SOUTHERN Co GAS (GAS) 10-Q 28 Apr 15 2015 Q1 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 23, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	AGL RESOURCES INC.
Document Type	10-Q
Current Fiscal Year End Date	-19
Entity Common Stock, Shares Outstanding		119,934,611
Amendment Flag	FALSE
Entity Central Index Key	1004155
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Financial Position (Unaudited) (USD $)	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014
In Millions, unless otherwise specified
Current assets
Cash and cash equivalents	$41		$31		$267
Short-term investments	8		8		49
Receivables
Natural gas, unbilled and other	834		797		1,075
Energy marketing	611		779		1,226
Less allowance for uncollectible accounts	48		35		49
Total receivables, net	1,397		1,541		2,252
Inventories, net	302		716		253
Derivative instruments	189		245		127
Regulatory assets	63		83		250
Assets held for sale					264
Other	79		266		127
Total current assets	2,079		2,890		3,589
Long-term assets and other deferred debits
Property, plant and equipment	11,689		11,552		11,054
Less accumulated depreciation	2,515		2,462		2,367
Property, plant and equipment, net	9,174		9,090		8,687
Goodwill	1,827		1,827		1,827
Regulatory assets	634		631		696
Intangible assets	116		125		140
Derivative instruments	24		42		11
Other	284		304		314
Total long-term assets and other deferred debits	12,059		12,019		11,675
Total assets	14,138		14,909		15,264
Current liabilities
Energy marketing trade payables	586		777		1,119
Short-term debt	526		1,175		741
Other accounts payable – trade	285		312		434
Accrued expenses	259		229		385
Regulatory liabilities	168		112		161
Customer deposits and credit balances	109		125		104
Accrued environmental remediation liabilities	93		87		82
Temporary LIFO liquidation	87				252
Current portion of long-term debt	75		200		200
Derivative instruments	48		88		63
Liabilities held for sale					36
Other	135		114		177
Total current liabilities	2,371		3,219		3,754
Long-term liabilities and other deferred credits
Long-term debt	3,524		3,602		3,610
Accumulated deferred income taxes	1,738		1,724		1,655
Regulatory liabilities	1,612		1,601		1,550
Accrued pension and retiree welfare benefits	526		525		405
Accrued environmental remediation liabilities	326		327		358
Derivative instruments	4		5		19
Other	73		78		70
Total long-term liabilities and other deferred credits	7,803		7,862		7,667
Total liabilities and other deferred credits	10,174		11,081		11,421
Commitments, guarantees and contingencies (see Note 10)
Equity
Common stock, $5 par value; 750,000,000 shares authorized: outstanding: 119,927,459 shares at March 31, 2015, 119,647,149 shares at December 31, 2014, and 119,247,421 shares at March 31, 2014	601		599		597
Additional paid-in capital	2,090		2,087		2,060
Retained earnings	1,444		1,312		1,289
Accumulated other comprehensive loss	-201	[1]	-206	[1]	-135	[1]
Treasury shares, at cost: 216,523 shares at March 31, 2015, December 31, 2014, and March 31, 2014	-8		-8		-8
Total common shareholders’ equity	3,926		3,784		3,803
Noncontrolling interest	38		44		40
Total equity	3,964		3,828		3,843
Total liabilities and equity	$14,138		$14,909		$15,264
[1]	All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Financial Position (Unaudited) (Parentheticals) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
Common stock, par value (in Dollars per share)	$5	$5
Common stock, shares authorized	750,000,000	750,000,000	750,000,000
Common stock, shares outstanding	119,927,459	119,647,149	119,247,421
Treasury shares, shares	216,523	216,523	216,523

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Income (Unaudited) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Operating revenues (includes revenue taxes of $56 for the three months in 2015 and $68 for the three months in 2014)	$1,721		$2,462
Operating expenses
Cost of goods sold	935		1,400
Operation and maintenance	249		289
Depreciation and amortization	97		93
Taxes other than income taxes	76		88
Total operating expenses	1,357		1,870
Operating income	364		592
Other income	3		3
Interest expense, net	-44		-46
Income before income taxes	323		549
Income tax expense	118		203
Income from continuing operations	205		346
(Loss) income from discontinued operations, net of tax			-50
Net income	205		296
Less net income attributable to the noncontrolling interest	12		12
Net income attributable to AGL Resources Inc.	193		284
Amounts attributable to AGL Resources Inc.
Income from continuing operations attributable to AGL Resources Inc.	$193		$334
Basic earnings (loss) per common share
Continuing operations (in Dollars per share)	$1.62		$2.82
Discontinued operations (in Dollars per share)			($0.43)
Basic earnings per common share attributable to AGL Resources Inc. (in Dollars per share)	$1.62		$2.39
Diluted earnings (loss) per common share
Continuing operations (in Dollars per share)	$1.62	[1]	$2.81	[1]
Discontinued operations (in Dollars per share)		[1]	($0.43)	[1]
Diluted earnings per common share attributable to AGL Resources Inc. (in Dollars per share)	$1.62		$2.38
Cash dividends declared per common share (in Dollars per share)	$0.51		$0.49
Weighted average number of common shares outstanding
Basic (in Shares)	119.3	[2]	118.5	[2]
Diluted (in Shares)	119.6	[1]	118.9	[1]
[1]	There were no outstanding stock options excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. for any of the periods presented because their effect would have been anti-dilutive as the exercise prices were greater than the average market price.
[2]	Daily weighted average shares outstanding.

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements of Income (Unaudited) (Parentheticals) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating revenues, revenue taxes	$56	$68

Condensed_Consolidated_Stateme4

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Net income	$205		$296
Other comprehensive income (loss), net of tax
Reclassification of actuarial losses to net benefit cost (net of income tax of $2 and $1 for the three months ended March 31, 2015 and 2014, respectively)	3		1
Cash flow hedges, net of tax
Net derivative instrument gain arising during the period (net of income tax of $1 for the three months ended March 31, 2015)	2		4
Reclassification of realized derivative instrument gain to net income			-4
Cash flow hedges, net	2	[1]		[1]
Other comprehensive income, net of tax	5	[1]	1	[1]
Retirement benefit plans, net	3	[1]	1	[1]
Comprehensive income	210		297
Less comprehensive income attributable to noncontrolling interest	12		12
Comprehensive income attributable to AGL Resources Inc.	$198		$285
[1]	All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

Condensed_Consolidated_Stateme5

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parentheticals) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Reclassification of losses to net benefit cost, income tax	$2	$1
Net derivative instrument gains (losses) arising during the period, income tax	$1

Condensed_Consolidated_Stateme6

Condensed Consolidated Statements of Equity (Unaudited) (USD $)	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock [Member]	Noncontrolling Interest [Member]	Total
In Millions, except Share data
Balance at Dec. 31, 2013	$595	$2,054	$1,063	($136)	($8)	$45	$3,613
Balance, shares (in Shares) at Dec. 31, 2013	118,900,000
Net income			284			12	296
Other comprehensive income				1			1	[1]
Dividends on common stock			-58				-58
Distributions to noncontrolling interest						-17	-17
Stock granted, share-based compensation, net of forfeitures		-11					-11
Stock issued, dividend reinvestment plan		2					2
Stock issued, share-based compensation, net of forfeitures	2	12					14
Stock issued, share-based compensation, net of forfeitures (in Shares)	300,000
Stock-based compensation expense, net of tax		3					3
Balance at Mar. 31, 2014	597	2,060	1,289	-135	-8	40	3,843
Balance, shares (in Shares) at Mar. 31, 2014	119,200,000						119,247,421
Balance at Dec. 31, 2014	599	2,087	1,312	-206	-8	44	3,828
Balance, shares (in Shares) at Dec. 31, 2014	119,600,000						119,647,149
Net income			193			12	205
Other comprehensive income				5			5	[1]
Dividends on common stock			-61				-61
Distributions to noncontrolling interest						-18	-18
Stock granted, share-based compensation, net of forfeitures		-12					-12
Stock issued, dividend reinvestment plan		3					3
Stock issued, dividend reinvestment plan (in Shares)	100,000
Stock issued, share-based compensation, net of forfeitures	2	10					12
Stock issued, share-based compensation, net of forfeitures (in Shares)	200,000
Stock-based compensation expense, net of tax		2					2
Balance at Mar. 31, 2015	$601	$2,090	$1,444	($201)	($8)	$38	$3,964
Balance, shares (in Shares) at Mar. 31, 2015	119,900,000						119,927,459
[1]	All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

Condensed_Consolidated_Stateme7

Condensed Consolidated Statements of Equity (Unaudited) (Parentheticals) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Dividends on common stock, per share	$0.51	$0.49

Condensed_Consolidated_Stateme8

Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities
Net income	$205	$296
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization	97	93
Change in derivative instrument assets and liabilities	33	-17
Deferred income taxes	5	8
Loss from discontinued operations, net of tax		50
Changes in certain assets and liabilities
Inventories, net of temporary LIFO liquidation	501	656
Prepaid and miscellaneous taxes	267	199
Accrued/deferred natural gas costs	22	-228
Accrued expenses	-54	-15
Receivables, other than energy marketing	-24	-319
Energy marketing receivables and trade payables, net	-23	8
Trade payables, other than energy marketing	-13	52
Other, net	104	63
Net cash flow provided by operating activities of discontinued operations		7
Net cash flow provided by operating activities	1,120	853
Cash flows from investing activities
Expenditures for property, plant and equipment	-188	-161
Other, net	4	2
Net cash flow used in investing activities of discontinued operations		-5
Net cash flow used in investing activities	-184	-164
Cash flows from financing activities
Net repayments of commercial paper	-649	-430
Payment of senior notes	-200
Dividends paid on common shares	-61	-58
Distribution to noncontrolling interest	-18	-17
Other, net	2	4
Net cash flow used in financing activities	-926	-501
Net increase in cash and cash equivalents – continuing operations	10	186
Net increase in cash and cash equivalents – discontinued operations		2
Cash and cash equivalents (including held for sale) at beginning of period	31	105
Cash and cash equivalents (including held for sale) at end of period	41	293
Less cash and cash equivalents held for sale at end of period		26
Cash and cash equivalents (excluding held for sale) at end of period	41	267
Cash paid (received) during the period for
Interest	57	58
Income taxes	($140)	$14

Note_1_Organization_and_Basis_

Note 1 - Organization and Basis of Presentation	3 Months Ended
	Mar. 31, 2015
Disclosure Text Block [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Note 1 - Organization and Basis of Presentation
	General
	AGL Resources Inc. is an energy services holding company that conducts substantially all of its operations through its subsidiaries. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company,” or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries.
	Our Condensed Consolidated Statements of Financial Position as of December 31, 2014 were derived from our audited consolidated financial statements, but do not include all disclosures required by GAAP. We have prepared the accompanying unaudited condensed consolidated financial statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. Our unaudited condensed consolidated financial statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair statement of our financial results for the interim periods and should be read in conjunction with our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K.
	Due to the seasonal nature of our business and other factors, our results of operations and our financial condition for the periods presented are not necessarily indicative of the results of operations or financial condition to be expected for or as of any other period.
	Basis of Presentation
	Our unaudited condensed consolidated financial statements include our accounts, the accounts of our wholly owned subsidiaries, the accounts of our majority owned or otherwise controlled subsidiaries and the accounts of our variable interest entity, SouthStar, for which we are the primary beneficiary. For unconsolidated entities that we do not control, we use the equity method of accounting and our proportionate share of income or loss is recorded on the unaudited Condensed Consolidated Statements of Income. See Note 9 for additional information. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts is probable under the affiliates’ rate regulation process.
	In November 2014, we filed a Form 10-Q/A to revise our March 31, 2014 financial statements and other affected disclosures for items related to the recognition of revenues for certain of our regulatory infrastructure programs and the amortization of our intangible assets as originally filed in our Form 10-Q for the period ended March 31, 2014. Our financial statements for the period ended March 31, 2014, reflect the revised amounts reported in our 2014 Form 10-Q/A.
	In September 2014, we closed on the sale of Tropical Shipping, which operated within our former cargo shipping segment. The assets and liabilities of these businesses as of March 31, 2014 are classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position, and the financial results of these businesses for the three months ended March 31, 2014 are reflected as discontinued operations on the unaudited Condensed Consolidated Statements of Income. Amounts shown in the following notes, unless otherwise indicated, exclude assets held for sale and discontinued operations. Cargo shipping also included our investment in Triton, which was not part of the sale and has been reclassified into our “other” non-reportable segments. See Note 12 for additional information on the sale of Tropical Shipping.

Note_2_Significant_Accounting_

Note 2 - Significant Accounting Policies and Methods of Application	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Note 2 - Significant Accounting Policies and Methods of Application
	Our accounting policies are described in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. There were no significant changes to our accounting policies during the three months ended March 31, 2015.
	Use of Accounting Estimates
	The preparation of our financial statements in conformity with GAAP requires us to use judgment and make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing accounting literature or in the development of estimates that impact our financial statements. The most significant estimates relate to the accounting for our rate-regulated subsidiaries, goodwill and other intangible assets, derivative and hedging activities, uncollectible accounts and other allowances for contingent losses, retirement plan benefit obligations and provisions for income taxes. We evaluate our estimates on an ongoing basis, and our actual results could differ from our estimates.
	Cash and Cash Equivalents
	Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of March 31, 2014, there was $26 million of cash and cash equivalents held by Tropical Shipping that was excluded from cash and cash equivalents within our unaudited Condensed Consolidated Statements of Financial Position and included in assets held for sale. For more information on the sale of Tropical Shipping, see Note 12.
	Energy Marketing Receivables and Payables
	Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing trade payables.
	Our wholesale services segment has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of March 31, 2015 and 2014, and December 31, 2014, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.
	Inventories
	For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 10 for information regarding a regulatory filing by Atlanta Gas Light related to natural gas inventory.
	Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are expected to be restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO inventory liquidation. Any temporary LIFO liquidation is included as a current liability in our unaudited Condensed Consolidated Statements of Financial Position. Interim inventory decrements that are not expected to be restored prior to year end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of March 31, 2015 is expected to be restored prior to year-end. The inventory decrement as of March 31, 2014 was restored prior to December 31, 2014.
	Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For these segments, we evaluate the weighted average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, we record pre-tax adjustments to our unaudited Condensed Consolidated Statements of Income to reduce the weighted average cost of the natural gas inventory to market value. For the three months ended March 31, 2015 and 2014, we had LOCOM adjustments primarily at wholesale services of $10 million and $2 million, respectively.
	Additionally, we have $12 million of inventory at wholesale services that is currently inaccessible due to operational issues at a third party storage facility. The owner of the storage facility is working to resolve these issues. While we expect this inventory to be fully recovered, the timing of withdrawal of this gas may be impacted by the operational issues.
	Regulated Operations
	We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for estimated expenditures that have not yet been incurred. Generally, regulatory assets and regulatory liabilities are amortized into our unaudited Condensed Consolidated Statements of Income over the period authorized by the regulatory commissions.
	Fair Value Measurements
	We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents, and derivative assets and liabilities. The carrying values of receivables, short- and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate fair value. Our nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 4 to our consolidated financial statements and in related notes included in Item 8 of our 2014 Form 10-K.
	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observance of those inputs in accordance with the fair value hierarchy.
	Derivative Instruments
	The fair values of the natural gas and weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflect the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We also use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the life of the related debt. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 and Note 5 for additional derivative disclosures.
	Goodwill
	We perform an annual goodwill impairment test on our reporting units that contain goodwill during the fourth quarter of each year, or more frequently if impairment indicators arise. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, the income approach and the market approach, using assumptions consistent with a market participant’s perspective. The results of the two valuation approaches are weighted to estimate the fair value of each reporting unit. There were no triggering events during the current period that would require us to perform an interim impairment test. The amounts of goodwill as of March 31, 2015 and 2014, and December 31, 2014 are provided below.
	In millions		Distribution	Retail		Midstream	Consolidated
			operations	operations		operations
	Goodwill		$1,640	$173		$14	$1,827
	Earnings Per Common Share
	We compute basic earnings per common share attributable to AGL Resources Inc. by dividing our net income attributable to the common shareholders of AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. that occurs when the exercise and/or conversion of all potentially dilutive common shares is added to the common shares outstanding.
	We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. for the periods presented as if performance units currently earned under the plan ultimately vest and as if stock options currently exercisable at prices below the average market prices are exercised.
			Three months ended March 31,
	In millions (except per share amounts)		2015	2014
	Income from continuing operations attributable to AGL Resources Inc.		$193	$334
	Loss from discontinued operations, net of tax		-	(50	)
	Net income attributable to AGL Resources Inc.		$193	$284
	Denominator:
	Basic weighted average number of common shares outstanding (1)		119.3	118.5
	Effect of dilutive securities		0.3	0.4
	Diluted weighted average number of common shares outstanding (2)		119.6	118.9
	Basic earnings per common share
	Continuing operations		$1.62	$2.82
	Discontinued operations		-	(0.43	)
	Basic earnings per common share attributable to AGL Resources Inc.		$1.62	$2.39
	Diluted earnings per common share (2)
	Continuing operations		$1.62	$2.81
	Discontinued operations		-	(0.43	)
	Diluted earnings per common share attributable to AGL Resources Inc.		$1.62	$2.38
		-1	Daily weighted average shares outstanding.
		-2	There were no outstanding stock options excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. for any of the periods presented because their effect would have been anti-dilutive as the exercise prices were greater than the average market price.
	Accounting Developments
	In February 2015, the FASB issued updated authoritative guidance related to the consolidation of other legal entities into our financial statements. The amendments modify aspects of the consolidation determination that could potentially impact us, including the analysis of limited partnerships and similar legal entities, fee arrangements, and related party relationships. The guidance will be effective for us beginning January 1, 2016. Early adoption is permitted. We may elect to apply the new guidance either retrospectively to each prior period presented or via a cumulative effect adjustment upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method.
	In April 2015, the FASB issued updated authoritative guidance related to debt issuance costs. The amendment modifies the presentation of unamortized debt issuance costs on our consolidated statements of financial position. Under the new guidance, we will present such amounts as a direct deduction from the face amount of the debt, similar to unamortized debt discounts and premiums, rather than as an asset. Amortization of the debt issuance costs will continue to be reported as interest expense. The guidance will be effective for us beginning January 1, 2016. Early adoption is permitted. The new guidance must be applied retrospectively to each prior period presented. We have determined that the impact of this new guidance will not be material.
	In April 2015, the FASB issued authoritative guidance related to the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense of the period incurred. The new guidance may be applied either prospectively or retrospectively, is effective for us beginning January 1, 2016, and early adoption is permitted. We are currently evaluating our software arrangements in light of the new guidance.

Note_3_Regulated_Operations

Note 3 - Regulated Operations	3 Months Ended
	Mar. 31, 2015
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets and Liabilities [Text Block]	Note 3 - Regulated Operations
	Our regulatory assets and liabilities reflected within our unaudited Condensed Consolidated Statements of Financial Position as of the dates presented are summarized in the following table.
	In millions		31-Mar-15	31-Dec-14	31-Mar-14
	Regulatory assets
	Recoverable ERC		$37	$49	$38
	Recoverable pension and retiree welfare benefit costs		11	12	9
	Deferred natural gas costs		7	3	161
	Recoverable seasonal rates		-	10	-
	Other		8	9	42
	Total regulatory assets - current		63	83	250
	Recoverable ERC		331	326	419
	Recoverable pension and retiree welfare benefit costs		108	110	97
	Recoverable regulatory infrastructure program costs		73	69	57
	Long-term debt fair value adjustment		72	74	80
	Other		50	52	43
	Total regulatory assets - long-term		634	631	696
	Total regulatory assets		$697	$714	$946
	Regulatory liabilities
	Accrued natural gas costs		$53	$27	$24
	Bad debt over collection		30	33	41
	Accumulated removal costs		25	25	27
	Deferred seasonal rates		20	-	20
	Other		40	27	49
	Total regulatory liabilities - current		168	112	161
	Accumulated removal costs		1,524	1,520	1,456
	Regulatory income tax liability		27	34	27
	Unamortized investment tax credit		22	22	25
	Bad debt over collection		19	12	14
	Other		20	13	28
	Total regulatory liabilities - long-term		1,612	1,601	1,550
	Total regulatory liabilities		$1,780	$1,713	$1,711
	Base rates are designed to provide the opportunity to recover cost and earn a return on investment during the period rates are in effect. As such, all of our regulatory assets recoverable through base rates are subject to review by the respective state regulatory commission during future rate proceedings. We are not aware of evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries.
	Unrecognized Ratemaking Amounts The following table illustrates our authorized ratemaking amounts that are not recognized in our unaudited Condensed Consolidated Statements of Financial Position. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of our regulatory infrastructure programs. These amounts will be recognized as revenues in our financial statements in the periods they are billable to our customers.
	In millions		Atlanta Gas Light	Virginia Natural Gas	Elizabethtown Gas	Total
	31-Mar-15		$119	$12	$2	$133
	31-Dec-14		113	12	2	127
	31-Mar-14		88	12	2	102
	Natural Gas Costs We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms established by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. We defer or accrue the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities.
	Environmental Remediation Costs We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites, substantially all of which is related to our former MGP sites. The ERC assets and liabilities are associated with our distribution operations segment and remediation costs are generally recoverable from customers through rate mechanisms approved by regulators. Accordingly, both costs incurred to remediate the former MGP sites, plus the future estimated cost recorded as liabilities, net of amounts previously collected, are recognized as a regulatory asset until recovered from customers.
	Our accrued environmental remediation liabilities are estimates of future remediation costs for investigation and cleanup of our current and former operating sites that are contaminated. These estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, on an undiscounted basis. These estimates contain various assumptions, which we refine and update on an ongoing basis. These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, legal expenses or other costs for which we may be held liable but for which we cannot reasonably estimate an amount.
	Our accrued environmental remediation liabilities are not regulatory liabilities; however, the associated expenses are deferred as a corresponding regulatory asset until the costs are recovered from customers. We primarily recover these deferred costs through three rate riders that authorize dollar-for-dollar recovery. We expect to collect $37 million in revenues over the next 12 months, which is reflected as a current regulatory asset. The following table provides more information on the estimated costs to remediate our current and former operating sites as of March 31, 2015.
	In millions		# of	Probabilistic model cost estimates	Engineering	Amount	Expected costs over	Cost recovery
			sites		estimates	recorded	next 12 months	period
	Illinois (1)		26	$208 - $466	$43	$242	$45	As incurred
	New Jersey		6	105-177	14	112	14	7 years
	Georgia and Florida		13	40 -81	15	55	26	5 years
	North Carolina (2)		1	n/a	10	10	8	No recovery
	Total		46	$353 - $724	$82	$419	$93
		-1	Nicor Gas is responsible in whole or in part for 26 MGP sites, of which two sites have been remediated and their use is no longer restricted by the environmental condition of the property. Nicor Gas and Commonwealth Edison Company are parties to an agreement to cooperate in cleaning up residue at 23 of the sites. Nicor Gas’ allocated share of cleanup costs for these sites is 52%.
		-2	We have no regulatory recovery mechanism for the site in North Carolina. Therefore, there is no amount included within our regulatory assets and changes in estimated costs are recognized in income in the period of change.
	In July 2014, we reached a $77 million insurance settlement for environmental claims relating to potential contamination at our MGP sites in New Jersey and North Carolina. The terms of the settlement required the $77 million to be paid in two installments. We received $45 million in the third quarter of 2014 and this payment was primarily recorded as a reduction to our recoverable ERC regulatory asset. The remaining $32 million is due in the third quarter of 2015. We will file for approval with the New Jersey BPU to utilize the insurance proceeds related to the New Jersey sites to reduce the ERC expenditures that otherwise would have been recovered from our customers in future periods. Once approved, the settlement is expected to reduce our recoverable ERC regulatory asset and have a favorable impact on the rates for our Elizabethtown Gas customers.

Note_4_Fair_Value_Measurements

Note 4 - Fair Value Measurements	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 4 - Fair Value Measurements
	The methods used to determine the fair values of our assets and liabilities are described within Note 2.
	Derivative Instruments
	The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value on a recurring basis in our unaudited Condensed Consolidated Statements of Financial Position as of the dates presented. See Note 5 for additional derivative instrument information.
			31-Mar-15			31-Dec-14			31-Mar-14
	In millions		Assets (1)	Liabilities		Assets (1)	Liabilities		Assets (1)	Liabilities
	Quoted prices in active markets (Level 1)		$-	$(106	)	$58	$(80	)	$18	$(38	)
	Significant other observable inputs (Level 2)		108	(52	)	174	(94	)	50	(75	)
	Netting of cash collateral		104	106		52	81		69	31
	Total carrying value (2)		$212	$(52	)	$284	$(93	)	$137	$(82	)
		-1	Balances of $1 million at March 31, 2015, $3 million at December 31, 2014 and $1 million at March 31, 2014, associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.
		-2	There were no significant unobservable inputs (Level 3) or significant transfers between Level 1, Level 2 or Level 3 for any of the dates presented.
	Debt
	Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which are recorded at their acquisition-date fair value. We amortize the fair value adjustment of Nicor Gas’ first mortgage bonds over the lives of the bonds. The following table lists the carrying amount and fair value of our long-term debt as of the dates presented.
	In millions		31-Mar-15	31-Dec-14		31-Mar-14
	Long-term debt carrying amount		$3,599	$3,802		$3,810
	Long-term debt fair value (1)		4,102	4,231		4,095
		-1	Fair value determined using Level 2 inputs.

Note_5_Derivative_Instruments

Note 5 - Derivative Instruments	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	Note 5 - Derivative Instruments
	Our objectives and strategies for using derivative instruments, related accounting policies and methods used to determine their fair values are described in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. See Note 4 for additional fair value disclosures.
	Certain of our derivative instruments contain credit-risk-related or other contingent features that could require us to post collateral in the normal course of business when our financial instruments are in net liability positions. As of March 31, 2015, December 31, 2014 and March 31, 2014, for agreements with such features, derivative instruments with liability fair values totaled $52 million, $93 million and $82 million, respectively, for which we had posted no collateral to our counterparties. The maximum collateral that could be required with these features is $7 million. For more information, see “Energy Marketing Receivables and Payables” in Note 2, which also have credit-risk-related contingent features. Our derivative instrument activities are included within operating cash flows as an increase (decrease) to net income of $33 million and $(17) million for the three months ended March 31, 2015 and 2014, respectively. See Note 4 for additional derivative instrument information. The following table summarizes the ways in which we account for our derivative instruments and the impact on our unaudited condensed consolidated financial statements.
	Accounting	Recognition and Measurement
	Treatment	Statements of Financial Position	Statements of Income
	Cash flow hedge	Derivative carried at fair value	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
		Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated OCI (loss)	Effective portion of the gain or loss realized and unrealized on the derivative instrument is reclassified out of accumulated OCI (loss) and into earnings when the hedged transaction affects earnings
	Fair value hedge	Derivative carried at fair value	Gains or losses realized and unrealized on the derivative instrument and the hedged item are recognized in earnings. As a result, to the extent the hedge is effective, the gains or losses will offset and there is no impact on earnings. Any hedge ineffectiveness will impact earnings.
		Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item
	Not	Derivative carried at fair value	Gains or losses realized and unrealized on the derivative instrument are recognized in earnings
	designated
	as hedges	Distribution operations’ gains and losses on derivative instruments are deferred as regulatory assets or liabilities until included in cost of goods sold	Gains or losses realized and unrealized on these derivative instruments are ultimately included in billings to customers and are recognized in cost of goods sold in the same period as the related revenues.
	Quantitative Disclosures Related to Derivative Instruments
	As of the dates presented, our derivative instruments were comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. As of the dates presented, we had a net long natural gas contracts position outstanding in the following quantities:
	In Bcf (1)		March 31, 2015 (2)			31-Dec-14			31-Mar-14
	Cash flow hedges		9			9			6
	Not designated as hedges		231			75			277
	Total volumes		240			84			283
	Short position – cash flow hedges		(6	)		(7	)		(2	)
	Short position – not designated as hedges		(2,735	)		(2,825	)		(2,489	)
	Long position – cash flow hedges		15			16			8
	Long position – not designated as hedges		2,966			2,900			2,766
	Net long position		240			84			283
	-1	Volumes related to Nicor Gas exclude variable-priced contracts, which are carried at fair value, but whose fair values are not directly impacted by changes in commodity prices.
	-2	Approximately 96% of these contracts have durations of two years or less and the remaining 4% expire between two and five years.
	Derivative Instruments in our Unaudited Condensed Consolidated Statements of Financial Position
	In accordance with regulatory requirements, gains and losses on derivative instruments used to hedge natural gas purchases for customer use at distribution operations are reflected in accrued natural gas costs within our unaudited Condensed Consolidated Statements of Financial Position until billed to customers. The following amounts deferred as a regulatory asset or liability in our unaudited Condensed Consolidated Statements of Financial Position represent the net realized gains (losses) related to these natural gas cost hedges as of the periods presented.
			Three months ended
			March 31,
	In millions		2015			2014
	Nicor Gas		$(3	)		$2
	Elizabethtown Gas		(4	)		3
	The following table presents the fair values and unaudited Condensed Consolidated Statements of Financial Position classifications of our derivative instruments as of the dates presented.
				March 31,						December 31,				March 31,
				2015						2014				2014
	In millions	Classification		Assets			Liabilities			Assets		Liabilities		Assets		Liabilities
	Designated as cash flow or fair value hedges
	Natural gas contracts	Current		$-			$(6	)		$6		$(11	)	$2		$-
	Natural gas contracts	Long-term		-			(1	)		-		(1	)	-		-
	Interest rate swap agreements	Current		1			-			-		-		-		-
	Interest rate swap agreements	Long-term		3			-			-		-		-		-
	Total designated as cash flow or fair value hedges			$4			$(7	)		$6		$(12	)	$2		$-
	Not designated as hedges
	Natural gas contracts	Current		$557			$(592	)		$1,061		$(1,020	)	$675		$(703	)
	Natural gas contracts	Long-term		98			(109	)		145		(119	)	80		(98	)
	Total not designated as hedges			$655			$(701	)		$1,206		$(1,139	)	$755		$(801	)
	Gross amount of recognized assets and liabilities (1) (2)			659			(708	)		1,212		(1,151	)	757		(801	)
	Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)			(446	)		656			(925	)	1,058		(619	)	719
	Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)			$213			$(52	)		$287		$(93	)	$138		$(82	)
	-1	The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Statements of Financial Position to the extent that we have netting arrangements with the counterparties.
	-2	As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities do not include cash collateral held on deposit in broker margin accounts of $210 million as of March 31, 2015, $133 million as of December 31, 2014, and $100 million as of March 31, 2014. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table.
	-3	As of March 31, 2015, December 31, 2014, and March 31, 2014, we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets.
	Derivative Instruments in the UnauditedCondensed Consolidated Statements of Income
	The following table presents the impacts of our derivative instruments in our unaudited Condensed Consolidated Statements of Income for the periods presented.
			Three months ended March 31,
	In millions		2015			2014
	Designated as cash flow or fair value hedges
	Natural gas contracts - net (loss) gain reclassified from OCI into cost of goods sold		$(1	)		$3
	Natural gas contracts - net gain reclassified from OCI into operation and maintenance expense		-			1
	Interest rate swaps - net gain reclassified from OCI into interest expense		1			-
	Income tax benefit		-			-
	Total designated as cash flow or fair value hedges, net of tax		-			4
	Not designated as hedges (1)
	Natural gas contracts - net (loss) recorded in operating revenues		(24	)		(30	)
Natural gas contracts - net (loss) gain recorded in cost of goods sold (2)		(2	)		2
Income tax benefit		10			11
Total not designated as hedges, net of tax		(16	)		(17	)
Total gains (losses) on derivative instruments, net of tax		$(16	)		$(13	)
	-1	Associated with the fair value of derivative instruments held at March 31, 2015 and 2014.
	-2	Excludes losses recorded in cost of goods sold associated with weather derivatives of $2 million and $5 million for the three months ended March 31, 2015 and 2014, respectively.
Any amounts recognized in operating income related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for the three months ended March 31, 2015 and 2014. Our expected gains to be reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues and recognized in our unaudited Condensed Consolidated Statements of Income over the next 12 months are $9 million. These deferred gains and losses are related to natural gas derivative contracts associated with retail operations’ and Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at March 31, 2015. The effective portions of gains and losses on derivative instruments qualifying as cash flow hedges that were recognized in OCI during the periods are presented in our unaudited Condensed Consolidated Statements of Income. See Note 8 for these amounts.
There have been no other significant changes to our derivative instruments, as described in Note 2, Note 4 and Note 5 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K.

Note_6_Employee_Benefit_Plans

Note 6 - Employee Benefit Plans	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	Note 6 - Employee Benefit Plans
	Pension Benefits
	We sponsor the AGL Resources Inc. Retirement Plan, a tax-qualified defined benefit retirement plan for our eligible employees, which is described in Note 6 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. Following are the components of our pension costs for the periods indicated.
		Three months ended March 31,
	In millions	2015		2014
	Service cost	$7		$6
	Interest cost	11		12
	Expected return on plan assets	(16	)	(16	)
	Net amortization of prior service cost	(1	)	-
	Recognized actuarial loss	8		5
	Net periodic pension benefit cost	$9		$7
	Welfare Benefits
	The benefits of our Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. are described in Note 6 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. Following are the components of our welfare costs for the periods indicated.
		Three months ended March 31,
	In millions	2015		2014
	Service cost	$1		$1
	Interest cost	3		4
	Expected return on plan assets	(2	)	(2	)
	Net amortization of prior service cost	-		(1	)
	Recognized actuarial loss	1		1
	Net periodic welfare benefit cost	$3		$3

Note_7_Debt_and_Credit_Facilit

Note 7 - Debt and Credit Facilities	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Note 7 - Debt and Credit Facilities
	The following table provides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities for the periods presented. We fully and unconditionally guarantee all debt issued by AGL Capital. For additional information on our debt, see Note 8 in our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K.
					31-Mar-15					31-Mar-14
	Dollars in millions		Year(s) due		Weighted		Outstanding		Outstanding at	Weighted		Outstanding
					average				December 31,	average
					interest rate				2014	interest rate
					-1					-1
	Short-term debt
	Commercial paper - AGL Capital (2)		2015		0.5	%	$176		$590	0.3	%	$440
	Commercial paper - Nicor Gas (2)		2015		0.4		350		585	0.2		301
	Total short-term debt				0.4	%	$526		$1,175	0.3	%	$741
	Current portion of long-term debt		2016		2.9	%	$75		$200	5	%	$200
	Long-term debt - excluding current portion
	Senior notes		2016-2043		5	%	$2,625		$2,625	5	%	$2,625
	First mortgage bonds		2016-2038		6		425		500	5.6		500
	Gas facility revenue bonds		2022-2033		0.8		200		200	0.9		200
	Medium-term notes		2017-2027		7.8		181		181	7.8		181
	Total principal long-term debt				4.9	%	3,431		3,506	4.9	%	3,506
	Fair value adjustment of long-term debt (3)		n/a		n/a		77		80	n/a		88
	Unamortized debt premium, net		n/a		n/a		16		16	n/a		16
	Total non-principal long-term debt				n/a		93		96	n/a		104
	Total long-term debt – excluding current portion						$3,524		$3,602			$3,610
	Total debt						$4,125		$4,977			$4,551
	-1	Interest rates are calculated based on the daily weighted average balance outstanding for the three months ended March 31.
	-2	As of March 31, 2015, the effective interest rates on our commercial paper borrowings were 0.5% for AGL Capital and 0.4% for Nicor Gas.
	-3	See Note 4 for additional information on our fair value measurements.
	Commercial Paper Programs
	We maintain commercial paper programs at AGL Capital and at Nicor Gas that consist of short-term, unsecured promissory notes used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are highest during the injection period in advance of the Heating Season. Nicor Gas’ commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in AGL Capital’s commercial paper program. During the first three months of 2015, our commercial paper maturities ranged from 1 to 58 days, and at March 31, 2015, remaining terms to maturity ranged from 1 to 20 days. Total borrowings and repayments netted to a payment of $649 million during the first three months of 2015. During the first three months of 2015, we had no commercial paper issuances with original maturities over three months.
	Senior Notes
	On January 15, 2015, $200 million of senior notes matured and were repaid using the proceeds from commercial paper borrowings.
	Interest Rate Swaps
	On January 23, 2015, we executed $800 million in notional value of 10 year and 30 year fixed-rate, forward-starting interest rate swaps to hedge potential interest rate volatility prior to anticipated issuances of senior notes during 2015 and 2016. These debt issuances will be used to reduce our commercial paper for the amount that was borrowed to repay our senior notes that matured in January 2015 and to fund upcoming debt maturities as well as increased capital expenditures associated with utility investment and construction of our new pipeline projects. We have designated the forward-starting interest rate swaps, which will be settled on the debt issuance dates, as cash flow hedges. We performed a qualitative assessment of effectiveness as of March 31, 2015 and concluded that the hedges remain highly effective.
	Financial and Non-Financial Covenants
	The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month; however, our goal is to maintain these ratios at levels between 50% and 60%. These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash pension adjustments, welfare benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.
			31-Mar-15		31-Dec-14		31-Mar-14
	AGL Credit Facility		50	%	55	%	54	%
	Nicor Gas Credit Facility		54	%	62	%	54	%
	The credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations and other matters customarily restricted in such agreements.
	Default Provisions
	Our credit facilities and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. The most important default events include the following:
		●	a maximum leverage ratio
		●	insolvency events and/or nonpayment of scheduled principal or interest payments
		●	acceleration of other financial obligations, and
		●	change of control provisions.
	We have no triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other triggering events. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, for all periods presented.

Note_8_Equity

Note 8 - Equity	3 Months Ended
	Mar. 31, 2015
Stockholders' Equity Note [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	Note 8 - Equity
	Our OCI (loss) amounts are aggregated within our accumulated other comprehensive loss on our unaudited Condensed Consolidated Statements of Financial Position. The following table provides changes in the components of our accumulated other comprehensive loss balances, net of the related income tax effects.
			2015						2014
	In millions (1)		Cash flow hedges		Retirement benefit plans		Total		Cash flow hedges		Retirement benefit plans		Total
	For the three months ended March 31,
	As of beginning of period		$(6	)	$(200	)	$(206	)	$1		$(137	)	$(136	)
	OCI, before reclassifications		2		-		2		4		-		4
	Amounts reclassified from accumulated OCI		-		3		3		(4	)	1		(3	)
	Net current period other comprehensive income		2		3		5		-		1		1
	As of end of period		$(4	)	$(197	)	$(201	)	$1		$(136	)	$(135	)
		-1	All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.
	The following table provides details of the reclassifications out of accumulated other comprehensive loss and the ultimate favorable (unfavorable) impact on net income for the periods presented.
			Three months ended March 31,
	In millions (1)		2015		2014
	Cash flow hedges
	Cost of goods sold (natural gas contracts)		$(1	)	$3
	Operation and maintenance expense (natural gas contracts)		-		1
	Interest expense (interest rate contracts)		1		-
	Total before income tax		-		4
	Income tax benefit		-		-
	Total cash flow hedges, net of income tax		-		4
	Retirement benefit plans
	Operation and maintenance expense (actuarial losses) (2)		(5	)	(2	)
	Total before income tax		(5	)	(2	)
	Income tax benefit		2		1
	Total retirement benefit plans		(3	)	(1	)
	Total reclassification for the period		$(3	)	$3
		-1	Amounts in parentheses indicate reductions to our net income and to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the net income impacts are immediate.
		-2	Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 6 for additional details about net periodic benefit cost.

Note_9_Nonwholly_Owned_Entitie

Note 9 - Non-wholly Owned Entities	3 Months Ended
	Mar. 31, 2015
Noncontrolling Interest [Abstract]
Noncontrolling Interest Disclosure [Text Block]	Note 9 - Non-Wholly Owned Entities
	SouthStar, a joint venture owned by us and Piedmont, is our only variable interest entity (VIE) for which we are the primary beneficiary. This requires us to consolidate its assets, liabilities, revenues and expenses. For additional information on SouthStar, see Note 10 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. Earnings from SouthStar in 2015 and 2014 were allocated entirely in accordance with the ownership interests.
	Cash flows used in our investing activities include capital expenditures for SouthStar of $1 million for the three months ended March 31, 2015, and $2 million for the three months ended March 31, 2014. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year, which generally occurs in the first quarter of each fiscal year. For the three months ended March 31, 2015 and 2014, SouthStar distributed $18 million and $17 million, respectively, to Piedmont. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. The following table provides additional information on SouthStar’s assets and liabilities as of the dates presented.
			31-Mar-15				31-Dec-14				31-Mar-14
	In millions		Consolidated	SouthStar (1)	-2%		Consolidated	SouthStar (1)	-2%		Consolidated	SouthStar (1)	-2%
	Current assets		$2,079	$182	9	%	$2,890	$238	8	%	$3,589	$235	7	%
	Goodwill and other intangible assets		1,943	119	6		1,952	125	6		1,967	131	7
	Long-term assets and other deferred debits		10,116	17	-		10,067	17	-		9,708	16	-
	Total assets		$14,138	$318	2	%	$14,909	$380	3	%	$15,264	$382	3	%
	Current liabilities		$2,371	$46	2	%	$3,219	$71	2	%	$3,754	$106	3	%
	Long-term liabilities and other deferred credits		7,803	1	-		7,862	-	-		7,667	-	-
	Total Liabilities		10,174	47	-		11,081	71	1		11,421	106	1
	Equity		3,964	271	7		3,828	309	8		3,843	276	7
	Total liabilities and equity		$14,138	$318	2	%	$14,909	$380	3	%	$15,264	$382	3	%
	-1	These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.
	-2	SouthStar’s percentage of the amount in our unaudited Condensed Consolidated Statements of Financial Position.
	The following table provides information on SouthStar’s operating revenues and operating expenses for the periods presented, which are consolidated within our unaudited Condensed Consolidated Statements of Income.
			Three months ended March 31,
	In millions		2015	2014
	Operating revenues		$311	$374
	Operating expenses
	Cost of goods sold		203	270
	Operation and maintenance		23	23
	Depreciation and amortization		2	3
	Taxes other than income taxes		1	-
	Total operating expenses		229	296
	Operating income		$82	$78
	Equity Method Investments
	For more information about our equity method investments, see Note 10 to our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K. The carrying amounts within our unaudited Condensed Consolidated Statements of Financial Position of our investments that are accounted for under the equity method were as follows:
			March 31,	December 31,	March 31,
	In millions		2015	2014	2014
	Triton		$57	$62	$67
	Horizon Pipeline		14	14	15
	Other (1)		5	4	1
	Total		$76	$80	$83
		-1	Primarily includes our current investment of $2 million in PennEast Pipeline and $3 million in Atlantic Coast Pipeline as of March 31, 2015 and $1 million and $2 million, respectively, as of December 31, 2014.
	Income from our equity method investments is classified as other income in our unaudited Condensed Consolidated Statements of Income. The following table provides the income from our equity method investments for the periods presented.
			Three months ended March 31,
	In millions		2015	2014
	Triton		$-	$2
	Horizon Pipeline		1	1
	Total		$1	$3
	In the third quarter of 2014, we entered into partnerships to form two new interstate pipeline companies within our midstream operations segment as described below. The capacity from these pipelines will further enhance system reliability as well as provide access to a more diverse supply of natural gas. We have concluded that, at present, both companies are VIEs. We are not considered the primary beneficiary and, therefore, we have not consolidated the financial statements for these companies in our unaudited condensed consolidated financial statements because we share in the ability to direct the activities that most significantly impact their economic performance with their other member companies. We have accounted for our investment in these companies using the equity method of accounting, and have classified the investment within other noncurrent assets in our unaudited Condensed Consolidated Statements of Financial Position.
	PennEast Pipeline In August 2014, we entered into a partnership in which we hold a 20% ownership interest in a new interstate pipeline company formed to develop and operate a 108-mile natural gas pipeline between New Jersey and Pennsylvania with initial transportation capacity of 1 Bcf per day, which may be expanded to 1.2 Bcf per day. Subject to FERC approval, construction is scheduled to begin in the first quarter of 2017.
	Atlantic Coast Pipeline In September 2014, we entered into a project in which we hold a 5% ownership interest to develop and operate a 550-mile natural gas pipeline in North Carolina, Virginia and West Virginia with initial transportation capacity of 1.5 Bcf per day, which may be expanded to 2.0 Bcf per day. Subject to FERC approval, construction is scheduled to begin in the second half of 2016.

Note_10_Commitments_Guarantees

Note 10 - Commitments, Guarantees and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	Note 10 - Commitments, Guarantees and Contingencies
	We incur various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.
	We also are involved in legal or administrative proceedings before various courts and agencies with respect to general claims, environmental remediation, gas cost prudence reviews and other matters. Although we are unable to determine the ultimate outcomes of these contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable. For more information on these matters, see Note 11 in our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K.
	Contingencies and Guarantees
	Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur. We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees is remote. No liability has been recorded for such guarantees and indemnifications, as the fair value was inconsequential at inception.
	Regulatory Matters
	In December 2012, we filed a petition with the Georgia Commission for approval to resolve a volumetric imbalance of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. In September 2014, we filed a stipulation that was entered between us, staff of the Georgia Commission and several Marketers that included a resolution of the 4.6 Bcf imbalance over a five-year period from January 1, 2015 through December 31, 2019. The Georgia Commission approved the stipulation in December 2014. Over the five-year period, discretionary funds available to the Universal Service Fund, which is controlled by the Georgia Commission, will be used to resolve 25% of the imbalance, or approximately 1.15 Bcf of natural gas. Atlanta Gas Light is obligated to resolve 25% of the 4.6 Bcf imbalance, or approximately 1.15 Bcf of natural gas, through system injections. The cost to resolve the remaining balance of approximately 2.3 Bcf of natural gas will be recovered from all Marketers through charges for system retained storage gas as it is used by the Marketers. As of March 31, 2015 Atlanta Gas Light had replaced approximately 15% of its 1.15 Bcf obligation and we have a reserve in our unaudited Condensed Consolidated Statements of Financial Position representing the remaining future estimated obligation.
	In August 2014, staff of the Illinois Commission and the CUB filed testimony in the 2003 gas cost prudence review disputing certain gas loan transactions offered by Nicor Gas under its Chicago Hub services requesting refunds of $18 million and $22 million, respectively. We filed surrebuttal testimony in December 2014 in this proceeding disputing that any refund is due, as Nicor Gas was authorized to enter into these transactions, and revenues associated with such transactions reduced ratepayers’ costs as either credits to the PGA or reductions to base rates consistent with then-current Illinois Commission orders governing these activities. We believe these claims engage in hindsight speculation, which is expressly prohibited in a prudence review examination, and we intend to vigorously defend against these claims. Evidentiary hearings occurred in March 2015. Post-trial briefs will be filed later in 2015 and no date has been set for a proposed decision by the Administrative Law Judges. Similar gas loan transactions were provided in other open PGA review years. The resolution will ultimately be decided by the Illinois Commission. We are currently unable to predict the ultimate outcome and have recorded no liability for this matter.
	In February 2015, Atlanta Gas Light made a filing with the Georgia Commission for a true-up recovery of $178 million related to our 15-year pipeline replacement program that ended on December 31, 2013. This recovery is for unrecovered revenue requirement for the program through December 2014. The surcharge increases proposed in the filing include an initial one-time $2.46 rate increase collected from 2016 through 2025, or an alternative phased-in schedule of four $0.58 cumulative increases in 2017, 2018, 2019 and 2020 collected through 2030. Our petition is under review, however, the Georgia Commission has not scheduled a formal proceeding for this and we are currently unable to predict the ultimate outcome of this matter.
	One of the capital projects under Atlanta Gas Light’s pipeline replacement program experienced construction issues on certain segments in late 2013, and prior to these segments being placed into service it was necessary to complete mitigation work. Atlanta Gas Light is pursuing contractual and legal claims against third party contractors responsible for the construction issues. In August, 2014, Atlanta Gas Light reached an agreement with the Georgia Commission whereby it would delay recovery of the mitigation costs to a future rate proceeding after completion of litigation and the amount of recoveries from third party contractors was known. The mitigation costs of $32 million were not included in the February 2015 true-up filing discussed above. We are currently unable to predict the ultimate outcome of this matter.
	Environmental Matters
	We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. See Note 3 for additional information on our environmental remediation costs.
	Litigation
	We are involved in litigation arising in the normal course of business. Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. Management believes that while the resolution of these contingencies, whether individually or in aggregate, could be material to earnings in a particular quarter, they will not have a material adverse effect on our consolidated financial position or cash flows for the year. For additional litigation information, see Note 11 in our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K.
	PBR Proceeding Nicor Gas’ PBR plan was a regulatory plan that provided economic incentives based on natural gas cost performance. The PBR plan went into effect in 2000 and was terminated effective January 1, 2003, following allegations that Nicor Gas acted improperly in connection with the plan. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. Since 2002, the amount of the savings and losses required to be shared has been disputed by the CUB and others, with the Illinois Attorney General intervening, and subject to extensive contested discovery and other regulatory proceedings before administrative law judges and the Illinois Commission. In 2009, the staff of the Illinois Commission, Illinois Attorney General and CUB requested refunds of $85 million, $255 million and $305 million, respectively.
	On June 7, 2013, the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas customers through our PGA mechanism based upon natural gas throughput over 12 months beginning on July 1, 2013. All refunds were completed in the first half of 2014. The CUB’s February 28, 2014 appeal of the Illinois Commission’s order requesting refunds consistent with its 2009 request was rejected by the appellate court in Illinois on March 18, 2015. The CUB could appeal this decision to the Illinois Supreme Court.

Note_11_Segment_Information

Note 11 - Segment Information	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Segment Reporting Disclosure [Text Block]	Note 11 - Segment Information
	Our reportable segments comprise revenue-generating components of the company for which we produce separate financial information internally that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through four reportable segments – distribution operations, retail operations, wholesale services and midstream operations. Our non-reportable segments are combined and presented as “other segments.”
	Effective September 1, 2014, we closed on the sale of Tropical Shipping, which operated within our former cargo shipping segment. The assets and liabilities of these businesses as of March 31, 2014 are classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position, and the financial results of these businesses for the three months ended March 31, 2014 are reflected as discontinued operations on the unaudited Condensed Consolidated Statements of Income. Amounts shown in this note, unless otherwise indicated, exclude assets held for sale and discontinued operations. Cargo shipping also included our investment in Triton, which was not part of the sale and has been reclassified to a non-reportable segment. See Note 12 for additional information on our discontinued operations.
	Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities that construct, manage and maintain intrastate natural gas pipelines and distribution facilities in seven states. Although the operations of distribution operations are geographically dispersed, the operating subsidiaries within the distribution operations segment are regulated utilities with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.
	We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, retail operations provides home protection products and services. Our wholesale services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, this segment provides natural gas asset management and/or related logistics services for each of our utilities except Nicor Gas, as well as for non-affiliated companies. Our midstream operations segment includes our non-utility storage and pipeline operations, including the operation of high-deliverability natural gas storage assets. Our “other” non-reportable segments include subsidiaries that individually are not significant on a stand-alone basis and that do not fit into one of our reportable segments.
	The chief operating decision maker of the company is the Chairman, President and Chief Executive Officer, who utilizes EBIT as the primary measure of profit and loss in assessing the results of each segment’s operations. EBIT includes operating income and other income and expenses. Items we do not include in EBIT are income taxes and financing costs, including interest expense, each of which we evaluate on a consolidated basis. Summarized Statements of Income, Statements of Financial Position and capital expenditure information by segment as of and for the periods presented are shown in the following tables.
	Three months ended March 31, 2015
	In millions		Distribution		Retail	Wholesale	Midstream		Other		Intercompany eliminations		Consolidated
			operations		operations	services (1)	operations		segments (2)
	Operating revenues from external parties		$1,285		$341	$90	$19		$6		$(20	)	$1,721
	Intercompany revenues		56		-	-	-		-		(56	)	-
	Total operating revenues		1,341		341	90	19		6		(76	)	1,721
	Operating expenses
	Cost of goods sold		776		210	9	10		5		(75	)	935
	Operation and maintenance		185		37	24	6		(2	)	(1	)	249
	Depreciation and amortization		82		6	-	5		4		-		97
	Taxes other than income taxes		71		1	1	1		2		-		76
	Total operating expenses		1,114		254	34	22		9		(76	)	1,357
	Operating income (loss)		227		87	56	(3	)	(3	)	-		364
	Other income		1		-	-	1		1		-		3
	EBIT		$228		$87	$56	$(2	)	$(2	)	$-		$367
	Identifiable and total assets (3)		$11,899		$1,100	$698	$693		$9,052		$(9,304	)	$14,138
	Capital expenditures		$170		$2	$1	$3		$12		$-		$188
	Three months ended March 31, 2014
	In millions		Distribution		Retail	Wholesale	Midstream		Other		Intercompany eliminations		Consolidated
			operations		operations	services (1)	operations		segments (2)
	Operating revenues from external parties		$1,726		$406	$331	$44		$3		$(48	)	$2,462
	Intercompany revenues		75		-	-	-		-		(75	)	-
	Total operating revenues		1,801		406	331	44		3		(123	)	2,462
	Operating expenses
	Cost of goods sold		1,202		280	3	36		-		(121	)	1,400
	Operation and maintenance		211		37	36	6		1		(2	)	289
	Depreciation and amortization		78		8	-	5		2		-		93
	Taxes other than income taxes		82		1	1	1		3		-		88
	Total operating expenses		1,573		326	40	48		6		(123	)	1,870
	Operating income (loss)		228		80	291	(4	)	(3	)	-		592
	Other income		1		-	-	1		1		-		3
	EBIT		$229		$80	$291	$(3	)	$(2	)	$-		$595
	Identifiable and total assets (3)		$11,823		$738	$1,782	$698		$9,844		$(9,885	)	$15,000
	Capital expenditures		$150		$3	$1	$-		$7		$-		$161
	-1	The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.
	In millions		Third party gross revenues		Intercompany revenues	Total gross revenues	Less gross gas costs		Operating revenues
	Three months ended March 31, 2015		$2,146		$150	$2,296	$2,206		$90
	Three months ended March 31, 2014		4,049		298	4,347	4,016		331
	-2	Our other non-reportable segments include our investment in Triton, which was part of our cargo shipping segment that is classified as discontinued operations. For more information, see Note 12.
	-3	Identifiable assets are those used in each segment’s operations. Amounts as of March 31, 2014 exclude assets held for sale.
	Information by segment on our Consolidated Statements of Financial Position as of December 31, 2014, is as follows:
	In millions		Identifiable and
			total assets
	Distribution operations		$12,041
	Retail operations		670
	Wholesale services		1,402
	Midstream operations		694
	Other segments		9,723
	Intercompany elimination		(9,621	)
	Consolidated		$14,909

Note_12_Discontinued_Operation

Note 12 - Discontinued Operations	3 Months Ended
	Mar. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Note 12 - Discontinued Operations
	On September 1, 2014, we closed on the sale of Tropical Shipping to an unrelated third party. The after-tax cash proceeds and distributions from the transaction were approximately $225 million. We determined that the cumulative foreign earnings of Tropical Shipping would no longer be indefinitely reinvested offshore. Accordingly, we recognized income tax expense of $60 million, of which $31 million was recorded in the first quarter of 2014, and the remaining $29 million was recorded in the third quarter of 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in our repatriation of $86 million in cash.
	During the first quarter of 2014, based upon the negotiated sales price, we also recorded a goodwill impairment charge of $19 million, for which there was no income tax benefit. Additionally, we recognized a total of $7 million charge in the second and third quarters of 2014 related to the suspension of depreciation and amortization for assets that we were not compensated for by the buyer. The assets and liabilities of Tropical Shipping classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position are as follows:
		March 31,
	In millions	2014
	Current assets
	Cash and cash equivalents	$26
	Short-term investments	3
	Receivables	34
	Inventories	9
	Other	2
	Total current assets	74
	Long-term assets and other deferred debits
	Property, plant and equipment, net	123
	Goodwill	42
	Intangible assets	19
	Other	6
	Total long-term assets and other deferred debits	190
	Total assets held for sale	$264
	Current liabilities
	Other accounts payable – trade	$9
	Accrued expenses	4
	Other	23
	Total liabilities held for sale	$36
	The financial results of these businesses are reflected as discontinued operations, and the prior period presented has been recast to reflect the discontinued operations. The components of discontinued operations recorded on the unaudited Condensed Consolidated Statements of Income are as follows:
		Three months ended
	In millions	31-Mar-14
	Operating revenues	$89
	Operating expenses
	Cost of goods sold	54
	Operation and maintenance	28
	Depreciation and amortization	5
	Taxes other than income taxes	1
	Loss on sale and goodwill impairment	19
	Total operating expenses	107
	Operating loss	(18	)
	Loss before income taxes	(18	)
	Income tax expense	(32	)
	Loss from discontinued operations, net of tax	$(50	)

Accounting_Policies_by_Policy_

Accounting Policies, by Policy (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation
	Our unaudited condensed consolidated financial statements include our accounts, the accounts of our wholly owned subsidiaries, the accounts of our majority owned or otherwise controlled subsidiaries and the accounts of our variable interest entity, SouthStar, for which we are the primary beneficiary. For unconsolidated entities that we do not control, we use the equity method of accounting and our proportionate share of income or loss is recorded on the unaudited Condensed Consolidated Statements of Income. See Note 9 for additional information. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts is probable under the affiliates’ rate regulation process.
	In November 2014, we filed a Form 10-Q/A to revise our March 31, 2014 financial statements and other affected disclosures for items related to the recognition of revenues for certain of our regulatory infrastructure programs and the amortization of our intangible assets as originally filed in our Form 10-Q for the period ended March 31, 2014. Our financial statements for the period ended March 31, 2014, reflect the revised amounts reported in our 2014 Form 10-Q/A.
	In September 2014, we closed on the sale of Tropical Shipping, which operated within our former cargo shipping segment. The assets and liabilities of these businesses as of March 31, 2014 are classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position, and the financial results of these businesses for the three months ended March 31, 2014 are reflected as discontinued operations on the unaudited Condensed Consolidated Statements of Income. Amounts shown in the following notes, unless otherwise indicated, exclude assets held for sale and discontinued operations. Cargo shipping also included our investment in Triton, which was not part of the sale and has been reclassified into our “other” non-reportable segments. See Note 12 for additional information on the sale of Tropical Shipping.
Use of Estimates, Policy [Policy Text Block]	Use of Accounting Estimates
	The preparation of our financial statements in conformity with GAAP requires us to use judgment and make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing accounting literature or in the development of estimates that impact our financial statements. The most significant estimates relate to the accounting for our rate-regulated subsidiaries, goodwill and other intangible assets, derivative and hedging activities, uncollectible accounts and other allowances for contingent losses, retirement plan benefit obligations and provisions for income taxes. We evaluate our estimates on an ongoing basis, and our actual results could differ from our estimates.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents
	Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of March 31, 2014, there was $26 million of cash and cash equivalents held by Tropical Shipping that was excluded from cash and cash equivalents within our unaudited Condensed Consolidated Statements of Financial Position and included in assets held for sale. For more information on the sale of Tropical Shipping, see Note 12.
Energy Marketing Receivables And Payables [Policy Text Block]	Energy Marketing Receivables and Payables
	Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing trade payables.
	Our wholesale services segment has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of March 31, 2015 and 2014, and December 31, 2014, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.
Inventory, Policy [Policy Text Block]	Inventories
	For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 10 for information regarding a regulatory filing by Atlanta Gas Light related to natural gas inventory.
	Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are expected to be restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO inventory liquidation. Any temporary LIFO liquidation is included as a current liability in our unaudited Condensed Consolidated Statements of Financial Position. Interim inventory decrements that are not expected to be restored prior to year end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of March 31, 2015 is expected to be restored prior to year-end. The inventory decrement as of March 31, 2014 was restored prior to December 31, 2014.
	Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For these segments, we evaluate the weighted average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, we record pre-tax adjustments to our unaudited Condensed Consolidated Statements of Income to reduce the weighted average cost of the natural gas inventory to market value. For the three months ended March 31, 2015 and 2014, we had LOCOM adjustments primarily at wholesale services of $10 million and $2 million, respectively.
	Additionally, we have $12 million of inventory at wholesale services that is currently inaccessible due to operational issues at a third party storage facility. The owner of the storage facility is working to resolve these issues. While we expect this inventory to be fully recovered, the timing of withdrawal of this gas may be impacted by the operational issues.
Public Utilities, Policy [Policy Text Block]	Regulated Operations
	We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for estimated expenditures that have not yet been incurred. Generally, regulatory assets and regulatory liabilities are amortized into our unaudited Condensed Consolidated Statements of Income over the period authorized by the regulatory commissions.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value Measurements
	We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents, and derivative assets and liabilities. The carrying values of receivables, short- and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate fair value. Our nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 4 to our consolidated financial statements and in related notes included in Item 8 of our 2014 Form 10-K.
	Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observance of those inputs in accordance with the fair value hierarchy.
Derivatives, Policy [Policy Text Block]	Derivative Instruments
	The fair values of the natural gas and weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflect the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We also use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the life of the related debt. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 and Note 5 for additional derivative disclosures.
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	Goodwill
	We perform an annual goodwill impairment test on our reporting units that contain goodwill during the fourth quarter of each year, or more frequently if impairment indicators arise. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. To estimate the fair value of our reporting units, we use two generally accepted valuation approaches, the income approach and the market approach, using assumptions consistent with a market participant’s perspective. The results of the two valuation approaches are weighted to estimate the fair value of each reporting unit. There were no triggering events during the current period that would require us to perform an interim impairment test. The amounts of goodwill as of March 31, 2015 and 2014, and December 31, 2014 are provided below.
	In millions		Distribution	Retail		Midstream	Consolidated
			operations	operations		operations
	Goodwill		$1,640	$173		$14	$1,827
Earnings Per Share, Policy [Policy Text Block]	Earnings Per Common Share
	We compute basic earnings per common share attributable to AGL Resources Inc. by dividing our net income attributable to the common shareholders of AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. that occurs when the exercise and/or conversion of all potentially dilutive common shares is added to the common shares outstanding.
	We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. for the periods presented as if performance units currently earned under the plan ultimately vest and as if stock options currently exercisable at prices below the average market prices are exercised.
			Three months ended March 31,
	In millions (except per share amounts)		2015	2014
	Income from continuing operations attributable to AGL Resources Inc.		$193	$334
	Loss from discontinued operations, net of tax		-	(50	)
	Net income attributable to AGL Resources Inc.		$193	$284
	Denominator:
	Basic weighted average number of common shares outstanding (1)		119.3	118.5
	Effect of dilutive securities		0.3	0.4
	Diluted weighted average number of common shares outstanding (2)		119.6	118.9
	Basic earnings per common share
	Continuing operations		$1.62	$2.82
	Discontinued operations		-	(0.43	)
	Basic earnings per common share attributable to AGL Resources Inc.		$1.62	$2.39
	Diluted earnings per common share (2)
	Continuing operations		$1.62	$2.81
	Discontinued operations		-	(0.43	)
	Diluted earnings per common share attributable to AGL Resources Inc.		$1.62	$2.38
		-1	Daily weighted average shares outstanding.
		-2	There were no outstanding stock options excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. for any of the periods presented because their effect would have been anti-dilutive as the exercise prices were greater than the average market price.
New Accounting Pronouncements, Policy [Policy Text Block]	Accounting Developments
	In February 2015, the FASB issued updated authoritative guidance related to the consolidation of other legal entities into our financial statements. The amendments modify aspects of the consolidation determination that could potentially impact us, including the analysis of limited partnerships and similar legal entities, fee arrangements, and related party relationships. The guidance will be effective for us beginning January 1, 2016. Early adoption is permitted. We may elect to apply the new guidance either retrospectively to each prior period presented or via a cumulative effect adjustment upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method.
	In April 2015, the FASB issued updated authoritative guidance related to debt issuance costs. The amendment modifies the presentation of unamortized debt issuance costs on our consolidated statements of financial position. Under the new guidance, we will present such amounts as a direct deduction from the face amount of the debt, similar to unamortized debt discounts and premiums, rather than as an asset. Amortization of the debt issuance costs will continue to be reported as interest expense. The guidance will be effective for us beginning January 1, 2016. Early adoption is permitted. The new guidance must be applied retrospectively to each prior period presented. We have determined that the impact of this new guidance will not be material.
	In April 2015, the FASB issued authoritative guidance related to the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense of the period incurred. The new guidance may be applied either prospectively or retrospectively, is effective for us beginning January 1, 2016, and early adoption is permitted. We are currently evaluating our software arrangements in light of the new guidance.

Note_2_Significant_Accounting_1

Note 2 - Significant Accounting Policies and Methods of Application (Tables)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Schedule of Goodwill [Table Text Block]	In millions	Distribution	Retail		Midstream	Consolidated
		operations	operations		operations
	Goodwill	$1,640	$173		$14	$1,827
Schedule of Weighted Average Number of Shares [Table Text Block]		Three months ended March 31,
	In millions (except per share amounts)	2015	2014
	Income from continuing operations attributable to AGL Resources Inc.	$193	$334
	Loss from discontinued operations, net of tax	-	(50	)
	Net income attributable to AGL Resources Inc.	$193	$284
	Denominator:
	Basic weighted average number of common shares outstanding (1)	119.3	118.5
	Effect of dilutive securities	0.3	0.4
	Diluted weighted average number of common shares outstanding (2)	119.6	118.9
	Basic earnings per common share
	Continuing operations	$1.62	$2.82
	Discontinued operations	-	(0.43	)
	Basic earnings per common share attributable to AGL Resources Inc.	$1.62	$2.39
	Diluted earnings per common share (2)
	Continuing operations	$1.62	$2.81
	Discontinued operations	-	(0.43	)
	Diluted earnings per common share attributable to AGL Resources Inc.	$1.62	$2.38

Note_3_Regulated_Operations_Ta

Note 3 - Regulated Operations (Tables)	3 Months Ended
	Mar. 31, 2015
Note 3 - Regulated Operations (Tables) [Line Items]
Schedule of Regulatory Assets [Table Text Block]	In millions	31-Mar-15	31-Dec-14	31-Mar-14
	Regulatory assets
	Recoverable ERC	$37	$49	$38
	Recoverable pension and retiree welfare benefit costs	11	12	9
	Deferred natural gas costs	7	3	161
	Recoverable seasonal rates	-	10	-
	Other	8	9	42
	Total regulatory assets - current	63	83	250
	Recoverable ERC	331	326	419
	Recoverable pension and retiree welfare benefit costs	108	110	97
	Recoverable regulatory infrastructure program costs	73	69	57
	Long-term debt fair value adjustment	72	74	80
	Other	50	52	43
	Total regulatory assets - long-term	634	631	696
	Total regulatory assets	$697	$714	$946
	Regulatory liabilities
	Accrued natural gas costs	$53	$27	$24
	Bad debt over collection	30	33	41
	Accumulated removal costs	25	25	27
	Deferred seasonal rates	20	-	20
	Other	40	27	49
	Total regulatory liabilities - current	168	112	161
	Accumulated removal costs	1,524	1,520	1,456
	Regulatory income tax liability	27	34	27
	Unamortized investment tax credit	22	22	25
	Bad debt over collection	19	12	14
	Other	20	13	28
	Total regulatory liabilities - long-term	1,612	1,601	1,550
	Total regulatory liabilities	$1,780	$1,713	$1,711
Environmental Exit Costs by Cost [Table Text Block]	In millions	# of	Probabilistic model cost estimates	Engineering	Amount	Expected costs over	Cost recovery
		sites		estimates	recorded	next 12 months	period
	Illinois (1)	26	$208 - $466	$43	$242	$45	As incurred
	New Jersey	6	105-177	14	112	14	7 years
	Georgia and Florida	13	40 -81	15	55	26	5 years
	North Carolina (2)	1	n/a	10	10	8	No recovery
	Total	46	$353 - $724	$82	$419	$93
Regulatory Asset Off Balance Sheet [Member]
Note 3 - Regulated Operations (Tables) [Line Items]
Schedule of Regulatory Assets [Table Text Block]	In millions	Atlanta Gas Light	Virginia Natural Gas	Elizabethtown Gas	Total
	31-Mar-15	$119	$12	$2	$133
	31-Dec-14	113	12	2	127
	31-Mar-14	88	12	2	102

Note_4_Fair_Value_Measurements1

Note 4 - Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2015
Note 4 - Fair Value Measurements (Tables) [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	In millions	31-Mar-15	31-Dec-14		31-Mar-14
	Long-term debt carrying amount	$3,599	$3,802		$3,810
	Long-term debt fair value (1)	4,102	4,231		4,095
Natural Gas and Interest Rate Derivatives [Member]
Note 4 - Fair Value Measurements (Tables) [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]		31-Mar-15			31-Dec-14			31-Mar-14
	In millions	Assets (1)	Liabilities		Assets (1)	Liabilities		Assets (1)	Liabilities
	Quoted prices in active markets (Level 1)	$-	$(106	)	$58	$(80	)	$18	$(38	)
	Significant other observable inputs (Level 2)	108	(52	)	174	(94	)	50	(75	)
	Netting of cash collateral	104	106		52	81		69	31
	Total carrying value (2)	$212	$(52	)	$284	$(93	)	$137	$(82	)

Note_5_Derivative_Instruments_

Note 5 - Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	In Bcf (1)		March 31, 2015 (2)			31-Dec-14			31-Mar-14
	Cash flow hedges		9			9			6
	Not designated as hedges		231			75			277
	Total volumes		240			84			283
	Short position – cash flow hedges		(6	)		(7	)		(2	)
	Short position – not designated as hedges		(2,735	)		(2,825	)		(2,489	)
	Long position – cash flow hedges		15			16			8
	Long position – not designated as hedges		2,966			2,900			2,766
	Net long position		240			84			283
Loss Recognized In Income [Table Text Block]			Three months ended
			March 31,
	In millions		2015			2014
	Nicor Gas		$(3	)		$2
	Elizabethtown Gas		(4	)		3
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]				March 31,						December 31,				March 31,
				2015						2014				2014
	In millions	Classification		Assets			Liabilities			Assets		Liabilities		Assets		Liabilities
	Designated as cash flow or fair value hedges
	Natural gas contracts	Current		$-			$(6	)		$6		$(11	)	$2		$-
	Natural gas contracts	Long-term		-			(1	)		-		(1	)	-		-
	Interest rate swap agreements	Current		1			-			-		-		-		-
	Interest rate swap agreements	Long-term		3			-			-		-		-		-
	Total designated as cash flow or fair value hedges			$4			$(7	)		$6		$(12	)	$2		$-
	Not designated as hedges
	Natural gas contracts	Current		$557			$(592	)		$1,061		$(1,020	)	$675		$(703	)
	Natural gas contracts	Long-term		98			(109	)		145		(119	)	80		(98	)
	Total not designated as hedges			$655			$(701	)		$1,206		$(1,139	)	$755		$(801	)
	Gross amount of recognized assets and liabilities (1) (2)			659			(708	)		1,212		(1,151	)	757		(801	)
	Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)			(446	)		656			(925	)	1,058		(619	)	719
	Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)			$213			$(52	)		$287		$(93	)	$138		$(82	)
Schedule of Derivative Instruments [Table Text Block]			Three months ended March 31,
	In millions		2015			2014
	Designated as cash flow or fair value hedges
	Natural gas contracts - net (loss) gain reclassified from OCI into cost of goods sold		$(1	)		$3
	Natural gas contracts - net gain reclassified from OCI into operation and maintenance expense		-			1
	Interest rate swaps - net gain reclassified from OCI into interest expense		1			-
	Income tax benefit		-			-
	Total designated as cash flow or fair value hedges, net of tax		-			4
	Not designated as hedges (1)
	Natural gas contracts - net (loss) recorded in operating revenues		(24	)		(30	)
	Natural gas contracts - net (loss) gain recorded in cost of goods sold (2)		(2	)		2
	Income tax benefit		10			11
	Total not designated as hedges, net of tax		(16	)		(17	)
	Total gains (losses) on derivative instruments, net of tax		$(16	)		$(13	)

Note_6_Employee_Benefit_Plans_

Note 6 - Employee Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Schedule of Net Benefit Costs [Table Text Block]		Three months ended March 31,
	In millions	2015		2014
	Service cost	$7		$6
	Interest cost	11		12
	Expected return on plan assets	(16	)	(16	)
	Net amortization of prior service cost	(1	)	-
	Recognized actuarial loss	8		5
	Net periodic pension benefit cost	$9		$7
		Three months ended March 31,
	In millions	2015		2014
	Service cost	$1		$1
	Interest cost	3		4
	Expected return on plan assets	(2	)	(2	)
	Net amortization of prior service cost	-		(1	)
	Recognized actuarial loss	1		1
	Net periodic welfare benefit cost	$3		$3

Note_7_Debt_and_Credit_Facilit1

Note 7 - Debt and Credit Facilities (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Schedule of Debt [Table Text Block]				31-Mar-15					31-Mar-14
	Dollars in millions	Year(s) due		Weighted		Outstanding		Outstanding at	Weighted		Outstanding
				average				December 31,	average
				interest rate				2014	interest rate
				-1					-1
	Short-term debt
	Commercial paper - AGL Capital (2)	2015		0.5	%	$176		$590	0.3	%	$440
	Commercial paper - Nicor Gas (2)	2015		0.4		350		585	0.2		301
	Total short-term debt			0.4	%	$526		$1,175	0.3	%	$741
	Current portion of long-term debt	2016		2.9	%	$75		$200	5	%	$200
	Long-term debt - excluding current portion
	Senior notes	2016-2043		5	%	$2,625		$2,625	5	%	$2,625
	First mortgage bonds	2016-2038		6		425		500	5.6		500
	Gas facility revenue bonds	2022-2033		0.8		200		200	0.9		200
	Medium-term notes	2017-2027		7.8		181		181	7.8		181
	Total principal long-term debt			4.9	%	3,431		3,506	4.9	%	3,506
	Fair value adjustment of long-term debt (3)	n/a		n/a		77		80	n/a		88
	Unamortized debt premium, net	n/a		n/a		16		16	n/a		16
	Total non-principal long-term debt			n/a		93		96	n/a		104
	Total long-term debt – excluding current portion					$3,524		$3,602			$3,610
	Total debt					$4,125		$4,977			$4,551
Schedule of Capitalization [Table Text Block]		31-Mar-15		31-Dec-14		31-Mar-14
	AGL Credit Facility	50	%	55	%	54	%
	Nicor Gas Credit Facility	54	%	62	%	54	%

Note_8_Equity_Tables

Note 8 - Equity (Tables)	3 Months Ended
	Mar. 31, 2015
Stockholders' Equity Note [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]		2015						2014
	In millions (1)	Cash flow hedges		Retirement benefit plans		Total		Cash flow hedges		Retirement benefit plans		Total
	For the three months ended March 31,
	As of beginning of period	$(6	)	$(200	)	$(206	)	$1		$(137	)	$(136	)
	OCI, before reclassifications	2		-		2		4		-		4
	Amounts reclassified from accumulated OCI	-		3		3		(4	)	1		(3	)
	Net current period other comprehensive income	2		3		5		-		1		1
	As of end of period	$(4	)	$(197	)	$(201	)	$1		$(136	)	$(135	)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]		Three months ended March 31,
	In millions (1)	2015		2014
	Cash flow hedges
	Cost of goods sold (natural gas contracts)	$(1	)	$3
	Operation and maintenance expense (natural gas contracts)	-		1
	Interest expense (interest rate contracts)	1		-
	Total before income tax	-		4
	Income tax benefit	-		-
	Total cash flow hedges, net of income tax	-		4
	Retirement benefit plans
	Operation and maintenance expense (actuarial losses) (2)	(5	)	(2	)
	Total before income tax	(5	)	(2	)
	Income tax benefit	2		1
	Total retirement benefit plans	(3	)	(1	)
	Total reclassification for the period	$(3	)	$3

Note_9_Nonwholly_Owned_Entitie1

Note 9 - Non-wholly Owned Entities (Tables)	3 Months Ended
	Mar. 31, 2015
Noncontrolling Interest [Abstract]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Table Text Block]		31-Mar-15				31-Dec-14				31-Mar-14
	In millions	Consolidated	SouthStar (1)	-2%		Consolidated	SouthStar (1)	-2%		Consolidated	SouthStar (1)	-2%
	Current assets	$2,079	$182	9	%	$2,890	$238	8	%	$3,589	$235	7	%
	Goodwill and other intangible assets	1,943	119	6		1,952	125	6		1,967	131	7
	Long-term assets and other deferred debits	10,116	17	-		10,067	17	-		9,708	16	-
	Total assets	$14,138	$318	2	%	$14,909	$380	3	%	$15,264	$382	3	%
	Current liabilities	$2,371	$46	2	%	$3,219	$71	2	%	$3,754	$106	3	%
	Long-term liabilities and other deferred credits	7,803	1	-		7,862	-	-		7,667	-	-
	Total Liabilities	10,174	47	-		11,081	71	1		11,421	106	1
	Equity	3,964	271	7		3,828	309	8		3,843	276	7
	Total liabilities and equity	$14,138	$318	2	%	$14,909	$380	3	%	$15,264	$382	3	%
Schedule of Variable Interest Entities [Table Text Block]		Three months ended March 31,
	In millions	2015	2014
	Operating revenues	$311	$374
	Operating expenses
	Cost of goods sold	203	270
	Operation and maintenance	23	23
	Depreciation and amortization	2	3
	Taxes other than income taxes	1	-
	Total operating expenses	229	296
	Operating income	$82	$78
Equity Method Investments [Table Text Block]		March 31,	December 31,	March 31,
	In millions	2015	2014	2014
	Triton	$57	$62	$67
	Horizon Pipeline	14	14	15
	Other (1)	5	4	1
	Total	$76	$80	$83
Schedule of Other Nonoperating Income, by Component [Table Text Block]		Three months ended March 31,
	In millions	2015	2014
	Triton	$-	$2
	Horizon Pipeline	1	1
	Total	$1	$3

Note_11_Segment_Information_Ta

Note 11 - Segment Information (Tables)	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	In millions	Distribution		Retail	Wholesale	Midstream		Other		Intercompany eliminations		Consolidated
		operations		operations	services (1)	operations		segments (2)
	Operating revenues from external parties	$1,285		$341	$90	$19		$6		$(20	)	$1,721
	Intercompany revenues	56		-	-	-		-		(56	)	-
	Total operating revenues	1,341		341	90	19		6		(76	)	1,721
	Operating expenses
	Cost of goods sold	776		210	9	10		5		(75	)	935
	Operation and maintenance	185		37	24	6		(2	)	(1	)	249
	Depreciation and amortization	82		6	-	5		4		-		97
	Taxes other than income taxes	71		1	1	1		2		-		76
	Total operating expenses	1,114		254	34	22		9		(76	)	1,357
	Operating income (loss)	227		87	56	(3	)	(3	)	-		364
	Other income	1		-	-	1		1		-		3
	EBIT	$228		$87	$56	$(2	)	$(2	)	$-		$367
	Identifiable and total assets (3)	$11,899		$1,100	$698	$693		$9,052		$(9,304	)	$14,138
	Capital expenditures	$170		$2	$1	$3		$12		$-		$188
	In millions	Distribution		Retail	Wholesale	Midstream		Other		Intercompany eliminations		Consolidated
		operations		operations	services (1)	operations		segments (2)
	Operating revenues from external parties	$1,726		$406	$331	$44		$3		$(48	)	$2,462
	Intercompany revenues	75		-	-	-		-		(75	)	-
	Total operating revenues	1,801		406	331	44		3		(123	)	2,462
	Operating expenses
	Cost of goods sold	1,202		280	3	36		-		(121	)	1,400
	Operation and maintenance	211		37	36	6		1		(2	)	289
	Depreciation and amortization	78		8	-	5		2		-		93
	Taxes other than income taxes	82		1	1	1		3		-		88
	Total operating expenses	1,573		326	40	48		6		(123	)	1,870
	Operating income (loss)	228		80	291	(4	)	(3	)	-		592
	Other income	1		-	-	1		1		-		3
	EBIT	$229		$80	$291	$(3	)	$(2	)	$-		$595
	Identifiable and total assets (3)	$11,823		$738	$1,782	$698		$9,844		$(9,885	)	$15,000
	Capital expenditures	$150		$3	$1	$-		$7		$-		$161
Reconciliation of Revenue from Segments to Consolidated [Table Text Block]	In millions	Third party gross revenues		Intercompany revenues	Total gross revenues	Less gross gas costs		Operating revenues
	Three months ended March 31, 2015	$2,146		$150	$2,296	$2,206		$90
	Three months ended March 31, 2014	4,049		298	4,347	4,016		331
Schedule of Segment Reporting Information by Segment Total Assets Goodwill [Table Text Block]	In millions	Identifiable and
		total assets
	Distribution operations	$12,041
	Retail operations	670
	Wholesale services	1,402
	Midstream operations	694
	Other segments	9,723
	Intercompany elimination	(9,621	)
	Consolidated	$14,909

Note_12_Discontinued_Operation1

Note 12 - Discontinued Operations (Tables)	3 Months Ended
	Mar. 31, 2015
Balance Sheet [Member]
Note 12 - Discontinued Operations (Tables) [Line Items]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]		March 31,
	In millions	2014
	Current assets
	Cash and cash equivalents	$26
	Short-term investments	3
	Receivables	34
	Inventories	9
	Other	2
	Total current assets	74
	Long-term assets and other deferred debits
	Property, plant and equipment, net	123
	Goodwill	42
	Intangible assets	19
	Other	6
	Total long-term assets and other deferred debits	190
	Total assets held for sale	$264
	Current liabilities
	Other accounts payable – trade	$9
	Accrued expenses	4
	Other	23
	Total liabilities held for sale	$36
Income Statement [Member]
Note 12 - Discontinued Operations (Tables) [Line Items]
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]		Three months ended
	In millions	31-Mar-14
	Operating revenues	$89
	Operating expenses
	Cost of goods sold	54
	Operation and maintenance	28
	Depreciation and amortization	5
	Taxes other than income taxes	1
	Loss on sale and goodwill impairment	19
	Total operating expenses	107
	Operating loss	(18	)
	Loss before income taxes	(18	)
	Income tax expense	(32	)
	Loss from discontinued operations, net of tax	$(50	)

Note_2_Significant_Accounting_2

Note 2 - Significant Accounting Policies and Methods of Application (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Note 2 - Significant Accounting Policies and Methods of Application (Details) [Line Items]
Inventory Valuation Reserves	$10	$2
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in Shares)	0	0
Inaccessible [Member]
Note 2 - Significant Accounting Policies and Methods of Application (Details) [Line Items]
Inventory, Gross	12
Tropical Shipping [Member]
Note 2 - Significant Accounting Policies and Methods of Application (Details) [Line Items]
Investments and Cash		$26

Note_2_Significant_Accounting_3

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Changes in Amount of Goodwill (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
In Millions, unless otherwise specified
Goodwill [Line Items]
Goodwill	$1,827	$1,827	$1,827
Distribution Operations [Member]
Goodwill [Line Items]
Goodwill	1,640
Retail Operations [Member]
Goodwill [Line Items]
Goodwill	173
Midstream Operations [Member]
Goodwill [Line Items]
Goodwill	$14

Note_2_Significant_Accounting_4

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Potentially Dilutive Common Share Calculation (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Potentially Dilutive Common Share Calculation [Abstract]
Income from continuing operations attributable to AGL Resources Inc. (in Dollars)	$193		$334
Loss from discontinued operations, net of tax (in Dollars)			-50
Net income attributable to AGL Resources Inc. (in Dollars)	$193		$284
Basic weighted average number of common shares outstanding (1) (in Shares)	119.3	[1]	118.5	[1]
Effect of dilutive securities (in Shares)	0.3		0.4
Diluted weighted average number of common shares outstanding (2) (in Shares)	119.6	[2]	118.9	[2]
Basic earnings per common share
Continuing operations	$1.62		$2.82
Discontinued operations			($0.43)
Basic earnings per common share attributable to AGL Resources Inc.	$1.62		$2.39
Diluted earnings per common share (2)
Continuing operations	$1.62	[2]	$2.81	[2]
Discontinued operations		[2]	($0.43)	[2]
Diluted earnings per common share attributable to AGL Resources Inc.	$1.62		$2.38
[1]	Daily weighted average shares outstanding.
[2]	There were no outstanding stock options excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. for any of the periods presented because their effect would have been anti-dilutive as the exercise prices were greater than the average market price.

Note_3_Regulated_Operations_De

Note 3 - Regulated Operations (Details) (USD $)	1 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Jul. 31, 2014	Sep. 30, 2014	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
Note 3 - Regulated Operations (Details) [Line Items]
Regulatory Assets, Current (in Dollars)			$63	$83	$250
Number of Former Operating Sites			46
Increase (Decrease) in Insurance Settlements Receivable (in Dollars)	77
Insurance Settlements Receivable, Number of Installments	2
Proceeds from Insurance Settlement, Operating Activities (in Dollars)		45
Insurance Settlements Receivable, Current (in Dollars)			32
Recoverable ERC Assets [Member]
Note 3 - Regulated Operations (Details) [Line Items]
Regulatory Assets, Current (in Dollars)			$37
Nicor Gas [Member]
Note 3 - Regulated Operations (Details) [Line Items]
Number of Former Operating Sites			26
Number of Sites with Completed Cleanups			2
Number of Sites with Cleanup Responsibility			23
Cleanup Costs Allocated Percentage			52.00%

Note_3_Regulated_Operations_De1

Note 3 - Regulated Operations (Details) - Summary of Regulatory Assets and Liabilities (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
In Millions, unless otherwise specified
Regulatory assets
Regulatory assets - current	$63	$83	$250
Regulatory assets - long-term	634	631	696
Total regulatory assets	697	714	946
Regulatory liabilities
Regulatory liabilities - current	168	112	161
Regulatory liabilities - long-term	1,612	1,601	1,550
Total regulatory liabilities	1,780	1,713	1,711
Accrued natural gas costs [Member]
Regulatory liabilities
Regulatory liabilities - current	53	27	24
Bad debt rider [Member]
Regulatory liabilities
Regulatory liabilities - current	30	33	41
Regulatory liabilities - long-term	19	12	14
Accumulated removal costs [Member]
Regulatory liabilities
Regulatory liabilities - current	25	25	27
Regulatory liabilities - long-term	1,524	1,520	1,456
Deferred Seasonal Rates [Member]
Regulatory liabilities
Regulatory liabilities - current	20		20
Other Regulatory Liabilities [Member]
Regulatory liabilities
Regulatory liabilities - current	40	27	49
Regulatory liabilities - long-term	20	13	28
Regulatory Income Tax Liability [Member]
Regulatory liabilities
Regulatory liabilities - long-term	27	34	27
Unamortized investment tax credit [Member]
Regulatory liabilities
Regulatory liabilities - long-term	22	22	25
Recoverable Environmental Remediation Costs [Member]
Regulatory assets
Regulatory assets - current	37	49	38
Regulatory assets - long-term	331	326	419
Recoverable Pension and Other Retirement Benefit Costs [Member]
Regulatory assets
Regulatory assets - current	11	12	9
Regulatory assets - long-term	108	110	97
Deferred Natural Gas Costs [Member]
Regulatory assets
Regulatory assets - current	7	3	161
Seasonal Rates [Member]
Regulatory assets
Regulatory assets - current		10
Other Regulatory Assets [Member]
Regulatory assets
Regulatory assets - current	8	9	42
Regulatory assets - long-term	50	52	43
Recoverable Regulatory Infrastructure Program Costs [Member]
Regulatory assets
Regulatory assets - long-term	73	69	57
Long-term Debt Fair Value Adjustment [Member]
Regulatory assets
Regulatory assets - long-term	$72	$74	$80

Note_3_Regulated_Operations_De2

Note 3 - Regulated Operations (Details) - Estimated Recognition of Rate Making Assets (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
In Millions, unless otherwise specified
Regulatory Assets [Line Items]
Regulatory Asset	$697	$714	$946
Regulatory Asset Off Balance Sheet [Member] | Atlanta Gas Light [Member]
Regulatory Assets [Line Items]
Regulatory Asset	119	113	88
Regulatory Asset Off Balance Sheet [Member] | Virginia Natural Gas [Member]
Regulatory Assets [Line Items]
Regulatory Asset	12	12	12
Regulatory Asset Off Balance Sheet [Member] | Elizabethtown Gas [Member]
Regulatory Assets [Line Items]
Regulatory Asset	2	2	2
Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	$133	$127	$102

Note_3_Regulated_Operations_De3

Note 3 - Regulated Operations (Details) - Costs Related to Remediation of Former Operating Sites (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Environmental Exit Cost [Line Items]
# of sites	46
Probabilistic model cost estimates, low estimate	$353
Probabilistic model cost estimates, high estimate	724
Engineering estimates	82
Amount recorded	419	[1]
Expected costs over next 12 months	93
Illinois Environmental [Member]
Environmental Exit Cost [Line Items]
# of sites	26	[1],[2]
Probabilistic model cost estimates, low estimate	208
Probabilistic model cost estimates, high estimate	466
Engineering estimates	43	[1]
Amount recorded	242	[1],[2]
Expected costs over next 12 months	45	[1],[2]
New Jersey Environmental [Member]
Environmental Exit Cost [Line Items]
# of sites	6
Probabilistic model cost estimates, low estimate	105
Probabilistic model cost estimates, high estimate	177
Engineering estimates	14
Amount recorded	112	[1]
Expected costs over next 12 months	14
Cost recovery period	7 years
Georgia And Florida [Member]
Environmental Exit Cost [Line Items]
# of sites	13
Probabilistic model cost estimates, low estimate	40
Probabilistic model cost estimates, high estimate	81
Engineering estimates	15
Amount recorded	55	[1]
Expected costs over next 12 months	26
Cost recovery period	5 years
North Carolina Environmental [Member]
Environmental Exit Cost [Line Items]
# of sites	1	[2]
Engineering estimates	10	[2]
Amount recorded	10	[1],[2]
Expected costs over next 12 months	$8	[2]
Cost recovery period	0 years	[2]
[1]	Nicor Gas is responsible in whole or in part for 26 MGP sites, of which two sites have been remediated and their use is no longer restricted by the environmental condition of the property. Nicor Gas and Commonwealth Edison Company are parties to an agreement to cooperate in cleaning up residue at 23 of the sites. Nicor Gas' allocated share of cleanup costs for these sites is 52%.
[2]	We have no regulatory recovery mechanism for the site in North Carolina. Therefore, there is no amount included within our regulatory assets and changes in estimated costs are recognized in income in the period of change.

Note_4_Fair_Value_Measurements2

Note 4 - Fair Value Measurements (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
In Millions, unless otherwise specified
Fair Value Disclosures [Abstract]
Weather Derivative Premium	$1	$3	$1

Note_4_Fair_Value_Measurements3

Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities (Natural Gas Derivatives [Member], USD $)	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014
In Millions, unless otherwise specified
Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities [Line Items]
Derivative Assets	$212	[1],[2]	$284	[1],[2]	$137	[1],[2]
Derivative Liabilities	-52	[2]	-93	[2]	-82	[2]
Netting of cash collateral	104	[1]	52	[1]	69	[1]
Netting of cash collateral	106		81		31
Fair Value, Inputs, Level 1 [Member]
Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities [Line Items]
Derivative Assets		[1]	58	[1]	18	[1]
Derivative Liabilities	-106		-80		-38
Fair Value, Inputs, Level 2 [Member]
Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities [Line Items]
Derivative Assets	108	[1]	174	[1]	50	[1]
Derivative Liabilities	($52)		($94)		($75)
[1]	Balances of $1 million at March 31, 2015, $3 million at December 31, 2014 and $1 million at March 31, 2014, associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.
[2]	There were no significant unobservable inputs (Level 3) or significant transfers between Level 1, Level 2 or Level 3 for any of the dates presented.

Note_4_Fair_Value_Measurements4

Note 4 - Fair Value Measurements (Details) - Amortized Cost and Fair Value of Long-Term Debt (USD $)	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014
In Millions, unless otherwise specified
Note 4 - Fair Value Measurements (Details) - Amortized Cost and Fair Value of Long-Term Debt [Line Items]
Long-term debt carrying amount	$3,599		$3,802		$3,810
Fair Value, Inputs, Level 2 [Member]
Note 4 - Fair Value Measurements (Details) - Amortized Cost and Fair Value of Long-Term Debt [Line Items]
Long-term debt fair value (1)	$4,102	[1]	$4,231	[1]	$4,095	[1]
[1]	Fair value determined using Level 2 inputs.

Note_5_Derivative_Instruments_1

Note 5 - Derivative Instruments (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$52	$82	$93
Increase (Decrease) in Risk Management Assets and Liabilities	-33	17
Collateral Already Posted, Aggregate Fair Value	210	100	133
Price Risk Cash Flow Hedge Unrealized Gain (Loss) to be Reclassified During Next 12 Months	9
Less Than Two Years [Member] | Natural Gas [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Percent of Derivative Contracts	96.00%
Less Than Two Years [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Term of Contract	2 years
Expiring in Two to Five Years [Member] | Natural Gas [Member] | Maximum [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Term of Contract	5 years
Expiring in Two to Five Years [Member] | Natural Gas [Member] | Minimum [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Term of Contract	2 years
Expiring in Two to Five Years [Member] | Natural Gas [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Percent of Derivative Contracts	4.00%
Weather Derivatives [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	-2	-5
Maximum [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Collateral, Obligation to Return Cash	$7

Note_5_Derivative_Instruments_2

Note 5 - Derivative Instruments (Details) - Net Long Natural Gas Contracts	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014
	ft3		ft3		ft3
Note 5 - Derivative Instruments (Details) - Net Long Natural Gas Contracts [Line Items]
Cash flow hedges	9,000,000,000	[1],[2]	9,000,000,000	[1]	6,000,000,000	[1]
Not designated as hedges	231,000,000,000	[1],[2]	75,000,000,000	[1]	277,000,000,000	[1]
Total volumes	240,000,000,000	[1],[2]	84,000,000,000	[1]	283,000,000,000	[1]
Net long position	240,000,000,000	[1],[2]	84,000,000,000	[1]	283,000,000,000	[1]
Designated as Hedging Instrument [Member]
Note 5 - Derivative Instruments (Details) - Net Long Natural Gas Contracts [Line Items]
Short position	-6,000,000,000	[1],[2]	-7,000,000,000	[1]	-2,000,000,000	[1]
Long position	15,000,000,000	[1],[2]	16,000,000,000	[1]	8,000,000,000	[1]
Not Designated as Hedging Instrument [Member]
Note 5 - Derivative Instruments (Details) - Net Long Natural Gas Contracts [Line Items]
Short position	-2,735,000,000,000	[1],[2]	-2,825,000,000,000	[1]	-2,489,000,000,000	[1]
Long position	2,966,000,000,000	[1],[2]	2,900,000,000,000	[1]	2,766,000,000,000	[1]
[1]	Volumes related to Nicor Gas exclude variable-priced contracts, which are carried at fair value, but whose fair values are not directly impacted by changes in commodity prices.
[2]	Approximately 96% of these contracts have durations of two years or less and the remaining 4% expire between two and five years.

Note_5_Derivative_Instruments_3

Note 5 - Derivative Instruments (Details) - Gains and Losses on Derivative Instruments (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Nicor Gas [Member]
Note 5 - Derivative Instruments (Details) - Gains and Losses on Derivative Instruments [Line Items]
Realized losses related to hedging natural gas costs	($3)	$2
Elizabethtown Gas [Member]
Note 5 - Derivative Instruments (Details) - Gains and Losses on Derivative Instruments [Line Items]
Realized losses related to hedging natural gas costs	($4)	$3

Note_5_Derivative_Instruments_4

Note 5 - Derivative Instruments (Details) - Derivative Instruments on the Condensed Consolidated Statements of Financial Position (USD $)	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]
Assets	$4		$6		$2
Liabilities	-7		-12
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)	-52		-93		-82
Current Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets			6		2
Liabilities	-6		-11
Current Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	557		1,061		675
Liabilities	-592		-1,020		-703
Long-Term Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Liabilities	-1		-1
Long-Term Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	98		145		80
Liabilities	-109		-119		-98
Long-Term Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Assets	659	[1],[2]	1,212	[1],[2]	757	[1],[2]
Liabilities	-708	[1],[2]	-1,151	[1],[2]	-801	[1],[2]
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)	-446	[1]	-925	[1]	-619	[1]
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)	656	[1]	1,058	[1]	719	[1]
Current Interest Rate Swap Agreements [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	1
Long-term Interest Rate Swap Agreements [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	3
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)	213	[3]	287	[3]	138	[3]
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)	-52	[3]	-93	[3]	-82	[3]
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	655		1,206		755
Liabilities	($701)		($1,139)		($801)
[1]	As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities do not include cash collateral held on deposit in broker margin accounts of $210 million as of March 31, 2015, $133 million as of December 31, 2014, and $100 million as of March 31, 2014. Cash collateral is included in the "Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position" line of this table.
[2]	The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Statements of Financial Position to the extent that we have netting arrangements with the counterparties.
[3]	As of March 31, 2015, December 31, 2014, and March 31, 2014, we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets.

Note_5_Derivative_Instruments_5

Note 5 - Derivative Instruments (Details) - Derivative Instruments on the Consolidated Statements of Income (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Designated as cash flow or fair value hedges
Total designated as cash flow or fair value hedges, net of tax			$4
Not designated as hedges (1)
Total gains (losses) on derivative instruments, net of tax	-16		-13
Cost of Sales [Member] | Cash Flow Hedging [Member]
Designated as cash flow or fair value hedges
Natural gas contracts - gain reclassified from OCI	-1		3
Cost of Sales [Member] | Fair Value Hedging [Member]
Not designated as hedges (1)
Natural gas contracts - net value adjustments	-2	[1],[2]	2	[1],[2]
Operating Expense [Member] | Cash Flow Hedging [Member]
Designated as cash flow or fair value hedges
Natural gas contracts - gain reclassified from OCI			1
Interest Expense [Member] | Cash Flow Hedging [Member]
Designated as cash flow or fair value hedges
Interest rate swaps - net gain reclassified from OCI into interest expense	1
Sales [Member] | Fair Value Hedging [Member]
Not designated as hedges (1)
Natural gas contracts - net value adjustments	-24	[1]	-30	[1]
Cash Flow Hedging [Member]
Designated as cash flow or fair value hedges
Total designated as cash flow or fair value hedges, net of tax			4
Fair Value Hedging [Member]
Not designated as hedges (1)
Income tax benefit	10	[1]	11	[1]
Total not designated as hedges, net of tax	($16)	[1]	($17)	[1]
[1]	Associated with the fair value of derivative instruments held at March 31, 2015 and 2014.
[2]	Excludes losses recorded in cost of goods sold associated with weather derivatives of $2 million and $5 million for the three months ended March 31, 2015 and 2014, respectively.

Note_6_Employee_Benefit_Plans_1

Note 6 - Employee Benefit Plans (Details) - Components of Pension and Other Retirement Benefit Costs (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Pension Plan [Member]
Note 6 - Employee Benefit Plans (Details) - Components of Pension and Other Retirement Benefit Costs [Line Items]
Service cost	$7	$6
Interest cost	11	12
Expected return on plan assets	-16	-16
Net amortization of prior service cost	-1
Recognized actuarial loss	8	5
Net periodic pension benefit cost	9	7
Other Postretirement Benefit Plan [Member]
Note 6 - Employee Benefit Plans (Details) - Components of Pension and Other Retirement Benefit Costs [Line Items]
Service cost	1	1
Interest cost	3	4
Expected return on plan assets	-2	-2
Net amortization of prior service cost		-1
Recognized actuarial loss	1	1
Net periodic pension benefit cost	$3	$3

Note_7_Debt_and_Credit_Facilit2

Note 7 - Debt and Credit Facilities (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Jan. 23, 2015	Dec. 31, 2014
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Proceeds from (Repayments of) Commercial Paper (in Dollars)	($649)	($430)
Repayments of Senior Debt (in Dollars)	200
Commercial Paper [Member] | Minimum [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Term	1 day
Debt Instrument, Remaining Maturity Term	1 day
Commercial Paper [Member] | Maximum [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Term	58 days
Debt Instrument, Remaining Maturity Term	20 days
Commercial Paper [Member] | AGL Capital [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Interest Rate, Effective Percentage	0.50%
Commercial Paper [Member] | Nicor Gas [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Interest Rate, Effective Percentage	0.40%
Target ratio [Member] | Minimum [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Ratio of Indebtedness to Net Capital	0.5
Target ratio [Member] | Maximum [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Ratio of Indebtedness to Net Capital	0.6
Interest Rate Swap [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Derivative, Notional Amount (in Dollars)			$800
Maximum [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Ratio of Indebtedness to Net Capital	0.7
Nicor Gas [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Ratio of Indebtedness to Net Capital	0.54	0.54		0.62

Note_7_Debt_and_Credit_Facilit3

Note 7 - Debt and Credit Facilities (Details) - Debt Schedule (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014
Long-term debt - excluding current portion
Total long-term debt – excluding current portion	$3,524		$3,602		$3,610
Total debt	4,125		4,977		4,551
Commercial Paper [Member] | AGL Capital [Member]
Short-term debt
Maturity Date	2015
Weighted average interest rate	0.50%	[1]			0.30%	[1]
Outstanding	176	[1]	590	[1],[2]	440	[1],[2]
Long-term debt - excluding current portion
Maturity Date	2015
Commercial Paper [Member] | Nicor Gas [Member]
Short-term debt
Maturity Date	2015
Weighted average interest rate	0.40%	[1]			0.20%	[1]
Outstanding	350	[1]	585	[1],[2]	301	[1],[2]
Long-term debt - excluding current portion
Maturity Date	2015
Commercial Paper [Member]
Short-term debt
Weighted average interest rate	0.40%	[2]			0.30%	[2]
Outstanding	526		1,175	[2]	741
Current Portion Long-Term Debt [Member]
Short-term debt
Maturity Date	2016
Weighted average interest rate	2.90%				5.00%
Outstanding	75		200	[2]	200	[2]
Long-term debt - excluding current portion
Maturity Date	2016
Senior Notes [Member] | Minimum [Member]
Short-term debt
Maturity Date	2016
Long-term debt - excluding current portion
Maturity Date	2016
Senior Notes [Member] | Maximum [Member]
Short-term debt
Maturity Date	2043
Long-term debt - excluding current portion
Maturity Date	2043
Senior Notes [Member]
Long-term debt - excluding current portion
Weighted average interest rate	5.00%				5.00%
Outstanding	2,625		2,625	[2]	2,625	[2]
First Mortgage Bonds [Member] | Minimum [Member]
Short-term debt
Maturity Date	2016
Long-term debt - excluding current portion
Maturity Date	2016
First Mortgage Bonds [Member] | Maximum [Member]
Short-term debt
Maturity Date	2038
Long-term debt - excluding current portion
Maturity Date	2038
First Mortgage Bonds [Member]
Long-term debt - excluding current portion
Weighted average interest rate	6.00%				5.60%
Outstanding	425		500	[2]	500	[2]
Gas Facility Revenue Bonds [Member] | Minimum [Member]
Short-term debt
Maturity Date	2022
Long-term debt - excluding current portion
Maturity Date	2022
Gas Facility Revenue Bonds [Member] | Maximum [Member]
Short-term debt
Maturity Date	2033
Long-term debt - excluding current portion
Maturity Date	2033
Gas Facility Revenue Bonds [Member]
Long-term debt - excluding current portion
Weighted average interest rate	0.80%				0.90%
Outstanding	200		200	[2]	200	[2]
Medium-term Notes [Member] | Minimum [Member]
Short-term debt
Maturity Date	2017
Long-term debt - excluding current portion
Maturity Date	2017
Medium-term Notes [Member] | Maximum [Member]
Short-term debt
Maturity Date	2027
Long-term debt - excluding current portion
Maturity Date	2027
Medium-term Notes [Member]
Long-term debt - excluding current portion
Weighted average interest rate	7.80%				7.80%
Outstanding	181		181	[2]	181	[2]
Long-term Debt Principal [Member]
Long-term debt - excluding current portion
Weighted average interest rate	4.90%	[2]			4.90%	[2]
Outstanding	3,431		3,506	[2]	3,506
Long-term Debt Fair Value Adjustment [Member]
Short-term debt
Maturity Date
Long-term debt - excluding current portion
Maturity Date
Weighted average interest rate		[3]				[3]
Outstanding	77	[3]	80	[2],[3]	88	[2],[3]
Unamortized Debt Premium Discount, Net [Member]
Short-term debt
Maturity Date
Long-term debt - excluding current portion
Maturity Date
Weighted average interest rate
Outstanding	16		16	[2]	16	[2]
Long-term Debt Non-principal [Member]
Long-term debt - excluding current portion
Weighted average interest rate		[2]				[2]
Outstanding	$93		$96	[2]	$104
[1]	As of March 31, 2015, the effective interest rates on our commercial paper borrowings were 0.5% for AGL Capital and 0.4% for Nicor Gas.
[2]	Interest rates are calculated based on the daily weighted average balance outstanding for the three months ended March 31.
[3]	See Note 4 for additional information on our fair value measurements.

Note_7_Debt_and_Credit_Facilit4

Note 7 - Debt and Credit Facilities (Details) - Debt-to-Capitalization Ratios	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014
AGL Resources Inc [Member]
Schedule of Capitalization [Line Items]
Debt-to-capitalization ratios	0.5	0.55	0.54
Nicor Gas [Member]
Schedule of Capitalization [Line Items]
Debt-to-capitalization ratios	0.54	0.62	0.54

Note_8_Equity_Details_Other_Co

Note 8 - Equity (Details) - Other Comprehensive Income (Loss) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Other Comprehensive Income (Loss) [Abstract]
As of beginning of period	($6)	[1]	$1	[1]
As of beginning of period	-200	[1]	-137	[1]
As of beginning of period	-206	[1]	-136	[1]
OCI, before reclassifications	2	[1]	4	[1]
OCI, before reclassifications		[1]		[1]
OCI, before reclassifications	2	[1]	4	[1]
Amounts reclassified from accumulated OCI		[1]	-4	[1]
Amounts reclassified from accumulated OCI	3	[1]	1	[1]
Amounts reclassified from accumulated OCI	3	[1]	-3	[1]
Net current period other comprehensive income	2	[1]		[1]
Net current period other comprehensive income	3	[1]	1	[1]
Net current period other comprehensive income	5	[1]	1	[1]
As of end of period	-4	[1]	1	[1]
As of end of period	-197	[1]	-136	[1]
As of end of period	($201)	[1]	($135)	[1]
[1]	All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

Note_8_Equity_Details_Reclassi

Note 8 - Equity (Details) - Reclassifications Out of Accumulated Other Comprehensive Loss (USD $)	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Cash flow hedges
Interest expense (interest rate contracts)	($44,000,000)		($46,000,000)
Total before income tax	323,000,000		549,000,000
Income tax benefit	118,000,000		203,000,000
Net of tax	193,000,000		284,000,000
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Natural Gas Derivatives [Member]
Cash flow hedges
Cost of goods sold (natural gas contracts)	-1,000,000	[1]	3,000,000	[1]
Operation and maintenance expense (natural gas contracts)		[1]	1,000,000	[1]
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Interest Rate Contract [Member]
Cash flow hedges
Interest expense (interest rate contracts)	1,000,000	[1]		[1]
Total before income tax		[1]	4,000,000	[1]
Income tax benefit		[1]		[1]
Net of tax		[1]	4,000,000	[1]
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Cash flow hedges
Total before income tax	-5,000,000	[1]	-2,000,000	[1]
Income tax benefit	2,000,000	[1]	1,000,000	[1]
Net of tax	-3,000,000	[1]	-1,000,000	[1]
Retirement benefit plans
Operation and maintenance expense (actuarial losses) (2)	-5,000,000	[1],[2]	-2,000,000	[1],[2]
Reclassification out of Accumulated Other Comprehensive Income [Member]
Cash flow hedges
Net of tax	($3,000,000)	[1]	$3,000,000	[1]
[1]	Amounts in parentheses indicate reductions to our net income and to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the net income impacts are immediate.
[2]	Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 6 for additional details about net periodic benefit cost.

Note_9_Nonwholly_Owned_Entitie2

Note 9 - Non-wholly Owned Entities (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Note 9 - Non-wholly Owned Entities (Details) [Line Items]
Payments to Acquire Property, Plant, and Equipment	$188	$161
Payments of Ordinary Dividends, Noncontrolling Interest	18	17
Equity Method Investments	76	83	80
South Star [Member] | AGL Resources Inc [Member]
Note 9 - Non-wholly Owned Entities (Details) [Line Items]
Equity Method Investment, Ownership Percentage	85.00%
South Star [Member] | Piedmont [Member]
Note 9 - Non-wholly Owned Entities (Details) [Line Items]
Payments of Ordinary Dividends, Noncontrolling Interest	18	17
South Star [Member]
Note 9 - Non-wholly Owned Entities (Details) [Line Items]
Payments to Acquire Property, Plant, and Equipment	1	2
PennEast Pipeline [Member] | Corporate Joint Venture [Member]
Note 9 - Non-wholly Owned Entities (Details) [Line Items]
Equity Method Investment, Ownership Percentage			20.00%
Natural Gas Pipeline Length (in Miles)			108
Natural Gas Pipeline Capacity (in Cubic Feet)			1,000,000,000
Natural Gas Pipeline Expansion Capacity (in Cubic Feet)			1,200,000,000
PennEast Pipeline [Member]
Note 9 - Non-wholly Owned Entities (Details) [Line Items]
Equity Method Investments	2		1
Atlantic Coast Pipeline [Member] | Corporate Joint Venture [Member]
Note 9 - Non-wholly Owned Entities (Details) [Line Items]
Equity Method Investment, Ownership Percentage			5.00%
Natural Gas Pipeline Length (in Miles)			550
Natural Gas Pipeline Capacity (in Cubic Feet)			1,500,000,000
Natural Gas Pipeline Expansion Capacity (in Cubic Feet)			2,000,000,000
Atlantic Coast Pipeline [Member]
Note 9 - Non-wholly Owned Entities (Details) [Line Items]
Equity Method Investments	$3		$2

Note_9_Nonwholly_Owned_Entitie3

Note 9 - Non-wholly Owned Entities (Details) - SouthStar’s Assets and Liabilities (USD $)	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Current assets	$2,079		$2,890		$3,589
Goodwill and other intangible assets	1,943		1,952		1,967
Long-term assets and other deferred debits	10,116		10,067		9,708
Total assets	14,138		14,909		15,264
Current liabilities	2,371		3,219		3,754
Long-term liabilities and other deferred credits	7,803		7,862		7,667
Total Liabilities	10,174		11,081		11,421
Equity	3,964		3,828		3,843		3,613
Total liabilities and equity	14,138		14,909		15,264
South Star Percentage To Consolidated [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Current assets	9.00%	[1]	8.00%	[1]	7.00%	[1]
Goodwill and other intangible assets	6.00%	[1]	6.00%	[1]	7.00%	[1]
Long-term assets and other deferred debits		[1]		[1]		[1]
Total assets	2.00%	[1]	3.00%	[1]	3.00%	[1]
Current liabilities	2.00%	[1]	2.00%	[1]	3.00%	[1]
Long-term liabilities and other deferred credits		[1]		[1]		[1]
Total Liabilities		[1]	1.00%	[1]	1.00%	[1]
Equity	7.00%	[1]	8.00%	[1]	7.00%	[1]
Total liabilities and equity	2.00%	[1]	3.00%	[1]	3.00%	[1]
South Star [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Current assets	182	[2]	238	[2]	235	[2]
Goodwill and other intangible assets	119	[2]	125	[2]	131	[2]
Long-term assets and other deferred debits	17	[2]	17	[2]	16	[2]
Total assets	318	[2]	380	[2]	382	[2]
Current liabilities	46	[2]	71	[2]	106	[2]
Long-term liabilities and other deferred credits	1	[2]		[2]		[2]
Total Liabilities	47	[2]	71	[2]	106	[2]
Equity	271	[2]	309	[2]	276	[2]
Total liabilities and equity	$318	[2]	$380	[2]	$382	[2]
[1]	SouthStar's percentage of the amount in our unaudited Condensed Consolidated Statements of Financial Position.
[2]	These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.

Note_9_Nonwholly_Owned_Entitie4

Note 9 - Non-wholly Owned Entities (Details) - SouthStar’s Revenues and Expenses (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Variable Interest Entity [Line Items]
Operating revenues	$1,721	$2,462
Operating income	364	592
Cost of goods sold	935	1,400
Operation and maintenance	249	289
Depreciation and amortization	97	93
Taxes other than income taxes	76	88
Total operating expenses	1,357	1,870
South Star [Member]
Variable Interest Entity [Line Items]
Operating revenues	311	374
Operating income	82	78
Cost of goods sold	203	270
Operation and maintenance	23	23
Depreciation and amortization	2	3
Taxes other than income taxes	1
Total operating expenses	$229	$296

Note_9_Nonwholly_Owned_Entitie5

Note 9 - Non-wholly Owned Entities (Details) - Equity Method Investments (USD $)	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014
In Millions, unless otherwise specified
Schedule of Equity Method Investments [Line Items]
Equity method investments	$76		$80		$83
Triton [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	57		62		67
Horizon Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	14		14		15
Other Equity Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	$5	[1]	$4	[1]	$1	[1]
[1]	Includes our current investment of $2 million in PennEast Pipeline and $3 million in Atlantic Coast Pipeline as of March 31, 2015 and $1 million and $2 million, respectively, as of December 31, 2014.

Note_9_Nonwholly_Owned_Entitie6

Note 9 - Non-wholly Owned Entities (Details) - Income from Equity Method Investments (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Note 9 - Non-wholly Owned Entities (Details) - Income from Equity Method Investments [Line Items]
Income from equity method investment	$1	$3
Triton [Member]
Note 9 - Non-wholly Owned Entities (Details) - Income from Equity Method Investments [Line Items]
Income from equity method investment		2
Horizon Pipeline [Member]
Note 9 - Non-wholly Owned Entities (Details) - Income from Equity Method Investments [Line Items]
Income from equity method investment	$1	$1

Note_10_Commitments_Guarantees1

Note 10 - Commitments, Guarantees and Contingencies (Details) (USD $)	1 Months Ended			0 Months Ended	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Feb. 28, 2015	Jun. 07, 2013	Aug. 31, 2014	Dec. 31, 2009	Mar. 31, 2015
	ft3	ft3
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Gas Balancing Volume Amount (in Cubic Feet)	1,150,000,000	4,600,000,000
Natural Gas Imbalance Resolution Period		5 years
Discretionary Funds Used For Natural Gas Imbalance, Percentage	25.00%
True-up Recovery [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Gain Contingency, Unrecorded Amount			$178
Pipeline Replacement Program Period			15 years
Gain Contingency, Unrecorded Amount, Initial One-time Increase (in Dollars per Item)			2.46
Gain Contingency, Unrecorded Amount, Alternative Phased-in Cumulative Increases (in Dollars per Item)			0.58
Mitigation Costs [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Gain Contingency, Unrecorded Amount							32
Natural Gas Remainder [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Gas Balancing Volume Amount (in Cubic Feet)							2,300,000,000
Atlanta Gas Light [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Gas Balancing Volume Amount (in Cubic Feet)	1,150,000,000
Percent of NaturalGas Imbalance Obligated	25.00%
Gas Balancing Volume Replaced Percent							15.00%
Illinois Commission [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Loss Contingency, Damages Sought, Value					18	85
Loss Contingency, Damages Awarded, Value				72
CUB [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Loss Contingency, Damages Sought, Value					22	305
IAGO [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Loss Contingency, Damages Sought, Value						$255

Note_11_Segment_Information_De

Note 11 - Segment Information (Details)	12 Months Ended
	Dec. 31, 2014
Note 11 - Segment Information (Details) [Line Items]
Number of Reportable Segments	4
Distribution Operations [Member]
Note 11 - Segment Information (Details) [Line Items]
Number of States in which Entity Operates	7

Note_11_Segment_Information_De1

Note 11 - Segment Information (Details) - Intersegment Reporting (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014
Segment Reporting Information [Line Items]
Revenues	$1,721		$2,462
Operating expenses
Cost of goods sold	935		1,400
Operation and maintenance	249		289
Depreciation and amortization	97		93
Taxes other than income taxes	76		88
Total operating expenses	1,357		1,870
Operating income (loss)	364		592
Other income (expense)	3		3
EBIT	367		595
Identifiable and total assets	14,138		15,264		14,909
Capital expenditures	188		161
Intersegment Eliminations [Member] | Distribution Operations [Member]
Segment Reporting Information [Line Items]
Revenues	56	[1]	75	[1]
Intersegment Eliminations [Member] | Retail Operations [Member]
Segment Reporting Information [Line Items]
Revenues	0			[1]
Intersegment Eliminations [Member] | Wholesale Services [Member]
Segment Reporting Information [Line Items]
Revenues		[1],[2]		[1],[2]
Intersegment Eliminations [Member] | Midstream Operations [Member]
Segment Reporting Information [Line Items]
Revenues	0	[1]		[1]
Intersegment Eliminations [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	0	[1]		[1]
Intersegment Eliminations [Member] | Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-56		-75
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	0	[1]		[1]
Operating expenses
Identifiable and total assets					-9,621
Operating Segments [Member] | Distribution Operations [Member]
Segment Reporting Information [Line Items]
Revenues	1,341		1,801
Operating Segments [Member] | Retail Operations [Member]
Segment Reporting Information [Line Items]
Revenues	341		406
Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting Information [Line Items]
Revenues	90	[2]	331	[2]
Operating Segments [Member] | Midstream Operations [Member]
Segment Reporting Information [Line Items]
Revenues	19		44
Operating Segments [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	6	[1]	3	[1]
Operating Segments [Member] | Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-76		-123
Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	1,721		2,462
Distribution Operations [Member] | Continuing Operations [Member]
Operating expenses
Identifiable and total assets	11,899	[3]	11,823	[3]
Distribution Operations [Member]
Segment Reporting Information [Line Items]
Revenues	1,285		1,726
Operating expenses
Cost of goods sold	776		1,202
Operation and maintenance	185		211
Depreciation and amortization	82		78
Taxes other than income taxes	71		82
Total operating expenses	1,114		1,573
Operating income (loss)	227		228
Other income (expense)	1		1
EBIT	228		229
Identifiable and total assets					12,041
Capital expenditures	170		150
Retail Operations [Member] | Continuing Operations [Member]
Operating expenses
Identifiable and total assets	1,100	[3]	738	[3]
Retail Operations [Member]
Segment Reporting Information [Line Items]
Revenues	341		406
Operating expenses
Cost of goods sold	210		280
Operation and maintenance	37		37
Depreciation and amortization	6		8
Taxes other than income taxes	1		1
Total operating expenses	254		326
Operating income (loss)	87		80
EBIT	87		80
Identifiable and total assets					670
Capital expenditures	2		3
Wholesale Services [Member] | Continuing Operations [Member]
Operating expenses
Identifiable and total assets	698	[2],[3]	1,782	[2],[3]
Wholesale Services [Member]
Segment Reporting Information [Line Items]
Revenues	90	[2]	331	[2]
Operating expenses
Cost of goods sold	9	[2]	3	[2]
Operation and maintenance	24	[2]	36	[2]
Depreciation and amortization		[2]		[2]
Taxes other than income taxes	1	[2]	1	[2]
Total operating expenses	34	[2]	40	[2]
Operating income (loss)	56	[2]	291	[2]
Other income (expense)		[2]		[2]
EBIT	56	[2]	291	[2]
Identifiable and total assets					1,402
Capital expenditures	1	[2]	1	[2]
Midstream Operations [Member] | Continuing Operations [Member]
Operating expenses
Identifiable and total assets	693	[3]	698	[3]
Midstream Operations [Member]
Segment Reporting Information [Line Items]
Revenues	19		44
Operating expenses
Cost of goods sold	10		36
Operation and maintenance	6		6
Depreciation and amortization	5		5
Taxes other than income taxes	1		1
Total operating expenses	22		48
Operating income (loss)	-3		-4
Other income (expense)	1		1
EBIT	-2		-3
Identifiable and total assets					694
Capital expenditures	3
Other Segments [Member] | Continuing Operations [Member]
Operating expenses
Identifiable and total assets	9,052	[1],[3]	9,844	[1],[3]
Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	6	[1]	3	[1]
Operating expenses
Cost of goods sold	5	[1]		[1]
Operation and maintenance	-2	[1]	1	[1]
Depreciation and amortization	4	[1]	2	[1]
Taxes other than income taxes	2	[1]	3	[1]
Total operating expenses	9	[1]	6	[1]
Operating income (loss)	-3	[1]	-3	[1]
Other income (expense)	1	[1]	1	[1]
EBIT	-2	[1]	-2	[1]
Identifiable and total assets					9,723
Capital expenditures	12	[1]	7	[1]
Intercompany Eliminations [Member] | Continuing Operations [Member]
Operating expenses
Identifiable and total assets	-9,304	[3]	-9,885	[3]
Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-20		-48
Operating expenses
Cost of goods sold	-75		-121
Operation and maintenance	-1		-2
Total operating expenses	-76		-123
Continuing Operations [Member]
Operating expenses
Identifiable and total assets	$14,138	[3]	$15,000	[3]	$14,909
[1]	Our other non-reportable segments include our investment in Triton, which was part of our cargo shipping segment that is classified as discontinued operations. For more information, see Note 12.
[2]	The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.
[3]	Identifiable assets are those used in each segment's operations. Amounts as of March 31, 2014 exclude assets held for sale.

Note_11_Segment_Information_De2

Note 11 - Segment Information (Details) - Operating Revenues (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	$1,721		$2,462
Third Party Gross Costs	935		1,400
Operating Segments [Member] | Third Party Gross Revenues [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	2,146		4,049
Operating Segments [Member] | Intercompany Revenues [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	150		298
Operating Segments [Member] | Total Gross Revenues [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	2,296		4,347
Operating Segments [Member] | Third Party Gross Costs [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Third Party Gross Costs	2,206		4,016
Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	90	[1]	331	[1]
Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	1,721		2,462
Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	90	[1]	331	[1]
Third Party Gross Costs	$9	[1]	$3	[1]
[1]	The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.

Note_11_Segment_Information_De3

Note 11 - Segment Information (Details) - Segment Reporting (USD $)	Mar. 31, 2015		Dec. 31, 2014	Mar. 31, 2014
In Millions, unless otherwise specified
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets	$14,138		$14,909	$15,264
Distribution Operations [Member] | Continuing Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets	11,899	[1]		11,823	[1]
Distribution Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets			12,041
Retail Operations [Member] | Continuing Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets	1,100	[1]		738	[1]
Retail Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets			670
Wholesale Services [Member] | Continuing Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets	698	[1],[2]		1,782	[1],[2]
Wholesale Services [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets			1,402
Midstream Operations [Member] | Continuing Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets	693	[1]		698	[1]
Midstream Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets			694
Other Segments [Member] | Continuing Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets	9,052	[1],[3]		9,844	[1],[3]
Other Segments [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets			9,723
Intersegment Eliminations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets			-9,621
Continuing Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Assets	$14,138	[1]	$14,909	$15,000	[1]
[1]	Identifiable assets are those used in each segment's operations. Amounts as of March 31, 2014 exclude assets held for sale.
[2]	The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.
[3]	Our other non-reportable segments include our investment in Triton, which was part of our cargo shipping segment that is classified as discontinued operations. For more information, see Note 12.

Note_12_Discontinued_Operation2

Note 12 - Discontinued Operations (Details) (USD $)	3 Months Ended		0 Months Ended	3 Months Ended	6 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Sep. 01, 2014	Sep. 30, 2014	Sep. 30, 2014
Note 12 - Discontinued Operations (Details) [Line Items]
Discontinued Operation, Tax Effect of Discontinued Operation		($32,000,000)
Income Tax Expense (Benefit)	118,000,000	203,000,000
Distributed Earnings Of Foreign Subsidiaries [Member] | Tropical Shipping [Member]
Note 12 - Discontinued Operations (Details) [Line Items]
Discontinued Operation, Tax Effect of Discontinued Operation			60,000,000
Distributed Earnings Of Foreign Subsidiaries [Member]
Note 12 - Discontinued Operations (Details) [Line Items]
Effective Income Tax Rate Reconciliation, Repatriation of Foreign Earnings, Amount				86,000,000
Tropical Shipping [Member]
Note 12 - Discontinued Operations (Details) [Line Items]
Proceeds from Divestiture of Businesses			225,000,000
Discontinued Operation, Tax Effect of Discontinued Operation		31,000,000		29,000,000
Goodwill, Impairment Loss, Net of Tax		19,000,000
Income Tax Expense (Benefit)		0
Depreciation And Amortization Suspension					$7,000,000

Note_12_Discontinued_Operation3

Note 12 - Discontinued Operations (Details) - Assets and Liabilities of Tropical Shipping (USD $)	Mar. 31, 2014
In Millions, unless otherwise specified
Current assets
Cash and cash equivalents	$26
Total current assets	264
Current liabilities
Total liabilities held for sale	36
Tropical Shipping [Member]
Current assets
Cash and cash equivalents	26
Short-term investments	3
Receivables	34
Inventories	9
Other	2
Total current assets	74
Long-term assets and other deferred debits
Property, plant and equipment, net	123
Goodwill	42
Intangible assets	19
Other	6
Total long-term assets and other deferred debits	190
Total assets held for sale	264
Current liabilities
Other accounts payable – trade	9
Accrued expenses	4
Other	23
Total liabilities held for sale	$36

Note_12_Discontinued_Operation4

Note 12 - Discontinued Operations (Details) - Discontinued Operations from Statement of Income (USD $)	3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Mar. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues		$89
Operating expenses
Cost of goods sold		54
Operation and maintenance		28
Depreciation and amortization		5
Taxes other than income taxes		1
Total operating expenses		107
Operating loss		-18
Loss before income taxes		-18
Income tax expense		-32
Loss from discontinued operations, net of tax		-50
Tropical Shipping [Member]
Operating expenses
Loss on sale and goodwill impairment		19
Income tax expense	$29	$31