plan Assets	31.00%	28.00%
Pension Plans [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	25.00%	'
Defined Benefit Plan Assets	25.00%	24.00%
Pension Plans [Member] | Fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	23.00%	'
Defined Benefit Plan Assets	23.00%	27.00%
Pension Plans [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	1.00%	1.00%
Pension Plans [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	14.00%	'
Defined Benefit Plan Assets	14.00%	13.00%
Pension Plans [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	9.00%	'
Defined Benefit Plan Assets	6.00%	7.00%
Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Other Postretirement Benefits [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	40.00%	'
Defined Benefit Plan Assets	40.00%	38.00%
Other Postretirement Benefits [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	21.00%	'
Defined Benefit Plan Assets	25.00%	24.00%
Other Postretirement Benefits [Member] | Domestic fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	25.00%	'
Defined Benefit Plan Assets	24.00%	28.00%
Other Postretirement Benefits [Member] | Global fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	4.00%	'
Defined Benefit Plan Assets	4.00%	3.00%
Other Postretirement Benefits [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	1.00%	'
Defined Benefit Plan Assets	0.00%	0.00%
Other Postretirement Benefits [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	6.00%	'
Defined Benefit Plan Assets	5.00%	5.00%
Other Postretirement Benefits [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	2.00%	2.00%
Alabama Power [Member] | Pension Plans [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Alabama Power [Member] | Pension Plans [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	26.00%	'
Defined Benefit Plan Assets	31.00%	28.00%
Alabama Power [Member] | Pension Plans [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	25.00%	'
Defined Benefit Plan Assets	25.00%	24.00%
Alabama Power [Member] | Pension Plans [Member] | Fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	23.00%	'
Defined Benefit Plan Assets	23.00%	27.00%
Alabama Power [Member] | Pension Plans [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	1.00%	1.00%
Alabama Power [Member] | Pension Plans [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	14.00%	'
Defined Benefit Plan Assets	14.00%	13.00%
Alabama Power [Member] | Pension Plans [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	9.00%	'
Defined Benefit Plan Assets	6.00%	7.00%
Alabama Power [Member] | Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Alabama Power [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	44.00%	'
Defined Benefit Plan Assets	47.00%	46.00%
Alabama Power [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	20.00%	'
Defined Benefit Plan Assets	20.00%	20.00%
Alabama Power [Member] | Other Postretirement Benefits [Member] | Domestic fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	24.00%	'
Defined Benefit Plan Assets	27.00%	28.00%
Alabama Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	1.00%	'
Defined Benefit Plan Assets	0.00%	0.00%
Alabama Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	8.00%	'
Defined Benefit Plan Assets	4.00%	4.00%
Alabama Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	2.00%	2.00%
Georgia Power [Member] | Pension Plans [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Georgia Power [Member] | Pension Plans [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	26.00%	'
Defined Benefit Plan Assets	31.00%	28.00%
Georgia Power [Member] | Pension Plans [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	25.00%	'
Defined Benefit Plan Assets	25.00%	24.00%
Georgia Power [Member] | Pension Plans [Member] | Fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	23.00%	'
Defined Benefit Plan Assets	23.00%	27.00%
Georgia Power [Member] | Pension Plans [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	1.00%	1.00%
Georgia Power [Member] | Pension Plans [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	14.00%	'
Defined Benefit Plan Assets	14.00%	13.00%
Georgia Power [Member] | Pension Plans [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	9.00%	'
Defined Benefit Plan Assets	6.00%	7.00%
Georgia Power [Member] | Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Georgia Power [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	41.00%	'
Defined Benefit Plan Assets	36.00%	34.00%
Georgia Power [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	21.00%	'
Defined Benefit Plan Assets	30.00%	27.00%
Georgia Power [Member] | Other Postretirement Benefits [Member] | Domestic fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	24.00%	'
Defined Benefit Plan Assets	21.00%	27.00%
Georgia Power [Member] | Other Postretirement Benefits [Member] | Global fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	8.00%	'
Defined Benefit Plan Assets	8.00%	7.00%
Georgia Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	1.00%	'
Defined Benefit Plan Assets	0.00%	0.00%
Georgia Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	3.00%	3.00%
Georgia Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	2.00%	'
Defined Benefit Plan Assets	2.00%	2.00%
Gulf Power [Member] | Pension Plans [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Gulf Power [Member] | Pension Plans [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	26.00%	'
Defined Benefit Plan Assets	31.00%	28.00%
Gulf Power [Member] | Pension Plans [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	25.00%	'
Defined Benefit Plan Assets	25.00%	24.00%
Gulf Power [Member] | Pension Plans [Member] | Fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	23.00%	'
Defined Benefit Plan Assets	23.00%	27.00%
Gulf Power [Member] | Pension Plans [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	1.00%	1.00%
Gulf Power [Member] | Pension Plans [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	14.00%	'
Defined Benefit Plan Assets	14.00%	13.00%
Gulf Power [Member] | Pension Plans [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	9.00%	'
Defined Benefit Plan Assets	6.00%	7.00%
Gulf Power [Member] | Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Gulf Power [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	25.00%	'
Defined Benefit Plan Assets	30.00%	27.00%
Gulf Power [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	24.00%	'
Defined Benefit Plan Assets	24.00%	23.00%
Gulf Power [Member] | Other Postretirement Benefits [Member] | Domestic fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	25.00%	'
Defined Benefit Plan Assets	25.00%	29.00%
Gulf Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	1.00%	1.00%
Gulf Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	14.00%	'
Defined Benefit Plan Assets	14.00%	13.00%
Gulf Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	9.00%	'
Defined Benefit Plan Assets	6.00%	7.00%
Mississippi Power [Member] | Pension Plans [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Mississippi Power [Member] | Pension Plans [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	26.00%	'
Defined Benefit Plan Assets	31.00%	28.00%
Mississippi Power [Member] | Pension Plans [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	25.00%	'
Defined Benefit Plan Assets	25.00%	24.00%
Mississippi Power [Member] | Pension Plans [Member] | Fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	23.00%	'
Defined Benefit Plan Assets	23.00%	27.00%
Mississippi Power [Member] | Pension Plans [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	1.00%	1.00%
Mississippi Power [Member] | Pension Plans [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	14.00%	'
Defined Benefit Plan Assets	14.00%	13.00%
Mississippi Power [Member] | Pension Plans [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	9.00%	'
Defined Benefit Plan Assets	6.00%	7.00%
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	100.00%	'
Defined Benefit Plan Assets	100.00%	100.00%
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	21.00%	'
Defined Benefit Plan Assets	25.00%	22.00%
Mississippi Power [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	20.00%	'
Defined Benefit Plan Assets	20.00%	19.00%
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Fixed income [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	38.00%	'
Defined Benefit Plan Assets	38.00%	42.00%
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	3.00%	'
Defined Benefit Plan Assets	1.00%	1.00%
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	11.00%	'
Defined Benefit Plan Assets	11.00%	10.00%
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Defined Benefit Plan Assets, Target	7.00%	'
Defined Benefit Plan Assets	5.00%	6.00%

Retirement_Benefits_Fair_Value

Retirement Benefits - Fair Values of Pension Plan and Other Postretirement Benefit Plan Assets (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	$8,650,000,000		$7,890,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-3,000,000		'		'
Fair Value, Plan Assets and Liabilities	8,647,000,000		'		'
Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,272,000,000	[1]	1,833,000,000	[2]	'
Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,119,000,000	[1]	1,891,000,000	[2]	'
Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	599,000,000		516,000,000		'
Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	156,000,000		127,000,000		'
Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	978,000,000		879,000,000		'
Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	471,000,000		399,000,000		'
Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	224,000,000		553,000,000		'
Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,260,000,000		1,099,000,000		'
Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	571,000,000		593,000,000		'
Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	898,000,000		817,000,000		'
Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	202,000,000	[3]	183,000,000	[2]	'
Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	121,000,000	[3]	108,000,000	[2]	'
Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	34,000,000		24,000,000		'
Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,000,000		4,000,000		'
Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	35,000,000		31,000,000		'
Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	46,000,000		42,000,000		'
Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	19,000,000		44,000,000		'
Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	369,000,000		320,000,000		'
Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	46,000,000		40,000,000		'
Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	20,000,000		21,000,000		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,795,000,000		2,338,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	2,795,000,000		'		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,433,000,000	[1]	1,163,000,000	[2]	'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,101,000,000	[1]	912,000,000	[2]	'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,000,000		5,000,000		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	260,000,000		258,000,000		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	206,000,000		183,000,000		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	157,000,000	[3]	140,000,000	[2]	'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	39,000,000	[3]	33,000,000	[2]	'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	10,000,000		10,000,000		'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	4,284,000,000		4,115,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-3,000,000		'		'
Fair Value, Plan Assets and Liabilities	4,281,000,000		'		'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	839,000,000	[1]	670,000,000	[2]	'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,018,000,000	[1]	979,000,000	[2]	'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	599,000,000		516,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	156,000,000		127,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	978,000,000		876,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	471,000,000		399,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	223,000,000		548,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	636,000,000		583,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	45,000,000	[3]	43,000,000	[2]	'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	82,000,000	[3]	75,000,000	[2]	'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	34,000,000		24,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,000,000		4,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	35,000,000		31,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	46,000,000		42,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	19,000,000		44,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	369,000,000		320,000,000		'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,571,000,000		1,437,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	1,571,000,000		'		'
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[1]	0	[2]	'
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[1]	0	[2]	'
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		3,000,000		'
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,000,000,000		841,000,000		782,000,000
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	571,000,000		593,000,000		582,000,000
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	56,000,000		51,000,000		'
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[3]	0	[2]	'
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[3]	0	[2]	'
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	36,000,000		30,000,000		30,000,000
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	20,000,000		21,000,000		23,000,000
Alabama Power [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,256,000,000		2,062,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-1,000,000		'		'
Fair Value, Plan Assets and Liabilities	2,255,000,000		'		'
Alabama Power [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	593,000,000	[2]	479,000,000	[2]	'
Alabama Power [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	552,000,000	[2]	494,000,000	[2]	'
Alabama Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	156,000,000		135,000,000		'
Alabama Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	41,000,000		33,000,000		'
Alabama Power [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	255,000,000		231,000,000		'
Alabama Power [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	123,000,000		104,000,000		'
Alabama Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	58,000,000		144,000,000		'
Alabama Power [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	329,000,000		287,000,000		'
Alabama Power [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	149,000,000		155,000,000		'
Alabama Power [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	387,000,000		341,000,000		'
Alabama Power [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	78,000,000	[2]	71,000,000	[2]	'
Alabama Power [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	27,000,000	[2]	25,000,000	[2]	'
Alabama Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	17,000,000		7,000,000		'
Alabama Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,000,000		2,000,000		'
Alabama Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	12,000,000		11,000,000		'
Alabama Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,000,000		5,000,000		'
Alabama Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	10,000,000		19,000,000		'
Alabama Power [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	211,000,000		178,000,000		'
Alabama Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	17,000,000		15,000,000		'
Alabama Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	7,000,000		8,000,000		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	729,000,000		610,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	729,000,000		'		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	374,000,000	[2]	304,000,000	[2]	'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	287,000,000	[2]	238,000,000	[2]	'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		1,000,000		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	68,000,000		67,000,000		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	85,000,000		78,000,000		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	67,000,000	[2]	62,000,000	[2]	'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	14,000,000	[2]	12,000,000	[2]	'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	4,000,000		4,000,000		'
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,117,000,000		1,076,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-1,000,000		'		'
Fair Value, Plan Assets and Liabilities	1,116,000,000		'		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	219,000,000	[2]	175,000,000	[2]	'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	265,000,000	[2]	256,000,000	[2]	'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	156,000,000		135,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	41,000,000		33,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	255,000,000		230,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	123,000,000		104,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	58,000,000		143,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	282,000,000		244,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	11,000,000	[2]	9,000,000	[2]	'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	13,000,000	[2]	13,000,000	[2]	'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	17,000,000		7,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,000,000		2,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	12,000,000		11,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,000,000		5,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	10,000,000		19,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	211,000,000		178,000,000		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	410,000,000		376,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	410,000,000		'		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		1,000,000		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	261,000,000		220,000,000		217,000,000
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	149,000,000		155,000,000		161,000,000
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	20,000,000		19,000,000		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	13,000,000		11,000,000		11,000,000
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	7,000,000		8,000,000		8,000,000
Georgia Power [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	3,055,000,000		2,805,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-1,000,000		'		'
Fair Value, Plan Assets and Liabilities	3,054,000,000		'		'
Georgia Power [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	802,000,000	[2]	651,000,000	[2]	'
Georgia Power [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	748,000,000	[2]	672,000,000	[2]	'
Georgia Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	212,000,000		183,000,000		'
Georgia Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	55,000,000		45,000,000		'
Georgia Power [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	346,000,000		313,000,000		'
Georgia Power [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	166,000,000		142,000,000		'
Georgia Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	79,000,000		197,000,000		'
Georgia Power [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	445,000,000		391,000,000		'
Georgia Power [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	202,000,000		211,000,000		'
Georgia Power [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	406,000,000		382,000,000		'
Georgia Power [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	99,000,000	[2]	92,000,000	[2]	'
Georgia Power [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	69,000,000	[2]	61,000,000	[2]	'
Georgia Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	7,000,000		6,000,000		'
Georgia Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,000,000		1,000,000		'
Georgia Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	11,000,000		10,000,000		'
Georgia Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	34,000,000		32,000,000		'
Georgia Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,000,000		18,000,000		'
Georgia Power [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	158,000,000		142,000,000		'
Georgia Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	14,000,000		13,000,000		'
Georgia Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,000,000		7,000,000		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	987,000,000		831,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	987,000,000		'		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	506,000,000	[2]	413,000,000	[2]	'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	389,000,000	[2]	324,000,000	[2]	'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		2,000,000		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	92,000,000		92,000,000		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	89,000,000		78,000,000		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	74,000,000	[2]	65,000,000	[2]	'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	12,000,000	[2]	10,000,000	[2]	'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	3,000,000		3,000,000		'
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,513,000,000		1,463,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-1,000,000		'		'
Fair Value, Plan Assets and Liabilities	1,512,000,000		'		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	296,000,000	[2]	238,000,000	[2]	'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	359,000,000	[2]	348,000,000	[2]	'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	212,000,000		183,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	55,000,000		45,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	346,000,000		312,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	166,000,000		142,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	79,000,000		195,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	300,000,000		287,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	25,000,000	[2]	27,000,000	[2]	'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	57,000,000	[2]	51,000,000	[2]	'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	7,000,000		6,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,000,000		1,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	11,000,000		10,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	34,000,000		32,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,000,000		18,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	158,000,000		142,000,000		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	555,000,000		511,000,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	555,000,000		'		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		1,000,000		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	353,000,000		299,000,000		296,000,000
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	202,000,000		211,000,000		220,000,000
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	17,000,000		17,000,000		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	11,000,000		10,000,000		9,000,000
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,000,000		7,000,000		7,000,000
Gulf Power [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	381,941,000		347,458,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-115,000		'		'
Fair Value, Plan Assets and Liabilities	381,826,000		'		'
Gulf Power [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	100,306,000	[2]	80,714,000	[2]	'
Gulf Power [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	93,547,000	[2]	83,286,000	[2]	'
Gulf Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	26,461,000		22,724,000		'
Gulf Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,873,000		5,594,000		'
Gulf Power [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	43,222,000		38,673,000		'
Gulf Power [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	20,810,000		17,581,000		'
Gulf Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	9,889,000		24,356,000		'
Gulf Power [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	55,632,000		48,401,000		'
Gulf Power [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	25,201,000		26,129,000		'
Gulf Power [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	17,278,000		16,056,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-5,000		'		'
Fair Value, Plan Assets and Liabilities	17,273,000		'		'
Gulf Power [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	4,406,000	[2]	3,609,000	[2]	'
Gulf Power [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	4,109,000	[2]	3,723,000	[2]	'
Gulf Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,161,000		1,016,000		'
Gulf Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	303,000		250,000		'
Gulf Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,897,000		1,728,000		'
Gulf Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,417,000		1,298,000		'
Gulf Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	434,000		1,087,000		'
Gulf Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,443,000		2,175,000		'
Gulf Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,108,000		1,170,000		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	123,406,000		102,951,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	123,406,000		'		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	63,269,000	[2]	51,215,000	[2]	'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	48,606,000	[2]	40,166,000	[2]	'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	38,000		208,000		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	11,493,000		11,362,000		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	5,419,000		4,602,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	5,419,000		'		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,778,000	[2]	2,290,000	[2]	'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,136,000	[2]	1,795,000	[2]	'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,000		9,000		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	504,000		508,000		'
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	189,195,000		181,200,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-115,000		'		'
Fair Value, Plan Assets and Liabilities	189,080,000		'		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	37,037,000	[2]	29,499,000	[2]	'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	44,941,000	[2]	43,120,000	[2]	'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	26,461,000		22,724,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,873,000		5,594,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	43,222,000		38,534,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	20,810,000		17,581,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	9,851,000		24,148,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	8,812,000		8,626,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-5,000		'		'
Fair Value, Plan Assets and Liabilities	8,807,000		'		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,628,000	[2]	1,319,000	[2]	'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,973,000	[2]	1,928,000	[2]	'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,161,000		1,016,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	303,000		250,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,897,000		1,722,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,417,000		1,298,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	433,000		1,078,000		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		15,000		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	69,340,000		63,307,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	69,340,000		'		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		139,000		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	44,139,000		37,039,000		34,989,000
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	25,201,000		26,129,000		26,053,000
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	3,047,000		2,828,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	3,047,000		'		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		6,000		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,939,000		1,667,000		1,657,000
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,108,000		1,155,000		1,232,000
Mississippi Power [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	383,687,000		348,933,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-115,000		'		'
Fair Value, Plan Assets and Liabilities	383,572,000		'		'
Mississippi Power [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	100,764,000	[2]	81,057,000	[2]	'
Mississippi Power [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	93,975,000	[2]	83,640,000	[2]	'
Mississippi Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	26,582,000		22,820,000		'
Mississippi Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,904,000		5,618,000		'
Mississippi Power [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	43,420,000		38,836,000		'
Mississippi Power [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	20,905,000		17,656,000		'
Mississippi Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	9,934,000		24,460,000		'
Mississippi Power [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	55,887,000		48,606,000		'
Mississippi Power [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	25,316,000		26,240,000		'
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	23,057,000		21,842,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-5,000		'		'
Fair Value, Plan Assets and Liabilities	23,052,000		'		'
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	4,898,000	[2]	4,036,000	[2]	'
Mississippi Power [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	4,568,000	[2]	4,164,000	[2]	'
Mississippi Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	5,213,000		5,187,000		'
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	337,000		280,000		'
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,109,000		1,932,000		'
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,016,000		879,000		'
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	969,000		1,623,000		'
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,716,000		2,434,000		'
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,231,000		1,307,000		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	123,971,000		103,389,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	123,971,000		'		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	63,558,000	[2]	51,433,000	[2]	'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	48,829,000	[2]	40,337,000	[2]	'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	38,000		209,000		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	11,546,000		11,410,000		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,025,000		5,149,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	6,025,000		'		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	3,089,000	[2]	2,561,000	[2]	'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,375,000	[2]	2,008,000	[2]	'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,000		11,000		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	560,000		569,000		'
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	190,059,000		181,968,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-115,000		'		'
Fair Value, Plan Assets and Liabilities	189,944,000		'		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	37,206,000	[2]	29,624,000	[2]	'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	45,146,000	[2]	43,303,000	[2]	'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	26,582,000		22,820,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	6,904,000		5,618,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	43,420,000		38,696,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	20,905,000		17,656,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	9,896,000		24,251,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	13,645,000		13,528,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	-5,000		'		'
Fair Value, Plan Assets and Liabilities	13,640,000		'		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,809,000	[2]	1,475,000	[2]	'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,193,000	[2]	2,156,000	[2]	'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	5,213,000		5,187,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	337,000		280,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,109,000		1,925,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	1,016,000		879,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	968,000		1,612,000		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		14,000		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	69,657,000		63,576,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	69,657,000		'		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		140,000		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	44,341,000		37,196,000		32,434,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	25,316,000		26,240,000		24,151,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	3,387,000		3,165,000		'
Liabilities Fair Value	'		'		'
Fair Value, Plan Liabilities	0		'		'
Fair Value, Plan Assets and Liabilities	3,387,000		'		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0	[2]	0	[2]	'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		7,000		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	0		0		'
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	2,156,000		1,865,000		1,851,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member]	'		'		'
Assets Fair Value	'		'		'
Fair Value, Plan Assets	$1,231,000		$1,293,000		$1,377,000
[1]	*Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.B Fair Value Measurements Using Quoted Prices in Active Markets for Identical AssetsB SignificantOtherObservableInputsB SignificantUnobservableInputs As of December 31, 2012:(Level 1)B (Level 2)B (Level 3)B Total (in millions)Assets: Domestic equity*$1,163B $670B $bB $1,833International equity*912B 979B bB 1,891Fixed income: U.S. Treasury, government, and agency bondsbB 516B bB 516Mortgage- and asset-backed securitiesbB 127B bB 127Corporate bondsbB 876B 3B 879Pooled fundsbB 399B bB 399Cash equivalents and other5B 548B bB 553Real estate investments258B bB 841B 1,099Private equitybB bB 593B 593Total$2,338B $4,115B $1,437B $7,890
[2]	*Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
[3]	*Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.B Fair Value Measurements Using QuotedB Prices in Active Markets for Identical AssetsB SignificantOtherObservableInputsB SignificantUnobservableInputs As of December 31, 2012:(Level 1)B (Level 2)B (Level 3)B Total (in millions)Assets: Domestic equity*$140B $43B $bB $183International equity*33B 75B bB 108Fixed income: U.S. Treasury, government, and agency bondsbB 24B bB 24Mortgage- and asset-backed securitiesbB 4B bB 4Corporate bondsbB 31B bB 31Pooled fundsbB 42B bB 42Cash equivalents and otherbB 44B bB 44Trust-owned life insurancebB 320B bB 320Real estate investments10B bB 30B 40Private equitybB bB 21B 21Total$183B $583B $51B $817

Retirement_Benefits_Changes_in1

Retirement Benefits - Changes in Fair Value Measurement of Level 3 Pension Plan Assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plans [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	$7,890,000,000	'
Actual return on investments:	'	'
Total return on investments	1,098,000,000	1,010,000,000
Fair value of plan assets end of year	8,650,000,000	7,890,000,000
Pension Plans [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	1,260,000,000	1,099,000,000
Pension Plans [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	571,000,000	593,000,000
Other Postretirement Benefits [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	817,000,000	'
Actual return on investments:	'	'
Total return on investments	129,000,000	93,000,000
Fair value of plan assets end of year	898,000,000	817,000,000
Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	46,000,000	40,000,000
Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	20,000,000	21,000,000
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	1,571,000,000	1,437,000,000
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	841,000,000	782,000,000
Actual return on investments:	'	'
Related to investments held at year end	74,000,000	56,000,000
Related to investments sold during the year	30,000,000	3,000,000
Total return on investments	104,000,000	59,000,000
Purchases, sales, and settlements	55,000,000	0
Fair value of plan assets end of year	1,000,000,000	841,000,000
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	593,000,000	582,000,000
Actual return on investments:	'	'
Related to investments held at year end	8,000,000	1,000,000
Related to investments sold during the year	51,000,000	41,000,000
Total return on investments	59,000,000	42,000,000
Purchases, sales, and settlements	-81,000,000	-31,000,000
Fair value of plan assets end of year	571,000,000	593,000,000
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	56,000,000	51,000,000
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	30,000,000	30,000,000
Actual return on investments:	'	'
Related to investments held at year end	3,000,000	0
Related to investments sold during the year	1,000,000	0
Total return on investments	4,000,000	0
Purchases, sales, and settlements	2,000,000	0
Fair value of plan assets end of year	36,000,000	30,000,000
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	21,000,000	23,000,000
Actual return on investments:	'	'
Related to investments held at year end	0	0
Related to investments sold during the year	2,000,000	1,000,000
Total return on investments	2,000,000	1,000,000
Purchases, sales, and settlements	-3,000,000	-3,000,000
Fair value of plan assets end of year	20,000,000	21,000,000
Alabama Power [Member] | Pension Plans [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	2,062,000,000	'
Actual return on investments:	'	'
Total return on investments	285,000,000	274,000,000
Fair value of plan assets end of year	2,256,000,000	2,062,000,000
Alabama Power [Member] | Pension Plans [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	329,000,000	287,000,000
Alabama Power [Member] | Pension Plans [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	149,000,000	155,000,000
Alabama Power [Member] | Other Postretirement Benefits [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	341,000,000	'
Actual return on investments:	'	'
Total return on investments	61,000,000	39,000,000
Fair value of plan assets end of year	387,000,000	341,000,000
Alabama Power [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	17,000,000	15,000,000
Alabama Power [Member] | Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	7,000,000	8,000,000
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	410,000,000	376,000,000
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	220,000,000	217,000,000
Actual return on investments:	'	'
Related to investments held at year end	19,000,000	2,000,000
Related to investments sold during the year	8,000,000	1,000,000
Total return on investments	27,000,000	3,000,000
Purchases, sales, and settlements	14,000,000	0
Fair value of plan assets end of year	261,000,000	220,000,000
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	155,000,000	161,000,000
Actual return on investments:	'	'
Related to investments held at year end	2,000,000	0
Related to investments sold during the year	13,000,000	2,000,000
Total return on investments	15,000,000	2,000,000
Purchases, sales, and settlements	-21,000,000	-8,000,000
Fair value of plan assets end of year	149,000,000	155,000,000
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	20,000,000	19,000,000
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	11,000,000	11,000,000
Actual return on investments:	'	'
Related to investments held at year end	1,000,000	0
Related to investments sold during the year	0	0
Total return on investments	1,000,000	0
Purchases, sales, and settlements	1,000,000	0
Fair value of plan assets end of year	13,000,000	11,000,000
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	8,000,000	8,000,000
Actual return on investments:	'	'
Related to investments held at year end	0	0
Related to investments sold during the year	0	0
Total return on investments	0	0
Purchases, sales, and settlements	-1,000,000	0
Fair value of plan assets end of year	7,000,000	8,000,000
Georgia Power [Member] | Pension Plans [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	2,805,000,000	'
Actual return on investments:	'	'
Total return on investments	387,000,000	377,000,000
Fair value of plan assets end of year	3,055,000,000	2,805,000,000
Georgia Power [Member] | Pension Plans [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	445,000,000	391,000,000
Georgia Power [Member] | Pension Plans [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	202,000,000	211,000,000
Georgia Power [Member] | Other Postretirement Benefits [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	382,000,000	'
Actual return on investments:	'	'
Total return on investments	56,000,000	43,000,000
Fair value of plan assets end of year	406,000,000	382,000,000
Georgia Power [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	14,000,000	13,000,000
Georgia Power [Member] | Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	6,000,000	7,000,000
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	555,000,000	511,000,000
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	299,000,000	296,000,000
Actual return on investments:	'	'
Related to investments held at year end	25,000,000	2,000,000
Related to investments sold during the year	10,000,000	1,000,000
Total return on investments	35,000,000	3,000,000
Purchases, sales, and settlements	19,000,000	0
Fair value of plan assets end of year	353,000,000	299,000,000
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	211,000,000	220,000,000
Actual return on investments:	'	'
Related to investments held at year end	3,000,000	0
Related to investments sold during the year	17,000,000	2,000,000
Total return on investments	20,000,000	2,000,000
Purchases, sales, and settlements	-29,000,000	-11,000,000
Fair value of plan assets end of year	202,000,000	211,000,000
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	17,000,000	17,000,000
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	10,000,000	9,000,000
Actual return on investments:	'	'
Related to investments held at year end	1,000,000	1,000,000
Related to investments sold during the year	0	0
Total return on investments	1,000,000	1,000,000
Purchases, sales, and settlements	0	0
Fair value of plan assets end of year	11,000,000	10,000,000
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	7,000,000	7,000,000
Actual return on investments:	'	'
Related to investments held at year end	0	0
Related to investments sold during the year	0	0
Total return on investments	0	0
Purchases, sales, and settlements	-1,000,000	0
Fair value of plan assets end of year	6,000,000	7,000,000
Gulf Power [Member] | Pension Plans [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	347,458,000	'
Actual return on investments:	'	'
Total return on investments	49,076,000	45,762,000
Fair value of plan assets end of year	381,941,000	347,458,000
Gulf Power [Member] | Pension Plans [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	55,632,000	48,401,000
Gulf Power [Member] | Pension Plans [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	25,201,000	26,129,000
Gulf Power [Member] | Other Postretirement Benefits [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	16,056,000	'
Actual return on investments:	'	'
Total return on investments	2,119,000	2,131,000
Fair value of plan assets end of year	17,278,000	16,056,000
Gulf Power [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	2,443,000	2,175,000
Gulf Power [Member] | Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	1,108,000	1,170,000
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	69,340,000	63,307,000
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	37,039,000	34,989,000
Actual return on investments:	'	'
Related to investments held at year end	3,357,000	1,918,000
Related to investments sold during the year	1,310,000	132,000
Total return on investments	4,667,000	2,050,000
Purchases, sales, and settlements	2,433,000	0
Fair value of plan assets end of year	44,139,000	37,039,000
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	26,129,000	26,053,000
Actual return on investments:	'	'
Related to investments held at year end	376,000	44,000
Related to investments sold during the year	2,282,000	1,396,000
Total return on investments	2,658,000	1,440,000
Purchases, sales, and settlements	-3,586,000	-1,364,000
Fair value of plan assets end of year	25,201,000	26,129,000
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	3,047,000	2,828,000
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	1,667,000	1,657,000
Actual return on investments:	'	'
Related to investments held at year end	108,000	107,000
Related to investments sold during the year	57,000	6,000
Total return on investments	165,000	113,000
Purchases, sales, and settlements	107,000	-103,000
Fair value of plan assets end of year	1,939,000	1,667,000
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	1,155,000	1,232,000
Actual return on investments:	'	'
Related to investments held at year end	16,000	-1,000
Related to investments sold during the year	104,000	80,000
Total return on investments	120,000	79,000
Purchases, sales, and settlements	-167,000	-156,000
Fair value of plan assets end of year	1,108,000	1,155,000
Mississippi Power [Member] | Pension Plans [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	348,933,000	'
Actual return on investments:	'	'
Total return on investments	49,431,000	39,668,000
Fair value of plan assets end of year	383,687,000	348,933,000
Mississippi Power [Member] | Pension Plans [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	55,887,000	48,606,000
Mississippi Power [Member] | Pension Plans [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	25,316,000	26,240,000
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	21,842,000	'
Actual return on investments:	'	'
Total return on investments	2,379,000	2,427,000
Fair value of plan assets end of year	23,057,000	21,842,000
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	2,716,000	2,434,000
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	1,231,000	1,307,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	69,657,000	63,576,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	37,196,000	32,434,000
Actual return on investments:	'	'
Related to investments held at year end	3,385,000	4,629,000
Related to investments sold during the year	1,316,000	133,000
Total return on investments	4,701,000	4,762,000
Purchases, sales, and settlements	2,444,000	0
Fair value of plan assets end of year	44,341,000	37,196,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	26,240,000	24,151,000
Actual return on investments:	'	'
Related to investments held at year end	378,000	44,000
Related to investments sold during the year	2,300,000	3,415,000
Total return on investments	2,678,000	3,459,000
Purchases, sales, and settlements	-3,602,000	-1,370,000
Fair value of plan assets end of year	25,316,000	26,240,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member]	'	'
Actual return on investments:	'	'
Fair value of plan assets end of year	3,387,000	3,165,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	1,865,000	1,851,000
Actual return on investments:	'	'
Related to investments held at year end	158,000	119,000
Related to investments sold during the year	64,000	7,000
Total return on investments	222,000	126,000
Purchases, sales, and settlements	69,000	-112,000
Fair value of plan assets end of year	2,156,000	1,865,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member]	'	'
Changes in the fair value measurement of the Level 3 items in the pension plan assets	'	'
Fair value of plan assets beginning of year	1,293,000	1,377,000
Actual return on investments:	'	'
Related to investments held at year end	18,000	-1,000
Related to investments sold during the year	110,000	90,000
Total return on investments	128,000	89,000
Purchases, sales, and settlements	-190,000	-173,000
Fair value of plan assets end of year	$1,231,000	$1,293,000

Retirement_Benefits_Textual_De

Retirement Benefits - Textual (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Annual salary increase on net periodic benefit costs	3.59%	3.59%	3.84%	3.84%
Annual increase or decrease in assumed medical care cost trend rate	1.00%	'	'	'
Total accumulated benefit obligation for the pension plans	$8,100,000,000	$8,500,000,000	'	'
Period over which company has elected to amortize changes in the market value of all plan assets	'5 years	'	'	'
Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Expected postretirement trust contributions	0	'	'	'
Discount rate on net periodic benefit costs	5.02%	4.26%	4.98%	5.52%
Projected benefit obligations	8,863,000,000	9,302,000,000	8,079,000,000	'
Total matching contributions	39,000,000	479,000,000	'	'
Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Expected postretirement trust contributions	13,000,000	'	'	'
Discount rate on net periodic benefit costs	4.85%	4.05%	4.88%	5.40%
Initial Cost Trend Rate	7.00%	'	'	'
Ultimate Cost Trend Rate	5.00%	'	'	'
Year That Ultimate Rate Is Reached	'2021	'	'	'
Projected benefit obligations	1,682,000,000	1,872,000,000	1,787,000,000	'
Total matching contributions	39,000,000	55,000,000	'	'
Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Projected benefit obligations	8,300,000,000	'	'	'
Non Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Projected benefit obligations	549,000,000	'	'	'
Employee Saving Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Matching limit of contribution by employer	85.00%	'	'	'
Maximum limit of contribution of employees base salary	6.00%	'	'	'
Total matching contributions	84,000,000	82,000,000	78,000,000	'
Alabama Power [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Annual salary increase on net periodic benefit costs	3.59%	3.59%	3.84%	3.84%
Annual increase or decrease in assumed medical care cost trend rate	1.00%	'	'	'
Total accumulated benefit obligation for the pension plans	1,900,000,000	2,000,000,000	'	'
Period over which company has elected to amortize changes in the market value of all plan assets	'5 years	'	'	'
Alabama Power [Member] | Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Voluntary contribution to pension plan	0	'	'	'
Expected postretirement trust contributions	0	'	'	'
Discount rate on net periodic benefit costs	5.02%	4.27%	4.98%	5.52%
Projected benefit obligations	2,112,000,000	2,218,000,000	1,932,000,000	'
Total matching contributions	9,000,000	8,000,000	'	'
Alabama Power [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Discount rate on net periodic benefit costs	4.86%	4.06%	4.88%	5.41%
Initial Cost Trend Rate	7.00%	'	'	'
Ultimate Cost Trend Rate	5.00%	'	'	'
Year That Ultimate Rate Is Reached	'2021	'	'	'
Projected benefit obligations	431,000,000	490,000,000	470,000,000	'
Total matching contributions	7,000,000	11,000,000	'	'
Alabama Power [Member] | Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Projected benefit obligations	2,000,000,000	'	'	'
Alabama Power [Member] | Non Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Projected benefit obligations	110,000,000	'	'	'
Alabama Power [Member] | Employee Saving Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Matching limit of contribution by employer	85.00%	'	'	'
Maximum limit of contribution of employees base salary	6.00%	'	'	'
Total matching contributions	20,000,000	19,000,000	18,000,000	'
Georgia Power [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Expected postretirement trust contributions	13,000,000	'	'	'
Annual salary increase on net periodic benefit costs	3.59%	3.59%	3.84%	3.84%
Annual increase or decrease in assumed medical care cost trend rate	1.00%	'	'	'
Period over which company has elected to amortize changes in the market value of all plan assets	'5 years	'	'	'
Georgia Power [Member] | Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Voluntary contribution to pension plan	0	'	'	'
Expected postretirement trust contributions	0	'	'	'
Discount rate on net periodic benefit costs	5.02%	4.27%	4.98%	5.52%
Total accumulated benefit obligation for the pension plans	2,900,000,000	3,100,000,000	'	'
Projected benefit obligations	3,116,000,000	3,312,000,000	2,909,000,000	'
Total matching contributions	12,000,000	11,000,000	'	'
Georgia Power [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Discount rate on net periodic benefit costs	4.85%	4.04%	4.87%	5.40%
Initial Cost Trend Rate	7.00%	'	'	'
Ultimate Cost Trend Rate	5.00%	'	'	'
Year That Ultimate Rate Is Reached	'2021	'	'	'
Projected benefit obligations	723,000,000	800,000,000	774,000,000	'
Total matching contributions	11,000,000	17,000,000	'	'
Georgia Power [Member] | Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Projected benefit obligations	3,000,000,000	'	'	'
Georgia Power [Member] | Non Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Projected benefit obligations	148,000,000	'	'	'
Georgia Power [Member] | Employee Saving Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Matching limit of contribution by employer	85.00%	'	'	'
Maximum limit of contribution of employees base salary	6.00%	'	'	'
Total matching contributions	24,000,000	24,000,000	24,000,000	'
Gulf Power [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Annual salary increase on net periodic benefit costs	3.59%	3.59%	3.84%	3.84%
Annual increase or decrease in assumed medical care cost trend rate	1.00%	'	'	'
Period over which company has elected to amortize changes in the market value of all plan assets	'5 years	'	'	'
Gulf Power [Member] | Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Discount rate on net periodic benefit costs	5.02%	4.27%	4.98%	5.53%
Total accumulated benefit obligation for the pension plans	353,000,000	371,000,000	'	'
Projected benefit obligations	395,328,000	413,501,000	352,834,000	'
Total matching contributions	1,134,000	14,220,000	'	'
Gulf Power [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Expected postretirement trust contributions	0	'	'	'
Discount rate on net periodic benefit costs	4.86%	4.06%	4.88%	5.41%
Initial Cost Trend Rate	7.00%	'	'	'
Ultimate Cost Trend Rate	5.00%	'	'	'
Year That Ultimate Rate Is Reached	'2021	'	'	'
Projected benefit obligations	68,579,000	75,395,000	70,923,000	'
Total matching contributions	2,381,000	2,648,000	'	'
Gulf Power [Member] | Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Expected postretirement trust contributions	0	'	'	'
Projected benefit obligations	374,000,000	'	'	'
Gulf Power [Member] | Non Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Projected benefit obligations	21,000,000	'	'	'
Gulf Power [Member] | Employee Saving Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Matching limit of contribution by employer	85.00%	'	'	'
Maximum limit of contribution of employees base salary	6.00%	'	'	'
Total matching contributions	4,100,000	4,000,000	3,700,000	'
Mississippi Power [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Annual salary increase on net periodic benefit costs	3.59%	3.59%	3.84%	3.84%
Annual increase or decrease in assumed medical care cost trend rate	1.00%	'	'	'
Total accumulated benefit obligation for the pension plans	370,000,000	392,000,000	'	'
Period over which company has elected to amortize changes in the market value of all plan assets	'5 years	'	'	'
Total matching contributions	4,100,000	3,900,000	3,800,000	'
Mississippi Power [Member] | Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Discount rate on net periodic benefit costs	5.01%	4.26%	4.98%	5.51%
Projected benefit obligations	409,395,000	432,553,000	369,680,000	'
Total matching contributions	2,430,000	44,930,000	'	'
Mississippi Power [Member] | Other Postretirement Benefits [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Discount rate on net periodic benefit costs	4.85%	4.04%	4.87%	5.39%
Initial Cost Trend Rate	7.00%	'	'	'
Ultimate Cost Trend Rate	5.00%	'	'	'
Year That Ultimate Rate Is Reached	'2021	'	'	'
Projected benefit obligations	80,940,000	91,783,000	87,447,000	'
Total matching contributions	2,562,000	3,052,000	'	'
Mississippi Power [Member] | Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Expected postretirement trust contributions	0	'	'	'
Projected benefit obligations	382,000,000	'	'	'
Mississippi Power [Member] | Non Qualified Pension Plans [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Projected benefit obligations	$28,000,000	'	'	'
Mississippi Power [Member] | Employee Saving Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Matching limit of contribution by employer	85.00%	'	'	'
Maximum limit of contribution of employees base salary	6.00%	'	'	'

Acquisitions_Textual_Details

Acquisitions - Textual (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Aug. 27, 2013

Dec. 31, 2013

Apr. 23, 2013

Dec. 31, 2013

Sep. 28, 2012

Dec. 31, 2013

Apr. 23, 2013

Jun. 29, 2012

Dec. 31, 2013

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Adobe Solar LLC [Member]

Adobe Solar LLC [Member]

Campo Verde Solar LLC [Member]

Campo Verde Solar LLC [Member]

Spectrum Nevada Solar Llc [Member]

Spectrum Nevada Solar Llc [Member]

Apex Nevada Solar Llc [Member]

Apex Nevada Solar Llc [Member]

Apex Nevada Solar Llc [Member]

MW

MW

MW

MW

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Power of Solar Polycrystalline Silicon Facility

'

'

'

'

'

20

[1],[2]

'

139

[1],[3]

'

30

[1],[4]

'

'

20

[1]

Beginning Year of Output of Constructed Plant

'

'

'

'

'

'2014

[2]

'

'2013

[3]

'

'2013

[4]

'

'

'2012

Life Output Of Plant

'

'

'

'

'

'20 years

[2]

'

'20 years

[3]

'

'25 years

[4]

'

'25 years

'25 years

Payments to Acquire Businesses, Gross

'

'

'

'

$100,000,000

$100,000,000

[2]

$136,600,000

$136,600,000

[3]

'

$17,600,000

[4]

'

'

$102,000,000

Business Acquisition Cost of Acquired Entity Purchase Consideration Cash Paid

'

'

'

'

'

'

132,200,000

'

'

'

96,000,000

'

'

Construction in Progress, Gross

7,151,000,000

5,989,000,000

9,843,000

24,835,000

'

'

'

'

'

'

'

'

'

Business Acquisition Cost Paid Upon Achievement Of Milestones

'

'

'

'

'

'

4,400,000

'

'

'

6,000,000

'

'

Business Acquisition Cost Paid To Other Assets

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

Business Acquisition Cost Paid At Closing

'

'

'

'

'

'

'

'

17,600,000

'

'

102,000,000

'

Business Acquisition Cost of Acquired Entity Purchase Consideration Cash Will Be Paid

'

'

'

'

'

'

$355,500,000

'

$104,000,000

'

'

'

'

[1]

megawatt (MW)

[2]

This acquisition is expected to occur in spring 2014, and the purchase price is expected to be $100 million.

[3]

Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar Inc. to complete the construction of the solar facility.

[4]

Under an engineering, procurement, and construction agreement, an additional $104 million was paid to a subsidiary of Sun Edison, LLC to complete the construction of the solar facility.

Contingencies_and_Regulatory_M2

Contingencies and Regulatory Matters - Current And Actual Cost Estimate (Details) (Mississippi Power [Member], USD $)	12 Months Ended			0 Months Ended		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 22, 2013	Jan. 24, 2013	Dec. 31, 2013		Dec. 31, 2013		Dec. 31, 2013
				Electricity Generation Plant, Non-Nuclear [Member]	Electricity Generation Plant, Non-Nuclear [Member]	Kemper IGCC [Member]		Kemper IGCC [Member]		Kemper IGCC [Member]
								Project Estimate [Member]		Current Estimate [Member]
Loss Contingencies [Line Items]	'	'	'	'	'	'		'		'
Plant Subject to Cost Cap	'	'	'	$2,400,000,000	$2,400,000,000	$3,250,000,000	[1]	$2,400,000,000	[1],[2]	$4,060,000,000	[1]
Cost Of Lignite Mine And Equipment	'	'	'	'	'	230,000,000		210,000,000	[2]	230,000,000
Cost Of CO2 Pipeline Facilities	'	'	'	'	'	90,000,000		140,000,000	[2]	110,000,000
Cost Of AFUDC	'	'	'	'	'	280,000,000	[3]	170,000,000	[2],[3]	450,000,000	[3]
AFUDC Cost	8,500,000	'	'	'	'	'		'		'
Plant General Exceptions	'	'	'	'	'	70,000,000		50,000,000	[2]	100,000,000
Plant Regulatory Asset	'	'	'	'	'	70,000,000	[4]	0	[2],[4]	90,000,000	[4]
Total Kemper IGCC	2,880,000,000	'	'	'	'	3,990,000,000	[1]	2,970,000,000	[1],[2]	5,040,000,000	[1]
Loss Contingency, Estimate of Possible Loss	1,180,000,000	'	'	'	'	'		'		'
Noncash transactions - accrued property additions at year-end	$164,863,000	$214,863,000	$135,902,000	'	'	'		'		'
[1]	The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions.
[2]	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
[3]	Mississippi Powerbs original estimate included recovery of financing costs during construction which was not approved by the Mississippi PSC in June 2012 as described in "Rate Recovery of Kemper IGCC Costs."
[4]	The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs b Regulatory Assets."

Contingencies_and_Regulatory_M3

Contingencies and Regulatory Matters - Textual (Details) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2009

Dec. 10, 2013

Jun. 30, 2012

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Nov. 21, 2013

Aug. 13, 2013

Jul. 31, 2007

Sep. 30, 2013

Mar. 31, 2013

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Sep. 30, 2012

Aug. 13, 2013

Aug. 13, 2013

Dec. 31, 2013

Aug. 13, 2013

Aug. 13, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 02, 2013

Dec. 17, 2013

Nov. 04, 2013

Sep. 03, 2013

Jul. 11, 2013

Apr. 22, 2013

Jan. 31, 2013

Jul. 31, 2007

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2008

Oct. 15, 2013

Jan. 02, 2013

Jun. 01, 2012

Apr. 02, 2012

Jan. 02, 2012

Jun. 01, 2011

Jan. 02, 2011

Jan. 02, 2014

Feb. 27, 2014

Jan. 02, 2014

Jan. 02, 2014

Dec. 17, 2013

Dec. 31, 2013

Apr. 17, 2013

Sep. 30, 2013

Jul. 11, 2013

Jul. 11, 2013

Jul. 11, 2013

Jul. 11, 2013

Jul. 11, 2013

Jan. 10, 2014

Dec. 17, 2013

Dec. 31, 2009

Dec. 31, 2013

Dec. 31, 2013

Jul. 11, 2013

Apr. 02, 2013

Mar. 19, 2013

Apr. 02, 2012

Jun. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 04, 2013

Mar. 22, 2013

Mar. 15, 2013

Mar. 05, 2013

Apr. 30, 2012

Mar. 31, 2012

Feb. 28, 2012

Nov. 30, 2011

Jun. 30, 2011

Dec. 31, 2010

Jan. 02, 2014

Feb. 27, 2014

Feb. 03, 2014

Feb. 02, 2014

Dec. 31, 2013

Jul. 11, 2013

Jul. 11, 2013

Jan. 25, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Mar. 22, 2013

Feb. 26, 2013

Jan. 24, 2013

Dec. 31, 2013

Dec. 31, 2012

Mar. 29, 2013

Jan. 02, 2013

Jan. 02, 2013

Dec. 31, 2013

Dec. 31, 2010

Nov. 30, 2011

Oct. 20, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 03, 2013

Nov. 04, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Kemper IGCC [Member]

Kemper IGCC [Member]

Gulf Power and Mississippi Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

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

Other Regulatory Assets, Deferred and Other Deferred Credits and Liabilities [Member]

Other regulatory liabilities current [Member]

Other regulatory liabilities current [Member]

Regulatory Clause Revenues, under-recovered [Member]

Regulatory Clause Revenues, under-recovered [Member]

Prime Rate [Member]

Settlement Agreement [Member]

Provisions

MW

MW

Purchased_Power_Agreement

MW

Property

MW

Minimum [Member]

Maximum [Member]

Fuel Recovery Clause [Member]

Current Rate Stabilization And Equalization [Member]

Current Rate Stabilization And Equalization [Member]

MW

Purchased_Power_Agreement

Purchased_Power_Agreement

MW

Purchased_Power_Agreement

MW

Subsequent Event [Member]

Subsequent Event [Member]

Minimum [Member]

Maximum [Member]

Pending Litigation [Member]

Storm Costs [Member]

Plant Bowen [Member]

Plant Branch Unit Two [Member]

Plant Boulevard [Member]

Plant Branch [Member]

Plant Yates [Member]

Plant McManus [Member]

Plant Kraft [Member]

Plant Mitchell [Member]

Georgia Advanced Solar Initiative [Member]

Plant Vogtle Units 3 And 4 [Member]

Utility Scale Projects [Member]

Electric Distribution [Member]

Customer

MW

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Plant Daniel Units 1 and 2 [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Retail [Member]

MRA Revenue [Member]

MRA Revenue [Member]

MB Revenue [Member]

MB Revenue [Member]

Hurricane [Member]

Hurricane [Member]

Gulf Power [Member]

Gulf Power [Member]

Electricity Generation Plant, Non-Nuclear [Member]

Electricity Generation Plant, Non-Nuclear [Member]

Electricity Generation Plant, Non-Nuclear [Member]

Kemper IGCC [Member]

Kemper IGCC [Member]

Kemper IGCC [Member]

Kemper IGCC [Member]

Kemper IGCC [Member]

Kemper IGCC [Member]

Mine [Member]

Plant Daniel Units 3 and 4 [Member]

Plant Daniel Units 3 and 4 [Member]

Plant Daniel Units 1 and 2 [Member]

Minimum [Member]

Maximum [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

MW

Minimum [Member]

Maximum [Member]

Property

MW

MW

Subsequent Event [Member]

Subsequent Event [Member]

Purchased_Power_Agreement

MW

MW

MW

MW

MW

MW

MW

Subsequent Event [Member]

Property

MW

MW

mi

Plant Daniel Units 1 and 2 [Member]

MW

Minimum [Member]

Maximum [Member]

Maximum Up To Year Two Thousand Twenty [Member]

MW

kWh

MW

MW

MW

Loss Contingencies [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent Of Designated Customer Value Benchmark Survey

'

'

'

'

'

'

'

'

'

'

'

'

33.30%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Insurance Recovery [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (Loss) Related to Litigation Settlement

'

'

'

($202,000,000)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of Insurance Claim Received in Respect of Litigation Settlement

'

'

'

'

15,000,000

25,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Legal Fee Related to Insurance Recoveries

4,000,000

6,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Amount Received of Insurance Claim in Respect of Litigation Settlement

11,000,000

19,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Environmental Matters [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Civil penalties under Clean Air Act per day, lower range

25,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Civil penalties under Clean Air Act per day, upper range

37,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Environmental remediation liability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,400,000

'

'

'

'

'

'

'

3,100,000

47,300,000

'

'

'

'

'

'

Civil penalties per violation rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of times of punitive damages in comparison to cost incurred by Environmental Protection Agency

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

FERC Matters [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in Annual Base Wholesale Revenues

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22,600,000

'

'

'

'

'

'

'

'

'

'

'

32,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating lease, initial term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Property, Plant and Equipment, Generation, Useful Life

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'30 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period Over Which Annual Revenue Will Increase Under Tariff

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'12 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

24,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Nuclear Fuel Disposal Costs [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Claims awarded to companies related to nuclear fuel disposal litigation

'

'

'

'

'

'

'

'

'

'

'

17,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

27,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Retail Regulatory Matters [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Portion of Actual Earnings Above Approved ROE Band Retained by Subsidiary Company

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

33.33%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Portion of Actual Earnings Above Approved ROE Band Refunded to Customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

66.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Anticipates of elimination adjustment will result in additional revenues

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,000,000

'

'

106,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual PEP Lookback Refund To Customers

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rate Adjustment Period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum percentage of Rate RSE

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum annual percentage of ratio rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum projected retail return on common equity at which retail rates remain unchanged

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum projected retail return on common equity at which retail rates remain unchanged

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum increase in rate RSE

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowed Equity Ratio

'

'

'

'

'

'

'

'

'

'

45.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Provisions

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Cost Of Equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.75%

6.21%

'

5.85%

6.53%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Adjusting Point Of Weighted Cost Of Equity

'

'

'

'

'

'

'

'

'

'

5.98%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.19%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period Of Treasury Yield Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'30 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent Of Basis Points

'

'

'

'

'

'

'

'

'

'

0.07%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.25%

'

'

'

'

'

0.75%

'

'

'

'

'

'

'

'

'

Under recovered certified PPA balance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Approved And Certified Energy From Wind-Powered Generating Facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200

'

'

200

200

'

200

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Wind Farms

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Under Recovered Rate Cnp Balance

'

'

'

'

'

'

'

'

'

'

58,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecovered Retail Revenue Requirement For Environmental Compliance

'

'

'

'

'

'

'

'

'

72,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Under recovered environmental clause

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period Which Deferred Regulatory Asset Account, Amortized

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period Which Afforded Regulatory Asset Treatment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Compliance-related Operation Maintenance Expenditures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operation And Maintenance Cost Deferred To Regulatory Asset

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Incremental Increase In Pension Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Approved billing rate under rate ECR up to (cents per KWH)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.0591

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Future stated rates under rate Ecr factor in terms of per units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.02681

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Over recovered fuel cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

42,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

56,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14,500,000

7,300,000

19,000,000

300,000

2,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount Of Under Recovered Emissions Allowance Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,800,000

400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Under recovered fuel cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Regulatory Liabilities, Current

92,000,000

107,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

3,000,000

'

'

'

'

'

27,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

17,000,000

73,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

24,981,000

5,376,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13,408,000

25,887,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred over recovered regulatory clause revenues

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15,000,000

0

'

'

'

'

'

15,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum Period for recovery deferred storm-related operations and maintenance costs and any future reserve deficit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'24 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum total rate NDR charge per month, non-residential customer account

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum total rate NDR charge per month, residential customer account

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Old Natural Disaster Reserve Authorized Limit

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated NDR reserve reflected as other regulatory liabilities, deferred

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

96,000,000

103,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of units for which outage operations and maintenance expenses accrued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period over which deferred costs are being amortized to nuclear operations and maintenance expenses

'

'

'

'

'

'

'

'

'

'

'

'

'18 months

'18 months

'18 months

'

'

'18 months

'

'

'18 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Nuclear outage expense

'

'

'

'

'

'

'

'

'

'

'

'

32,000,000

28,000,000

31,000,000

'

38,000,000

31,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period To Amortize Expense

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outage Expenditures

'

'

'

'

'

'

'

'

'

'

78,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Base Rate Increases

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

74,000,000

'

125,000,000

17,000,000

'

562,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Intervenors Approved ARP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Intervenors

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in traditional base tariff rates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Increase In ECCR Tariff

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Demand Side Management Tariffs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Increase In Demand Side Management Tariffs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Increase In Municipal Franchise Fee Tariff

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Base Revenue under Alternate Base Plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

110,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period For Levelized Revenue Requirements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in Tariff Rate Two

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

101,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in Tariff Rate Three

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

36,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Increase In ECCR Tariff One

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

76,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Increase In ECCR Tariff Two

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

131,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Decrease In Demand Side Management Tariffs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue to be Received from Increase in Base Rate One

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

187,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue to be Received from Increase in Base Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

170,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Retail Rate of Return on Common Equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.95%

'

10.00%

12.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Test Period For PSC

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,093

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capacity Of Units Approved For Decertification Of Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

32

319

28

1,016

579

122

316

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Extension Period For Mercury And Air Toxics Standards

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period for Environmental Construction

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'9 years

'

'

'

'

'

'

'

'

'

'

'9 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capacity Of Small Power Production Facility

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

169

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

155

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Wind PPAs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

2

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Energy From Solar Generation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

525

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50

'

425

100

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Wind PPAs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Energy From Wind-Powered Generating Facilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in total annual billing based on fuel cost recovery rate approved by Georgia Power

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

122,000,000

567,000,000

'

'

43,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Adjustment To Fuel Cost Recovery Rate If Under Recovered Fuel Balance Exceeds Budget Thereafter

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Required Period For Options And Hedges

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'24 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Under recovered fuel balance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

21,000,000

'

'

'

Deferral of maintenance costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Electric generating capacity in Mega Watts under consortium agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,100

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of proportionate share owed in Consortium Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45.70%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of New Nuclear Generating Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase In NCCR Tariff Year One

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

'

'

35,000,000

'

223,000,000

60,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization to earnings of financing costs capitalized over the five year period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

91,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization period for financing costs collected

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Costs included in CWIP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,740,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) In Projected Certified Construction Capital Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated In-service Capital Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amendment To Estimated In-service Capital Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,800,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Construction Capital Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,800,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Adjustment to Contract Price Related to Issues that May Impact Project Budget and Schedule

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

425,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Construction And Capital Costs Included In Semi Annual Construction Monitoring Report

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,200,000,000

'

'

'

'

'

'

'

2,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional Construction Capital Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Plants For Decertification

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

16

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Over recovered fuel balance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

58,000,000

230,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

17,100,000

'

'

'

'

Percent ownership

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

14.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

Required Customers For Energy Efficiency Programs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Required Period For Filing Quick Start Plans

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'6 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period For Quick Start Plans To Be In Effect

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage Of PSC Retail Rate Increase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of Decrease in Annual Revenue After Revised Notice

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.16%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Decrease in Annual Revenue After Revised Notice

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Project expenditures, cumulative

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

320,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Project expenditures, cumulative, proportionate share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

162,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

AFUDC Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (decrease) in annual revenue, percent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proposed Change in Annual Revenues

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,100,000

'

'

1,200,000

'

'

'

'

30,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proposed property damage reserve

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

PSC Retail Rate Increase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period Adjustment For SRR Rate Level

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

PSC Approved Annual Property Damage Reserve Accrual

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,200,000

'

'

'

'

'

'

'

'

'

'

'

3,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Storm Reserve Balance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Integrated Coal Gasification Combined Cycle [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Plant capacity under coal gasification combined cycle technology in Mega Watts

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

582

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

New Co2 Pipeline Infrastructure

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

61

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,400,000,000

'

2,400,000,000

3,250,000,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Costs Related to Grant Funding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

245,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum cap construction cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,880,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,990,000,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Costs included in CWIP

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,740,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss Contingency, Estimate of Possible Loss

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,180,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,300,000

10,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost deferred in other regulatory assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

70,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other deferred charges and assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Previously expensed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Pre-Tax Charge To Income

'

'

'

'

'

'

1,200,000,000

1,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,100,000,000

78,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

After Tax Charge To Income

'

'

'

'

'

'

'

729,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

680,500,000

48,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Alternate Financing

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue Requirement Obligations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Settlement Agreement To Increase Rates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

172,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Related regulatory liability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

62,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

98,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Retail Revenues

14,541,000,000

14,187,000,000

15,071,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,952,000,000

4,933,000,000

4,972,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,620,000,000

7,362,000,000

8,099,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

799,139,000

747,453,000

792,463,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,300,000

'

'

'

'

'

'

'

'

1,170,000,000

1,144,471,000

1,208,490,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Period Rate Plan For Cost Accrued Through Additional Prudence Review

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'7 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revisions To Revenue Requirement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reduced Percentage Interest Transferred under Asset Purchase Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Electric Generating Units, Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

'

'

'

'

'

'

'

659

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

'

'

'

75

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

'

'

'

'

'

'

'

'

Capacity Revenues Under Power Supply Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

17,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Term of management fee contract

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'40 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'40 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of Carbon dioxide captured from project by purchase Denbury

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

70.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of contract to purchase carbon dioxide from Kemper IGCC

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchase of interest in plant

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

17.50%

'

'

17.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deposit Received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

150,000,000

'

'

'

'

'

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum Period to Refund Deposit upon Termination of Asset Purchase Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum Period of Discretion

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Tax credits (Phase I)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

133,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Tax credits (Phase II)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

279,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrued tax benefits on tax credits

28,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

276,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum percentage of carbon dioxide that must be capture and sequester to remain eligible for the phase II tax credits

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Prudence Review Of Plant Cost Within Settlement Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'6 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual PEP Filing Rate Increase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.93%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual PEP Filing Rate Increase Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Cost of Project One

'

'

'

'

'

'

'

'

660,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

660,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

330,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated Cost of Project, Proportionate Share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

330,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncash transactions - accrued property additions at year-end

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

18,000,000

31,000,000

19,000,000

'

'

'

'

'

'

'

5,567,000

11,203,000

32,590,000

'

'

'

'

'

'

'

'

208,000,000

261,000,000

391,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

164,863,000

214,863,000

135,902,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,546,000

27,369,000

19,439,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Base Revenue In Year One

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Base Revenue In Year Two

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.93%

9.97%

7.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.79%

'

Period of Treasury Rate Above Basis Points

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'6 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Cost of Removal Obligations

1,270,000,000

1,194,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

828,000,000

759,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

43,000,000

63,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

151,340,000

143,461,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

228,148,000

213,413,000

'

'

'

'

'

'

'

'

'

'

'

'

'

62,500,000

Recovery Period For Natural Disaster Reserve Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'24 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Customer Surcharge Storm Recovery Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

Customer Surcharge Storm Recovery Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

'

'

'

'

'

'

Cumulative damage costs limit under PSC order

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Retail Rate Increase (Decrease)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65,200,000

'

'

'

'

'

'

'

'

'

'

'

Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

Fuel Vendor Payment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

26,600,000

'

'

'

'

'

Purchased Power Over (Under) Recovered Balance Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchased Power, Over Under Recovered Balance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,800,000

800,000

'

'

Under Recovered Environmental Cost

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14,400,000

1,900,000

'

'

Period of Establishment of Conservation Goals, in Years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period Numeric Conservation Goals Cover, in Years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Under Recovered Energy Conservation Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

'

'

'

Over Recovered Energy Conservation Costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

800,000

'

'

Bonus Depreciation for Property Acquired

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

50.00%

50.00%

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Positive Impact From Bonus Depreciation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$98,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$560,000,000

$620,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions.

Joint_Ownership_Agreements_Det

Joint Ownership Agreements (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
	MW
Jointly owned utility plant interests	'		'	'
Plant acquisition adjustment	$123,000,000		$124,000,000	'
Plant Vogtle (nuclear) Units 1 and 2 [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	45.70%		'	'
Plant in Service	3,375,000,000		'	'
Accumulated Depreciation	2,028,000,000		'	'
Construction Work in Progress	0		'	'
Plant Hatch (nuclear) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	50.10%		'	'
Plant in Service	1,092,000,000		'	'
Accumulated Depreciation	551,000,000		'	'
Construction Work in Progress	0		'	'
Plant Miller (coal) Units 1 and 2 [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	91.80%		'	'
Plant in Service	1,410,000,000		'	'
Accumulated Depreciation	575,000,000		'	'
Construction Work in Progress	0		'	'
Plant Scherer (coal) Units 1 and 2 [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	8.40%		'	'
Plant in Service	209,000,000		'	'
Accumulated Depreciation	80,000,000		'	'
Construction Work in Progress	0		'	'
Plant Wansley (coal) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	53.50%		'	'
Plant in Service	800,000,000		'	'
Accumulated Depreciation	260,000,000		'	'
Construction Work in Progress	0		'	'
Rocky Mountain (pumped storage) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	25.40%		'	'
Plant in Service	182,000,000		'	'
Accumulated Depreciation	120,000,000		'	'
Construction Work in Progress	0		'	'
Intercession City (combustion turbine) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	33.30%		'	'
Plant in Service	14,000,000		'	'
Accumulated Depreciation	4,000,000		'	'
Construction Work in Progress	0		'	'
Plant Stanton (combined cycle) Unit A [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	65.00%		'	'
Plant in Service	156,000,000		'	'
Accumulated Depreciation	42,000,000		'	'
Construction Work in Progress	0		'	'
Alabama Power [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	1,000		'	'
Percent Ownership	14.00%		'	'
Plant acquisition adjustment	12,000,000		12,000,000	'
Joint Ownership Agreements (Textual) [Abstract]	'		'	'
Jointly Owned Affiliate Equity	84,000,000		'	'
Jointly Owned Affiliate Long Term Debt	125,000,000		'	'
Jointly Owned Affiliate Long Term Debt Annual Interest Requirement	3,000,000		'	'
Dividends paid by equity method investment	7,000,000		14,000,000	15,000,000
Ownership percentage, equity method investment	50.00%		'	'
Alabama Power [Member] | SEGCO [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	1,020		'	'
Joint Ownership Agreements (Textual) [Abstract]	'		'	'
Share Of Purchased Power	88,000,000		109,000,000	142,000,000
Unconditional guarantee to pay outstanding pollution control revenue bond principal	25,000,000		'	'
Guarantee of unsecured senior notes	50,000,000		'	'
Alabama Power [Member] | Senior notes due December 1, 2018 [Member] | SEGCO [Member]	'		'	'
Joint Ownership Agreements (Textual) [Abstract]	'		'	'
Guarantee of unsecured senior notes	100,000,000		'	'
Alabama Power [Member] | Natural Gas Pipeline [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Construction Work in Progress	1,000,000		'	'
Alabama Power [Member] | Plant Miller (coal) Units 1 and 2 [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	1,320		'	'
Percent Ownership	91.84%	[1]	'	'
Plant in Service	1,410,000,000		'	'
Accumulated Depreciation	575,000,000		'	'
Construction Work in Progress	89,000,000		'	'
Alabama Power [Member] | SEGCO [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	86.00%		'	'
Alabama Power [Member] | Greene County [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	500		'	'
Percent Ownership	60.00%	[2]	'	'
Plant in Service	157,000,000		'	'
Accumulated Depreciation	91,000,000		'	'
Construction Work in Progress	5,000,000		'	'
Georgia Power [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Plant acquisition adjustment	28,000,000		28,000,000	'
Georgia Power [Member] | SEGCO [Member]	'		'	'
Joint Ownership Agreements (Textual) [Abstract]	'		'	'
Share Of Purchased Power	91,000,000		107,000,000	'
Georgia Power [Member] | Purchased Power from Affiliates [Member] | SEGCO [Member]	'		'	'
Joint Ownership Agreements (Textual) [Abstract]	'		'	'
Share Of Purchased Power	'		'	141,000,000
Georgia Power [Member] | Alabama Power [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	1,020		'	'
Georgia Power [Member] | Plant Vogtle (nuclear) Units 1 and 2 [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	45.70%		'	'
Plant in Service	3,375,000,000		'	'
Accumulated Depreciation	2,028,000,000		'	'
Construction Work in Progress	53,000,000		'	'
Georgia Power [Member] | Plant Hatch (nuclear) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	50.10%		'	'
Plant in Service	1,092,000,000		'	'
Accumulated Depreciation	551,000,000		'	'
Construction Work in Progress	52,000,000		'	'
Georgia Power [Member] | Plant Scherer (coal) Units 1 and 2 [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	8.40%		'	'
Plant in Service	209,000,000		'	'
Accumulated Depreciation	80,000,000		'	'
Construction Work in Progress	24,000,000		'	'
Georgia Power [Member] | Plant Wansley (coal) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	53.50%		'	'
Plant in Service	800,000,000		'	'
Accumulated Depreciation	260,000,000		'	'
Construction Work in Progress	36,000,000		'	'
Georgia Power [Member] | Rocky Mountain (pumped storage) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	25.40%		'	'
Plant in Service	182,000,000		'	'
Accumulated Depreciation	120,000,000		'	'
Construction Work in Progress	0		'	'
Georgia Power [Member] | Intercession City (combustion turbine) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	33.30%		'	'
Plant in Service	14,000,000		'	'
Accumulated Depreciation	4,000,000		'	'
Construction Work in Progress	0		'	'
Georgia Power [Member] | Vogtle Units 3 and 4 [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	45.70%		'	'
Georgia Power [Member] | Plant Scherer Unit 3 (coal) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	75.00%		'	'
Plant in Service	1,155,000,000		'	'
Accumulated Depreciation	398,000,000		'	'
Construction Work in Progress	19,000,000		'	'
Gulf Power [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Plant acquisition adjustment	2,031,000		2,286,000	'
Gulf Power [Member] | Plant Scherer Unit 3 (coal) [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	818		'	'
Percent Ownership	25.00%		'	'
Plant in Service	382,374,000	[3]	'	'
Accumulated Depreciation	123,862,000		'	'
Construction Work in Progress	6,303,000		'	'
Plant acquisition adjustment	2,000,000		'	'
Gulf Power [Member] | Plant Daniel Units 1 &2 2 [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	1,000		'	'
Percent Ownership	50.00%		'	'
Plant in Service	282,370,000		'	'
Accumulated Depreciation	172,365,000		'	'
Construction Work in Progress	169,085,000		'	'
Mississippi Power [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Plant acquisition adjustment	81,412,000		81,412,000	'
Mississippi Power [Member] | Greene County [Member] | Alabama Power [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	500		'	'
Percent Ownership	40.00%		'	'
Plant in Service	96,153,000		'	'
Accumulated Depreciation	49,731,000		'	'
Construction Work in Progress	3,017,000		'	'
Mississippi Power [Member] | Plant Daniel Units 1 &2 2 [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	50.00%		'	'
Mississippi Power [Member] | Plant Daniel Units 1 &2 2 [Member] | Gulf Power [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	1,000		'	'
Percent Ownership	50.00%		'	'
Plant in Service	299,179,000		'	'
Accumulated Depreciation	152,952,000		'	'
Construction Work in Progress	168,539,000		'	'
Southern Power [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Total Megawatt Capacity	659		'	'
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Plant in Service	156,000,000		'	'
Accumulated Depreciation	$41,800,000		'	'
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Southern Power [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	65.00%		'	'
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Orlando Utilities Commission [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	28.00%		'	'
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Florida Municipal Power Agency [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	3.50%		'	'
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Kissimmee Utility Authority [Member]	'		'	'
Jointly owned utility plant interests	'		'	'
Percent Ownership	3.50%		'	'
[1]	Jointly owned with PowerSouth Energy Cooperative, Inc.
[2]	Jointly owned with an affiliate, Mississippi Power.
[3]	Includes net plant acquisition adjustment of $2.0 million.

Income_Taxes_Current_and_Defer

Income Taxes - Current and Deferred Income Tax Provisions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Federal -	'	'	'
Current	$363,000	$177,000	$57,000
Deferred	386,000	1,011,000	1,035,000
Total federal taxes	749,000	1,188,000	1,092,000
State -	'	'	'
Current	-10,000	61,000	8,000
Deferred	110,000	85,000	119,000
Total state taxes	100,000	146,000	127,000
Income taxes	849,000	1,334,000	1,219,000
Alabama Power [Member]	'	'	'
Federal -	'	'	'
Current	243,000	262,000	20,000
Deferred	160,000	137,000	377,000
Total federal taxes	403,000	399,000	397,000
State -	'	'	'
Current	36,000	51,000	-1,000
Deferred	39,000	27,000	82,000
Total state taxes	75,000	78,000	81,000
Income taxes	478,000	477,000	478,000
Georgia Power [Member]	'	'	'
Federal -	'	'	'
Current	277,000	273,000	106,000
Deferred	374,000	370,000	479,000
Total federal taxes	651,000	643,000	585,000
State -	'	'	'
Current	-30,000	38,000	19,000
Deferred	102,000	7,000	21,000
Total state taxes	72,000	45,000	40,000
Income taxes	723,000	688,000	625,000
Gulf Power [Member]	'	'	'
Federal -	'	'	'
Current	5,009	-92,610	-1,548
Deferred	63,134	161,096	56,087
Total federal taxes	68,143	68,486	54,539
State -	'	'	'
Current	-2,410	-2,484	-412
Deferred	13,935	13,209	7,141
Total state taxes	11,525	10,725	6,729
Income taxes	79,668	79,211	61,268
Mississippi Power [Member]	'	'	'
Federal -	'	'	'
Current	23,345	1,212	-27,099
Deferred	-342,870	16,994	65,206
Total federal taxes	-319,525	18,206	38,107
State -	'	'	'
Current	5,219	1,656	-2,473
Deferred	-53,529	694	6,559
Total state taxes	-48,310	2,350	4,086
Income taxes	-367,835	20,556	42,193
Southern Power [Member]	'	'	'
Federal -	'	'	'
Current	-120,200	-133,100	61,600
Deferred	158,700	210,400	12,400
Total federal taxes	38,500	77,300	74,000
State -	'	'	'
Current	-5,200	-3,000	9,800
Deferred	12,600	18,300	-7,900
Total state taxes	7,400	15,300	1,900
Income taxes	$45,895	$92,621	$75,857

Income_Taxes_Deferred_Tax_Asse

Income Taxes - Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Deferred tax liabilities -	'	'
Total - deferred tax liabilities	$10,420,000,000	$9,701,000,000
Deferred Tax Liabilities, Gross	13,995,000,000	13,619,000,000
Deferred tax assets -	'	'
Total - deferred tax assets	3,624,000,000	3,972,000,000
Total deferred tax liabilities, net	3,575,000,000	3,918,000,000
Portion included in current assets/(liabilities), net	143,000,000	237,000,000
Valuation allowance	-49,000,000	-54,000,000
Accumulated deferred income taxes	10,563,000,000	9,938,000,000
Deferred State Tax Assets [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	77,000,000	68,000,000
Asset retirement obligations-asset [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	824,000,000	720,000,000
Kemper IGCC Loss [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	472,000,000	0
Unbilled revenues [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	116,000,000	101,000,000
Accelerated depreciation [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	9,710,000,000	9,022,000,000
Property basis differences [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	1,515,000,000	1,254,000,000
Leveraged lease basis differences [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	287,000,000	278,000,000
Employee benefit obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	491,000,000	536,000,000
Deferred tax assets -	'	'
Total - deferred tax assets	1,048,000,000	1,678,000,000
Regulatory assets associated with employee benefit obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	705,000,000	988,000,000
Premium on reacquired debt [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	113,000,000	84,000,000
Regulatory assets associated with asset retirement obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	824,000,000	1,108,000,000
Federal effect of state deferred taxes [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	421,000,000	394,000,000
Other deferred tax liabilities [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	350,000,000	349,000,000
Over recovered fuel clause [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	30,000,000	135,000,000
Other property basis differences [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	157,000,000	134,000,000
Deferred costs [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	84,000,000	39,000,000
Tax credit carryforward [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	121,000,000	256,000,000
Other Comprehensive Income Losses [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	54,000,000	84,000,000
Other deferred tax assets [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	220,000,000	363,000,000
Alabama Power [Member]	'	'
Deferred tax liabilities -	'	'
Total - deferred tax liabilities	3,578,000,000	3,379,000,000
Deferred Tax Liabilities, Gross	4,516,000,000	4,419,000,000
Deferred tax assets -	'	'
Total - deferred tax assets	938,000,000	1,040,000,000
Portion included in current assets/(liabilities), net	25,000,000	25,000,000
Accumulated deferred income taxes	3,603,000,000	3,404,000,000
Alabama Power [Member] | Accelerated depreciation [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	3,187,000,000	2,989,000,000
Alabama Power [Member] | Property basis differences [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	458,000,000	420,000,000
Alabama Power [Member] | Leveraged lease basis differences [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	33,000,000	36,000,000
Alabama Power [Member] | Employee benefit obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	209,000,000	218,000,000
Deferred tax assets -	'	'
Total - deferred tax assets	231,000,000	408,000,000
Alabama Power [Member] | Regulatory assets associated with employee benefit obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	198,000,000	378,000,000
Alabama Power [Member] | Under recovered fuel clause [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	0	16,000,000
Alabama Power [Member] | Asset retirement obligation [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	38,000,000	0
Deferred tax assets -	'	'
Total - deferred tax assets	303,000,000	248,000,000
Alabama Power [Member] | Regulatory assets associated with asset retirement obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	265,000,000	248,000,000
Alabama Power [Member] | Federal effect of state deferred taxes [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	205,000,000	194,000,000
Alabama Power [Member] | Other deferred tax liabilities [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	128,000,000	114,000,000
Alabama Power [Member] | Unbilled revenues [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	41,000,000	39,000,000
Alabama Power [Member] | Storm reserve [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	32,000,000	34,000,000
Alabama Power [Member] | Other Comprehensive Income Losses [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	18,000,000	19,000,000
Alabama Power [Member] | Other deferred tax assets [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	108,000,000	98,000,000
Georgia Power [Member]	'	'
Deferred tax liabilities -	'	'
Total - deferred tax liabilities	5,132,000,000	4,709,000,000
Deferred Tax Liabilities, Gross	6,596,000,000	6,365,000,000
Deferred tax assets -	'	'
Total - deferred tax assets	1,464,000,000	1,656,000,000
Portion included in current assets/(liabilities), net	68,000,000	152,000,000
Accumulated deferred income taxes	5,200,000,000	4,861,000,000
Georgia Power [Member] | Accelerated depreciation [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	4,479,000,000	4,201,000,000
Georgia Power [Member] | Property basis differences [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	873,000,000	757,000,000
Georgia Power [Member] | Employee benefit obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	232,000,000	255,000,000
Deferred tax assets -	'	'
Total - deferred tax assets	388,000,000	644,000,000
Georgia Power [Member] | Regulatory assets associated with employee benefit obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	276,000,000	536,000,000
Georgia Power [Member] | Premium on reacquired debt [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	73,000,000	77,000,000
Georgia Power [Member] | Regulatory assets associated with asset retirement obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	495,000,000	446,000,000
Deferred tax assets -	'	'
Total - deferred tax assets	495,000,000	446,000,000
Georgia Power [Member] | Federal effect of state deferred taxes [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	159,000,000	142,000,000
Georgia Power [Member] | Other deferred tax liabilities [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	168,000,000	93,000,000
Georgia Power [Member] | Unbilled revenues [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	53,000,000	39,000,000
Georgia Power [Member] | Over recovered fuel clause [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	22,000,000	89,000,000
Georgia Power [Member] | Other property basis differences [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	93,000,000	100,000,000
Georgia Power [Member] | Deferred costs [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	84,000,000	39,000,000
Georgia Power [Member] | Cost of removal [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	17,000,000	29,000,000
Georgia Power [Member] | Tax credit carryforward [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	118,000,000	86,000,000
Georgia Power [Member] | Federal Tax Credit Carryforward [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	3,000,000	0
Georgia Power [Member] | Other deferred tax assets [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	32,000,000	42,000,000
Gulf Power [Member]	'	'
Deferred tax liabilities -	'	'
Total - deferred tax liabilities	725,974,000	646,980,000
Deferred Tax Liabilities, Gross	858,980,000	804,881,000
Deferred tax assets -	'	'
Total - deferred tax assets	133,006,000	157,901,000
Portion included in current assets/(liabilities), net	8,381,000	1,972,000
Accumulated deferred income taxes	734,355,000	648,952,000
Gulf Power [Member] | Accelerated depreciation [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	721,087,000	696,502,000
Gulf Power [Member] | Property basis differences [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	45,960,000	0
Gulf Power [Member] | Employee benefit obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	25,800,000	28,579,000
Gulf Power [Member] | Pension and other employee benefits [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	33,015,000	61,939,000
Gulf Power [Member] | Regulatory assets associated with employee benefit obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	27,660,000	57,279,000
Gulf Power [Member] | Fuel Recovery Clause [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	7,972,000	0
Gulf Power [Member] | Asset retirement obligation [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	6,554,000	6,502,000
Gulf Power [Member] | Regulatory assets associated with asset retirement obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	6,554,000	6,502,000
Gulf Power [Member] | Federal effect of state deferred taxes [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	24,277,000	20,656,000
Gulf Power [Member] | Other deferred tax liabilities [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	23,947,000	16,019,000
Gulf Power [Member] | Other Postretirement Benefits [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	17,816,000	17,905,000
Gulf Power [Member] | Over recovered fuel clause [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	0	6,922,000
Gulf Power [Member] | Other property basis differences [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	0	23,549,000
Gulf Power [Member] | Tax credit carryforward [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	18,420,000	938,000
Gulf Power [Member] | Property reserve [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	15,144,000	13,773,000
Gulf Power [Member] | Other Comprehensive Income Losses [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	696,000	993,000
Gulf Power [Member] | Other deferred tax assets [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	17,084,000	4,724,000
Mississippi Power [Member]	'	'
Deferred tax liabilities -	'	'
Total - deferred tax liabilities	57,182,000	209,143,000
Deferred Tax Liabilities, Gross	730,649,000	658,814,000
Deferred tax assets -	'	'
Total - deferred tax assets	673,467,000	449,671,000
Portion included in current assets/(liabilities), net	15,626,000	35,815,000
Accumulated deferred income taxes	72,808,000	244,958,000
Mississippi Power [Member] | Accelerated depreciation [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	371,553,000	385,899,000
Mississippi Power [Member] | Property basis differences [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	130,679,000	72,451,000
Mississippi Power [Member] | Pension and other employee benefits [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	23,769,000	33,756,000
Deferred tax assets -	'	'
Total - deferred tax assets	57,999,000	87,416,000
Mississippi Power [Member] | Regulatory assets associated with employee benefit obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	33,127,000	68,717,000
Mississippi Power [Member] | Regulatory assets associated with Kemper IGCC [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	30,708,000	10,492,000
Mississippi Power [Member] | Under recovered fuel clause [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	1,777,000	9,492,000
Mississippi Power [Member] | Asset retirement obligation [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	16,764,000	16,851,000
Mississippi Power [Member] | Regulatory assets associated with asset retirement obligations [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	16,764,000	16,851,000
Mississippi Power [Member] | Long-term service agreement [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	0	5,544,000
Mississippi Power [Member] | Rate Differential [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	56,074,000	27,270,000
Mississippi Power [Member] | Federal effect of state deferred taxes [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	30,615,000	0
Deferred tax assets -	'	'
Total - deferred tax assets	0	7,732,000
Mississippi Power [Member] | Other deferred tax liabilities [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	35,583,000	33,886,000
Mississippi Power [Member] | Property insurance [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	23,693,000	23,171,000
Mississippi Power [Member] | Premium on long-term debt [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	23,736,000	26,778,000
Mississippi Power [Member] | Unbilled revenues [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	12,136,000	11,642,000
Mississippi Power [Member] | Over recovered fuel clause [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	7,741,000	38,955,000
Mississippi Power [Member] | Kemper IGCC Loss [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	472,000,000	31,200,000
Mississippi Power [Member] | Interest rate hedges [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	5,094,000	5,644,000
Mississippi Power [Member] | Investment tax credit carryforward [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	0	170,938,000
Mississippi Power [Member] | Kemper Rate Factor - Regulatory Liability Retail [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	36,210,000	0
Mississippi Power [Member] | Other deferred tax assets [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	18,094,000	23,800,000
Southern Power [Member]	'	'
Deferred tax liabilities -	'	'
Total - deferred tax liabilities	724,200,000	550,500,000
Deferred Tax Liabilities, Gross	844,400,000	636,000,000
Deferred tax assets -	'	'
Total - deferred tax assets	127,700,000	91,700,000
Total deferred tax liabilities, net	120,200,000	85,500,000
Portion included in current assets/(liabilities), net	200,000	200,000
Valuation allowance	-7,500,000	-6,200,000
Accumulated deferred income taxes	724,390,000	550,685,000
Southern Power [Member] | Accelerated depreciation and other property basis differences [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	829,500,000	632,900,000
Southern Power [Member] | Federal effect of state deferred taxes [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	29,700,000	25,200,000
Southern Power [Member] | Levelized capacity revenues [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	11,200,000	0
Deferred tax assets -	'	'
Total - deferred tax assets	6,000,000	4,500,000
Southern Power [Member] | State Net Operating Loss [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	17,000,000	8,300,000
Southern Power [Member] | Other deferred tax liabilities [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	900,000	0
Southern Power [Member] | Other property basis differences [Member]	'	'
Deferred tax liabilities -	'	'
Deferred Tax Liabilities, Gross	2,800,000	3,100,000
Deferred tax assets -	'	'
Total - deferred tax assets	2,900,000	3,900,000
Southern Power [Member] | Tax credit carryforward [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	1,100,000	1,100,000
Southern Power [Member] | Investment tax credit carryforward [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	58,000,000	28,600,000
Southern Power [Member] | Unrealized Loss [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	11,200,000	15,700,000
Southern Power [Member] | Other deferred tax assets [Member]	'	'
Deferred tax assets -	'	'
Total - deferred tax assets	$1,800,000	$4,400,000

Income_Taxes_Reconciliation_of

Income Taxes - Reconciliation of Federal Statutory Income Tax Rate (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of federal statutory income tax rate to effective income tax rate	'	'	'
Federal statutory rate	35.00%	35.00%	35.00%
State income tax, net of federal deduction	2.50%	2.50%	2.40%
Employee stock plans dividend deduction	-1.60%	-1.00%	-1.10%
Non-deductible book depreciation	1.50%	0.90%	0.70%
AFUDC-Equity	-2.60%	-1.30%	-1.50%
ITC basis difference	-1.20%	-0.30%	-0.20%
Other	-0.50%	-0.20%	-0.30%
Effective income tax rate	33.10%	35.60%	35.00%
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	2.20%	3.70%	0.60%
Amortization of ITC	-1.70%	-1.00%	-0.40%
ITC basis difference	-14.50%	-2.60%	-3.10%
Other	0.30%	-0.60%	-0.30%
Effective income tax rate	21.30%	34.50%	31.80%
Gulf Power [Member]	'	'	'
Reconciliation of federal statutory income tax rate to effective income tax rate	'	'	'
Federal statutory rate	35.00%	35.00%	35.00%
State income tax, net of federal deduction	3.50%	3.30%	2.50%
Non-deductible book depreciation	0.50%	0.50%	0.50%
Difference in prior years' deferred and current tax rate	-0.20%	-0.20%	-0.30%
AFUDC-Equity	-1.10%	-0.90%	-2.00%
Other	-0.10%	-0.20%	-0.20%
Effective income tax rate	37.60%	37.50%	35.50%
Mississippi Power [Member]	'	'	'
Reconciliation of federal statutory income tax rate to effective income tax rate	'	'	'
Federal statutory rate	35.00%	35.00%	35.00%
State income tax, net of federal deduction	3.70%	1.30%	1.90%
Non-deductible book depreciation	-0.10%	0.30%	0.30%
AFUDC-Equity	5.00%	-18.60%	-6.30%
Other	0.10%	-1.20%	-0.30%
Effective income tax rate	43.70%	16.80%	30.60%
Alabama Power [Member]	'	'	'
Reconciliation of federal statutory income tax rate to effective income tax rate	'	'	'
Federal statutory rate	35.00%	35.00%	35.00%
State income tax, net of federal deduction	4.00%	4.10%	4.30%
Non-deductible book depreciation	1.00%	0.90%	0.80%
Difference in prior years' deferred and current tax rate	-0.10%	-0.10%	-0.10%
AFUDC-Equity	-0.90%	-0.50%	-0.60%
Other	-0.10%	-0.30%	-0.40%
Effective income tax rate	38.90%	39.10%	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	2.50%	1.60%	1.50%
Non-deductible book depreciation	1.30%	1.20%	0.80%
AFUDC-Equity	-0.60%	-1.00%	-1.90%
Other	-0.40%	-0.10%	-0.50%
Effective income tax rate	37.80%	36.70%	34.90%

Income_Taxes_Changes_in_Unreco

Income Taxes - Changes in Unrecognized Tax Benefits (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in unrecognized tax benefits [Roll Forward]	'	'	'
Unrecognized tax benefits at beginning of year	$70,000,000	$120,000,000	$296,000,000
Tax positions from current periods	3,000,000	13,000,000	46,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	0	7,000,000	1,000,000
Tax positions decrease from prior periods	-66,000,000	-56,000,000	-111,000,000
Reductions due to settlements	0	-10,000,000	-112,000,000
Reductions due to expired statute of limitations	0	-4,000,000	0
Unrecognized tax benefits at end of year	7,000,000	70,000,000	120,000,000
Southern Power [Member]	'	'	'
Changes in unrecognized tax benefits [Roll Forward]	'	'	'
Unrecognized tax benefits at beginning of year	2,900,000	2,600,000	2,300,000
Tax positions from current periods	1,600,000	700,000	400,000
Tax positions decrease from prior periods	-3,000,000	-200,000	-100,000
Reductions due to settlements	0	-200,000	0
Unrecognized tax benefits at end of year	1,500,000	2,900,000	2,600,000
Gulf Power [Member]	'	'	'
Changes in unrecognized tax benefits [Roll Forward]	'	'	'
Unrecognized tax benefits at beginning of year	5,007,000	2,892,000	3,870,000
Tax positions from current periods	45,000	2,630,000	540,000
Tax positions decrease from prior periods	-5,007,000	515,000	-1,518,000
Reductions due to settlements	0	-1,030,000	0
Unrecognized tax benefits at end of year	45,000	5,007,000	2,892,000
Mississippi Power [Member]	'	'	'
Changes in unrecognized tax benefits [Roll Forward]	'	'	'
Unrecognized tax benefits at beginning of year	5,755,000	4,964,000	4,288,000
Tax positions from current periods	226,000	1,186,000	1,486,000
Tax positions decrease from prior periods	-2,141,000	-26,000	-810,000
Reductions due to settlements	0	-369,000	0
Unrecognized tax benefits at end of year	3,840,000	5,755,000	4,964,000
Alabama Power [Member]	'	'	'
Changes in unrecognized tax benefits [Roll Forward]	'	'	'
Unrecognized tax benefits at beginning of year	31,000,000	32,000,000	43,000,000
Tax positions from current periods	0	5,000,000	6,000,000
Tax positions decrease from prior periods	-31,000,000	-4,000,000	-17,000,000
Reductions due to settlements	0	-2,000,000	0
Unrecognized tax benefits at end of year	0	31,000,000	32,000,000
Georgia Power [Member]	'	'	'
Changes in unrecognized tax benefits [Roll Forward]	'	'	'
Unrecognized tax benefits at beginning of year	23,000,000	47,000,000	237,000,000
Tax positions from current periods	0	3,000,000	9,000,000
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	0	3,000,000	0
Tax positions decrease from prior periods	-23,000,000	-19,000,000	-87,000,000
Reductions due to settlements	0	-8,000,000	-112,000,000
Reductions due to expired statute of limitations	0	-3,000,000	0
Unrecognized tax benefits at end of year	$0	$23,000,000	$47,000,000

Income_Taxes_Impact_of_Unrecog

Income Taxes - Impact of Unrecognized Tax Benefits on Effective Tax Rate, If Recognized (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Impact on effective tax rate	'	'	'	'
Tax positions impacting the effective tax rate	$7,000	$5,000	$69,000	'
Tax positions not impacting the effective tax rate	0	65,000	51,000	'
Balance of unrecognized tax benefits	7,000	70,000	120,000	296,000
Alabama Power [Member]	'	'	'	'
Impact on effective tax rate	'	'	'	'
Tax positions impacting the effective tax rate	0	0	5,000	'
Tax positions not impacting the effective tax rate	0	31,000	27,000	'
Balance of unrecognized tax benefits	0	31,000	32,000	43,000
Georgia Power [Member]	'	'	'	'
Impact on effective tax rate	'	'	'	'
Tax positions impacting the effective tax rate	0	0	28,000	'
Tax positions not impacting the effective tax rate	0	23,000	19,000	'
Balance of unrecognized tax benefits	0	23,000	47,000	237,000
Gulf Power [Member]	'	'	'	'
Impact on effective tax rate	'	'	'	'
Tax positions impacting the effective tax rate	45	45	1,804	'
Tax positions not impacting the effective tax rate	0	4,962	1,088	'
Balance of unrecognized tax benefits	45	5,007	2,892	3,870
Mississippi Power [Member]	'	'	'	'
Impact on effective tax rate	'	'	'	'
Tax positions impacting the effective tax rate	3,840	3,656	4,144	'
Tax positions not impacting the effective tax rate	0	2,099	820	'
Balance of unrecognized tax benefits	3,840	5,755	4,964	4,288
Southern Power [Member]	'	'	'	'
Impact on effective tax rate	'	'	'	'
Tax positions impacting the effective tax rate	1,500	300	500	'
Tax positions not impacting the effective tax rate	0	2,600	2,100	'
Balance of unrecognized tax benefits	$1,500	$2,900	$2,600	$2,300

Income_Taxes_Accrued_Interest_

Income Taxes - Accrued Interest for Unrecognized Tax Benefits (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Accrued Interest For Unrecognized Tax Benefits [Roll Forward]	'	'	'
Interest accrued at beginning of year	$1,000,000	$10,000,000	$29,000,000
Interest reclassified due to settlements	0	-9,000,000	-24,000,000
Interest accrued during the period	0	0	5,000,000
Balance at end of year	1,000,000	1,000,000	10,000,000
Alabama Power [Member]	'	'	'
Reconciliation of Accrued Interest For Unrecognized Tax Benefits [Roll Forward]	'	'	'
Interest accrued at beginning of year	0	1,900,000	1,500,000
Interest reclassified due to settlements	0	-1,900,000	0
Interest accrued during the period	0	0	400,000
Balance at end of year	0	0	1,900,000
Georgia Power [Member]	'	'	'
Reconciliation of Accrued Interest For Unrecognized Tax Benefits [Roll Forward]	'	'	'
Interest accrued at beginning of year	0	6,000,000	27,000,000
Interest reclassified due to settlements	0	-6,000,000	-24,000,000
Interest accrued during the period	0	0	3,000,000
Balance at end of year	0	0	6,000,000
Mississippi Power [Member]	'	'	'
Reconciliation of Accrued Interest For Unrecognized Tax Benefits [Roll Forward]	'	'	'
Interest accrued at beginning of year	772,000	680,000	413,000
Interest accrued during the period	399,000	92,000	267,000
Balance at end of year	$1,171,000	$772,000	$680,000

Income_Taxes_Textual_Details

Income Taxes - Textual (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jan. 02, 2013
Income Tax Disclosure [Line Items]	'	'	'	'	'
Net cash payments/(refunds) for income taxes	$139,000,000	$38,000,000	($401,000,000)	'	'
Net operating loss carryforward	707,000,000	'	'	'	'
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward	41,000,000	'	'	'	'
Deferred tax assets	3,624,000,000	3,972,000,000	'	'	'
Tax Credit Carryforward, Amount	28,000,000	'	'	'	'
State Investment Tax Credit	118,000,000	'	'	'	'
Tax regulatory assets	1,400,000,000	'	'	'	'
Tax regulatory liabilities	202,000,000	'	'	'	'
Amortization of deferred investment tax credits	16,000,000	23,000,000	19,000,000	'	'
Unamortized investment tax credits	966,000,000	894,000,000	'	'	'
Percentage of additional bonus depreciation for property acquired	100.00%	'	'	'	'
Percentage of extension bonus depreciation for property acquired	50.00%	'	'	'	'
Balance of unrecognized tax benefits	7,000,000	70,000,000	120,000,000	296,000,000	'
Alabama Power [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Net cash payments/(refunds) for income taxes	296,000,000	309,000,000	-139,000,000	'	'
Deferred tax assets	938,000,000	1,040,000,000	'	'	'
Tax regulatory assets	519,000,000	'	'	'	'
Tax regulatory liabilities	75,000,000	'	'	'	'
Amortization of deferred investment tax credits	8,000,000	8,000,000	8,000,000	'	'
Unamortized investment tax credits	133,000,000	141,000,000	'	'	'
Percentage of additional bonus depreciation for property acquired	100.00%	'	'	'	'
Percentage of extension bonus depreciation for property acquired	50.00%	'	'	'	'
Balance of unrecognized tax benefits	0	31,000,000	32,000,000	43,000,000	'
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern	'12 months	'	'	'	'
Georgia Power [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Net cash payments/(refunds) for income taxes	298,000,000	312,000,000	54,000,000	'	'
Deferred tax assets	1,464,000,000	1,656,000,000	'	'	'
State Investment Tax Credit	27,000,000	36,000,000	53,000,000	'	'
Tax regulatory assets	722,000,000	'	'	'	'
Tax regulatory liabilities	112,000,000	'	'	'	'
Regulatory Liabilities	'	'	62,000,000	'	'
Amortization of deferred investment tax credits	5,000,000	13,000,000	9,000,000	'	'
Federal Tax Credits	3,000,000	'	'	'	'
State Investment Tax Credit Carryforward	118,000,000	'	'	'	'
Unamortized investment tax credits	203,000,000	208,000,000	'	'	'
Percentage of additional bonus depreciation for property acquired	100.00%	'	'	'	'
Percentage of extension bonus depreciation for property acquired	50.00%	'	'	'	'
Balance of unrecognized tax benefits	0	23,000,000	47,000,000	237,000,000	'
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern	'12 months	'	'	'	'
Gulf Power [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Net cash payments/(refunds) for income taxes	-10,727,000	-96,639,000	-26,345,000	'	'
Deferred tax assets	133,006,000	157,901,000	'	'	'
Tax regulatory assets	50,900,000	'	'	'	'
Tax regulatory liabilities	5,200,000	'	'	'	'
Amortization of deferred investment tax credits	1,400,000	1,400,000	1,300,000	'	'
Unamortized investment tax credits	4,055,000	5,408,000	'	'	'
Percentage of additional bonus depreciation for property acquired	100.00%	'	'	'	'
Percentage of extension bonus depreciation for property acquired	50.00%	'	'	'	'
Balance of unrecognized tax benefits	45,000	5,007,000	2,892,000	3,870,000	'
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern	'12 months	'	'	'	'
Mississippi Power [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Net cash payments/(refunds) for income taxes	-134,198,000	-77,580,000	-41,024,000	'	'
Deferred tax assets	673,467,000	449,671,000	'	'	'
Tax Credit Carryforward, Amount	276,400,000	'	'	'	'
Tax regulatory assets	144,400,000	'	'	'	'
Tax regulatory liabilities	10,200,000	'	'	'	'
Regulatory Liabilities	98,100,000	'	'	'	'
Amortization of deferred investment tax credits	1,200,000	1,200,000	1,300,000	'	'
Unamortized investment tax credits	284,248,000	370,554,000	'	'	'
Minimum Percentage of Carbon Dioxide That Must Capture and Sequester to Remain Eligible for Tax Credits	65.00%	'	'	'	'
Percentage of additional bonus depreciation for property acquired	100.00%	'	'	'	'
Percentage of extension bonus depreciation for property acquired	50.00%	'	'	'	'
Reduction in income tax expense, investment tax credits	-144,036,000	-82,464,000	0	'	'
Balance of unrecognized tax benefits	3,840,000	5,755,000	4,964,000	4,288,000	'
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern	'12 months	'	'	'	'
Mississippi Power [Member] | Kemper IGCC [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Unamortized investment tax credits	276,400,000	'	'	'	'
Mississippi Power [Member] | Investment tax credit carryforward [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Deferred tax assets	0	170,938,000	'	'	'
Southern Power [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Net cash payments/(refunds) for income taxes	-226,179,000	-175,269,000	-26,486,000	'	'
Deferred Tax Asset, Reimbursable	2,600,000	'	'	'	'
Net operating loss carryforward	240,800,000	117,700,000	'	'	'
Deferred tax assets	127,700,000	91,700,000	'	'	'
Increase (decrease) in deferred tax assets valuation allowance	18,600,000	'	'	'	'
Operating Loss Carryforwards In Year Three	87,000,000	'	'	'	'
Operating Loss Carryforwards In Year Four	40,000,000	'	'	'	'
Operating Loss Carryforwards In Year Five	107,000,000	'	'	'	'
Percentage of additional bonus depreciation for property acquired	'	'	'	100.00%	'
Percentage of extension bonus depreciation for property acquired	50.00%	50.00%	'	'	'
Reduction in income tax expense, investment tax credits	-158,096,000	-45,047,000	-84,723,000	'	'
Balance of unrecognized tax benefits	1,500,000	2,900,000	2,600,000	2,300,000	'
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern	'12 months	'	'	'	'
Positive Impact From Bonus Depreciation	'	'	'	'	98,900,000
Southern Power [Member] | Accounts Payable - Affiliated Companies [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Deferred Tax Asset, Reimbursable	1,000,000	'	'	'	'
Southern Power [Member] | Georgia Power [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Deferred Tax Liability, Reimbursable	2,800,000	'	'	'	'
Southern Power [Member] | Georgia Power [Member] | Receivables - Affiliated Companies [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Deferred Tax Liability, Reimbursable	300,000	'	'	'	'
Southern Power [Member] | Operating Loss Carryforward [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Deferred tax assets	11,000,000	5,400,000	'	'	'
Southern Power [Member] | Investment tax credit carryforward [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Deferred tax assets	58,000,000	28,600,000	'	'	'
Southern Power [Member] | Investment tax credit carryforward [Member] | Nacogdoches Biomass Generating Plant [Member]	'	'	'	'	'
Income Tax Disclosure [Line Items]	'	'	'	'	'
Tax credit carryforward	158,100,000	45,000,000	84,700,000	42,900,000	'
Reduction in income tax expense, investment tax credits	$31,300,000	$6,900,000	$7,300,000	'	'

Financing_Scheduled_Maturities

Financing - Scheduled Maturities and Redemptions of Securities Due Within One Year (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

4.92% Redeemable Preferred Stock [Member]

4.72% Redeemable Preferred Stock [Member]

4.64% Redeemable Preferred Stock [Member]

4.60% Redeemable Preferred Stock [Member]

4.52% Redeemable Preferred Stock [Member]

4.20% Redeemable Preferred Stock [Member]

5.83% Class A Preferred Stock [Member]

5.20% Class A Preferred Stock [Member]

5.30% Class A Preferred Stock [Member]

5.625% Preference Stock [Member]

6.450% Preference Stock [Member]

6.500% Preference Stock [Member]

Redeemable Preferred/Preference Stock [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redeemable Preferred Stock/Preference Stock dividend rate percentage

'

'

'

'

0.0492

0.0472

0.0464

0.046

0.0452

0.042

0.0583

0.052

0.053

0.05625

0.0645

0.065

'

'

'

'

Par Value/Stated Capital Per Share

'

'

'

'

$100

[1]

$100

[1]

$100

[1]

$100

[1]

$100

[1]

$100

[1]

$25

$25

$25

$25

$25

[1],[2]

$25

[1],[2]

'

'

'

'

Temporary Equity, Shares Outstanding

'

'

'

'

80,000

[1]

50,000

[1]

60,000

[1]

100,000

[1]

50,000

[1]

135,115

[1]

1,520,000

6,480,000

4,000,000

6,000,000

6,000,000

[1],[2]

2,000,000

[1],[2]

'

'

334,210

334,210

Redemption Price Per Share

'

'

'

'

$103.23

[1]

$102.18

[1]

$103.14

[1]

$104.20

[1]

$102.93

[1]

$105

[1]

'

'

'

'

'

'

'

'

'

'

Scheduled maturities and redemptions of securities due within one year

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior notes

$428,000,000

$2,085,000,000

'

$250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

$0

$1,675,000,000

$0

$50,000,000

Other long-term debt

12,000,000

227,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capitalized leases

29,000,000

23,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,000,000

5,000,000

2,500,000

0

Pollution control revenue bonds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,300,000

51,500,000

Bank term loans

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

175,000,000

Total

$469,000,000

$2,335,000,000

$0

$250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

$5,000,000

$1,680,000,000

$13,789,000

$276,471,000

[1]

Redemption permitted any time after issuance

[2]

Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital

Financing_Committed_Credit_Arr

Financing - Committed Credit Arrangements With Banks (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Credit arrangements by company	'
Expires, 2014	$558	[1]
Expires, 2015	60	[1]
Expires, 2016	480	[1]
Expires, 2018	4,130	[1]
Total	5,228
Unused	5,214
Executable Term-Loans, One Year	148
Executable Term-Loans, Two Years	40
Due Within One Year, Term Out	188
Due Within One Year, No Term Out	370
Southern Company [Member]	'
Credit arrangements by company	'
Expires, 2014	0	[1]
Expires, 2015	0	[1]
Expires, 2016	0	[1]
Expires, 2018	1,000	[1]
Total	1,000
Unused	1,000
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Alabama Power [Member]	'
Credit arrangements by company	'
Expires, 2014	238	[1],[2]
Expires, 2015	35	[1],[2]
Expires, 2016	0	[1]
Expires, 2018	1,030	[1],[2]
Total	1,303
Unused	1,303
Executable Term-Loans, One Year	53
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	53
Due Within One Year, No Term Out	185
Georgia Power [Member]	'
Credit arrangements by company	'
Expires, 2014	0	[1]
Expires, 2015	0	[1]
Expires, 2016	150	[1],[3]
Expires, 2018	1,600	[1],[3]
Total	1,750
Unused	1,736
Executable Term-Loans, One Year	0
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Gulf Power [Member]	'
Credit arrangements by company	'
Expires, 2014	110	[1],[4]
Expires, 2015	0	[1]
Expires, 2016	165	[1],[4]
Expires, 2018	0	[1]
Total	275
Unused	275
Executable Term-Loans, One Year	45
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	45
Due Within One Year, No Term Out	65
Mississippi Power [Member]	'
Credit arrangements by company	'
Expires, 2014	135	[1],[4]
Expires, 2015	0	[1]
Expires, 2016	165	[1],[4]
Expires, 2018	0	[1]
Total	300
Unused	300
Executable Term-Loans, One Year	25
Executable Term-Loans, Two Years	40
Due Within One Year, Term Out	65
Due Within One Year, No Term Out	70
Southern Power [Member]	'
Credit arrangements by company	'
Expires, 2014	0	[1]
Expires, 2015	0	[1]
Expires, 2016	0	[1]
Expires, 2018	500	[1]
Total	500
Unused	500
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, 2014	75	[1]
Expires, 2015	25	[1]
Expires, 2016	0	[1]
Expires, 2018	0	[1]
Total	100
Unused	100
Executable Term-Loans, One Year	25
Executable Term-Loans, Two Years	0
Due Within One Year, Term Out	25
Due Within One Year, No Term Out	$50
[1]	No credit arrangements expire in 2017.
[2]	No credit arrangements expire in 2016 or 2017.
[3]	No credit arrangements expire in 2014, 2015, or 2017
[4]	No credit arrangements expire in 2015, 2017, or 2018.

Financing_Shortterm_Borrowings

Financing - Short-term Borrowings (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Short-term borrowings	'		'
Short-term Debt at the End of the Period, Amount Outstanding	$1,482,000,000	[1]	$820,000,000	[1]
Short-term Debt at the End of the Period, Weighted Average Interest Rate	0.40%	[1]	0.30%	[1]
Commercial paper [Member]	'		'
Short-term borrowings	'		'
Short-term Debt at the End of the Period, Amount Outstanding	1,082,000,000	[1]	820,000,000	[1]
Short-term Debt at the End of the Period, Weighted Average Interest Rate	0.20%	[1]	0.30%	[1]
Short-term bank debt [Member]	'		'
Short-term borrowings	'		'
Short-term Debt at the End of the Period, Amount Outstanding	400,000,000	[1]	0	[1]
Short-term Debt at the End of the Period, Weighted Average Interest Rate	0.90%	[1]	0.00%	[1]
Other Energy Service Contracts [Member]	'		'
Short-term borrowings	'		'
Notes Payable, Related Parties	'		5,000,000
Georgia Power [Member]	'		'
Short-term borrowings	'		'
Short-term Debt at the End of the Period, Amount Outstanding	1,047,000,000		'
Short-term Debt at the End of the Period, Weighted Average Interest Rate	0.50%		'
Debt Instrument, Face Amount	850,000,000		'
Georgia Power [Member] | Commercial paper [Member]	'		'
Short-term borrowings	'		'
Short-term Debt at the End of the Period, Amount Outstanding	647,000,000		'
Short-term Debt at the End of the Period, Weighted Average Interest Rate	0.20%		'
Georgia Power [Member] | Short-term bank debt [Member]	'		'
Short-term borrowings	'		'
Short-term Debt at the End of the Period, Amount Outstanding	400,000,000		'
Short-term Debt at the End of the Period, Weighted Average Interest Rate	0.90%		'
Gulf Power [Member] | Commercial paper [Member]	'		'
Short-term borrowings	'		'
Short-term Debt at the End of the Period, Amount Outstanding	136,000,000	[2]	124,000,000	[2]
Short-term Debt at the End of the Period, Weighted Average Interest Rate	0.20%	[2]	0.30%	[2]
Gulf Power [Member] | Other Energy Service Contracts [Member]	'		'
Short-term borrowings	'		'
Notes Payable, Related Parties	'		3,200,000
Mississippi Power [Member]	'		'
Short-term borrowings	'		'
Taxable Revenue Bonds	11,300,000		51,500,000
Southern Power [Member] | Commercial paper [Member]	'		'
Short-term borrowings	'		'
Short-term Debt at the End of the Period, Amount Outstanding	$0		$71,000,000
Short-term Debt at the End of the Period, Weighted Average Interest Rate	'		0.50%
[1]	Excludes notes payable related to other energy service contracts of $5 million at December 31, 2012.
[2]	Excludes notes payable related to other energy service contracts of $3.2 million for the period ended December 31, 2012.

Financing_Textual_Details

Financing - Textual (Details) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

2 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

2 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Feb. 20, 2014

Nov. 30, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Feb. 20, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Feb. 20, 2014

Feb. 20, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

Feb. 28, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Feb. 27, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

31-May-13

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2013

Jul. 15, 2013

Jul. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Nov. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Feb. 28, 2013

Dec. 31, 2011

Dec. 31, 2013

Sep. 30, 2013

Mar. 31, 2013

Jan. 31, 2013

Nov. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 19, 2013

Mar. 31, 2012

Feb. 27, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2011

Oct. 20, 2011

Dec. 31, 2011

Nov. 30, 2013

Nov. 30, 2013

Sep. 30, 2013

Jul. 31, 2013

Mar. 31, 2013

Nov. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

Nov. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Trust Preferred Securities Subject to Mandatory Redemption [Member]

Trust Preferred Securities Subject to Mandatory Redemption [Member]

Senior Notes [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Georgia Power [Member]

Subsidiaries [Member]

Subsidiaries [Member]

Subsidiaries [Member]

Subsidiaries [Member]

Southern Power and Traditional Operating Companies [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Gulf Power [Member]

Southern Company [Member]

Southern Company [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Alabama Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Southern Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Mississippi Power [Member]

Southern Company And Subsidiaries [Member]

Alabama Power and Gulf Power [Member]

Traditional Operating Companies [Member]

Traditional Operating Companies [Member]

Notes due April 30, 2033 [Member]

Notes due September 30, 2032 [Member]

loan

loan

Subsequent Event [Member]

Corporate, Non-Segment [Member]

Corporate, Non-Segment [Member]

Issued and Repurchased [Member]

Line of Credit [Member]

Line of Credit [Member]

Capital Lease Obligations [Member]

Capital Lease Obligations [Member]

Secured Debt [Member]

Secured Debt [Member]

Bank Loan Obligations [Member]

Senior Notes [Member]

Plant Vogtle Units 3 And 4 [Member]

Capital Lease Obligations [Member]

Capital Lease Obligations [Member]

Senior Notes [Member]

series

Subsequent Event [Member]

Minimum [Member]

Maximum [Member]

Plant Daniel [Member]

Senior Notes [Member]

First Series 2002 [Member]

First Series 2010 [Member]

Series Two Thousand Twelve [Member]

Series 2013A [Member]

Series G [Member]

Series H [Member]

Natural Gas Pipeline [Member]

Trust Preferred Securities Subject to Mandatory Redemption [Member]

Trust Preferred Securities Subject to Mandatory Redemption [Member]

Senior Notes And Pollution Control Bond [Member]

Secured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Series B 6.25% Senior Notes due July 15, 2012 [Member]

Series 2013A [Member]

loan

Subsequent Event [Member]

Subsequent Event [Member]

Kemper IGCC [Member]

Plant Daniel Units 3 and 4 [Member]

Plant Daniel Units 3 and 4 [Member]

Revenue Bonds [Member]

Series Two 2008A [Member]

Revenue Bonds [Member]

Revenue Bonds [Member]

Revenue Bonds [Member]

Revenue Bonds [Member]

Revenue Bonds [Member]

Revenue Bonds [Member]

Revenue Bonds [Member]

Capital Lease Obligations [Member]

Senior Notes [Member]

Senior Notes [Member]

Secured Debt [Member]

Southern Power [Member]

Southern Power [Member]

Debt Due 2029 [Member]

Debt Due 2044 [Member]

Subsequent Event [Member]

Minimum [Member]

Maximum [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012A [Member]

Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012A [Member]

Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012A [Member]

Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012A [Member]

Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012B [Member]

Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012B [Member]

Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012C [Member]

Series Two 2008A [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Financing (Textual) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from issuance of junior subordinated notes

$206,000,000

$206,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$206,000,000

$206,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred securities, outstanding

'

'

'

200,000,000

200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000,000

200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Prepayment of debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Promissory Note

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

19,400,000

4,200,000

Senior notes, current

428,000,000

2,085,000,000

'

'

'

'

'

'

'

0

1,675,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long term debt and capital lease obligations, maturities in 2014

'

'

'

'

'

'

'

'

'

5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long term debt and capital lease obligations, maturities in 2014

469,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long term debt and capital lease obligations, maturities in 2015

2,970,000,000

'

'

'

'

'

'

'

'

1,100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

527,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long term debt and capital lease obligations, maturities in 2016

1,830,000,000

'

'

'

'

'

'

'

'

710,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

302,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four

1,140,000,000

'

'

'

'

'

'

'

'

457,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long term debt and capital lease obligations, maturities in 2018

880,000,000

'

'

'

'

'

'

'

'

277,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

428,000,000

434,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75,000,000

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt maturities, 2015

2,375,000,000

2,375,000,000

'

'

'

'

'

'

'

1,050,000,000

1,050,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000,000

400,000,000

'

'

'

'

454,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt maturities, 2016

1,360,000,000

1,360,000,000

'

'

'

'

'

'

'

250,000,000

250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

110,000,000

110,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000,000

200,000,000

'

'

'

'

200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000,000

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt maturities, 2017

1,095,000,000

1,095,000,000

'

'

'

'

'

'

'

450,000,000

450,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

85,000,000

85,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

525,000,000

525,000,000

'

'

'

'

561,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35,000,000

35,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Maturities, Repayments of Principal in Year Five

850,000,000

250,000,000

'

'

'

'

'

'

'

250,000,000

250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Description of variable rate basis

'one-month

'

'

'

'

'

'

'

'one-month

'one-month

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'one-month

'one-month

'

'one-month

'

'one-month

'

'

'

'

'one-month

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Bank Loans

'

'

'

'

'

'

'

'

'

400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000,000

'

'

525,000,000

175,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Principal Amount of Floating Rate Bank Loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

550,000,000

'

'

'

Bank loans, period of extension

'

'

'

'

'

'

'

'4 months

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'90 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'2 years

'2 years

'

'366 days

'366 days

'

'

'

'

'18 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate Principal Amount Of Floating Rate Bank Loan

'

'

'

'

'

'

'

400,000,000

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

125,000,000

'

'

100,000,000

'

'

'

'

'

250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

First Advance On Bank Loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Second Advance On Bank Loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Bank Loans

'

'

'

'

'

'

'

3

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayment Aggregate Principal Amount Of Floating Rate Bank Loan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

125,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Bank loans outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

525,000,000

175,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Ratio of indebtedness to capitalization, debt covenant, required

65.00%

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent Of Eligible Project Costs To Be Reimbursed

'

'

'

'

'

'

'

'

'

'

'

'

70.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Eligible Project Costs To Be Reimbursed

'

'

'

'

'

'

'

'

'

'

'

'

3,460,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Jointly Owned Utility Plant, Proportionate Ownership Share

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45.70%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Basis Spread on Variable Rate

'

'

'

'

'

'

'

'

'

'

'

'

0.38%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Amount Outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Amount Available to Support Variable Rate Pollution Control Revenue Bonds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

69,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Amount Available for Commercial Paper Program and General Corporate Purposes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

206,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

'

'

'

'

'

500,000,000

'

'

'

850,000,000

'

'

'

'

'

'

500,000,000

500,000,000

'

'

'

'

'

'

'

'

'

'

'

1,600,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

90,000,000

'

'

'

'

'

'

'

'

'

'

'

'

300,000,000

'

'

'

'

'

'

'

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,250,000

'

'

'

'

2,100,000,000

'

'

'

'

'

Payments of Debt Issuance Costs

'

'

'

'

'

'

67,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unsecured Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000,000

1,800,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption Amount of Principal Notes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

125,000,000

'

'

'

'

60,000,000

30,000,000

'

'

'

'

'

'

'

'

'

'

'

250,000,000

'

'

'

19,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior Notes outstanding

17,300,000,000

17,400,000,000

'

'

'

'

'

'

'

6,900,000,000

7,900,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

945,000,000

945,000,000

'

'

'

'

'

'

'

'

'

'

'

'

1,800,000,000

1,300,000,000

'

'

'

'

'

'

'

'

4,900,000,000

'

4,800,000,000

1,600,000,000

1,300,000,000

'

'

'

'

'

'

'

'

1,100,000,000

1,100,000,000

'

'

'

'

'

'

'

'

'

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Current Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

275,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Secured Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

41,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45,000,000

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

153,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amortization Period For Line Of Credit Facility

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Pollution control revenue bonds, outstanding

'

'

'

'

'

'

'

'

'

1,700,000,000

1,800,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

296,000,000

309,000,000

'

'

'

'

41,000,000

'

42,000,000

21,000,000

13,000,000

'

'

'

'

'

1,200,000,000

1,200,000,000

'

'

'

'

'

153,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

82,700,000

82,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

194,000,000

3,200,000,000

3,400,000,000

'

'

Aggregate Pollution Control Revenue Bond

'

'

'

'

'

'

'

'

'

194,000,000

'

'

'

'

'

104,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption Amount of Principal

'

'

'

'

'

'

'

'

'

194,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue bond obligations face value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

270,000,000

'

'

'

'

'

270,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fixed stated interest rate of debt obligation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.49%

3.86%

7.90%

7.90%

'

'

'

'

'

'

'

1.40%

3.20%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.00%

4.35%

5.25%

'

'

'

'

'

6.90%

'

'

'

'

'

'

'

'

'

'

'

6.25%

5.25%

'

'

'

'

9.93%

9.97%

7.13%

'

'

'

'

'

'

7.13%

7.13%

'

'

'

'

'

'

'

'

4.90%

6.00%

'

'

'

'

'

'

Repayments of Senior Debt

'

'

'

'

'

'

'

'

'

1,775,000,000

850,000,000

427,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

90,000,000

91,363,000

608,000

'

'

'

'

'

'

'

'

'

'

'

'

'

250,000,000

950,000,000

750,000,000

'

'

'

'

'

'

'

'

0

0

575,000,000

'

575,000,000

'

'

'

'

'

50,000,000

90,000,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Significant Acquisitions and Disposals, Acquisition Costs, Assumption of Debt, at Fair Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

346,100,000

346,051,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value adjustment at date of purchase

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

76,100,000

76,051,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount, Authorized to Issue

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

33,750,000

40,070,000

15,300,000

15,800,000

11,250,000

21,250,000

21,250,000

'

'

'

'

'

'

'

'

Other revenue bond obligation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Taxable Revenue Bonds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,300,000

51,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period Of Nitrogen Supply Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capitalized lease obligations

163,000,000

80,000,000

'

'

'

'

'

'

'

45,000,000

50,000,000

'

'

61,000,000

61,000,000

'

'

'

'

'

'

'

'

'

'

30,000,000

30,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,000,000

0

'

5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

82,217,000

0

'

'

'

'

'

82,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capital leases, due 2014

0

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capital leases, due 2015

20,000,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capital leases, due 2016

26,000,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capital leases, due 2017

27,000,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capital leases, due 2018

27,000,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capital leases, due 2019 and thereafter

541,000,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

23,059,000,000

21,964,000,000

'

'

'

'

'

'

'

10,970,000,000

10,431,000,000

'

'

16,000,000

11,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,211,336,000

1,168,055,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,114,000,000

7,761,000,000

'

'

'

'

'

'

'

'

'

871,963,000

786,620,000

'

'

'

'

'

'

'

'

1,095,352,000

1,065,474,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deposit Received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

150,000,000

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum Period to Refund Deposit upon Termination of Asset Purchase Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum Period of Discretion

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchased price of plant

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

85,000,000

84,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of Principal obligation assumed under Lease

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

270,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenue Bond Obligations Fair Value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

346,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unused credit with banks

5,214,000,000

'

'

'

'

'

'

'

'

1,736,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

275,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000,000

'

1,303,000,000

'

'

'

'

'

'

'

'

'

'

500,000,000

'

'

'

'

'

'

'

'

'

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support

1,800,000,000

'

'

'

'

'

'

'

'

862,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

793,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

40,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Remarketed pollution control bonds

442,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Pollution Control Revenue Bonds Required To Be Remarketed

'

'

'

'

'

'

'

'

'

242,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Short-term debt outstanding, regulatory approved maximum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redeemable preferred stock, redemption period

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price of redeemable preferred stock, as a percent of liquidation amount

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Shares Issued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000

400,000

'

'

'

500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Dividend Rate, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.60%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Issuance of preference stock

50,000,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50,000,000

40,000,000

50,000,000

0

0

50,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Issuance Pollution Control Revenue Bonds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Short-term Debt

1,482,000,000

825,000,000

'

'

'

'

'

'

'

1,047,000,000

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

135,878,000

127,002,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

70,968,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Short-term borrowings related to other energy service contracts

'

'

'

'

'

'

'

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deposit Liability, Current

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$150,000,000

$75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum Period to Refund Deposit, Upon Notification, Due to Not Meeting Minimum Credit Rating

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment fee percentage (less than 1/4 of 1%)

0.25%

'

'

'

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.25%

'

'

'

'

'

'

'

'

'

'

0.25%

'

'

'

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0.25%

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Projected cash flows from fixed price PPAs, as a percentage of total projected cash flows for the next 12 months

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80.00%

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Ratio of indebtedness to capitalization, actual, end of period

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60.00%

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[1]

A total of $1.3 billion of biomass PPAs included under the non-affiliate capital and operating leases is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.

Commitments_Estimated_Longterm

Commitments - Estimated Long-term obligations (Details) (USD $)	Dec. 31, 2013
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	$101,000,000
2015	75,000,000
2016	65,000,000
2017	44,000,000
2018	31,000,000
2019 and thereafter	135,000,000
Total	451,000,000
Minimum Lease Payments, Capital Leases [Abstract]	'
2014	0	[1]
2015	20,000,000	[1]
2016	26,000,000	[1]
2017	27,000,000	[1]
2018	27,000,000	[1]
2019 and thereafter	541,000,000	[1]
Total	641,000,000	[1]
Less: amounts representing executory costs	142,000,000	[1],[2]
Net minimum lease payments	499,000,000	[1]
Less: amounts representing interest	166,000,000	[1],[3]
Present value of net minimum lease payments	333,000,000	[1],[4]
Alabama Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	15,000,000
2015	12,000,000
2016	12,000,000
2017	6,000,000
2018	4,000,000
2019 and thereafter	15,000,000
Total	64,000,000
Georgia Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	26,000,000
2015	20,000,000
2016	13,000,000
2017	9,000,000
2018	6,000,000
2019 and thereafter	11,000,000
Total	85,000,000
Capital And Operating Leases, Future Minimum Payments Due	4,415,000,000
Capital And Operating Leases, Future Minimum Payments Due Thereafter	3,119,000,000
Capital And Operating Leases, Future Minimum Payments Due In Five Years	264,000,000
Capital And Operating Leases, Future Minimum Payments Due In Four Years	273,000,000
Capital And Operating Leases, Future Minimum Payments Due In Three Years	300,000,000
Capital And Operating Leases, Future Minimum Payments Due In Two Years	271,000,000
Capital And Operating Leases, Future Minimum Payments Due, Next Twelve Months	188,000,000
Minimum Lease Payments, Capital Leases [Abstract]	'
Capital Leases, Future Minimum Payments, Lesser Of Fair Value and Present Value	482,000,000
Gulf Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	13,500,000
2015	10,000,000
2016	10,000,000
2017	600,000
Total	34,100,000
Railcars [Member] | Alabama Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	12,000,000
2015	10,000,000
2016	11,000,000
2017	6,000,000
2018	4,000,000
2019 and thereafter	15,000,000
Total	58,000,000
Vehicles And Other [Member] | Alabama Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	3,000,000
2015	2,000,000
2016	1,000,000
2017	0
2018	0
2019 and thereafter	0
Total	6,000,000
Barges and Rail Cars [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	56,000,000
2015	35,000,000
2016	30,000,000
2017	12,000,000
2018	6,000,000
2019 and thereafter	15,000,000
Total	154,000,000
Barges and Rail Cars [Member] | Georgia Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	20,000,000
2015	14,000,000
2016	8,000,000
2017	5,000,000
2018	2,000,000
2019 and thereafter	0
Total	49,000,000
Barges and Rail Cars [Member] | Gulf Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	13,300,000
2015	9,900,000
2016	9,900,000
2017	500,000
Total	33,600,000
Other Lease Payments [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	45,000,000
2015	40,000,000
2016	35,000,000
2017	32,000,000
2018	25,000,000
2019 and thereafter	120,000,000
Total	297,000,000
Other Lease Payments [Member] | Georgia Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	6,000,000
2015	6,000,000
2016	5,000,000
2017	4,000,000
2018	4,000,000
2019 and thereafter	11,000,000
Total	36,000,000
Other Lease Payments [Member] | Gulf Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	200,000
2015	100,000
2016	100,000
2017	100,000
Total	500,000
Purchased Power [Member]	'
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]	'
2014	201,000,000
2015	244,000,000
2016	260,000,000
2017	263,000,000
2018	266,000,000
2019 and thereafter	2,104,000,000
Total	3,338,000,000
Purchased Power [Member] | Alabama Power [Member]	'
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]	'
2014	36,000,000
2015	38,000,000
2016	39,000,000
2017	40,000,000
2018	42,000,000
2019 and thereafter	182,000,000
Total	377,000,000
Purchased Power [Member] | Gulf Power [Member]	'
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]	'
2014	52,900,000
2015	78,600,000
2016	78,700,000
2017	78,800,000
2018	78,900,000
2019 and thereafter	349,200,000
Total	717,100,000
Other Lease Payments [Member]	'
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract]	'
2014	21,000,000
2015	13,000,000
2016	11,000,000
2017	8,000,000
2018	7,000,000
2019 and thereafter	58,000,000
Total	118,000,000
Affiliate Capital Lease PPA [Member] | Georgia Power [Member]	'
Minimum Lease Payments, Capital Leases [Abstract]	'
2014	0
2015	22,000,000
2016	22,000,000
2017	23,000,000
2018	23,000,000
2019 and thereafter	278,000,000
Total	368,000,000
Less: amounts representing executory costs	55,000,000	[2]
Net minimum lease payments	313,000,000
Less: amounts representing interest	85,000,000	[5]
Present value of net minimum lease payments	228,000,000	[6]
Non-Affiliate Capital Lease PPA [Member] | Georgia Power [Member]	'
Minimum Lease Payments, Capital Leases [Abstract]	'
2014	0	[1]
2015	20,000,000	[1]
2016	26,000,000	[1]
2017	27,000,000	[1]
2018	27,000,000	[1]
2019 and thereafter	541,000,000	[1]
Total	641,000,000	[1]
Less: amounts representing executory costs	142,000,000	[1],[2]
Net minimum lease payments	499,000,000	[1]
Less: amounts representing interest	166,000,000	[1],[5]
Present value of net minimum lease payments	333,000,000	[1],[6]
Affiliate Operating Lease PPA [Member] | Georgia Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	55,000,000
2015	89,000,000
2016	99,000,000
2017	71,000,000
2018	62,000,000
2019 and thereafter	669,000,000
Total	1,045,000,000
Non-Affiliate Operating Lease PPA [Member] | Georgia Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	112,000,000	[1]
2015	127,000,000	[1]
2016	142,000,000	[1]
2017	144,000,000	[1]
2018	145,000,000	[1]
2019 and thereafter	1,573,000,000	[1]
Total	2,243,000,000	[1]
Minimum Lease Payments, Capital Leases [Abstract]	'
Biomass PPAs Amount	1,300,000,000
Plant Vogtle Nuclear Units 1 and 2 [Member] | Georgia Power [Member]	'
Minimum Lease Payments, Operating Leases [Abstract]	'
2014	21,000,000
2015	13,000,000
2016	11,000,000
2017	8,000,000
2018	7,000,000
2019 and thereafter	58,000,000
Total	$118,000,000
[1]	A total of $1.3 billion of biomass PPAs included under the non-affiliate capital and operating leases is contingent upon the counterparty meeting specified contract dates for posting collateral and commercial operation.
[2]	Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments.
[3]	Calculated Georgia Power's incremental borrowing rate at the inception of the leases.
[4]	When the PPAs with non-affiliates begin in 2015, Georgia Power will recognize capital lease assets and capital lease obligations totaling $333 million, equal to the lesser of the present value of the net minimum lease payments or the estimated fair value of the leased property.
[5]	Calculated at the Company's incremental borrowing rate at the inception of the leases.
[6]	When the PPAs begin in 2015, the Company will recognize capital lease assets and capital lease obligations totaling $482 million, equal to the lesser of the present value of the net minimum lease payments or the estimated fair value of the leased property.

Commitments_Details

Commitments (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Fuel expense	$5,510,000,000	$5,057,000,000	$6,262,000,000
Expense Under Purchase Power Agreements Accounted For As Operating Leases	157,000,000	171,000,000	199,000,000
Operating Leases, Rent Expense	123,000,000	155,000,000	176,000,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	101,000,000	'	'
Leasing commitment, 2015	75,000,000	'	'
Leasing commitment, 2016	65,000,000	'	'
Leasing commitment, 2017	44,000,000	'	'
Leasing commitment, 2018	31,000,000	'	'
Leasing commitment, 2019 and thereafter	135,000,000	'	'
Operating leases, future minimum lease payments due	451,000,000	'	'
Senior Notes	17,300,000,000	17,400,000,000	'
Barges and Rail Cars [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating Leases, Future Minimum Payments Due, Next Twelve Months	56,000,000	'	'
Leasing commitment, 2015	35,000,000	'	'
Leasing commitment, 2016	30,000,000	'	'
Leasing commitment, 2017	12,000,000	'	'
Leasing commitment, 2018	6,000,000	'	'
Leasing commitment, 2019 and thereafter	15,000,000	'	'
Operating leases, future minimum lease payments due	154,000,000	'	'
Alabama Power and Georgia Power [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating leases, future minimum lease payments due	59,000,000	'	'
Alabama Power [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Fuel expense	1,631,000,000	1,503,000,000	1,679,000,000
Expense Under Purchase Power Agreements Accounted For As Operating Leases	30,000,000	33,000,000	33,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share	14.00%	'	'
Operating Leases, Rent Expense	21,000,000	24,000,000	23,000,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	15,000,000	'	'
Leasing commitment, 2015	12,000,000	'	'
Leasing commitment, 2016	12,000,000	'	'
Leasing commitment, 2017	6,000,000	'	'
Leasing commitment, 2018	4,000,000	'	'
Leasing commitment, 2019 and thereafter	15,000,000	'	'
Operating leases, future minimum lease payments due	64,000,000	'	'
Long-term pollution control bonds	1,200,000,000	1,200,000,000	'
Alabama Power [Member] | Barges and Rail Cars [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating Leases, Rent Expense	18,000,000	19,000,000	18,000,000
Alabama Power [Member] | Residual Value, Leased Property [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating Leases, Future Minimum Payments Due, Next Twelve Months	8,000,000	'	'
Leasing commitment, 2015	5,000,000	'	'
Leasing commitment, 2016	4,000,000	'	'
Leasing commitment, 2018	0	'	'
Leasing commitment, 2019 and thereafter	12,000,000	'	'
Georgia Power [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Fuel expense	2,307,000,000	2,051,000,000	2,789,000,000
Capacity Payments	27,000,000	50,000,000	52,000,000
Deferred capacity expense	162,000,000	169,000,000	216,000,000
Operating Leases, Rent Expense	32,000,000	34,000,000	33,000,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	26,000,000	'	'
Percentage Of Minimum Lease Payments	100.00%	'	'
Leasing commitment, 2015	20,000,000	'	'
Leasing commitment, 2016	13,000,000	'	'
Leasing commitment, 2017	9,000,000	'	'
Leasing commitment, 2018	6,000,000	'	'
Leasing commitment, 2019 and thereafter	11,000,000	'	'
Operating leases, future minimum lease payments due	85,000,000	'	'
Long-term pollution control bonds	1,700,000,000	1,800,000,000	'
Senior Notes	6,900,000,000	7,900,000,000	'
Period Of Service For Gas Transportation Supplier	'1 year	'	'
Guarantor Obligations, Maximum Exposure, Undiscounted	43,000,000	'	'
Georgia Power [Member] | Plant McIntosh [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Period Of Service For Gas Transportation Supplier	'15 years	'	'
Georgia Power [Member] | MEAG Power [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Jointly Owned Utility Plant, Proportionate Ownership Share	5.00%	'	'
Georgia Power [Member] | Alabama Power [Member] | Payment Guarantee [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Long-term pollution control bonds	25,000,000	'	'
Georgia Power [Member] | Alabama Power [Member] | Financial Guarantee [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Senior Notes	100,000,000	'	'
Georgia Power [Member] | Barges and Rail Cars [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating Leases, Future Minimum Payments Due, Next Twelve Months	20,000,000	'	'
Leasing commitment, 2015	14,000,000	'	'
Leasing commitment, 2016	8,000,000	'	'
Leasing commitment, 2017	5,000,000	'	'
Leasing commitment, 2018	2,000,000	'	'
Leasing commitment, 2019 and thereafter	0	'	'
Operating leases, future minimum lease payments due	49,000,000	'	'
Georgia Power [Member] | Residual Value, Leased Property [Member] | 2018 [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating leases, future minimum lease payments due	30,000,000	'	'
Gulf Power [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Fuel expense	532,791,000	544,936,000	662,283,000
Expense Under Purchase Power Agreements Accounted For As Operating Leases	21,300,000	24,600,000	25,100,000
Deferred capacity expense	180,149,000	137,568,000	'
Operating Leases, Rent Expense	18,000,000	20,100,000	21,900,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	13,500,000	'	'
Number of Railcars Used Under Operating Lease	229	'	'
Leasing commitment, 2015	10,000,000	'	'
Leasing commitment, 2016	10,000,000	'	'
Leasing commitment, 2017	600,000	'	'
Operating leases, future minimum lease payments due	34,100,000	'	'
Long-term pollution control bonds	296,000,000	309,000,000	'
Senior Notes	945,000,000	945,000,000	'
Gulf Power [Member] | Plant Daniel [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Long-term pollution control bonds	41,000,000	'	'
Gulf Power [Member] | Barges and Rail Cars [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating Leases, Future Minimum Payments Due, Next Twelve Months	13,300,000	'	'
Leasing commitment, 2015	9,900,000	'	'
Leasing commitment, 2016	9,900,000	'	'
Leasing commitment, 2017	500,000	'	'
Operating leases, future minimum lease payments due	33,600,000	'	'
Gulf Power [Member] | Barges and Rail Cars [Member] | Plant Daniel [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating Leases, Future Minimum Payments Due, Next Twelve Months	1,400,000	'	'
Fuel cost recovery clause	3,100,000	3,600,000	2,600,000
Leasing commitment, 2015	1,400,000	'	'
Leasing commitment, 2016	1,400,000	'	'
Leasing commitment, 2017	1,400,000	'	'
Leasing commitment, 2018	0	'	'
Mississippi Power [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Fuel expense	491,250,000	411,226,000	490,415,000
Term of Management Fee Contract	'40 years	'	'
Management fee	38,700,000	'	'
Operating Leases, Rent Expense	10,100,000	11,100,000	32,600,000
Number of Railcars Used Under Operating Lease	229	'	'
Company's share of the leases	50.00%	'	'
Fuel cost recovery clause	3,100,000	3,600,000	2,600,000
Long-term pollution control bonds	82,700,000	82,700,000	'
Senior Notes	1,100,000,000	1,100,000,000	'
Mississippi Power [Member] | Plant Daniel [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Company's share of the leases	50.00%	'	'
Mississippi Power [Member] | Plant Watson [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Company's share of the leases	100.00%	'	'
Mississippi Power [Member] | Barges and Rail Cars [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Average leasing commitment, 2014	1,400,000	'	'
Average leasing commitment, 2015	1,400,000	'	'
Average leasing commitment, 2016	1,400,000	'	'
Average leasing commitment, 2017	1,400,000	'	'
Average leasing commitment, 2018	1,400,000	'	'
Mississippi Power [Member] | Fuel Handling Equipment [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating Leases, Rent Expense	200,000	200,000	400,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	200,000	'	'
Leasing commitment, 2015	200,000	'	'
Leasing commitment, 2016	200,000	'	'
Mississippi Power [Member] | Barge Transportation [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Operating Leases, Rent Expense	6,700,000	7,300,000	7,500,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	7,600,000	'	'
Leasing commitment, 2015	7,600,000	'	'
Leasing commitment, 2016	7,600,000	'	'
Southern Power [Member]	'	'	'
Recorded Unconditional Purchase Obligation [Line Items]	'	'	'
Fuel expense	473,805,000	426,257,000	454,790,000
Operating Leases, Rent Expense	1,900,000	800,000	600,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	2,700,000	'	'
Leasing commitment, 2015	2,500,000	'	'
Leasing commitment, 2016	2,500,000	'	'
Leasing commitment, 2017	2,500,000	'	'
Leasing commitment, 2018	2,600,000	'	'
Leasing commitment, 2019 and thereafter	83,900,000	'	'
Senior Notes	$1,600,000,000	$1,300,000,000	'

Common_Stock_and_Stock_Compens2

Common Stock and Stock Compensation - Stock Options, Assumptions Used (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	16.60%	17.70%	17.50%
Expected term (in years)	'5 years	'5 years	'5 years
Interest rate	0.90%	0.90%	2.30%
Dividend yield, percentage	4.40%	4.20%	4.80%
Weighted average grant-date fair value	$2.93	$3.39	$3.23
Performance Share Plan [Member]	'	'	'
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	12.00%	16.00%	19.20%
Expected term (in years)	'3 years	'3 years	'3 years
Interest rate	0.40%	0.40%	1.40%
Dividend yield	$1.96	$1.89	$1.82
Weighted average grant-date fair value	40.5	41.99	35.97
Alabama Power [Member]	'	'	'
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	16.60%	17.70%	17.50%
Expected term (in years)	'5 years	'5 years	'5 years
Interest rate	0.90%	0.90%	2.30%
Dividend yield, percentage	4.40%	4.20%	4.80%
Weighted average grant-date fair value	2.93	3.39	3.23
Alabama Power [Member] | Performance Share Plan [Member]	'	'	'
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	12.00%	16.00%	19.20%
Expected term (in years)	'3 years	'3 years	'3 years
Interest rate	0.40%	0.40%	1.40%
Dividend yield	$1.96	$1.89	$1.82
Weighted average grant-date fair value	40.5	41.99	35.97
Georgia Power [Member]	'	'	'
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	16.60%	17.70%	17.50%
Expected term (in years)	'5 years	'5 years	'5 years
Interest rate	0.90%	0.90%	2.30%
Dividend yield, percentage	4.40%	4.20%	4.80%
Weighted average grant-date fair value	2.93	3.39	3.23
Georgia Power [Member] | Performance Share Plan [Member]	'	'	'
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	12.00%	16.00%	19.20%
Expected term (in years)	'3 years	'3 years	'3 years
Interest rate	0.40%	0.40%	1.40%
Dividend yield	$1.96	$1.89	$1.82
Weighted average grant-date fair value	40.5	41.99	35.97
Gulf Power [Member]	'	'	'
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	16.60%	17.70%	17.50%
Expected term (in years)	'5 years	'5 years	'5 years
Interest rate	0.90%	0.90%	2.30%
Dividend yield, percentage	4.40%	4.20%	4.80%
Weighted average grant-date fair value	2.93	3.39	3.23
Gulf Power [Member] | Performance Share Plan [Member]	'	'	'
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	12.00%	16.00%	19.20%
Expected term (in years)	'3 years	'3 years	'3 years
Interest rate	0.40%	0.40%	1.40%
Dividend yield	$1.96	$1.89	$1.82
Weighted average grant-date fair value	40.5	41.99	35.97
Mississippi Power [Member] | Performance Share Plan [Member]	'	'	'
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	12.00%	16.00%	19.20%
Expected term (in years)	'3 years	'3 years	'3 years
Interest rate	0.40%	0.40%	1.40%
Dividend yield	$1.96	$1.89	$1.82
Weighted average grant-date fair value	40.5	41.99	35.97
Mississippi Power [Member] | Stock Options [Member]	'	'	'
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted	'	'	'
Expected volatility	16.60%	17.70%	17.50%
Expected term (in years)	'5 years	'5 years	'5 years
Interest rate	0.90%	0.90%	2.30%
Dividend yield, percentage	4.40%	4.20%	4.80%
Weighted average grant-date fair value	$2.93	$3.39	$3.23

Common_Stock_and_Stock_Compens3

Common Stock and Stock Compensation - Stock Option Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'
Shares Subject to Option, Outstanding, Beginning Balance	35,916,303
Shares Subject to Option, Granted	9,152,716
Shares Subject to Option, Exercised	-6,078,735
Shares Subject to Options, Cancelled	-170,918
Shares Subject to Option, Outstanding, Ending Balance	38,819,366
Shares Subject to Options, Exercisable, Ending Balance	24,150,442
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]	'
Options Outstanding, Weighted Average Exercise Price, Beginning of Period	$36.37
Options Granted, Weighted Average Exercise Price	$44.17
Options Exercised, Weighted Average Exercise Price	$33.39
Options Cancelled, Weighted Average Exercise Price	$43.30
Options Outstanding, Weighted Average Exercise Price, End of Period	$38.64
Options Exercisable, Weighted Average Exercise Price, End of Period	$35.70
Alabama Power [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'
Shares Subject to Option, Outstanding, Beginning Balance	6,060,552
Shares Subject to Option, Granted	1,319,038
Shares Subject to Option, Exercised	-1,035,611
Shares Subject to Options, Cancelled	-4,271
Shares Subject to Option, Outstanding, Ending Balance	6,339,708
Shares Subject to Options, Exercisable, Ending Balance	4,021,541
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]	'
Options Outstanding, Weighted Average Exercise Price, Beginning of Period	$36.02
Options Granted, Weighted Average Exercise Price	$44.07
Options Exercised, Weighted Average Exercise Price	$32.74
Options Cancelled, Weighted Average Exercise Price	$42.88
Options Outstanding, Weighted Average Exercise Price, End of Period	$38.23
Options Exercisable, Weighted Average Exercise Price, End of Period	$35.29
Georgia Power [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'
Shares Subject to Option, Outstanding, Beginning Balance	6,547,498
Shares Subject to Option, Granted	1,509,662
Shares Subject to Option, Exercised	-1,196,585
Shares Subject to Options, Cancelled	-11,421
Shares Subject to Option, Outstanding, Ending Balance	6,849,154
Shares Subject to Options, Exercisable, Ending Balance	4,321,853
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]	'
Options Outstanding, Weighted Average Exercise Price, Beginning of Period	$0
Options Granted, Weighted Average Exercise Price	$0
Options Exercised, Weighted Average Exercise Price	$0
Options Cancelled, Weighted Average Exercise Price	$0
Options Outstanding, Weighted Average Exercise Price, End of Period	$0
Options Exercisable, Weighted Average Exercise Price, End of Period	$0
Gulf Power [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'
Shares Subject to Option, Outstanding, Beginning Balance	1,388,915
Shares Subject to Option, Granted	285,209
Shares Subject to Option, Exercised	-281,377
Shares Subject to Options, Cancelled	0
Shares Subject to Option, Outstanding, Ending Balance	1,392,747
Shares Subject to Options, Exercisable, Ending Balance	883,985
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]	'
Options Outstanding, Weighted Average Exercise Price, Beginning of Period	$36.08
Options Granted, Weighted Average Exercise Price	$44.06
Options Exercised, Weighted Average Exercise Price	$33.62
Options Cancelled, Weighted Average Exercise Price	$0
Options Outstanding, Weighted Average Exercise Price, End of Period	$38.21
Options Exercisable, Weighted Average Exercise Price, End of Period	$35.29
Mississippi Power [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'
Shares Subject to Option, Outstanding, Beginning Balance	1,373,566
Shares Subject to Option, Granted	345,830
Shares Subject to Option, Exercised	-379,933
Shares Subject to Options, Cancelled	-5,870
Shares Subject to Option, Outstanding, Ending Balance	1,333,593
Shares Subject to Options, Exercisable, Ending Balance	898,518
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]	'
Options Outstanding, Weighted Average Exercise Price, Beginning of Period	$0
Options Granted, Weighted Average Exercise Price	$0
Options Exercised, Weighted Average Exercise Price	$0
Options Cancelled, Weighted Average Exercise Price	$0
Options Outstanding, Weighted Average Exercise Price, End of Period	$0
Options Exercisable, Weighted Average Exercise Price, End of Period	$0

Common_Stock_and_Stock_Compens4

Common Stock and Stock Compensation - Shares Used to Compute Diluted Earnings Per Share (Details)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings per Share	'	'	'
As reported shares	877	871	857
Effect of options	4	8	7
Diluted shares	881	879	864

Common_Stock_and_Stock_Compens5

Common Stock and Stock Compensation - Textual (Details) (USD $)	6 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Employee	Employee
Share-based Compensation [Abstract]	'	'	'	'
Stock Issued During Period, Shares, Southern Investment Plan and employee and director stock plans	'	6,900,000	12,100,000	'
Stock Issued During Period, Value, Southern Investment Plan and employee and director stock plans	'	$222,400,000	$397,000,000	'
Common Stock Shares Issued Previously Held In Treasury	4,400,000	'	'	'
Common Stock Previously Held In Treasury Amount	183,600,000	'	'	'
Common Stock Shares Issued Through At-The-Market Issuances	8,000,000	'	'	'
Common Stock Issued Through At-The-Market Issuances Amount	327,300,000	'	'	'
Common Stock Fees And Commissions	2,800,000	'	'	'
Share-based compensation arrangement by Share-based payment award, number of shares reserved for issuance, pursuant to Stock-based compensation plan	'	116,000,000	'	'
Number of employees participating in stock option program	5,776	5,776	'	'
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	147,000,000	147,000,000	'	'
Aggregate intrinsic value for options exercisable	142,000,000	142,000,000	'	'
Total unrecognized compensation cost related to award	9,000,000	9,000,000	'	'
Total compensation cost for award recognized in income	'	25,000,000	23,000,000	22,000,000
Total compensation cost for award recognized in income, tax benefit	'	10,000,000	9,000,000	8,000,000
Total intrinsic value of options exercised	'	77,000,000	162,000,000	155,000,000
Actual tax benefit for the tax deduction from stock option exercised	'	30,000,000	62,000,000	60,000,000
Cash received from issuance related to option exercise	'	204,000,000	397,000,000	528,000,000
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	0.00%	'	'
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	200.00%	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	16,000,000	'	'
Undistributed retained earnings of the subsidiaries	'	6,100,000,000	'	'
Performance Shares [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Stock Issued During Period, Shares, Southern Investment Plan and employee and director stock plans	'	700,000	'	'
Stock Options [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Option expiration period from date of grant	'	'10 years	'	'
Total unrecognized compensation cost related to award, weighted average period	'	'11 months	'	'
Performance Share Plan [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Total unrecognized compensation cost related to award	35,000,000	35,000,000	'	'
Total unrecognized compensation cost related to award, weighted average period	'	'11 months	'	'
Total compensation cost for award recognized in income	'	31,000,000	28,000,000	18,000,000
Total compensation cost for award recognized in income, tax benefit	'	12,000,000	11,000,000	7,000,000
Vesting period of performance share units issued under Performance Share Plan	'	'3 years	'	'
Performance share units, unvested	1,643,759	1,643,759	1,633,156	'
Performance share units, granted	'	929,653	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	'	807,702	'	'
Performance unit shares, forfeited	'	111,348	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number	240,980	240,980	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price	$41.27	$41.27	'	'
Maximum [Member] | Stock Options [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period	'	'3 years	'	'
Southern Company Common Stock [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Remaining shares available for awards	28,000,000	28,000,000	'	'
Alabama Power [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Remaining shares available for awards	28,000,000	28,000,000	'	'
Number of employees participating in stock option program	1,000	1,000	'	'
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	26,000,000	26,000,000	'	'
Aggregate intrinsic value for options exercisable	25,000,000	25,000,000	'	'
Total unrecognized compensation cost related to award	1,000,000	1,000,000	'	'
Total unrecognized compensation cost related to award, weighted average period	'	'11 months	'	'
Total compensation cost for award recognized in income	'	4,000,000	4,000,000	3,000,000
Total compensation cost for award recognized in income, tax benefit	'	2,000,000	1,000,000	1,000,000
Total intrinsic value of options exercised	'	11,000,000	28,000,000	23,000,000
Actual tax benefit for the tax deduction from stock option exercised	'	4,000,000	11,000,000	9,000,000
Alabama Power [Member] | Performance Shares [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Total unrecognized compensation cost related to award	6,000,000	6,000,000	'	'
Total unrecognized compensation cost related to award, weighted average period	'	'11 months	'	'
Total compensation cost for award recognized in income	'	5,000,000	5,000,000	3,000,000
Total compensation cost for award recognized in income, tax benefit	'	2,000,000	2,000,000	1,000,000
Vesting period of performance share units issued under Performance Share Plan	'	'3 years	'	'
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	0.00%	'	'
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	200.00%	'	'
Performance share units, unvested	284,826	284,826	280,536	'
Performance share units, granted	'	141,355	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	'	131,581	'	'
Performance unit shares, forfeited	'	5,484	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number	39,258	39,258	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price	$41.27	$41.27	'	'
Alabama Power [Member] | Stock Options [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Option expiration period from date of grant	'	'10 years	'	'
Alabama Power [Member] | Maximum [Member] | Stock Options [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period	'	'3 years	'	'
Georgia Power [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Remaining shares available for awards	28,000,000	28,000,000	'	'
Number of employees participating in stock option program	1,265	1,265	'	'
Option expiration period from date of grant	'	'10 years	'	'
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	27,000,000	27,000,000	'	'
Aggregate intrinsic value for options exercisable	26,000,000	26,000,000	'	'
Total intrinsic value of options exercised	'	16,000,000	34,000,000	32,000,000
Actual tax benefit for the tax deduction from stock option exercised	'	6,000,000	13,000,000	12,000,000
Vesting period of performance share units issued under Performance Share Plan	'	'3 years	'	'
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	0.00%	'	'
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	200.00%	'	'
Georgia Power [Member] | Performance Shares [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Vesting period of performance share units issued under Performance Share Plan	'	'3 years	'	'
Performance share units, unvested	273,100	273,100	280,000	'
Performance share units, granted	'	161,240	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	'	151,769	'	'
Performance unit shares, forfeited	'	16,371	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number	45,239	45,239	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price	$41.27	$41.27	'	'
Georgia Power [Member] | Performance Share Plan [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Total unrecognized compensation cost related to award	6,000,000	6,000,000	'	'
Total unrecognized compensation cost related to award, weighted average period	'	'11 months	'	'
Total compensation cost for award recognized in income	'	6,000,000	6,000,000	4,000,000
Total compensation cost for award recognized in income, tax benefit	'	2,000,000	2,000,000	1,000,000
Georgia Power [Member] | Maximum [Member] | Stock Options [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period	'	'3 years	'	'
Gulf Power [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Number of employees participating in stock option program	211	211	'	'
Option expiration period from date of grant	'	'10 years	'	'
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	5,700,000	5,700,000	'	'
Aggregate intrinsic value for options exercisable	5,500,000	5,500,000	'	'
Total unrecognized compensation cost related to award	400,000	400,000	'	'
Total unrecognized compensation cost related to award, weighted average period	'	'11 months	'	'
Total compensation cost for award recognized in income	'	700,000	'	'
Total compensation cost for award recognized in income, tax benefit	'	300,000	'	'
Total intrinsic value of options exercised	'	1,700,000	3,800,000	3,200,000
Actual tax benefit for the tax deduction from stock option exercised	'	600,000	1,500,000	1,200,000
Vesting period of performance share units issued under Performance Share Plan	'	'3 years	'	'
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	0.00%	'	'
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	200.00%	'	'
Gulf Power [Member] | Performance Shares [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Total unrecognized compensation cost related to award	1,200,000	1,200,000	'	'
Total compensation cost for award recognized in income	'	1,000,000	1,000,000	700,000
Total compensation cost for award recognized in income, tax benefit	'	400,000	400,000	300,000
Gulf Power [Member] | Performance Share Plan [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Total unrecognized compensation cost related to award, weighted average period	'	'11 months	'	'
Vesting period of performance share units issued under Performance Share Plan	'	'3 years	'	'
Performance share units, unvested	72,590	72,590	68,805	'
Performance share units, granted	'	30,627	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	'	25,102	'	'
Performance unit shares, forfeited	'	1,740	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number	7,476	7,476	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price	$41.27	$41.27	'	'
Gulf Power [Member] | Maximum [Member] | Stock Options [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period	'	'3 years	'	'
Gulf Power [Member] | Southern Company Common Stock [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Remaining shares available for awards	28,000,000	28,000,000	'	'
Mississippi Power [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Vesting period of performance share units issued under Performance Share Plan	'	'3 years	'	'
Mississippi Power [Member] | Performance Shares [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Total unrecognized compensation cost related to award	1,700,000	1,700,000	'	'
Total unrecognized compensation cost related to award, weighted average period	'	'11 months	'	'
Total compensation cost for award recognized in income	'	1,500,000	1,200,000	700,000
Total compensation cost for award recognized in income, tax benefit	'	600,000	400,000	300,000
Vesting period of performance share units issued under Performance Share Plan	'	'3 years	'	'
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	0.00%	'	'
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return	'	200.00%	'	'
Performance share units, unvested	41,537	41,537	68,486	'
Performance share units, granted	'	36,769	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	'	48,019	'	'
Performance unit shares, forfeited	'	15,699	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number	14,341	14,341	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price	$41.27	$41.27	'	'
Mississippi Power [Member] | Stock Options [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Remaining shares available for awards	28,000,000	28,000,000	'	'
Number of employees participating in stock option program	236	236	'	'
Option expiration period from date of grant	'	'10 years	'	'
Weighted average remaining contractual term for options outstanding	'	'6 years	'	'
Weighted average remaining contractual term for options exercisable	'	'4 years	'	'
Aggregate intrinsic value for options outstanding	4,600,000	4,600,000	'	'
Aggregate intrinsic value for options exercisable	4,400,000	4,400,000	'	'
Total unrecognized compensation cost related to award	300,000	300,000	'	'
Total unrecognized compensation cost related to award, weighted average period	'	'10 months	'	'
Total compensation cost for award recognized in income	'	1,000,000	900,000	800,000
Total compensation cost for award recognized in income, tax benefit	'	400,000	300,000	300,000
Total intrinsic value of options exercised	'	2,700,000	4,900,000	4,200,000
Actual tax benefit for the tax deduction from stock option exercised	'	$1,100,000	$1,900,000	$1,600,000
Mississippi Power [Member] | Maximum [Member] | Stock Options [Member]	'	'	'	'
Share-based Compensation [Abstract]	'	'	'	'
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period	'	'3 years	'	'

Nuclear_Insurance_Details

Nuclear Insurance (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Jointly Owned Utility Plant Interests [Line Items]	'
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act	$13,600,000,000
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant	375,000,000
Maximum amount that a company could be assessed per incident for each licensed reactor	127,000,000
Maximum aggregate amount that a reactor can assess in a calendar period for each incident	19,000,000
Block period considered for inflation adjustment against maximum assessment per reactor	'5 years
Maximum deductible waiting period	'26 weeks
Maximum coverage per occurrence per unit limit to obtain replacement power	490,000,000
Approximate period over which maximum per occurrence per unit limit is exhausted	'3 years
Aggregate payment for claims resulting from terrorist acts in one year period	3,200,000,000
Vogtle Units 3 and 4 [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Maximum limits for accidental property damage occurring during construction	2,750,000,000
Alabama Power [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act	13,600,000,000
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant	375,000,000
Maximum amount that a company could be assessed per incident for each licensed reactor	127,000,000
Maximum aggregate amount that a reactor can assess in a calendar period for each incident	19,000,000
Maximum assessment, excluding any applicable state premium taxes	255,000,000
Maximum aggregate amount to be paid in one year	38,000,000
Block period considered for inflation adjustment against maximum assessment per reactor	'5 years
Block period considered for inflation adjustment against maximum yearly assessment	'5 years
Maximum property damage insurance provided to nuclear generating facilities	500,000,000
Maximum additional coverage provided for losses under excess insurance	2,250,000,000
Maximum Sublimit Non-Nuclear Losses	1,700,000,000
Maximum deductible waiting period	'26 weeks
Maximum coverage per occurrence per unit limit to obtain replacement power	490,000,000
Approximate period over which maximum per occurrence per unit limit is exhausted	'3 years
Elected deductible waiting period	'12-week
Current maximum annual assessments under NEIL policies	43,000,000
Aggregate payment for claims resulting from terrorist acts in one year period	3,200,000,000
Georgia Power [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act	13,600,000,000
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant	375,000,000
Maximum amount that a company could be assessed per incident for each licensed reactor	127,000,000
Maximum aggregate amount that a reactor can assess in a calendar period for each incident	19,000,000
Maximum assessment, excluding any applicable state premium taxes	252,000,000
Maximum aggregate amount to be paid in one year	37,000,000
Block period considered for inflation adjustment against maximum assessment per reactor	'5 years
Block period considered for inflation adjustment against maximum yearly assessment	'5 years
Maximum property damage insurance provided to nuclear generating facilities	500,000,000
Maximum additional coverage provided for losses under excess insurance	2,250,000,000
Maximum Sublimit Non-Nuclear Losses	1,700,000,000
Maximum deductible waiting period	'26 weeks
Maximum coverage per occurrence per unit limit to obtain replacement power	490,000,000
Approximate period over which maximum per occurrence per unit limit is exhausted	'3 years
Elected deductible waiting period	'12-week
Current maximum annual assessments under NEIL policies	65,000,000
Aggregate payment for claims resulting from terrorist acts in one year period	3,200,000,000
Georgia Power [Member] | Vogtle Units 3 and 4 [Member]	'
Jointly Owned Utility Plant Interests [Line Items]	'
Maximum limits for accidental property damage occurring during construction	$2,750,000,000

Fair_Value_Measurements_Assets

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Fair Value, Measurements, Recurring [Member]	'		'
Assets:	'		'
Energy-related derivatives	$24,000,000		$26,000,000
Interest rate derivatives	3,000,000		10,000,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	491,000,000		384,000,000
Other investments	13,000,000		24,000,000
Fair value assets, total	1,994,000,000		1,746,000,000
Liabilities:	'		'
Energy-related derivatives	56,000,000		111,000,000
Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	664,000,000	[1]	518,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	231,000,000	[1]	200,000,000	[1]
Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	103,000,000	[1]	134,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	64,000,000	[1]	55,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	229,000,000	[1]	234,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	132,000,000	[1]	141,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	40,000,000	[1]	20,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Interest rate derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	491,000,000		384,000,000
Other investments	9,000,000		9,000,000
Fair value assets, total	1,124,000,000		874,000,000
Liabilities:	'		'
Energy-related derivatives	0		0
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	589,000,000	[1]	453,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	35,000,000	[1]	28,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Municipal bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Assets:	'		'
Energy-related derivatives	24,000,000		26,000,000
Interest rate derivatives	3,000,000		10,000,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	0		0
Other investments	0		0
Fair value assets, total	863,000,000		857,000,000
Liabilities:	'		'
Energy-related derivatives	56,000,000		111,000,000
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	75,000,000	[1]	65,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	196,000,000	[1]	172,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	103,000,000	[1]	134,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	64,000,000	[1]	55,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	229,000,000	[1]	234,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	132,000,000	[1]	141,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	37,000,000	[1]	20,000,000	[1]
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Interest rate derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	0		0
Other investments	4,000,000		15,000,000
Fair value assets, total	7,000,000		15,000,000
Liabilities:	'		'
Energy-related derivatives	0		0
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	3,000,000	[1]	0	[1]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member]	'		'
Assets:	'		'
Energy-related derivatives	7,000,000		5,000,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	236,000,000	[2]	'
Fair value assets, total	956,000,000		609,000,000
Liabilities:	'		'
Energy-related derivatives	8,000,000		18,000,000
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	466,000,000	[2]	355,000,000	[3]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	100,000,000	[2]	83,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	24,000,000	[2]	29,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	89,000,000	[2]	101,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	18,000,000	[2]	26,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	16,000,000	[2]	10,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	236,000,000	[2]	'
Fair value assets, total	663,000,000		319,000,000
Liabilities:	'		'
Energy-related derivatives	0		0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	392,000,000	[2]	291,000,000	[3]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	35,000,000	[2]	28,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[2]	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[2]	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[2]	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[2]	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Assets:	'		'
Energy-related derivatives	7,000,000		5,000,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	0	[2]	'
Fair value assets, total	290,000,000		290,000,000
Liabilities:	'		'
Energy-related derivatives	8,000,000		18,000,000
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	74,000,000	[2]	64,000,000	[3]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	65,000,000	[2]	55,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	24,000,000	[2]	29,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	89,000,000	[2]	101,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	18,000,000	[2]	26,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	13,000,000	[2]	10,000,000	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	0	[2]	'
Fair value assets, total	3,000,000		0
Liabilities:	'		'
Energy-related derivatives	0		0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[2]	0	[3]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[2]	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[2]	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[2]	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[2]	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	3,000,000	[2]	0	[2]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]	'		'
Assets:	'		'
Energy-related derivatives	5,000,000		11,000,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	'		15,000,000
Fair value assets, total	755,000,000		724,000,000
Liabilities:	'		'
Energy-related derivatives	21,000,000		45,000,000
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	198,000,000	[1]	163,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	131,000,000	[1]	117,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	79,000,000	[1]	105,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	64,000,000	[1]	55,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	140,000,000	[1]	133,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	114,000,000	[1]	115,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	24,000,000	[1]	10,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	'		15,000,000
Fair value assets, total	197,000,000		177,000,000
Liabilities:	'		'
Energy-related derivatives	0		0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	197,000,000	[1]	162,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Municipal bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Assets:	'		'
Energy-related derivatives	5,000,000		11,000,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	'		0
Fair value assets, total	558,000,000		547,000,000
Liabilities:	'		'
Energy-related derivatives	21,000,000		45,000,000
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	1,000,000	[1]	1,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	131,000,000	[1]	117,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	79,000,000	[1]	105,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	64,000,000	[1]	55,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	140,000,000	[1]	133,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	114,000,000	[1]	115,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	24,000,000	[1]	10,000,000	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	'		0
Fair value assets, total	0		0
Liabilities:	'		'
Energy-related derivatives	0		0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity fund [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]	'		'
Nuclear decommissioning trusts:	'		'
Nuclear decommissioning trusts	0	[1]	0	[1]
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member]	'		'
Assets:	'		'
Energy-related derivatives	6,962,000		4,358,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	15,929,000		15,231,000
Fair value assets, total	22,891,000		19,589,000
Liabilities:	'		'
Energy-related derivatives	17,043,000		27,112,000
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	15,929,000		15,231,000
Fair value assets, total	15,929,000		15,231,000
Liabilities:	'		'
Energy-related derivatives	0		0
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Assets:	'		'
Energy-related derivatives	6,962,000		4,358,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	0		0
Fair value assets, total	6,962,000		4,358,000
Liabilities:	'		'
Energy-related derivatives	17,043,000		27,112,000
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	0		0
Fair value assets, total	0		0
Liabilities:	'		'
Energy-related derivatives	0		0
Mississippi Power [Member]	'		'
Assets:	'		'
Energy-related derivatives	4,803,000		2,519,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	125,000,000		125,600,000
Fair value assets, total	129,803,000		128,119,000
Liabilities:	'		'
Energy-related derivatives	10,281,000		19,446,000
Foreign currency derivatives	1,000		37,000
Fair value liabilities, total	10,282,000		19,483,000
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	125,000,000		125,600,000
Fair value assets, total	125,000,000		125,600,000
Liabilities:	'		'
Energy-related derivatives	0		0
Foreign currency derivatives	0		0
Fair value liabilities, total	0		0
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Assets:	'		'
Energy-related derivatives	4,803,000		2,519,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	0		0
Fair value assets, total	4,803,000		2,519,000
Liabilities:	'		'
Energy-related derivatives	10,281,000		19,446,000
Foreign currency derivatives	1,000		37,000
Fair value liabilities, total	10,282,000		19,483,000
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	0		0
Fair value assets, total	0		0
Liabilities:	'		'
Energy-related derivatives	0		0
Foreign currency derivatives	0		0
Fair value liabilities, total	0		0
Southern Power [Member]	'		'
Assets:	'		'
Energy-related derivatives	600,000		2,100,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	68,000,000		26,000,000
Fair value assets, total	68,600,000		28,100,000
Liabilities:	'		'
Energy-related derivatives	600,000		1,300,000
Southern Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	68,000,000		26,000,000
Fair value assets, total	68,000,000		26,000,000
Liabilities:	'		'
Energy-related derivatives	0		0
Southern Power [Member] | Significant Other Observable Inputs (Level 2) [Member]	'		'
Assets:	'		'
Energy-related derivatives	600,000		2,100,000
Nuclear decommissioning trusts:	'		'
Cash equivalents	0		0
Fair value assets, total	600,000		2,100,000
Liabilities:	'		'
Energy-related derivatives	600,000		1,300,000
Southern Power [Member] | Significant Unobservable Inputs (Level 3) [Member]	'		'
Assets:	'		'
Energy-related derivatives	0		0
Nuclear decommissioning trusts:	'		'
Cash equivalents	0		0
Fair value assets, total	0		0
Liabilities:	'		'
Energy-related derivatives	$0		$0
[1]	Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information.
[2]	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information.
[3]	Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases.

Fair_Value_Measurements_Fair_V

Fair Value Measurements - Fair Value, Nature and Risk of Investments (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Foreign equity fund [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	$131,000,000	$117,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Monthly	'Monthly
Redemption Notice Period	'5 days	'5 days
Corporate bonds - commingled funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	8,000,000	9,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'Not applicableB	'Not applicableB
Equity - commingled funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	65,000,000	55,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily/Monthly	'Daily/Monthly
Redemption Notice Period	'Daily/7B daysB	'Daily/7B daysB
Other - commingled funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	24,000,000	10,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'Not applicableB	'Not applicableB
Trust-owned life insurance [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	110,000,000	96,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'15 daysB	'15 daysB
Money market funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	491,000,000	384,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'Not applicableB	'Not applicableB
Maximum [Member] | Foreign equity fund [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Redemption Notice Period	'5 days	'5 days
Maximum [Member] | Equity - commingled funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Redemption Notice Period	'7 days	'7 days
Maximum [Member] | Trust-owned life insurance [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Redemption Notice Period	'15 days	'15 days
Alabama Power [Member] | Equity - commingled funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	65,000,000	55,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily/Monthly	'Daily/Monthly
Redemption Notice Period	'Daily/7 Days	'Daily/7 days
Redemption Notice Period	'7 days	'7 days
Alabama Power [Member] | Trust-owned life insurance [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	110,000,000	96,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'15 days	'15 days
Redemption Notice Period	'15 days	'15 days
Alabama Power [Member] | Money market funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	236,000,000	'
Redemption Frequency	'Daily	'
Redemption Notice Period	'Not applicable	'
Georgia Power [Member] | Foreign equity fund [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	131,000,000	117,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'5 days	'5 days
Georgia Power [Member] | Corporate bonds - commingled funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	8,000,000	9,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'Not applicable	'Not applicable
Georgia Power [Member] | Other - commingled funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	24,000,000	10,000,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'Not applicable	'Not applicable
Georgia Power [Member] | Money market funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	'	15,000,000
Unfunded Commitments	'	0
Redemption Frequency	'	'Daily
Redemption Notice Period	'	'Not applicable
Georgia Power [Member] | Maximum [Member] | Foreign equity fund [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Redemption Notice Period	'5 days	'5 days
Gulf Power [Member] | Money market funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	15,929,000	15,231,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'Not applicable	'Not applicable
Mississippi Power [Member] | Money market funds [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	125,000,000	125,600,000
Unfunded Commitments	0	0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'NotB applicable	'Not applicable
Southern Power [Member]	'	'
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments	'	'
Fair Value	68,000,000	26,000,000
Unfunded Commitments	$0	$0
Redemption Frequency	'Daily	'Daily
Redemption Notice Period	'Not applicable	'Not applicable

Fair_Value_Measurements_Financ

Fair Value Measurements - Financial Instruments, Carrying Amount Not Equal to Fair Value (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Long-term debt:	'	'
Long-term debt, Carrying Amount	$21,650,000	$21,530,000
Long-term debt, Fair Value	22,197,000	23,480,000
Alabama Power [Member]	'	'
Long-term debt:	'	'
Long-term debt, Carrying Amount	6,228,000	6,179,000
Long-term debt, Fair Value	6,534,000	6,899,000
Georgia Power [Member]	'	'
Long-term debt:	'	'
Long-term debt, Carrying Amount	8,593,000	9,624,000
Long-term debt, Fair Value	8,782,000	10,427,000
Gulf Power [Member]	'	'
Long-term debt:	'	'
Long-term debt, Carrying Amount	1,233,163	1,245,870
Long-term debt, Fair Value	1,261,889	1,367,404
Mississippi Power [Member]	'	'
Long-term debt:	'	'
Long-term debt, Carrying Amount	2,098,639	1,840,933
Long-term debt, Fair Value	2,045,519	1,956,799
Southern Power [Member]	'	'
Long-term debt:	'	'
Long-term debt, Carrying Amount	1,620,000	1,306,000
Long-term debt, Fair Value	$1,660,000	$1,444,000

Fair_Value_Measurements_Textua

Fair Value Measurements - Textual (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Maximum number of months related to maturities in the portfolio not to exceeded from the date of purchase	'13 months
Maximum number of days related to dollar-weighted average portfolio maturities regarding commingled funds	'90 days
Georgia Power [Member]	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Notices Of Withdrawal Foreign Equity Funds	20.00%
Maximum number of months related to maturities in the portfolio not to exceeded from the date of purchase	'13 months
Maximum number of days related to dollar-weighted average portfolio maturities regarding commingled funds	'90 days
Minimum [Member] | Georgia Power [Member]	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Withdrawal Of Foreign Equity Fund Investment	1
Foreign Equity Fund Investment	10

Derivatives_EnergyRelated_Inte

Derivatives - Energy-Related, Interest Rate, and Foreign Currency Derivatives Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Fair Value Hedging [Member]	'
Interest rate derivative contracts	'
Notional Amount	$350
Derivative, Maturity Date	1-May-14
Fair Value Gain (Loss)	$3
Interest Rate Received [Member] | Fair Value Hedging [Member]	'
Interest rate derivative contracts	'
Interest Rate Received	4.15%
Interest Rate Paid [Member] | Fair Value Hedging [Member]	'
Interest rate derivative contracts	'
Interest Rate Paid	'3-month LIBOR + 1.96%
Interest Rate Paid, Description of Variable Rate Basis	'3-month LIBOR
Interest Rate Paid, Spread on Variable Rate	1.96%
Alabama Power [Member]	'
Energy-related derivative contracts	'
Net Purchased mmBtu	69,000,000	[1]
Longest Hedge Date	'2017
Mississippi Power [Member]	'
Energy-related derivative contracts	'
Net Purchased mmBtu	56,000,000	[2]
Longest Hedge Date	'2017
[1]	*million British thermal units (mmBtu)
[2]	*mmBtu b million British thermal units

Derivatives_Financial_Statemen

Derivatives - Financial Statement Presentation (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	$27,000	$36,000
Liability Derivatives	56,000	111,000
Hedging Instruments for Regulatory Purposes [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	23,000	23,000
Liability Derivatives	55,000	109,000
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other current assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	16,000	10,000
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	7,000	13,000
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	26,000	74,000
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	29,000	35,000
Designated as hedging instruments in cash flow and fair value hedges [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	3,000	10,000
Liability Derivatives	0	0
Designated as hedging instruments in cash flow and fair value hedges [Member] | Interest rate derivatives [Member] | Other current assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	3,000	7,000
Designated as hedging instruments in cash flow and fair value hedges [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	0	3,000
Designated as hedging instruments in cash flow and fair value hedges [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	0	0
Designated as hedging instruments in cash flow and fair value hedges [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	0	0
Not designated as hedging instruments [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	1,000	3,000
Liability Derivatives	1,000	2,000
Not designated as hedging instruments [Member] | Energy Related Derivative [Member] | Other current assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	0	1,000
Not designated as hedging instruments [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	1,000	2,000
Not designated as hedging instruments [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	1,000	1,000
Not designated as hedging instruments [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	0	1,000
Alabama Power [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	7,000	5,000
Liability Derivatives	8,000	18,000
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	7,000	5,000
Liability Derivatives	8,000	18,000
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other current assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	5,000	2,000
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	2,000	3,000
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	3,000	14,000
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	5,000	4,000
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	5,000	11,000
Liability Derivatives	21,000	45,000
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other current assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	3,000	6,000
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	2,000	5,000
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	13,000	30,000
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	8,000	15,000
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	6,962	4,358
Liability Derivatives	17,043	27,112
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other current assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	4,893	1,293
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	2,069	3,065
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	6,470	16,529
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	10,573	10,583
Mississippi Power [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	4,803	2,519
Liability Derivatives	10,282	19,483
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	4,803	2,519
Liability Derivatives	10,281	19,446
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other current assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	3,352	638
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	1,451	1,881
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	3,652	13,116
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	6,629	6,330
Mississippi Power [Member] | Designated as hedging instruments in cash flow and fair value hedges [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	0	0
Liability Derivatives	1	37
Mississippi Power [Member] | Designated as hedging instruments in cash flow and fair value hedges [Member] | Foreign currency derivatives [Member] | Other current assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	0	0
Mississippi Power [Member] | Designated as hedging instruments in cash flow and fair value hedges [Member] | Foreign currency derivatives [Member] | Other deferred charges and assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	0	0
Mississippi Power [Member] | Designated as hedging instruments in cash flow and fair value hedges [Member] | Foreign currency derivatives [Member] | Liabilities from risk management activities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	1	0
Mississippi Power [Member] | Designated as hedging instruments in cash flow and fair value hedges [Member] | Foreign currency derivatives [Member] | Other deferred credits and liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	0	37
Southern Power [Member] | Energy Related Derivative [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	600	2,100
Liability Derivatives	600	1,300
Southern Power [Member] | Not designated as hedging instruments [Member] | Energy Related Derivative [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	600	2,100
Liability Derivatives	600	1,300
Southern Power [Member] | Not designated as hedging instruments [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	400	1,700
Southern Power [Member] | Not designated as hedging instruments [Member] | Energy Related Derivative [Member] | Assets from risk management activities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Asset Derivatives	200	400
Southern Power [Member] | Not designated as hedging instruments [Member] | Energy Related Derivative [Member] | Other Current Liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	600	700
Southern Power [Member] | Not designated as hedging instruments [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]	'	'
Fair value of energy-related derivatives and interest rate derivatives	'	'
Liability Derivatives	$0	$600

Derivatives_Balance_Sheet_Offs

Derivatives - Balance Sheet Offsetting (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	$27,000		$36,000
Derivative Liability, Fair Value, Gross Liability	56,000		111,000
Alabama Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	7,000		5,000
Derivative Liability, Fair Value, Gross Liability	8,000		18,000
Mississippi Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	4,803		2,519
Derivative Liability, Fair Value, Gross Liability	10,282		19,483
Energy Related Derivative [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Offset Against Collateral	2,000		3,000
Derivative Liability, Fair Value, Amount Offset Against Collateral	34,000		88,000
Energy Related Derivative [Member] | Alabama Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Offset Against Collateral	2,000		1,000
Derivative Liability, Fair Value, Amount Offset Against Collateral	3,000		14,000
Energy Related Derivative [Member] | Georgia Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	16,000		34,000
Energy Related Derivative [Member] | Gulf Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Offset Against Collateral	1,000		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	11,000		23,000
Energy Related Derivative [Member] | Mississippi Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Offset Against Collateral	947		186
Derivative Liability, Fair Value, Amount Offset Against Collateral	6,425		17,113
Energy Related Derivative [Member] | Southern Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	600		2,100
Derivative Asset, Fair Value, Amount Offset Against Collateral	500		1,100
Derivative Liability, Fair Value, Gross Liability	600		1,300
Derivative Liability, Fair Value, Amount Offset Against Collateral	500		300
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	24,000	[1]	26,000	[1]
Derivative Liability, Fair Value, Gross Liability	56,000	[1]	111,000	[1]
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Alabama Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	7,000	[1]	5,000	[1]
Derivative Liability, Fair Value, Gross Liability	8,000	[1]	18,000	[1]
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Georgia Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	5,000	[1]	11,000	[1]
Derivative Liability, Fair Value, Gross Liability	21,000	[1]	45,000	[1]
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Gulf Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	7,000	[1]	4,000	[1]
Derivative Liability, Fair Value, Gross Liability	17,000	[1]	27,000	[1]
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Mississippi Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	4,803	[1]	2,519	[1]
Derivative Liability, Fair Value, Gross Liability	10,281	[1]	19,446	[1]
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Southern Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	600	[1]	2,100	[1]
Derivative Liability, Fair Value, Gross Liability	600	[1]	1,300	[1]
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	-22,000	[2]	-23,000	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-22,000	[2]	-23,000	[2]
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Alabama Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	-5,000	[2]	-4,000	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-5,000	[2]	-4,000	[2]
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Georgia Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	-5,000	[2]	-11,000	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-5,000	[2]	-11,000	[2]
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Gulf Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	-6,000	[3]	-4,000	[3]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-6,000	[3]	-4,000	[3]
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Mississippi Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	-3,856	[2]	-2,333	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-3,856	[2]	-2,333	[2]
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Southern Power [Member]	'		'
Derivative [Line Items]	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	-100	[2]	-1,000	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	($100)	[2]	($1,000)	[2]
[1]	The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
[2]	Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
[3]	(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

Derivatives_Pretax_Effect_of_D

Derivatives - Pre-tax Effect of Derivatives on Balance Sheets and Statements of Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	($55,000)	($109,000)	'
Regulatory Hedge Unrealized Gain	23,000	23,000	'
Other regulatory assets current [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-26,000	-74,000	'
Other regulatory assets deferred [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-29,000	-35,000	'
Other regulatory liabilities current [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	16,000	10,000	'
Other regulatory liabilities deferred [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	7,000	13,000	'
Alabama Power [Member] | Interest expense, net of amounts capitalized [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	-3,000	-3,000	3,000
Alabama Power [Member] | Interest rate derivatives [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	-18,000	-14,000
Alabama Power [Member] | Other regulatory assets current [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-3,000	-14,000	'
Alabama Power [Member] | Other regulatory assets deferred [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-5,000	-4,000	'
Alabama Power [Member] | Other regulatory assets [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-8,000	-18,000	'
Alabama Power [Member] | Other Current Liabilities [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	5,000	2,000	'
Alabama Power [Member] | Other regulatory liabilities deferred [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	2,000	3,000	'
Alabama Power [Member] | Other regulatory liabilities [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	7,000	5,000	'
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory assets current [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-13,000	-30,000	'
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory assets deferred [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-8,000	-15,000	'
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory assets [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-21,000	-45,000	'
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory liabilities current [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	3,000	6,000	'
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	2,000	5,000	'
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory liabilities [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	5,000	11,000	'
Gulf Power [Member] | Interest rate derivatives [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	0	0
Gulf Power [Member] | Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	-769	-933	-933
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-17,043	-27,112	'
Regulatory Hedge Unrealized Gain	6,962	4,358	'
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory assets current [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-6,470	-16,529	'
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory assets deferred [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-10,573	-10,583	'
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory liabilities current [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	4,893	1,293	'
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory liabilities deferred [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	2,069	3,065	'
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-10,281	-19,446	'
Regulatory Hedge Unrealized Gain	4,803	2,519	'
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory assets current [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-3,652	-13,116	'
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory assets deferred [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Loss	-6,629	-6,330	'
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory liabilities current [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	3,352	638	'
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other regulatory liabilities deferred [Member] | Energy Related Derivative [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Regulatory Hedge Unrealized Gain	1,451	1,881	'
Mississippi Power [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	-774	-14,364
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	-1,375	-1,073	48
Mississippi Power [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Energy Related Derivative [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	0	-3
Mississippi Power [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Energy Related Derivative [Member] | Fuel [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	0
Mississippi Power [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest rate derivatives [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	-774	-14,361
Mississippi Power [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	-1,375	-1,073	48
Southern Power [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	-200	100
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	-6,100	-10,100	-12,000
Southern Power [Member] | Energy Related Derivative [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	-200	100
Southern Power [Member] | Energy Related Derivative [Member] | Depreciation and amortization [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	400	400	400
Southern Power [Member] | Interest rate derivatives [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	0	0
Southern Power [Member] | Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	-6,500	-10,500	-11,400
Southern Power [Member] | Interest rate derivatives [Member] | Other income (expense), net [Member]	'	'	'
Pre-tax effect of derivatives designated as cash flow hedging instruments	'	'	'
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$0	$0	($1,000)

Derivatives_Textual_Details

Derivatives - Textual (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
	MMBTU
Derivatives (Textual) [Abstract]	'		'	'
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	9,000,000		'	'
Fair value of derivative liabilities with contingent features	$9,000,000		'	'
Maximum potential collateral requirements arising the from credit-risk-related contingent features	9,000,000		'	'
Alabama Power [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Net volume of energy-related derivative contracts for natural gas positions	69,000,000	[1]	'	'
Longest Hedge Date	'2017		'	'
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period	3,000,000		'	'
Fair value of derivative liabilities with contingent features	1,000,000		'	'
Maximum potential collateral requirements arising the from credit-risk-related contingent features	9,000,000		'	'
Georgia Power [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	5,000,000		'	'
Date through which deferred gains and losses are expected to be amortized into earnings	'2037		'	'
Fair value of derivative liabilities with contingent features	3,000,000		'	'
Maximum potential collateral requirements arising the from credit-risk-related contingent features	9,000,000		'	'
Gulf Power [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Net volume of energy-related derivative contracts for natural gas positions	88,620,000		'	'
Longest Hedge Date	'2018		'	'
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period	600,000		'	'
Fair value of derivative liabilities with contingent features	3,700,000		'	'
Maximum potential collateral requirements arising the from credit-risk-related contingent features	8,800,000		'	'
Mississippi Power [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Net volume of energy-related derivative contracts for natural gas positions	56,000,000	[2]	'	'
Longest Hedge Date	'2017		'	'
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period	1,400,000		'	'
Pre-tax losses from foreign currency derivatives designated as fair value hedging instruments including pre-tax losses associated with de-designated hedges prior to de-designation	'		600,000	3,600,000
Fair value of derivative liabilities with contingent features	1,500,000		'	'
Maximum potential collateral requirements arising the from credit-risk-related contingent features	8,800,000		'	'
Southern Power [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	1,400,000		'	'
Realized gain on termination of interest rate derivatives	0		-200,000	100,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	8,800,000		'	'
Interest rate hedges [Member] | Southern Power [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period	$900,000		'	'
Public Utilities, Inventory, Natural Gas [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Net volume of energy-related derivative contracts for natural gas positions	275,000,000		'	'
Public Utilities, Inventory, Natural Gas [Member] | Georgia Power [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Net volume of energy-related derivative contracts for natural gas positions	60,000,000		'	'
Longest Hedge Date	'2017		'	'
Public Utilities, Inventory, Natural Gas [Member] | Southern Power [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Net volume of energy-related derivative contracts for natural gas positions	1,600,000		'	'
Longest Non-Hedge Date	'2017		'	'
Public Utilities, Inventory, Fuel [Member]	'		'	'
Derivatives (Textual) [Abstract]	'		'	'
Longest Hedge Date	'2018		'	'
Longest Non-Hedge Date	'2017		'	'
[1]	*million British thermal units (mmBtu)
[2]	*mmBtu b million British thermal units

Segment_and_Related_Informatio2

Segment and Related Information - Financial Data for Business Segments and Products and Services (Details) (USD $)

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

entities

entities

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Number of traditional operating companies

4

'

'

'

'

'

'

'

4

'

'

Revenues

$3,927,000,000

$5,017,000,000

$4,246,000,000

$3,897,000,000

$3,703,000,000

$5,049,000,000

$4,181,000,000

$3,604,000,000

$17,087,000,000

$16,537,000,000

$17,657,000,000

Financial data for business segments

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

3,927,000,000

5,017,000,000

4,246,000,000

3,897,000,000

3,703,000,000

5,049,000,000

4,181,000,000

3,604,000,000

17,087,000,000

16,537,000,000

17,657,000,000

Depreciation and amortization

'

'

'

'

'

'

'

'

1,901,000,000

1,787,000,000

1,717,000,000

Interest income

'

'

'

'

'

'

'

'

19,000,000

40,000,000

21,000,000

Interest expense

'

'

'

'

'

'

'

'

824,000,000

859,000,000

857,000,000

Income taxes

'

'

'

'

'

'

'

'

849,000,000

1,334,000,000

1,219,000,000

Segment net income (loss)

414,000,000

852,000,000

297,000,000

81,000,000

383,000,000

976,000,000

623,000,000

368,000,000

1,644,000,000

[1],[2]

2,350,000,000

[1]

2,203,000,000

[1]

Total assets

64,546,000,000

'

'

'

63,149,000,000

'

'

'

64,546,000,000

63,149,000,000

59,267,000,000

Gross property additions

'

'

'

'

'

'

'

'

5,868,000,000

5,059,000,000

4,853,000,000

Kemper IGCC [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment and Related Information (Textual) [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Pre-Tax Charge To Income

'

'

'

1,200,000,000

'

'

'

'

1,200,000,000

'

'

After Tax Charge To Income

'

'

'

'

'

'

'

'

729,000,000

'

'

Electric Utilities [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

17,035,000,000

16,478,000,000

17,587,000,000

Financial data for business segments

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

17,035,000,000

16,478,000,000

17,587,000,000

Depreciation and amortization

'

'

'

'

'

'

'

'

1,886,000,000

1,772,000,000

1,700,000,000

Interest income

'

'

'

'

'

'

'

'

18,000,000

22,000,000

19,000,000

Interest expense

'

'

'

'

'

'

'

'

788,000,000

820,000,000

803,000,000

Income taxes

'

'

'

'

'

'

'

'

935,000,000

1,400,000,000

1,293,000,000

Segment net income (loss)

'

'

'

'

'

'

'

'

1,652,000,000

[1],[2]

2,321,000,000

[1]

2,214,000,000

[1]

Total assets

63,775,000,000

'

'

'

62,251,000,000

'

'

'

63,775,000,000

62,251,000,000

58,076,000,000

Gross property additions

'

'

'

'

'

'

'

'

5,859,000,000

5,054,000,000

4,844,000,000

Traditional Operating Companies [Member] | Electric Utilities [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

16,136,000,000

15,730,000,000

16,763,000,000

Financial data for business segments

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

16,136,000,000

15,730,000,000

16,763,000,000

Depreciation and amortization

'

'

'

'

'

'

'

'

1,711,000,000

1,629,000,000

1,576,000,000

Interest income

'

'

'

'

'

'

'

'

17,000,000

21,000,000

18,000,000

Interest expense

'

'

'

'

'

'

'

'

714,000,000

757,000,000

726,000,000

Income taxes

'

'

'

'

'

'

'

'

889,000,000

1,307,000,000

1,217,000,000

Segment net income (loss)

'

'

'

'

'

'

'

'

1,486,000,000

[1],[2]

2,145,000,000

[1]

2,052,000,000

[1]

Total assets

59,447,000,000

'

'

'

58,600,000,000

'

'

'

59,447,000,000

58,600,000,000

54,622,000,000

Gross property additions

'

'

'

'

'

'

'

'

5,226,000,000

4,813,000,000

4,589,000,000

Southern Power [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

346,000,000

425,000,000

359,000,000

Financial data for business segments

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

346,000,000

425,000,000

359,000,000

Southern Power [Member] | Electric Utilities [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

1,275,000,000

1,186,000,000

1,236,000,000

Financial data for business segments

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

1,275,000,000

1,186,000,000

1,236,000,000

Depreciation and amortization

'

'

'

'

'

'

'

'

175,000,000

143,000,000

124,000,000

Interest income

'

'

'

'

'

'

'

'

1,000,000

1,000,000

1,000,000

Interest expense

'

'

'

'

'

'

'

'

74,000,000

63,000,000

77,000,000

Income taxes

'

'

'

'

'

'

'

'

46,000,000

93,000,000

76,000,000

Segment net income (loss)

'

'

'

'

'

'

'

'

166,000,000

[1],[2]

175,000,000

[1]

162,000,000

[1]

Total assets

4,429,000,000

'

'

'

3,780,000,000

'

'

'

4,429,000,000

3,780,000,000

3,581,000,000

Gross property additions

'

'

'

'

'

'

'

'

633,000,000

241,000,000

255,000,000

All Other [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

139,000,000

141,000,000

149,000,000

Financial data for business segments

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

139,000,000

141,000,000

149,000,000

Depreciation and amortization

'

'

'

'

'

'

'

'

15,000,000

15,000,000

16,000,000

Interest income

'

'

'

'

'

'

'

'

2,000,000

19,000,000

3,000,000

Interest expense

'

'

'

'

'

'

'

'

36,000,000

39,000,000

54,000,000

Income taxes

'

'

'

'

'

'

'

'

-85,000,000

-66,000,000

-74,000,000

Segment net income (loss)

'

'

'

'

'

'

'

'

-10,000,000

[1],[2]

33,000,000

[1]

-8,000,000

[1]

Total assets

1,077,000,000

'

'

'

1,116,000,000

'

'

'

1,077,000,000

1,116,000,000

1,592,000,000

Gross property additions

'

'

'

'

'

'

'

'

9,000,000

5,000,000

9,000,000

Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

-87,000,000

-82,000,000

-79,000,000

Financial data for business segments

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

-87,000,000

-82,000,000

-79,000,000

Depreciation and amortization

'

'

'

'

'

'

'

'

0

0

1,000,000

Interest income

'

'

'

'

'

'

'

'

-1,000,000

-1,000,000

-1,000,000

Interest expense

'

'

'

'

'

'

'

'

0

0

0

Income taxes

'

'

'

'

'

'

'

'

-1,000,000

0

0

Segment net income (loss)

'

'

'

'

'

'

'

'

2,000,000

[1],[2]

-4,000,000

[1]

-3,000,000

[1]

Total assets

-306,000,000

'

'

'

-218,000,000

'

'

'

-306,000,000

-218,000,000

-401,000,000

Gross property additions

'

'

'

'

'

'

'

'

0

0

0

Eliminations [Member] | Electric Utilities [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

-376,000,000

-438,000,000

-412,000,000

Financial data for business segments

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

-376,000,000

-438,000,000

-412,000,000

Depreciation and amortization

'

'

'

'

'

'

'

'

0

0

0

Interest income

'

'

'

'

'

'

'

'

0

0

0

Interest expense

'

'

'

'

'

'

'

'

0

0

0

Income taxes

'

'

'

'

'

'

'

'

0

0

0

Segment net income (loss)

'

'

'

'

'

'

'

'

0

[1],[2]

1,000,000

[1]

0

[1]

Total assets

-101,000,000

'

'

'

-129,000,000

'

'

'

-101,000,000

-129,000,000

-127,000,000

Gross property additions

'

'

'

'

'

'

'

'

$0

$0

$0

[1]

(a) After dividends on preferred and preference stock of subsidiaries.

[2]

(b) Segment net income (loss) in 2013 includes $1.2 billion in pre-tax charges ($729 million after tax) for estimated probable losses on the Kemper IGCC. See Note (3) under "Integrated Coal Gasification Combined Cycle b Kemper IGCC Construction Schedule and Cost Estimate" for additional information.

Segment_and_Related_Informatio3

Segment and Related Information - Electric Utilities' Revenues (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Financial data for Products and Services	'	'	'	'	'	'	'	'	'	'	'
Electric Utilities Revenues	$3,927,000	$5,017,000	$4,246,000	$3,897,000	$3,703,000	$5,049,000	$4,181,000	$3,604,000	$17,087,000	$16,537,000	$17,657,000
Electric Utilities [Member]	'	'	'	'	'	'	'	'	'	'	'
Financial data for Products and Services	'	'	'	'	'	'	'	'	'	'	'
Electric Utilities Revenues	'	'	'	'	'	'	'	'	17,035,000	16,478,000	17,587,000
Other Electric Revenue [Member]	'	'	'	'	'	'	'	'	'	'	'
Financial data for Products and Services	'	'	'	'	'	'	'	'	'	'	'
Electric Utilities Revenues	'	'	'	'	'	'	'	'	639,000	616,000	611,000
Wholesale [Member]	'	'	'	'	'	'	'	'	'	'	'
Financial data for Products and Services	'	'	'	'	'	'	'	'	'	'	'
Electric Utilities Revenues	'	'	'	'	'	'	'	'	1,855,000	1,675,000	1,905,000
Retail [Member]	'	'	'	'	'	'	'	'	'	'	'
Financial data for Products and Services	'	'	'	'	'	'	'	'	'	'	'
Electric Utilities Revenues	'	'	'	'	'	'	'	'	$14,541,000	$14,187,000	$15,071,000

Quarterly_Financial_Informatio2

Quarterly Financial Information (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Summarized quarterly financial information	'	'	'	'	'	'	'	'	'		'		'
Operating revenues	$3,927,000	$5,017,000	$4,246,000	$3,897,000	$3,703,000	$5,049,000	$4,181,000	$3,604,000	$17,087,000		$16,537,000		$17,657,000
Operating Income (Loss)	799,000	1,491,000	640,000	325,000	814,000	1,740,000	1,143,000	766,000	3,255,000		4,463,000		4,231,000
Net Income (Loss) After Dividends on Preferred and Preference Stock	414,000	852,000	297,000	81,000	383,000	976,000	623,000	368,000	1,644,000	[1],[2]	2,350,000	[1]	2,203,000	[1]
Basic Earnings, Per Common Share	$0.47	$0.97	$0.34	$0.09	$0.44	$1.11	$0.71	$0.42	$1.88		$2.70		$2.57
Diluted Earnings, Per Common Share	$0.47	$0.97	$0.34	$0.09	$0.44	$1.11	$0.71	$0.42	$1.87		$2.67		$2.55
Dividends, Per Common Share	$0.51	$0.51	$0.51	$0.49	$0.49	$0.49	$0.49	$0.47	'		'		'
Trading Price Range, High, Per Common Share	$42.94	$45.75	$48.74	$46.95	$47.09	$48.59	$48.45	$46.06	'		'		'
Trading Price Range, Low, Per Common Share	$40.03	$40.63	$42.32	$42.82	$41.75	$44.64	$44.22	$43.71	'		'		'
Southern Power [Member]	'	'	'	'	'	'	'	'	'		'		'
Summarized quarterly financial information	'	'	'	'	'	'	'	'	'		'		'
Operating revenues	300,257	364,767	307,255	302,947	291,591	354,971	285,805	253,681	1,275,226		1,186,048		1,235,961
Operating Income (Loss)	53,781	116,497	55,024	64,673	65,816	119,234	90,038	56,343	289,975		331,431		336,451
Net Income (Loss) After Dividends on Preferred and Preference Stock	23,266	85,153	27,922	29,192	30,991	68,376	46,602	29,316	'		'		'
Mississippi Power [Member]	'	'	'	'	'	'	'	'	'		'		'
Summarized quarterly financial information	'	'	'	'	'	'	'	'	'		'		'
Operating revenues	267,582	325,206	306,435	245,934	235,779	305,419	266,084	228,714	1,145,157		1,035,996		1,112,877
Operating Income (Loss)	-24,412	-79,890	-388,395	-429,148	-46,338	66,151	46,986	30,213	-921,845		97,012		133,790
Net Income (Loss) After Dividends on Preferred and Preference Stock	12,921	-24,115	-219,110	-246,321	-14,965	54,625	35,027	25,255	-476,625		99,942		94,182
Alabama Power [Member]	'	'	'	'	'	'	'	'	'		'		'
Summarized quarterly financial information	'	'	'	'	'	'	'	'	'		'		'
Operating revenues	1,314,000	1,604,000	1,392,000	1,308,000	1,290,000	1,637,000	1,377,000	1,216,000	5,618,000		5,520,000		5,702,000
Operating Income (Loss)	312,000	500,000	357,000	307,000	271,000	544,000	390,000	291,000	1,476,000		1,496,000		1,514,000
Net Income (Loss) After Dividends on Preferred and Preference Stock	140,000	258,000	173,000	141,000	113,000	280,000	185,000	126,000	712,000		704,000		708,000
Georgia Power [Member]	'	'	'	'	'	'	'	'	'		'		'
Summarized quarterly financial information	'	'	'	'	'	'	'	'	'		'		'
Operating revenues	1,866,000	2,484,000	2,042,000	1,882,000	1,735,000	2,498,000	2,020,000	1,745,000	8,274,000		7,998,000		8,800,000
Operating Income (Loss)	404,000	872,000	552,000	412,000	400,000	924,000	535,000	344,000	2,240,000		2,203,000		2,047,000
Net Income (Loss) After Dividends on Preferred and Preference Stock	208,000	487,000	282,000	197,000	181,000	525,000	295,000	167,000	1,174,000		1,168,000		1,145,000
Gulf Power [Member]	'	'	'	'	'	'	'	'	'		'		'
Summarized quarterly financial information	'	'	'	'	'	'	'	'	'		'		'
Operating revenues	343,493	399,361	371,173	326,274	331,490	421,819	370,208	316,245	1,440,301		1,439,762		1,519,812
Operating Income (Loss)	56,436	87,776	69,151	51,640	53,818	93,813	71,465	49,098	265,003		268,194		224,724
Net Income (Loss) After Dividends on Preferred and Preference Stock	$25,301	$44,754	$32,582	$21,792	$22,549	$47,754	$34,963	$20,666	$124,429		$125,932		$105,005
[1]	(a) After dividends on preferred and preference stock of subsidiaries.
[2]	(b) Segment net income (loss) in 2013 includes $1.2 billion in pre-tax charges ($729 million after tax) for estimated probable losses on the Kemper IGCC. See Note (3) under "Integrated Coal Gasification Combined Cycle b Kemper IGCC Construction Schedule and Cost Estimate" for additional information.

Valuation_and_Qualifying_Accou1

Valuation and Qualifying Accounts (Details) (Allowance for Doubtful Accounts [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Valuation and Qualifying Accounts Disclosure [Line Items]	'		'		'
Balance at Beginning of period	$16,984		$26,155		$24,919
Additions Charged to Income	36,788		35,305		66,641
Additions Charged to Other Accounts	0		0		0
Deductions	35,917	[1]	44,476	[1]	65,405	[1]
Balance at End of Period	17,855		16,984		26,155
Alabama Power [Member]	'		'		'
Valuation and Qualifying Accounts Disclosure [Line Items]	'		'		'
Balance at Beginning of period	8,450		9,856		9,602
Additions Charged to Income	12,327		10,537		16,415
Additions Charged to Other Accounts	0		0		0
Deductions	12,427	[1]	11,943	[1]	16,161	[1]
Balance at End of Period	8,350		8,450		9,856
Georgia Power [Member]	'		'		'
Valuation and Qualifying Accounts Disclosure [Line Items]	'		'		'
Balance at Beginning of period	6,259		13,038		11,098
Additions Charged to Income	18,362		20,995		45,267
Additions Charged to Other Accounts	0		0		0
Deductions	19,547	[1]	27,774	[1]	43,327	[1]
Balance at End of Period	5,074		6,259		13,038
Gulf Power [Member]	'		'		'
Valuation and Qualifying Accounts Disclosure [Line Items]	'		'		'
Balance at Beginning of period	1,490		1,962		2,014
Additions Charged to Income	1,900		2,611		3,332
Additions Charged to Other Accounts	0		0		0
Deductions	2,259	[1]	3,083	[1]	3,384	[1]
Balance at End of Period	1,131		1,490		1,962
Mississippi Power [Member]	'		'		'
Valuation and Qualifying Accounts Disclosure [Line Items]	'		'		'
Balance at Beginning of period	373		547		638
Additions Charged to Income	3,757		628		1,235
Additions Charged to Other Accounts	0		0		0
Deductions	1,112	[1]	802	[1]	1,326	[1]
Balance at End of Period	$3,018		$373		$547
[1]	Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.