SOUTHERN Co GAS (GAS) 10-Q 4 May 16 2016 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 29, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	AGL RESOURCES INC.
Trading Symbol	gas
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		120,680,030
Amendment Flag	false
Entity Central Index Key	1,004,155
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Current assets
Cash and cash equivalents	$ 20	$ 19	$ 41
Receivables
Natural gas, unbilled revenues and other	564	516	834
Energy marketing	365	445	611
Less allowance for uncollectible accounts	36	29	48
Total receivables, net	893	932	1,397
Inventories	335	651	302
Derivative instruments, including cash collateral	160	206	189
Prepaid expenses	62	218	38
Regulatory assets	50	68	63
Other	17	21	49
Total current assets	1,537	2,115	2,079
Long-term assets and other deferred debits
Property, plant and equipment	12,777	12,566	11,689
Less accumulated depreciation	2,833	2,775	2,515
Property, plant and equipment, net	9,944	9,791	9,174
Goodwill	1,813	1,813	1,827
Regulatory assets	661	670	634
Intangible assets	105	109	116
Other	276	256	289
Total long-term assets and other deferred debits	12,799	12,639	12,040
Total assets	14,336	14,754	14,119
Current liabilities
Short-term debt	557	1,010	526
Current portion of long-term debt	470	545	75
Energy marketing trade payables	363	418	586
Other accounts payable – trade	250	255	285
Accrued expenses	231	200	259
Regulatory liabilities	159	134	168
Customer deposits and credit balances	141	165	109
Accrued environmental remediation liabilities	68	67	93
Derivative instruments, including cash collateral	64	44	48
Temporary LIFO liquidation	48	0	87
Current deferred income taxes	20	31	0
Other	118	131	135
Total current liabilities	2,489	3,000	2,371
Long-term liabilities and other deferred credits
Long-term debt	3,273	3,275	3,505
Accumulated deferred income taxes	1,921	1,912	1,738
Regulatory liabilities	1,632	1,611	1,612
Accrued pension and retiree welfare benefits	513	515	526
Accrued environmental remediation liabilities	355	364	326
Other	83	102	77
Total long-term liabilities and other deferred credits	7,777	7,779	7,784
Total liabilities and other deferred credits	$ 10,266	$ 10,779	$ 10,155
Commitments, guarantees and contingencies (see Note 11)
Contingently redeemable noncontrolling interest	$ 38	$ 0	$ 0
Equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,679,004 shares at March 31, 2016, 120,376,721 shares at December 31, 2015, and 119,927,459 shares at March 31, 2015	604	603	601
Additional paid-in capital	2,110	2,099	2,090
Retained earnings	1,539	1,421	1,444
Accumulated other comprehensive loss	(213)	(186)	(201)
Treasury shares, at cost: 216,523 shares at March 31, 2016, December 31, 2015, and March 31, 2015	(8)	(8)	(8)
Total common shareholders’ equity	4,032	3,929	3,926
Noncontrolling interest	0	46	38
Total equity	4,032	3,975	3,964
Total liabilities, redeemable noncontrolling interest and equity	$ 14,336	$ 14,754	$ 14,119

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Unaudited) (Parentheticals) - $ / shares	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 5	$ 5	$ 5
Common stock, shares authorized	750,000,000	750,000,000	750,000,000
Common stock, shares outstanding	120,679,004	120,376,721	119,927,459
Treasury shares, shares	216,523	216,523	216,523

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Operating revenues (includes revenue taxes of $40 and $56 for the three months ended March 31, 2016 and 2015, respectively)	$ 1,334	$ 1,721
Operating expenses
Cost of goods sold	578	935
Operation and maintenance	241	249
Depreciation and amortization	102	97
Taxes other than income taxes	62	76
Merger-related expenses	3	0
Total operating expenses	986	1,357
Operating income	348	364
Other income	3	3
Interest expense, net	(47)	(44)
Income before income taxes	304	323
Income tax expense	111	118
Net income	193	205
Less net income attributable to noncontrolling interest	11	12
Net income attributable to AGL Resources	$ 182	$ 193
Per common share information
Basic earnings per common share attributable to AGL Resources (in dollars per share)	$ 1.52	$ 1.62
Diluted earnings per common share attributable to AGL Resources (in dollars per share)	1.51	1.62
Cash dividends declared per common share (in dollars per share)	$ 0.53	$ 0.51
Weighted average number of common shares outstanding
Basic (in shares)	120.1	119.3
Diluted (in shares)	120.4	119.6

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Income (Unaudited) (Parentheticals) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Operating revenues, revenue taxes	$ 40	$ 56

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income	$ 193	$ 205
Retirement benefit plans, net of tax
Reclassification of actuarial losses to net benefit cost (net of income tax of $2 and $2 for the three months ended March 31, 2016 and 2015, respectively)	3	3
Retirement benefit plans, net	3	3
Cash flow hedges, net of tax
Net derivative (loss) gain arising during the period (net of income tax of $16 and $1 for the three months ended March 31, 2016 and 2015, respectively)	(29)	2
Reclassification of realized derivative gain to net income (net of income tax of less than $1 million)	(1)	0
Cash flow hedges, net	(30)	2
Other comprehensive (loss) income, net of tax	(27)	5
Comprehensive income	166	210
Less comprehensive income attributable to noncontrolling interest	11	12
Comprehensive income attributable to AGL Resources	$ 155	$ 198

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parentheticals) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Reclassification of losses to net benefit cost, income tax	$ 2	$ 2
Net derivative instruments gain arising during the period, income tax (benefit) expense	(16)	1
Reclassification of realized derivative instruments (gain) loss to net income, income tax (less than)	$ (1)	$ 0

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Equity (Unaudited) - USD ($) $ in Millions	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Shares [Member]	Noncontrolling Interest [Member]
Net income attributable to AGL Resources	$ 193
Balance at Dec. 31, 2014	3,828	$ 599	$ 2,087	$ 1,312	$ (206)	$ (8)	$ 44
Balance (in shares) at Dec. 31, 2014		119,600,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to AGL Resources	205			193			12
Other comprehensive income (loss)	5				5
Dividends on common stock	(61)			(61)
Distribution to noncontrolling interest	(18)						(18)
Stock granted, share-based compensation, net of forfeitures	(12)		(12)
Stock issued, dividend reinvestment plan	3	$ 0	3
Stock issued, dividend reinvestment plan (in shares)		100,000
Stock issued, share-based compensation, net of forfeitures	12	$ 2	10
Stock issued, share-based compensation, net of forfeitures (in shares)		200,000
Share-based compensation expense, net of tax	2		2
Balance at Mar. 31, 2015	$ 3,964	$ 601	2,090	1,444	(201)	(8)	38
Balance, shares (in shares) at Mar. 31, 2015	119,927,459	119,900,000
Net income attributable to AGL Resources	$ 182			182
Balance at Dec. 31, 2015	$ 3,975	$ 603	2,099	1,421	(186)	(8)	46
Balance (in shares) at Dec. 31, 2015	120,376,721	120,400,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to AGL Resources	$ 193						0
Other comprehensive income (loss)	(27)				(27)
Dividends on common stock	(64)			(64)
Stock granted, share-based compensation, net of forfeitures	(9)		(9)
Stock issued, dividend reinvestment plan	3	$ 0	3
Stock issued, dividend reinvestment plan (in shares)		0
Stock issued, share-based compensation, net of forfeitures	15	$ 1	14
Stock issued, share-based compensation, net of forfeitures (in shares)		300,000
Share-based compensation expense, net of tax	3		3
Reclassification of noncontrolling interest	(46)						(46)
Balance at Mar. 31, 2016	$ 4,032	$ 604	$ 2,110	$ 1,539	$ (213)	$ (8)	$ 0
Balance, shares (in shares) at Mar. 31, 2016	120,679,004	120,700,000

Condensed Consolidated Stateme9

Condensed Consolidated Statements of Equity (Unaudited) (Parentheticals) - $ / shares	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Stockholders' Equity [Abstract]
Dividends on common stock, per share (in dollars per share)	$ 0.53	$ 0.51

Condensed Consolidated Statem10

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash flows from operating activities:
Net income	$ 193	$ 205
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization	102	97
Change in derivative instrument assets and liabilities	51	33
Deferred income taxes	15	5
Changes in certain assets and liabilities
Inventories, net of temporary LIFO liquidation	364	501
Prepaid and miscellaneous taxes	231	267
Energy marketing receivables and trade payables, net	25	(23)
Accrued natural gas costs, net	0	22
Trade payables, other than energy marketing	(8)	(13)
Receivables, other than energy marketing	(39)	(24)
Accrued expenses	(53)	(54)
Other, net	(40)	104
Net cash flow provided by operating activities	841	1,120
Cash flows from investing activities:
Expenditures for property, plant and equipment	(235)	(188)
Other, net	(3)	4
Net cash flow used in investing activities	(238)	(184)
Cash flows from financing activities:
Net repayments of commercial paper	(453)	(649)
Payment of long-term debt	(75)	(200)
Dividends paid on common shares	(64)	(61)
Distribution to noncontrolling interest	(19)	(18)
Other, net	9	2
Net cash flow used in financing activities	(602)	(926)
Net increase in cash and cash equivalents	1	10
Cash and cash equivalents at beginning of period	19	31
Cash and cash equivalents at end of period	20	41
Cash paid (received) during the period for
Interest	53	57
Income taxes	$ (132)	$ (140)

Organization and Basis of Prese

Organization and Basis of Presentation	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Presentation	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 Balance Sheet as of December 31, 2015 was derived from our audited consolidated financial statements. 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 that would typically be included in our annual audited financial statements. 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 2015 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 and the accounts of our VIE 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 our unaudited Condensed Consolidated Statements of Income. See Note 10 for additional information on our non-wholly owned entities. 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. Certain amounts from prior periods have been reclassified to conform to the current period presentation. These reclassifications had no material impact on our prior period balances.

Proposed Merger with Southern C

Proposed Merger with Southern Company	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Proposed Merger with Southern Company	Proposed Merger with Southern Company On August 23, 2015, we entered into the Merger Agreement with Southern Company and a new wholly owned subsidiary of Southern Company (Merger Sub), providing for the merger of Merger Sub with and into AGL Resources, with us surviving as a wholly owned, direct subsidiary of Southern Company. At the effective time of the merger, which is expected to occur in the second half of 2016, each share of our common stock, other than certain excluded shares, will convert into the right to receive $66 in cash, without interest, less any applicable withholding taxes. We and Southern Company have made joint filings seeking regulatory approval with all of the required state regulatory agencies. Completion of the merger remains subject to various closing conditions, including (i) the receipt of remaining required regulatory approvals from the Illinois Commission and New Jersey BPU, and such approvals having become final orders and (ii) the absence of a judgment, order, decision, injunction, ruling or other finding or agency requirement of a governmental entity prohibiting the closing of the merger. To date, the proposed merger has been approved by the Maryland Commission, the Georgia Commission, the California Public Utilities Commission, the Virginia Commission and our shareholders. Additionally, we received consent from the Federal Communications Commission to transfer parent company control of radio licenses held by certain of our subsidiaries and the waiting period under the Hart-Scott-Rodino Act has expired. On April 28, 2016, Southern Company, AGL Resources, Nicor Gas, the Illinois Attorney General’s Office, and the CUB filed a settlement agreement with the Illinois Commission that resolves all remaining contested issues with regards to the merger approval. This settlement agreement, along with the other resolved matters, is still subject to approval by the Illinois Commission. The Merger Agreement contains certain termination rights for each party. In addition, the Merger Agreement, in certain circumstances, provides for the payment by AGL Resources of a $201 million termination fee to Southern Company and, in certain circumstances, provides for the reimbursement of expenses up to $5 million upon termination of the erger Agreement (which reimbursement would reduce on a dollar-for-dollar basis any termination fee subsequently paid by us). As of March 31, 2016 , we had recorded no liability for termination fees. During the three months ended March 31, 2016 , we recorded $3 million ( $2 million , net of tax) of merger-related costs on the accompanying unaudited Condensed Consolidated Statements of Income, which consisted primarily of legal expenses and additional share-based compensation expenses associated with the proposed merger. These costs are treated as tax deductible since the requisite closing conditions to the merger have not yet been satisfied. Once the merger is closed, we will evaluate the tax deductibility of all merger-related costs and adjust for any non-deductible amounts in the effective tax rate.

Significant Accounting Policies

Significant Accounting Policies and Methods of Application	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Significant Accounting Policies and Methods of Application	Significant Accounting Policies and Methods of Application Our significant accounting policies are described in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. There have been no significant changes to our accounting policies during the three months ended March 31, 2016 . 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, derivatives 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. Inventories For our regulated utilities, except Nicor Gas, natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. Nicor Gas’ inventory is carried at cost on a LIFO basis. Under the LIFO method, 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 liquidation on our unaudited Condensed Consolidated Balance Sheets. 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, 2016 is expected to be restored prior to year-end and the inventory decrement as of March 31, 2015 was restored prior to December 31, 2015 . Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For the periods presented, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our natural gas inventories to market value. Three Months Ended March 31, In millions 2016 2015 LOCOM adjustments $ 3 $ 10 Goodwill We perform an annual impairment test on our reporting units that contain goodwill during the fourth fiscal quarter of each year or more frequently if impairment indicators arise. The amounts of goodwill as of March 31, 2016 and 2015 , and December 31, 2015 are provided in the following table. In millions Distribution operations Retail operations Midstream operations Consolidated Goodwill - March 31, 2015 $ 1,640 $ 173 $ 14 $ 1,827 Impairment (1) — — (14 ) (14 ) Goodwill - December 31, 2015 1,640 173 — 1,813 Goodwill - March 31, 2016 $ 1,640 $ 173 $ — $ 1,813 (1) Based on the result of an interim impairment test performed as of September 30, 2015, we recorded a non-cash impairment charge of the full $14 million ( $9 million , net of tax) of goodwill at midstream operations. Earnings per Common Share The following table shows the calculation of our diluted shares attributable to AGL Resources 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 2016 2015 Net income attributable to AGL Resources $ 182 $ 193 Denominator: Basic weighted average number of shares outstanding (1) 120.1 119.3 Effect of dilutive securities 0.3 0.3 Diluted weighted average number of shares outstanding (2) 120.4 119.6 Earnings per common share Basic earnings per common share attributable to AGL Resources $ 1.52 $ 1.62 Diluted earnings per common share attributable to AGL Resources $ 1.51 $ 1.62 (1) Daily weighted average shares outstanding. (2) Excludes all outstanding stock options whose effect would have been anti-dilutive. Accounting Developments Accounting standards adopted in 2016 Effective January 1, 2016 , we adopted the accounting guidance described below, none of which had a material impact on our unaudited condensed consolidated financial statements. For additional information on these accounting standards, see Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. • accounting for a share-based compensation performance target that could be achieved after the requisite service period; • consolidation of other legal entities into our financial statements; • accounting for fees paid in connection with arrangements with cloud-based software providers; and • reducing the diversity in fair value measurements hierarchy disclosures. Other newly issued accounting standards and updated authoritative guidance In March 2016, the FASB issued updated authoritative guidance related to accounting for certain aspects of share-based payment transactions. The new guidance changes the income tax accounting related to the tax "windfall" or "shortfall" on share-based compensation, increases the tax withholding level allowed before triggering liability classification of the award and allows for a policy election to account for forfeitures as they occur. This guidance is effective for us beginning January 1, 2017, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance. In February 2016, the FASB issued updated authoritative guidance related to accounting for lease transactions. The new guidance will require all organizations that use leased assets, referred to as "lessees," to recognize all leases with terms of more than 12 months on the balance sheet as right of use assets and corresponding liabilities. Lessees will continue to recognize lease expense based on classification of the lease, using a straight-line expense pattern for operating leases and a front-loaded expense pattern for financing leases. The accounting for lessors is substantially equivalent to the existing guidance. It also requires additional disclosures, both qualitative and quantitative, including amount, timing, and uncertainty of cash flows arising from leases. The new guidance is effective for us beginning January 1, 2019 and must be applied using the modified retrospective approach to each prior period presented. Early adoption of this new guidance is permitted. We are currently evaluating the potential impact of this new guidance. In January 2016, the FASB issued updated authoritative guidance related to classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning January 1, 2018, and limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance, but do not anticipate that it will have a material impact on our consolidated financial statements. In November 2015, the FASB issued updated authoritative guidance related to the balance sheet classification of deferred taxes, which requires companies to present deferred income tax assets and deferred income tax liabilities as noncurrent on a classified balance sheet instead of the current requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. The guidance is effective for us beginning January 1, 2017, and early application is permitted either prospectively or retrospectively. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In July 2015, the FASB issued an update to authoritative guidance to simplify the measurement of certain inventories. Under the new guidance, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could refer to replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventories carried on a LIFO basis, which for us applies only to our Nicor Gas inventories. The guidance is to be applied prospectively, is effective for us beginning January 1, 2017, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance. In May 2014, the FASB issued an update to authoritative guidance related to revenue from contracts with customers. The update replaces most of the existing guidance with a single set of principles for recognizing revenue from contracts with customers. In July 2015, the FASB delayed the effective date by one year and the guidance will now be effective for us beginning January 1, 2018. Early adoption of the standard is permitted, but not before the original effective date of December 15, 2016. The new guidance must be applied retrospectively to each prior period presented or via a cumulative effect upon the date of initial application. We have not determined the impact of this new guidance, nor have we selected a transition method.

Regulated Operations

Regulated Operations	3 Months Ended
	Mar. 31, 2016
Regulated Operations [Abstract]
Regulatory Operations	Regulated Operations The accounting policies for our regulated operations are described within "Regulated Operations" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Our regulatory assets and liabilities reflected within our unaudited Condensed Consolidated Balance Sheets as of the dates presented are summarized in the following table. In millions March 31, 2016 December 31, 2015 March 31, 2015 Regulatory assets Recoverable ERC $ 21 $ 31 $ 37 Recoverable pension and retiree welfare benefit costs 12 12 11 Deferred natural gas costs 2 6 7 Recoverable seasonal rates — 10 — Other 15 9 8 Regulatory assets – current 50 68 63 Recoverable ERC 364 370 331 Recoverable pension and retiree welfare benefit costs 111 113 108 Recoverable regulatory infrastructure program costs 83 83 73 Long-term debt fair value adjustment 64 66 72 Other 39 38 50 Regulatory assets – long-term 661 670 634 Total regulatory assets $ 711 $ 738 $ 697 Regulatory liabilities Accumulated removal costs $ 53 $ 53 $ 25 Bad debt over collection 47 42 30 Accrued natural gas costs 20 24 53 Deferred seasonal rates 20 — 20 Other 19 15 40 Regulatory liabilities – current 159 134 168 Accumulated removal costs 1,551 1,538 1,524 Bad debt over collection 28 21 19 Regulatory income tax liability 26 27 27 Unamortized investment tax credit 19 20 22 Other 8 5 20 Regulatory liabilities – long-term 1,632 1,611 1,612 Total regulatory liabilities $ 1,791 $ 1,745 $ 1,780 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 agency 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 on our unaudited Condensed Consolidated Balance Sheets. 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 March 31, 2016 December 31, 2015 March 31, 2015 Atlanta Gas Light (1) $ 105 $ 103 $ 119 Virginia Natural Gas 12 12 12 Elizabethtown Gas 4 4 2 Nicor Gas 3 3 — Total $ 124 $ 122 $ 133 (1) In October 2015, Atlanta Gas Light received an order from the Georgia Commission, which included a final determination of the true-up recovery related to the PRP that allows Atlanta Gas Light to recover $144 million of the $178 million of incurred and allowed costs that were deferred for future recovery. Deferred/Accrued 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 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. 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 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 determined using engineering-based estimates and 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 corresponding regulatory assets until the costs are recovered from customers. We primarily recover these deferred costs through rate riders that authorize dollar-for-dollar recovery. We expect to collect $21 million in revenues over the next 12 months , which is reflected as a current regulatory asset. The following table provides additional information on the estimated costs to remediate our current and former operating sites as of March 31, 2016 . In millions # of sites Probabilistic model cost estimates Engineering-based estimates Amount recorded Expected costs over next 12 months Cost recovery period Illinois (1) 26 $200 - $457 $ 46 $ 246 $ 30 As incurred New Jersey 6 115 - 195 7 122 25 7 years Georgia and Florida 13 29 - 52 21 50 13 5 years North Carolina (2) 1 n/a 5 5 — No recovery Total 46 $344 - $704 $ 79 $ 423 $ 68 (1) Nicor Gas is responsible in whole or in part for 26 MGP sites, two of which 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 and there is no amount included within our regulatory assets. Changes in estimated costs are recognized in income during the period of change. Regulatory Infrastructure Programs An update to our infrastructure improvement programs at our utilities is as follows. Virginia Natural Gas In March 2016, the Virginia Commission approved an extension to our original Steps to Advance Virginia's Energy (SAVE) program, under which Virginia Natural Gas is allowed to invest up to $210 million on qualifying infrastructure projects through 2021 to replace more than 200 miles of aging pipeline infrastructure.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The methods used to determine the fair values of our assets and liabilities are described within "Fair Value Measurements" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Derivative Instruments The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value, net of counterparty offset and collateral, on a recurring basis on our unaudited Condensed Consolidated Balance Sheets as of the dates presented. See Note 6 herein for additional information on our derivative instruments. March 31, 2016 December 31, 2015 March 31, 2015 In millions Assets (1) Liabilities Assets (1) Liabilities Assets (1) Liabilities Quoted prices in active markets (Level 1) $ — $ (96 ) $ 53 $ (63 ) $ — $ (106 ) Significant other observable inputs (Level 2) 108 (65 ) 122 (46 ) 108 (52 ) Netting of counterparty offset and cash collateral 69 96 33 63 104 106 Total carrying value (2) $ 177 $ (65 ) $ 208 $ (46 ) $ 212 $ (52 ) (1) Balances of $9 million at March 31, 2016 , $10 million at December 31, 2015 and $1 million at March 31, 2015 , 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 March 31, 2016 December 31, 2015 March 31, 2015 Long-term debt carrying amount (1) $ 3,743 $ 3,820 $ 3,580 Long-term debt fair value (2) 4,156 4,066 4,102 (1) The change in the March 31, 2015 balance is related to our adoption of new accounting guidance in 2015 that resulted in the reclassification of debt issuance costs from other long-term assets to offset the related debt balances in long-term debt. (2) Fair value determined using Level 2 inputs.

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments Our objectives and strategies for using derivative instruments, and the related accounting policies and methods used to determine their fair values are described within "Fair Value Measurements" in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. See Note 5 herein for additional information on the fair value of our derivative instruments. 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, 2016 , December 31, 2015 and March 31, 2015 , for agreements with such features, derivative instruments with liability fair values totaled $65 million , $46 million and $52 million , respectively, for which we had posted no collateral to our counterparties as we exceed the minimum credit rating requirements. As of March 31, 2016 , the maximum collateral that could have been required with these features was less than $1 million . For additional information on our credit-risk-related contingent features, see “Energy Marketing Receivables and Payables” in Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Our derivative instrument activities are included within operating cash flows as increases to net income of $51 million and $33 million for the three months ended March 31, 2016 and 2015 , respectively. Quantitative Disclosures Related to Derivative Instruments Our derivative instruments include 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 natural gas contracts outstanding in the following quantities: In Bcf (1) March 31, 2016 (2) December 31, 2015 March 31, 2015 Cash flow hedges 5 5 9 Not designated as hedges 81 (14 ) 231 Total volumes 86 (9 ) 240 Short position – cash flow hedges (6 ) (6 ) (6 ) Short position – not designated as hedges (2,974 ) (3,089 ) (2,735 ) Long position – cash flow hedges 11 11 15 Long position – not designated as hedges 3,055 3,075 2,966 Net long (short) position 86 (9 ) 240 (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) 99% of these contracts have durations of two years or less and 1% expire between two and five years . Derivative Instruments on our Unaudited Condensed Consolidated Balance Sheets In accordance with regulatory requirements, gains and losses on derivative instruments used in hedging activities of natural gas purchases for customer use at distribution operations are reflected in accrued natural gas costs within our unaudited Condensed Consolidated Balance Sheets until they are billed to customers. The following amounts deferred as a regulatory asset or liability on our unaudited Condensed Consolidated Balance Sheets are included in the net realized gains (losses) related to these natural gas cost hedging activities as of the periods presented. Three Months Ended March 31, In millions 2016 2015 Nicor Gas $ (2 ) $ (3 ) Elizabethtown Gas (6 ) (4 ) The following table presents the fair values and unaudited Condensed Consolidated Balance Sheets classifications of our derivative instruments as of the dates presented. March 31, 2016 December 31, 2015 March 31, 2015 In millions Classification Assets Liabilities Assets Liabilities Assets Liabilities Designated as cash flow hedges Natural gas contracts Current $ 1 $ (4 ) $ 3 $ (5 ) $ — $ (6 ) Natural gas contracts Long-term — (1 ) — (2 ) — (1 ) Interest rate swap agreements Current — (36 ) 9 — 1 — Interest rate swap agreements Long-term — — — — 3 — Total designated as cash flow hedges $ 1 $ (41 ) $ 12 $ (7 ) $ 4 $ (7 ) Not designated as hedges Natural gas contracts Current $ 419 $ (432 ) $ 751 $ (672 ) $ 557 $ (592 ) Natural gas contracts Long-term 92 (83 ) 179 (187 ) 98 (109 ) Total not designated as hedges $ 511 $ (515 ) $ 930 $ (859 ) $ 655 $ (701 ) Gross amounts of recognized assets and liabilities (1) (2) $ 512 $ (556 ) $ 942 $ (866 ) $ 659 $ (708 ) Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets (2) (326 ) 491 (724 ) 820 (446 ) 656 Net amounts of assets and liabilities presented on our unaudited Condensed Consolidated Balance Sheets (3) $ 186 $ (65 ) $ 218 $ (46 ) $ 213 $ (52 ) (1) The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Balance Sheets 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 $165 million as of March 31, 2016 , $96 million as of December 31, 2015 , and $210 million as of March 31, 2015 . Cash collateral is included in the “Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets” line of this table. (3) As of March 31, 2016 , December 31, 2015 , and March 31, 2015 , we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets. Derivative Instruments on the Unaudited Condensed Consolidated Statements of Income The following table presents the impacts of our derivative instruments on our unaudited Condensed Consolidated Statements of Income for the periods presented. Three Months Ended March 31, In millions 2016 2015 Designated as cash flow hedges (1) Natural gas contracts - net loss reclassified from OCI into cost of goods sold $ — $ (1 ) Interest rate swaps - net gain reclassified from OCI into interest expense 1 1 Total designated as cash flow hedges, net of tax 1 — Not designated as hedges (1) Natural gas contracts - net fair value adjustments recorded in operating revenues 20 (24 ) Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2) (1 ) (2 ) Income tax (7 ) 10 Total not designated as hedges, net of tax 12 (16 ) Total gains (losses) on derivative instruments, net of tax $ 13 $ (16 ) (1) Associated with the fair value of derivative instruments held at March 31, 2016 and 2015. (2) Excludes gains (losses) recorded in cost of goods sold associated with weather derivatives of $3 million and $(2) million for the three months ended March 31, 2016 and 2015 , respectively, as they are accounted for based on intrinsic value rather than fair value. 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, 2016 and 2015 . Our expected net losses to be reclassified from OCI into cost of goods sold, operation and maintenance expense, interest expense and operating revenues to be recognized on our unaudited Condensed Consolidated Statements of Income over the next 12 months are $4 million . These deferred losses are related to natural gas derivative contracts associated with retail operations’ and Nicor Gas’ system use and our interest rate swaps. The expected losses are based upon the fair values of these financial instruments at March 31, 2016 . 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 on our unaudited Condensed Consolidated Statements of Income. See Note 9 for these amounts. There have been no other significant changes to our derivative instruments, as described in Note 3, Note 5, Note 6 and Note 10 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.

Employee Benefit Plans

Employee Benefit Plans	3 Months Ended
	Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Employee Benefit Plans	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 7 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Following are the components of our pension costs for the periods indicated. Three Months Ended March 31, In millions 2016 2015 Service cost (1) $ 6 $ 7 Interest cost (1) 10 11 Expected return on plan assets (16 ) (16 ) Net amortization of prior service credit — (1 ) Recognized actuarial loss 6 8 Net periodic pension benefit cost $ 6 $ 9 (1) Effective January 1, 2016, we use a spot rate approach to estimate the service cost and interest cost components. Historically, we estimated these components using a single weighted-average discount rate. Welfare Benefits The benefits of our Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. are described in Note 7 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Following are the components of our welfare costs for the periods indicated. Three Months Ended March 31, In millions 2016 2015 Service cost (1) $ 1 $ 1 Interest cost (1) 3 3 Expected return on plan assets (2 ) (2 ) Net amortization of prior service credit (1 ) — Recognized actuarial loss 1 1 Net periodic welfare benefit cost $ 2 $ 3 (1) Effective January 1, 2016, we use a spot rate approach to estimate the service cost and interest cost components. Historically, we estimated these components using a single weighted-average discount rate.

Debt and Credit Facilities

Debt and Credit Facilities	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Debt and Credit Facilities	Debt and Credit Facilities The following table provides maturity dates or ranges, 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 and the gas facility revenue bonds issued by Pivotal Utility. Additionally, substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. For additional information on our debt and credit facilities, see Note 9 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. March 31, 2016 March 31, 2015 Dollars in millions Year(s) due Weighted average interest rate (1) Outstanding December 31, 2015 Weighted average interest rate (1) Outstanding Short-term debt Commercial paper - AGL Capital (2) 2016 0.8 % $ 204 $ 471 0.5 % $ 176 Commercial paper - Nicor Gas (2) 2016 0.6 353 539 0.4 350 Total short-term debt 0.7 % $ 557 $ 1,010 0.4 % $ 526 Current portion of long-term debt 2016 5.2 % $ 470 $ 545 2.9 % $ 75 Long-term debt - excluding current portion Senior notes 2018-2043 4.9 % $ 2,455 $ 2,455 5.0 % $ 2,625 First mortgage bonds 2019-2038 5.9 375 375 6.0 425 Gas facility revenue bonds 2022-2033 1.1 200 200 0.8 200 Medium-term notes 2017-2027 7.8 181 181 7.8 181 Total principal long-term debt 4.8 % $ 3,211 $ 3,211 4.9 % $ 3,431 Unamortized fair value adjustment of long-term debt n/a n/a 66 68 n/a 77 Unamortized debt premium, net n/a n/a 16 16 n/a 16 Unamortized debt issuance costs n/a n/a (20 ) (20 ) n/a (19 ) Total non-principal long-term debt n/a n/a $ 62 $ 64 n/a $ 74 Total long-term debt - excluding current portion $ 3,273 $ 3,275 $ 3,505 Total debt $ 4,300 $ 4,830 $ 4,106 (1) Interest rates are calculated based on the daily weighted average balance outstanding for the three months ended March 31 , 2016 and 2015 . (2) As of March 31, 2016 , the effective interest rates on our commercial paper borrowings were 0.8% for AGL Capital and 0.6% for Nicor Gas. 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 2016 , our commercial paper maturities ranged from 1 to 59 days, and at March 31, 2016 , remaining terms to maturity ranged from 1 to 46 days. During the first three months of 2016 , there were no commercial paper issuances with original maturities over three months. Long-Term Debt On February 1, 2016, $75 million of Nicor Gas first mortgage bonds matured and were repaid using the proceeds from commercial paper borrowings. 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 our senior note issuance in the fourth quarter of 2015 and our anticipated issuances in 2016. We have designated the forward-starting interest rate swaps, which are settled on the respective debt issuance dates, as cash flow hedges. We settled $200 million of these interest rate swaps on November 18, 2015, in conjunction with the aforementioned senior note issuance. We performed a qualitative assessment of effectiveness on the remaining interest rate swaps as of March 31, 2016 and concluded that the remaining hedges are 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 month. The following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed. AGL Resources Nicor Gas March 31, 2016 December 31, 2015 March 31, 2015 March 31, 2016 December 31, 2015 March 31, 2015 Debt covenants (1) 50 % 54 % 50 % 47 % 56 % 54 % (1) As defined in our credit facilities, these ratios include standby letters of credit and performance/surety bonds and exclude accumulated OCI items related to non-cash pension adjustments, welfare benefits liability adjustments and accounting for cash flow hedges. 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.

Equity

Equity	3 Months Ended
	Mar. 31, 2016
Stockholders' Equity Note [Abstract]
Equity	Equity Our other comprehensive income (loss) amounts are aggregated within accumulated other comprehensive loss on our unaudited Condensed Consolidated Balance Sheets. The following table provides changes in the components of our accumulated other comprehensive loss balances, net of the related income tax effects. 2016 2015 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 $ 2 $ (188 ) $ (186 ) $ (6 ) $ (200 ) $ (206 ) OCI, before reclassifications (29 ) — (29 ) 2 — 2 Amounts reclassified from accumulated OCI (1 ) 3 2 — 3 3 Net current-period other comprehensive (loss) income (30 ) 3 (27 ) 2 3 5 As of end of period $ (28 ) $ (185 ) $ (213 ) $ (4 ) $ (197 ) $ (201 ) (1) All amounts are net of income taxes and noncontrolling interest. 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 favorable (unfavorable) impact on net income for the periods presented. Three Months Ended In millions (1) 2016 2015 Cash flow hedges: Cost of goods sold (natural gas contracts) $ — $ (1 ) Interest expense (interest rate contracts) 1 1 Total cash flow hedges, net of income tax 1 — Retirement benefit plans: Operation and maintenance expense (actuarial losses) (2) (5 ) (5 ) Total retirement benefit plans (5 ) (5 ) Income tax benefit 2 2 Total retirement benefit plans, net of income tax (3 ) (3 ) Total reclassification for the period $ (2 ) $ (3 ) (1) Amounts in parentheses indicate debits, or reductions, to our net income and credits 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 7 herein for additional details about net periodic benefit cost.

Non-Wholly Owned Entities and C

Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest	3 Months Ended
	Mar. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest	Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest SouthStar, a joint venture owned by us and Piedmont, is our only VIE for which we are the primary beneficiary. For additional information on SouthStar, see Note 11 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. Earnings from SouthStar in 2016 and 2015 were allocated entirely in accordance with the ownership interests. On December 9, 2015, we notified Piedmont of our election, in accordance with the change in control provisions in the Second Amended and Restated Limited Liability Company Agreement of SouthStar, to purchase Piedmont’s remaining 15% interest in SouthStar at fair market value. This purchase is contingent upon the closing of the merger between Piedmont and Duke Energy Corporation, which is subject to various closing conditions that are beyond our control and is expected to be completed in 2016. On February 12, 2016, we and Piedmont agreed to various terms of this purchase, including a fair market value of $160 million . During the first quarter of 2016, we reclassified the noncontrolling interest related to Piedmont's 15% interest in SouthStar, whose redemption is beyond our control, as a contingently redeemable noncontrolling interest. Previously, this noncontrolling interest was included in equity. If our purchase of this noncontrolling interest is completed, the difference between the purchase price and the amount of noncontrolling interest will be recorded in equity. A roll-forward of the contingently redeemable noncontrolling interest is detailed below: In millions Balance as of December 31, 2015 $ — Reclassification of noncontrolling interest 46 Net income attributable to noncontrolling interest 11 Distribution to noncontrolling interest (19 ) Balance as of March 31, 2016 $ 38 Cash flows used in our investing activities include capital expenditures for SouthStar of $1 million and $1 million for the three months ended March 31, 2016 and 2015 , respectively. 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 , 2016 and 2015 , SouthStar distributed $19 million and $18 million , respectively, to Piedmont. SouthStar’s counterparties 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. The SouthStar amounts exclude intercompany eliminations and the balances of our wholly-owned subsidiary with an 85% ownership interest in SouthStar. March 31, 2016 December 31, 2015 March 31, 2015 In millions Consolidated SouthStar % Consolidated SouthStar % Consolidated SouthStar % Current assets $ 1,537 $ 177 12 % $ 2,115 $ 245 12 % $ 2,079 $ 182 9 % Goodwill and other intangible assets 1,918 113 6 1,922 114 6 1,943 119 6 Long-term assets and other deferred debits 10,881 17 — 10,717 16 — 10,097 17 — Total assets $ 14,336 $ 307 2 % $ 14,754 $ 375 3 % $ 14,119 $ 318 2 % Current liabilities $ 2,489 $ 41 2 % $ 3,000 $ 54 2 % $ 2,371 $ 46 2 % Long-term liabilities and other deferred credits 7,777 1 — 7,779 — — 7,784 1 — Total liabilities 10,266 42 — 10,779 54 1 10,155 47 — Contingently redeemable noncontrolling interest 38 — — — — — — — — Equity 4,032 265 7 3,975 321 8 3,964 271 7 Total liabilities, redeemable noncontrolling interest and equity $ 14,336 $ 307 2 % $ 14,754 $ 375 3 % $ 14,119 $ 318 2 % 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 2016 2015 Operating revenues $ 254 $ 311 Operating expenses Cost of goods sold 157 203 Operation and maintenance 22 23 Depreciation and amortization 2 2 Taxes other than income taxes — 1 Total operating expenses 181 229 Operating income $ 73 $ 82 Equity Method Investments For more information about our equity method investments, see Note 11 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. The carrying amounts within our unaudited Condensed Consolidated Balance Sheets of our investments that are accounted for under the equity method were as follows: March 31, December 31, March 31, In millions 2016 2015 2015 Triton $ 48 $ 49 $ 57 Horizon Pipeline 14 14 14 PennEast Pipeline 12 9 2 Atlantic Coast Pipeline 9 7 3 Other 1 1 — Total $ 84 $ 80 $ 76 Income from our equity method investments is classified as other income on 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 2016 2015 Horizon Pipeline $ 1 $ 1

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments, Guarantees and Contingencies	Commitments, Guarantees and Contingencies We incur various contractual obligations and financial commitments in the normal course of business 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 commercial arrangements that are directly supported by related revenue-producing activities. We are also involved in legal or administrative proceedings before various courts and agencies with respect to general claims, environmental remediation and other matters. While 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 12 to our consolidated financial statements and related notes included in Item 8 of our 2015 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 liabilities have been recorded for such guarantees and indemnifications, as the fair values were inconsequential at inception. Regulatory Matters In August 2014, staff of the Illinois Commission and the CUB filed testimony in the Nicor Gas 2003 gas cost prudence review disputing certain gas loan transactions offered by Nicor Gas under its Chicago Hub services and requesting refunds of $18 million and $22 million , respectively. We filed surrebuttal testimony in December 2014 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. In July 2015, the Administrative Law Judge issued a proposed order concluding that Nicor Gas’ supply costs and purchases in 2003 were prudent, its reconciliation of the related costs was proper, and the propositions by the staff of the Illinois Commission and the CUB were based on hindsight speculation, which is expressly prohibited in a prudence review examination. In November 2015, the Illinois Commission granted the CUB's petition for a rehearing on this matter. In February 2016, the Administrative Law Judge issued a proposed order on the rehearing affirming the original order by the Illinois Commission, which was approved by the Illinois Commission in March 2016. 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 our current and former operating sites. See Note 4 herein for additional information on our environmental remediation costs. In September 2015, the Environmental Protection Agency filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas distribution system and the Environmental Protection Agency seeks a total civil penalty of approximately $0.3 million . While we are unable to predict the ultimate outcome of this matter, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition. 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 resolutions of these contingencies, whether individually or in aggregate, could possibly be material to earnings in a particular quarter, they will not have a material adverse effect on our consolidated balance sheets or cash flows for the year. For additional litigation information, see Note 12 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K.

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Segment Information	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.” 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 this segment are geographically dispersed, the operating subsidiaries within the segment have similar economic and risk characteristics as they are regulated utilities with rates determined by individual state regulatory agencies. 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 equipment 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 segment includes subsidiaries that are not significant on a stand-alone basis and that do not align with one of our reportable segments. The chief operating decision maker of the company is the 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 (loss) and other income and expenses and excludes income taxes and interest expense, which we evaluate on a consolidated basis. Summarized statements of income, balance sheets and capital expenditure information by segment as of, and for the periods presented, are shown in the following tables. Three months ended March 31, 2016 In millions Distribution operations Retail operations Wholesale services (1) Midstream operations Other Intercompany eliminations Consolidated Operating revenues from external parties $ 983 $ 286 $ 63 $ 15 $ 2 $ (15 ) $ 1,334 Intercompany revenues 45 — — — — (45 ) — Total operating revenues 1,028 286 63 15 2 (60 ) 1,334 Operating expenses Cost of goods sold 464 162 3 6 — (57 ) 578 Operation and maintenance 185 37 16 7 (2 ) (2 ) 241 Depreciation and amortization 89 6 — 4 3 — 102 Taxes other than income taxes 56 1 1 1 3 — 62 Merger-related expenses — — — — 3 — 3 Total operating expenses 794 206 20 18 7 (59 ) 986 Operating income (loss) 234 80 43 (3 ) (5 ) (1 ) 348 Other income — — 1 2 — — 3 EBIT $ 234 $ 80 $ 44 $ (1 ) $ (5 ) $ (1 ) $ 351 Total assets $ 12,405 $ 717 $ 723 $ 715 $ 9,342 $ (9,566 ) $ 14,336 Capital expenditures $ 204 $ 2 $ — $ 18 $ 11 $ — $ 235 Three months ended March 31, 2015 In millions Distribution operations Retail operations Wholesale services (1) Midstream operations Other Intercompany eliminations Consolidated 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 Total assets $ 11,896 $ 698 $ 1,100 $ 693 $ 9,036 $ (9,304 ) $ 14,119 Capital expenditures $ 170 $ 2 $ 1 $ 3 $ 12 $ — $ 188 (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 are shown in the following table. In millions Third party gross revenues Intercompany revenues Total gross Less gross Operating Three months ended March 31, 2016 $ 1,443 81 1,524 1,461 $ 63 Three months ended March 31, 2015 $ 2,146 150 2,296 2,206 $ 90 Identifiable assets are those used in each segment’s operations. Information by segment on our Consolidated Balance Sheet as of December 31, 2015 , is as follows: In millions Distribution operations Retail Wholesale Midstream Other Intercompany eliminations Consolidated Total assets $ 12,517 $ 686 $ 935 $ 692 $ 9,664 $ (9,740 ) $ 14,754

Significant Accounting Polici23

Significant Accounting Policies and Methods of Application (Policies)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Use of Accounting Estimates	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, derivatives 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.
Inventories	Inventories For our regulated utilities, except Nicor Gas, natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. Nicor Gas’ inventory is carried at cost on a LIFO basis. Under the LIFO method, 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 liquidation on our unaudited Condensed Consolidated Balance Sheets. 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, 2016 is expected to be restored prior to year-end and the inventory decrement as of March 31, 2015 was restored prior to December 31, 2015 . Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis.
Goodwill	Goodwill We perform an annual impairment test on our reporting units that contain goodwill during the fourth fiscal quarter of each year or more frequently if impairment indicators arise.
Earnings Per Common Share	Earnings per Common Share The following table shows the calculation of our diluted shares attributable to AGL Resources 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 2016 2015 Net income attributable to AGL Resources $ 182 $ 193 Denominator: Basic weighted average number of shares outstanding (1) 120.1 119.3 Effect of dilutive securities 0.3 0.3 Diluted weighted average number of shares outstanding (2) 120.4 119.6 Earnings per common share Basic earnings per common share attributable to AGL Resources $ 1.52 $ 1.62 Diluted earnings per common share attributable to AGL Resources $ 1.51 $ 1.62
Accounting Developments	Accounting Developments Accounting standards adopted in 2016 Effective January 1, 2016 , we adopted the accounting guidance described below, none of which had a material impact on our unaudited condensed consolidated financial statements. For additional information on these accounting standards, see Note 3 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. • accounting for a share-based compensation performance target that could be achieved after the requisite service period; • consolidation of other legal entities into our financial statements; • accounting for fees paid in connection with arrangements with cloud-based software providers; and • reducing the diversity in fair value measurements hierarchy disclosures. Other newly issued accounting standards and updated authoritative guidance In March 2016, the FASB issued updated authoritative guidance related to accounting for certain aspects of share-based payment transactions. The new guidance changes the income tax accounting related to the tax "windfall" or "shortfall" on share-based compensation, increases the tax withholding level allowed before triggering liability classification of the award and allows for a policy election to account for forfeitures as they occur. This guidance is effective for us beginning January 1, 2017, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance. In February 2016, the FASB issued updated authoritative guidance related to accounting for lease transactions. The new guidance will require all organizations that use leased assets, referred to as "lessees," to recognize all leases with terms of more than 12 months on the balance sheet as right of use assets and corresponding liabilities. Lessees will continue to recognize lease expense based on classification of the lease, using a straight-line expense pattern for operating leases and a front-loaded expense pattern for financing leases. The accounting for lessors is substantially equivalent to the existing guidance. It also requires additional disclosures, both qualitative and quantitative, including amount, timing, and uncertainty of cash flows arising from leases. The new guidance is effective for us beginning January 1, 2019 and must be applied using the modified retrospective approach to each prior period presented. Early adoption of this new guidance is permitted. We are currently evaluating the potential impact of this new guidance. In January 2016, the FASB issued updated authoritative guidance related to classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning January 1, 2018, and limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance, but do not anticipate that it will have a material impact on our consolidated financial statements. In November 2015, the FASB issued updated authoritative guidance related to the balance sheet classification of deferred taxes, which requires companies to present deferred income tax assets and deferred income tax liabilities as noncurrent on a classified balance sheet instead of the current requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. The guidance is effective for us beginning January 1, 2017, and early application is permitted either prospectively or retrospectively. We have determined that this new guidance will not have a material impact on our consolidated financial statements. In July 2015, the FASB issued an update to authoritative guidance to simplify the measurement of certain inventories. Under the new guidance, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could refer to replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventories carried on a LIFO basis, which for us applies only to our Nicor Gas inventories. The guidance is to be applied prospectively, is effective for us beginning January 1, 2017, and early adoption is permitted. We are currently evaluating the potential impact of this new guidance. In May 2014, the FASB issued an update to authoritative guidance related to revenue from contracts with customers. The update replaces most of the existing guidance with a single set of principles for recognizing revenue from contracts with customers. In July 2015, the FASB delayed the effective date by one year and the guidance will now be effective for us beginning January 1, 2018. Early adoption of the standard is permitted, but not before the original effective date of December 15, 2016. The new guidance must be applied retrospectively to each prior period presented or via a cumulative effect upon the date of initial application. We have not determined the impact of this new guidance, nor have we selected a transition method.

Significant Accounting Polici24

Significant Accounting Policies and Methods of Application (Tables)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Schedule of Inventory, Lower of Cost or Market Adjustment	For the periods presented, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our natural gas inventories to market value. Three Months Ended March 31, In millions 2016 2015 LOCOM adjustments $ 3 $ 10
Schedule of Goodwill	The amounts of goodwill as of March 31, 2016 and 2015 , and December 31, 2015 are provided in the following table. In millions Distribution operations Retail operations Midstream operations Consolidated Goodwill - March 31, 2015 $ 1,640 $ 173 $ 14 $ 1,827 Impairment (1) — — (14 ) (14 ) Goodwill - December 31, 2015 1,640 173 — 1,813 Goodwill - March 31, 2016 $ 1,640 $ 173 $ — $ 1,813 (1) Based on the result of an interim impairment test performed as of September 30, 2015, we recorded a non-cash impairment charge of the full $14 million ( $9 million , net of tax) of goodwill at midstream operations.
Schedule of Weighted Average Number of Shares	The following table shows the calculation of our diluted shares attributable to AGL Resources 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 2016 2015 Net income attributable to AGL Resources $ 182 $ 193 Denominator: Basic weighted average number of shares outstanding (1) 120.1 119.3 Effect of dilutive securities 0.3 0.3 Diluted weighted average number of shares outstanding (2) 120.4 119.6 Earnings per common share Basic earnings per common share attributable to AGL Resources $ 1.52 $ 1.62 Diluted earnings per common share attributable to AGL Resources $ 1.51 $ 1.62 (1) Daily weighted average shares outstanding. (2) Excludes all outstanding stock options whose effect would have been anti-dilutive.

Regulated Operations (Tables)

Regulated Operations (Tables)	3 Months Ended
	Mar. 31, 2016
Regulated Operations [Line Items]
Schedule of Regulatory Assets	Our regulatory assets and liabilities reflected within our unaudited Condensed Consolidated Balance Sheets as of the dates presented are summarized in the following table. In millions March 31, 2016 December 31, 2015 March 31, 2015 Regulatory assets Recoverable ERC $ 21 $ 31 $ 37 Recoverable pension and retiree welfare benefit costs 12 12 11 Deferred natural gas costs 2 6 7 Recoverable seasonal rates — 10 — Other 15 9 8 Regulatory assets – current 50 68 63 Recoverable ERC 364 370 331 Recoverable pension and retiree welfare benefit costs 111 113 108 Recoverable regulatory infrastructure program costs 83 83 73 Long-term debt fair value adjustment 64 66 72 Other 39 38 50 Regulatory assets – long-term 661 670 634 Total regulatory assets $ 711 $ 738 $ 697 Regulatory liabilities Accumulated removal costs $ 53 $ 53 $ 25 Bad debt over collection 47 42 30 Accrued natural gas costs 20 24 53 Deferred seasonal rates 20 — 20 Other 19 15 40 Regulatory liabilities – current 159 134 168 Accumulated removal costs 1,551 1,538 1,524 Bad debt over collection 28 21 19 Regulatory income tax liability 26 27 27 Unamortized investment tax credit 19 20 22 Other 8 5 20 Regulatory liabilities – long-term 1,632 1,611 1,612 Total regulatory liabilities $ 1,791 $ 1,745 $ 1,780
Environmental Exit Costs by Cost	he following table provides additional information on the estimated costs to remediate our current and former operating sites as of March 31, 2016 . In millions # of sites Probabilistic model cost estimates Engineering-based estimates Amount recorded Expected costs over next 12 months Cost recovery period Illinois (1) 26 $200 - $457 $ 46 $ 246 $ 30 As incurred New Jersey 6 115 - 195 7 122 25 7 years Georgia and Florida 13 29 - 52 21 50 13 5 years North Carolina (2) 1 n/a 5 5 — No recovery Total 46 $344 - $704 $ 79 $ 423 $ 68 (1) Nicor Gas is responsible in whole or in part for 26 MGP sites, two of which 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 and there is no amount included within our regulatory assets. Changes in estimated costs are recognized in income during the period of change.
Regulatory Asset Off Balance Sheet [Member]
Regulated Operations [Line Items]
Schedule of Regulatory Assets	The following table illustrates our authorized ratemaking amounts that are not recognized on our unaudited Condensed Consolidated Balance Sheets. 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 March 31, 2016 December 31, 2015 March 31, 2015 Atlanta Gas Light (1) $ 105 $ 103 $ 119 Virginia Natural Gas 12 12 12 Elizabethtown Gas 4 4 2 Nicor Gas 3 3 — Total $ 124 $ 122 $ 133 (1) In October 2015, Atlanta Gas Light received an order from the Georgia Commission, which included a final determination of the true-up recovery related to the PRP that allows Atlanta Gas Light to recover $144 million of the $178 million of incurred and allowed costs that were deferred for future recovery.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2016
Long-term Debt [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table lists the carrying amount and fair value of our long-term debt as of the dates presented. In millions March 31, 2016 December 31, 2015 March 31, 2015 Long-term debt carrying amount (1) $ 3,743 $ 3,820 $ 3,580 Long-term debt fair value (2) 4,156 4,066 4,102 (1) The change in the March 31, 2015 balance is related to our adoption of new accounting guidance in 2015 that resulted in the reclassification of debt issuance costs from other long-term assets to offset the related debt balances in long-term debt. (2) Fair value determined using Level 2 inputs.
Natural Gas and Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value, net of counterparty offset and collateral, on a recurring basis on our unaudited Condensed Consolidated Balance Sheets as of the dates presented. See Note 6 herein for additional information on our derivative instruments. March 31, 2016 December 31, 2015 March 31, 2015 In millions Assets (1) Liabilities Assets (1) Liabilities Assets (1) Liabilities Quoted prices in active markets (Level 1) $ — $ (96 ) $ 53 $ (63 ) $ — $ (106 ) Significant other observable inputs (Level 2) 108 (65 ) 122 (46 ) 108 (52 ) Netting of counterparty offset and cash collateral 69 96 33 63 104 106 Total carrying value (2) $ 177 $ (65 ) $ 208 $ (46 ) $ 212 $ (52 ) (1) Balances of $9 million at March 31, 2016 , $10 million at December 31, 2015 and $1 million at March 31, 2015 , 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.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of the dates presented, we had natural gas contracts outstanding in the following quantities: In Bcf (1) March 31, 2016 (2) December 31, 2015 March 31, 2015 Cash flow hedges 5 5 9 Not designated as hedges 81 (14 ) 231 Total volumes 86 (9 ) 240 Short position – cash flow hedges (6 ) (6 ) (6 ) Short position – not designated as hedges (2,974 ) (3,089 ) (2,735 ) Long position – cash flow hedges 11 11 15 Long position – not designated as hedges 3,055 3,075 2,966 Net long (short) position 86 (9 ) 240 (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) 99% of these contracts have durations of two years or less and 1% expire between two and five years .
Loss Recognized In Income	The following amounts deferred as a regulatory asset or liability on our unaudited Condensed Consolidated Balance Sheets are included in the net realized gains (losses) related to these natural gas cost hedging activities as of the periods presented. Three Months Ended March 31, In millions 2016 2015 Nicor Gas $ (2 ) $ (3 ) Elizabethtown Gas (6 ) (4 )
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following table presents the fair values and unaudited Condensed Consolidated Balance Sheets classifications of our derivative instruments as of the dates presented. March 31, 2016 December 31, 2015 March 31, 2015 In millions Classification Assets Liabilities Assets Liabilities Assets Liabilities Designated as cash flow hedges Natural gas contracts Current $ 1 $ (4 ) $ 3 $ (5 ) $ — $ (6 ) Natural gas contracts Long-term — (1 ) — (2 ) — (1 ) Interest rate swap agreements Current — (36 ) 9 — 1 — Interest rate swap agreements Long-term — — — — 3 — Total designated as cash flow hedges $ 1 $ (41 ) $ 12 $ (7 ) $ 4 $ (7 ) Not designated as hedges Natural gas contracts Current $ 419 $ (432 ) $ 751 $ (672 ) $ 557 $ (592 ) Natural gas contracts Long-term 92 (83 ) 179 (187 ) 98 (109 ) Total not designated as hedges $ 511 $ (515 ) $ 930 $ (859 ) $ 655 $ (701 ) Gross amounts of recognized assets and liabilities (1) (2) $ 512 $ (556 ) $ 942 $ (866 ) $ 659 $ (708 ) Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets (2) (326 ) 491 (724 ) 820 (446 ) 656 Net amounts of assets and liabilities presented on our unaudited Condensed Consolidated Balance Sheets (3) $ 186 $ (65 ) $ 218 $ (46 ) $ 213 $ (52 ) (1) The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Balance Sheets 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 $165 million as of March 31, 2016 , $96 million as of December 31, 2015 , and $210 million as of March 31, 2015 . Cash collateral is included in the “Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets” line of this table. (3) As of March 31, 2016 , December 31, 2015 , and March 31, 2015 , we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets.
Schedule of Derivative Instruments	The following table presents the impacts of our derivative instruments on our unaudited Condensed Consolidated Statements of Income for the periods presented. Three Months Ended March 31, In millions 2016 2015 Designated as cash flow hedges (1) Natural gas contracts - net loss reclassified from OCI into cost of goods sold $ — $ (1 ) Interest rate swaps - net gain reclassified from OCI into interest expense 1 1 Total designated as cash flow hedges, net of tax 1 — Not designated as hedges (1) Natural gas contracts - net fair value adjustments recorded in operating revenues 20 (24 ) Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2) (1 ) (2 ) Income tax (7 ) 10 Total not designated as hedges, net of tax 12 (16 ) Total gains (losses) on derivative instruments, net of tax $ 13 $ (16 ) (1) Associated with the fair value of derivative instruments held at March 31, 2016 and 2015. (2) Excludes gains (losses) recorded in cost of goods sold associated with weather derivatives of $3 million and $(2) million for the three months ended March 31, 2016 and 2015 , respectively, as they are accounted for based on intrinsic value rather than fair value.

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Schedule of Net Benefit Costs	Following are the components of our welfare costs for the periods indicated. Three Months Ended March 31, In millions 2016 2015 Service cost (1) $ 1 $ 1 Interest cost (1) 3 3 Expected return on plan assets (2 ) (2 ) Net amortization of prior service credit (1 ) — Recognized actuarial loss 1 1 Net periodic welfare benefit cost $ 2 $ 3 (1) Effective January 1, 2016, we use a spot rate approach to estimate the service cost and interest cost components. Historically, we estimated these components using a single weighted-average discount rate. Following are the components of our pension costs for the periods indicated. Three Months Ended March 31, In millions 2016 2015 Service cost (1) $ 6 $ 7 Interest cost (1) 10 11 Expected return on plan assets (16 ) (16 ) Net amortization of prior service credit — (1 ) Recognized actuarial loss 6 8 Net periodic pension benefit cost $ 6 $ 9 (1) Effective January 1, 2016, we use a spot rate approach to estimate the service cost and interest cost components. Historically, we estimated these components using a single weighted-average discount rate.

Debt and Credit Facilities (Tab

Debt and Credit Facilities (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Schedule of Debt	The following table provides maturity dates or ranges, 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 and the gas facility revenue bonds issued by Pivotal Utility. Additionally, substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. For additional information on our debt and credit facilities, see Note 9 to our consolidated financial statements and related notes included in Item 8 of our 2015 Form 10-K. March 31, 2016 March 31, 2015 Dollars in millions Year(s) due Weighted average interest rate (1) Outstanding December 31, 2015 Weighted average interest rate (1) Outstanding Short-term debt Commercial paper - AGL Capital (2) 2016 0.8 % $ 204 $ 471 0.5 % $ 176 Commercial paper - Nicor Gas (2) 2016 0.6 353 539 0.4 350 Total short-term debt 0.7 % $ 557 $ 1,010 0.4 % $ 526 Current portion of long-term debt 2016 5.2 % $ 470 $ 545 2.9 % $ 75 Long-term debt - excluding current portion Senior notes 2018-2043 4.9 % $ 2,455 $ 2,455 5.0 % $ 2,625 First mortgage bonds 2019-2038 5.9 375 375 6.0 425 Gas facility revenue bonds 2022-2033 1.1 200 200 0.8 200 Medium-term notes 2017-2027 7.8 181 181 7.8 181 Total principal long-term debt 4.8 % $ 3,211 $ 3,211 4.9 % $ 3,431 Unamortized fair value adjustment of long-term debt n/a n/a 66 68 n/a 77 Unamortized debt premium, net n/a n/a 16 16 n/a 16 Unamortized debt issuance costs n/a n/a (20 ) (20 ) n/a (19 ) Total non-principal long-term debt n/a n/a $ 62 $ 64 n/a $ 74 Total long-term debt - excluding current portion $ 3,273 $ 3,275 $ 3,505 Total debt $ 4,300 $ 4,830 $ 4,106 (1) Interest rates are calculated based on the daily weighted average balance outstanding for the three months ended March 31 , 2016 and 2015 . (2) As of March 31, 2016 , the effective interest rates on our commercial paper borrowings were 0.8% for AGL Capital and 0.6% for Nicor Gas.
Schedule of Capitalization	The following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed. AGL Resources Nicor Gas March 31, 2016 December 31, 2015 March 31, 2015 March 31, 2016 December 31, 2015 March 31, 2015 Debt covenants (1) 50 % 54 % 50 % 47 % 56 % 54 % (1) As defined in our credit facilities, these ratios include standby letters of credit and performance/surety bonds and exclude accumulated OCI items related to non-cash pension adjustments, welfare benefits liability adjustments and accounting for cash flow hedges.

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 2016
Stockholders' Equity Note [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	The following table provides changes in the components of our accumulated other comprehensive loss balances, net of the related income tax effects. 2016 2015 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 $ 2 $ (188 ) $ (186 ) $ (6 ) $ (200 ) $ (206 ) OCI, before reclassifications (29 ) — (29 ) 2 — 2 Amounts reclassified from accumulated OCI (1 ) 3 2 — 3 3 Net current-period other comprehensive (loss) income (30 ) 3 (27 ) 2 3 5 As of end of period $ (28 ) $ (185 ) $ (213 ) $ (4 ) $ (197 ) $ (201 ) (1) All amounts are net of income taxes and noncontrolling interest. Amounts in parentheses indicate debits to accumulated other comprehensive loss.
Reclassification out of Accumulated Other Comprehensive Income	The following table provides details of the reclassifications out of accumulated other comprehensive loss and the favorable (unfavorable) impact on net income for the periods presented. Three Months Ended In millions (1) 2016 2015 Cash flow hedges: Cost of goods sold (natural gas contracts) $ — $ (1 ) Interest expense (interest rate contracts) 1 1 Total cash flow hedges, net of income tax 1 — Retirement benefit plans: Operation and maintenance expense (actuarial losses) (2) (5 ) (5 ) Total retirement benefit plans (5 ) (5 ) Income tax benefit 2 2 Total retirement benefit plans, net of income tax (3 ) (3 ) Total reclassification for the period $ (2 ) $ (3 ) (1) Amounts in parentheses indicate debits, or reductions, to our net income and credits 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 7 herein for additional details about net periodic benefit cost.

Non-Wholly Owned Entities and31

Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest (Tables)	3 Months Ended
	Mar. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Temporary Equity	A roll-forward of the contingently redeemable noncontrolling interest is detailed below: In millions Balance as of December 31, 2015 $ — Reclassification of noncontrolling interest 46 Net income attributable to noncontrolling interest 11 Distribution to noncontrolling interest (19 ) Balance as of March 31, 2016 $ 38
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net	The SouthStar amounts exclude intercompany eliminations and the balances of our wholly-owned subsidiary with an 85% ownership interest in SouthStar. March 31, 2016 December 31, 2015 March 31, 2015 In millions Consolidated SouthStar % Consolidated SouthStar % Consolidated SouthStar % Current assets $ 1,537 $ 177 12 % $ 2,115 $ 245 12 % $ 2,079 $ 182 9 % Goodwill and other intangible assets 1,918 113 6 1,922 114 6 1,943 119 6 Long-term assets and other deferred debits 10,881 17 — 10,717 16 — 10,097 17 — Total assets $ 14,336 $ 307 2 % $ 14,754 $ 375 3 % $ 14,119 $ 318 2 % Current liabilities $ 2,489 $ 41 2 % $ 3,000 $ 54 2 % $ 2,371 $ 46 2 % Long-term liabilities and other deferred credits 7,777 1 — 7,779 — — 7,784 1 — Total liabilities 10,266 42 — 10,779 54 1 10,155 47 — Contingently redeemable noncontrolling interest 38 — — — — — — — — Equity 4,032 265 7 3,975 321 8 3,964 271 7 Total liabilities, redeemable noncontrolling interest and equity $ 14,336 $ 307 2 % $ 14,754 $ 375 3 % $ 14,119 $ 318 2 %
Schedule of Variable Interest Entities	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 2016 2015 Operating revenues $ 254 $ 311 Operating expenses Cost of goods sold 157 203 Operation and maintenance 22 23 Depreciation and amortization 2 2 Taxes other than income taxes — 1 Total operating expenses 181 229 Operating income $ 73 $ 82
Equity Method Investments	The carrying amounts within our unaudited Condensed Consolidated Balance Sheets of our investments that are accounted for under the equity method were as follows: March 31, December 31, March 31, In millions 2016 2015 2015 Triton $ 48 $ 49 $ 57 Horizon Pipeline 14 14 14 PennEast Pipeline 12 9 2 Atlantic Coast Pipeline 9 7 3 Other 1 1 — Total $ 84 $ 80 $ 76
Schedule of Other Nonoperating Income, by Component	Income from our equity method investments is classified as other income on 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 2016 2015 Horizon Pipeline $ 1 $ 1

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Summarized statements of income, balance sheets and capital expenditure information by segment as of, and for the periods presented, are shown in the following tables. Three months ended March 31, 2016 In millions Distribution operations Retail operations Wholesale services (1) Midstream operations Other Intercompany eliminations Consolidated Operating revenues from external parties $ 983 $ 286 $ 63 $ 15 $ 2 $ (15 ) $ 1,334 Intercompany revenues 45 — — — — (45 ) — Total operating revenues 1,028 286 63 15 2 (60 ) 1,334 Operating expenses Cost of goods sold 464 162 3 6 — (57 ) 578 Operation and maintenance 185 37 16 7 (2 ) (2 ) 241 Depreciation and amortization 89 6 — 4 3 — 102 Taxes other than income taxes 56 1 1 1 3 — 62 Merger-related expenses — — — — 3 — 3 Total operating expenses 794 206 20 18 7 (59 ) 986 Operating income (loss) 234 80 43 (3 ) (5 ) (1 ) 348 Other income — — 1 2 — — 3 EBIT $ 234 $ 80 $ 44 $ (1 ) $ (5 ) $ (1 ) $ 351 Total assets $ 12,405 $ 717 $ 723 $ 715 $ 9,342 $ (9,566 ) $ 14,336 Capital expenditures $ 204 $ 2 $ — $ 18 $ 11 $ — $ 235 Three months ended March 31, 2015 In millions Distribution operations Retail operations Wholesale services (1) Midstream operations Other Intercompany eliminations Consolidated 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 Total assets $ 11,896 $ 698 $ 1,100 $ 693 $ 9,036 $ (9,304 ) $ 14,119 Capital expenditures $ 170 $ 2 $ 1 $ 3 $ 12 $ — $ 188 (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 are shown in the following table.
Reconciliation of Revenue from Segments to Consolidated	In millions Third party gross revenues Intercompany revenues Total gross Less gross Operating Three months ended March 31, 2016 $ 1,443 81 1,524 1,461 $ 63 Three months ended March 31, 2015 $ 2,146 150 2,296 2,206 $ 90
Reconciliation of Assets from Segment to Consolidated	Identifiable assets are those used in each segment’s operations. Information by segment on our Consolidated Balance Sheet as of December 31, 2015 , is as follows: In millions Distribution operations Retail Wholesale Midstream Other Intercompany eliminations Consolidated Total assets $ 12,517 $ 686 $ 935 $ 692 $ 9,664 $ (9,740 ) $ 14,754

Proposed Merger with Southern33

Proposed Merger with Southern Company (Details) - USD ($)	Aug. 23, 2015	Mar. 31, 2016	Mar. 31, 2015
Business Acquisition [Line Items]
Merger-related expenses		$ 3,000,000	$ 0
Southern Company [Member]
Business Acquisition [Line Items]
Common stock right to convert to cash, price per share (in dollars per share)	$ 66
Merger termination fee	$ 201,000,000
Reimbursement of expenses upon termination, up to	$ 5,000,000
Liability for merger termination fee at carrying value		0
Operation and Maintenance Expense [Member] | Southern Company [Member]
Business Acquisition [Line Items]
Merger-related expenses		3,000,000
Merger related costs, net of tax		$ 2,000,000

Significant Accounting Polici34

Significant Accounting Policies and Methods of Application - Lower of Cost or Market Adjustments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Lower of Cost or Market Adjustments [Abstract]
LOCOM adjustments	$ 3	$ 10

Significant Accounting Polici35

Significant Accounting Policies and Methods of Application - Changes in Amount of Goodwill (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Goodwill [Roll Forward]
Impairment	$ (14)
Goodwill - ending balance	1,813
Goodwill, impairment loss, net of tax	9
Distribution Operations [Member]
Goodwill [Roll Forward]
Impairment	0
Goodwill - ending balance	1,640
Retail Operations [Member]
Goodwill [Roll Forward]
Impairment	0
Goodwill - ending balance	173
Midstream Operations [Member]
Goodwill [Roll Forward]
Impairment	(14)
Goodwill - ending balance	$ 0

Significant Accounting Polici36

Significant Accounting Policies and Methods of Application - Potentially Dilutive Common Share Calculation (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Potentially Dilutive Common Share Calculation [Abstract]
Net income attributable to AGL Resources	$ 182	$ 193
Denominator:
Basic weighted average number of shares outstanding (in shares)	120.1	119.3
Effect of dilutive securities (in shares)	0.3	0.3
Diluted weighted average number of shares outstanding (in shares)	120.4	119.6
Earnings per common share
Basic earnings per common share attributable to AGL Resources (in dollars per share)	$ 1.52	$ 1.62
Diluted earnings per common share attributable to AGL Resources (in dollars per share)	$ 1.51	$ 1.62

Regulated Operations (Details)

Regulated Operations (Details) $ in Millions	1 Months Ended	3 Months Ended
	Oct. 31, 2015USD ($)	Mar. 31, 2016USD ($)sitemi	Dec. 31, 2015USD ($)	Mar. 31, 2015USD ($)	Feb. 28, 2015USD ($)
Regulated Operations [Line Items]
Regulatory assets – current		$ 50	$ 68	$ 63
Number of former operating sites | site		46
Recoverable ERC Assets [Member]
Regulated Operations [Line Items]
Regulatory assets – current		$ 21
Nicor Gas [Member]
Regulated Operations [Line Items]
Number of former operating sites | site		26
Number of sites with completed cleanups | site		2
Number of sites with cleanup responsibility | site		23
Cleanup costs allocated (as a percent)		52.00%
True-up Recovery [Member] | Atlanta Gas Light [Member]
Regulated Operations [Line Items]
Allowable amount of costs incurred to be recovered	$ 144
Unrecovered program revenue to be recovered					$ 178
SAVE Program [Member] | Virginia Natural Gas [Member]
Regulated Operations [Line Items]
Approved infrastructure replacement program amount		$ 210
Natural gas pipeline, approved for replacement, more than (in miles) | mi		200

Regulated Operations - Summary

Regulated Operations - Summary of Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Regulatory assets
Regulatory assets – current	$ 50	$ 68	$ 63
Regulatory assets – long-term	661	670	634
Total regulatory assets	711	738	697
Regulatory liabilities
Regulatory liabilities – current	159	134	168
Regulatory liabilities – long-term	1,632	1,611	1,612
Total regulatory liabilities	1,791	1,745	1,780
Recoverable ERC [Member]
Regulatory assets
Regulatory assets – current	21	31	37
Regulatory assets – long-term	364	370	331
Recoverable Pension and Retiree Welfare Benefit Costs [Member]
Regulatory assets
Regulatory assets – current	12	12	11
Regulatory assets – long-term	111	113	108
Deferred Natural Gas Costs [Member]
Regulatory assets
Regulatory assets – current	2	6	7
Recoverable Seasonal Rates [Member]
Regulatory assets
Regulatory assets – current	0	10	0
Recoverable Regulatory Infrastructure Program Costs [Member]
Regulatory assets
Regulatory assets – long-term	83	83	73
Long-term Debt Fair Value Adjustment [Member]
Regulatory assets
Regulatory assets – long-term	64	66	72
Other [Member]
Regulatory assets
Regulatory assets – current	15	9	8
Regulatory assets – long-term	39	38	50
Accumulated Removal Costs [Member]
Regulatory liabilities
Regulatory liabilities – current	53	53	25
Regulatory liabilities – long-term	1,551	1,538	1,524
Bad Debt Over Collection [Member]
Regulatory liabilities
Regulatory liabilities – current	47	42	30
Regulatory liabilities – long-term	28	21	19
Accrued Natural Gas Costs [Member]
Regulatory liabilities
Regulatory liabilities – current	20	24	53
Deferred Seasonal Rates [Member]
Regulatory liabilities
Regulatory liabilities – current	20	0	20
Regulatory Income Tax Liability [Member]
Regulatory liabilities
Regulatory liabilities – long-term	26	27	27
Unamortized Investment Tax Credit [Member]
Regulatory liabilities
Regulatory liabilities – long-term	19	20	22
Other [Member]
Regulatory liabilities
Regulatory liabilities – current	19	15	40
Regulatory liabilities – long-term	$ 8	$ 5	$ 20

Regulated Operations - Estimate

Regulated Operations - Estimated Recognition of Rate Making Assets (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Regulatory Assets [Line Items]
Regulatory Asset	$ 711	$ 738	$ 697
Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	124	122	133
Atlanta Gas Light [Member] | Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	105	103	119
Virginia Natural Gas [Member] | Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	12	12	12
Elizabethtown Gas [Member] | Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	4	4	2
Nicor Gas [Member] | Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	$ 3	$ 3	$ 0

Regulated Operations - Costs Re

Regulated Operations - Costs Related to Remediation of Former Operating Sites (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)site	Dec. 31, 2015USD ($)	Mar. 31, 2015USD ($)
Environmental Exit Cost [Line Items]
Number of sites | site	46
Probabilistic model cost estimates, low estimate	$ 344
Probabilistic model cost estimates, high estimate	704
Engineering-based estimates	79
Amount recorded	423
Expected costs over next 12 months	$ 68	$ 67	$ 93
Illinois [Member]
Environmental Exit Cost [Line Items]
Number of sites | site	26
Probabilistic model cost estimates, low estimate	$ 200
Probabilistic model cost estimates, high estimate	457
Engineering-based estimates	46
Amount recorded	246
Expected costs over next 12 months	$ 30
New Jersey [Member]
Environmental Exit Cost [Line Items]
Number of sites | site	6
Probabilistic model cost estimates, low estimate	$ 115
Probabilistic model cost estimates, high estimate	195
Engineering-based estimates	7
Amount recorded	122
Expected costs over next 12 months	$ 25
Cost recovery period	7 years
Georgia And Florida [Member]
Environmental Exit Cost [Line Items]
Number of sites | site	13
Probabilistic model cost estimates, low estimate	$ 29
Probabilistic model cost estimates, high estimate	52
Engineering-based estimates	21
Amount recorded	50
Expected costs over next 12 months	$ 13
Cost recovery period	5 years
North Carolina [Member]
Environmental Exit Cost [Line Items]
Number of sites | site	1
Engineering-based estimates	$ 5
Amount recorded	5
Expected costs over next 12 months	$ 0

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Weather derivative premium	$ 9	$ 10	$ 1

Fair Value Measurements - Deriv

Fair Value Measurements - Derivative Assets and Liabilities (Details) - Natural Gas and Interest Rate Derivatives [Member] - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	$ 177	$ 208	$ 212
Liabilities	(65)	(46)	(52)
Netting of counterparty offset and cash collateral, Assets	69	33	104
Netting of counterparty offset and cash collateral, Liabilities	96	63	106
Quoted prices in active markets (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	0	53	0
Liabilities	(96)	(63)	(106)
Significant other observable inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Assets	108	122	108
Liabilities	$ (65)	$ (46)	$ (52)

Fair Value Measurements - Amort

Fair Value Measurements - Amortized Cost and Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt carrying amount	$ 3,743	$ 3,820	$ 3,580
Significant other observable inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt fair value	$ 4,156	$ 4,066	$ 4,102

Derivative Instruments (Details

Derivative Instruments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Derivative [Line Items]
Derivative liability, fair value, not offset against collateral	$ 65	$ 52	$ 46
Derivative, maximum collateral (less than)	1
Change in derivative instrument assets and liabilities	51	33
Collateral held on deposit in broker margin accounts	165	210	$ 96
Expected unrealized losses to be reclassified from OCI	$ 4
Expiring in Two Years or Less [Member]
Derivative [Line Items]
Percentage of derivative contracts	99.00%
Derivative term	2 years
Expiring in Two to Five Years [Member]
Derivative [Line Items]
Percentage of derivative contracts	1.00%
Weather Derivatives [Member]
Derivative [Line Items]
Realized gains (losses) related to hedging natural gas costs	$ 3	$ (2)
Minimum [Member] | Natural Gas [Member] | Expiring in Two to Five Years [Member]
Derivative [Line Items]
Derivative term	2 years
Maximum [Member] | Natural Gas [Member] | Expiring in Two to Five Years [Member]
Derivative [Line Items]
Derivative term	5 years

Derivative Instruments - Net Lo

Derivative Instruments - Net Long Natural Gas Contracts (Details) - Bcf	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Derivative [Line Items]
Total volumes	86	240	(9)
Cash Flow Hedges [Member]
Derivative [Line Items]
Total volumes	5	9	5
Not Designated as Hedges [Member]
Derivative [Line Items]
Total volumes	81	231	(14)
Short [Member] | Cash Flow Hedges [Member]
Derivative [Line Items]
Total volumes	6	6	6
Short [Member] | Not Designated as Hedges [Member]
Derivative [Line Items]
Total volumes	2,974	2,735	3,089
Long [Member] | Cash Flow Hedges [Member]
Derivative [Line Items]
Total volumes	11	15	11
Long [Member] | Not Designated as Hedges [Member]
Derivative [Line Items]
Total volumes	3,055	2,966	3,075
Net Long (Short) Position [Member]
Derivative [Line Items]
Total volumes	86	240	(9)

Derivative Instruments - Gains

Derivative Instruments - Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Nicor Gas [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Realized gains (losses) related to hedging natural gas costs	$ (2)	$ (3)
Elizabethtown Gas [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Realized gains (losses) related to hedging natural gas costs	$ (6)	$ (4)

Derivative Instruments - Deriva

Derivative Instruments - Derivative Instruments on the Condensed Consolidated Statements of Financial Position (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Derivatives, Fair Value [Line Items]
Assets	$ 512	$ 942	$ 659
Liabilities	(556)	(866)	(708)
Gross amounts offset in our unaudited Condensed Consolidated Balance Sheets	(326)	(724)	(446)
Gross amounts offset in our unaudited Condensed Consolidated Balance Sheets	491	820	656
Net amounts of assets presented in our unaudited Condensed Consolidated Balance Sheets	186	218	213
Net amounts of liabilities presented in our unaudited Condensed Consolidated Balance Sheets	(65)	(46)	(52)
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	1	12	4
Liabilities	(41)	(7)	(7)
Designated as Hedging Instrument [Member] | Current Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Assets	1	3	0
Liabilities	(4)	(5)	(6)
Designated as Hedging Instrument [Member] | Long-Term Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Assets	0	0	0
Liabilities	(1)	(2)	(1)
Designated as Hedging Instrument [Member] | Current Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Assets	0	9	1
Liabilities	(36)	0	0
Designated as Hedging Instrument [Member] | Long-term Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Assets	0	0	3
Liabilities	0	0	0
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	511	930	655
Liabilities	(515)	(859)	(701)
Not Designated as Hedging Instrument [Member] | Current Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Assets	419	751	557
Liabilities	(432)	(672)	(592)
Not Designated as Hedging Instrument [Member] | Long-Term Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Assets	92	179	98
Liabilities	$ (83)	$ (187)	$ (109)

Derivative Instruments - Deri48

Derivative Instruments - Derivative Instruments on the Consolidated Statements of Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Designated as cash flow hedges
Total designated as cash flow hedges, net of tax	$ 1	$ 0
Not designated as hedges
Income tax	(7)	10
Total not designated as hedges, net of tax	12	(16)
Total gains (losses) on derivative instruments, net of tax	13	(16)
Cash Flow Hedging [Member]
Designated as cash flow hedges
Total designated as cash flow hedges, net of tax	1	0
Natural Gas Contracts [Member] | Operating Revenues [Member]
Not designated as hedges
Natural gas contracts - net value adjustments	20	(24)
Natural Gas Contracts [Member] | Cost of Sales [Member]
Not designated as hedges
Natural gas contracts - net value adjustments	(1)	(2)
Natural Gas Contracts [Member] | Cost of Sales [Member] | Cash Flow Hedging [Member]
Designated as cash flow hedges
Net gain (loss) reclassified from OCI	0	(1)
Interest Rate Swaps [Member] | Interest Expense [Member] | Cash Flow Hedging [Member]
Designated as cash flow hedges
Net gain (loss) reclassified from OCI	$ 1	$ 1

Employee Benefit Plans - Compon

Employee Benefit Plans - Components of Pension and Other Retirement Benefit Costs (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 6	$ 7
Interest cost	10	11
Expected return on plan assets	(16)	(16)
Net amortization of prior service credit	0	(1)
Recognized actuarial loss	6	8
Net periodic pension benefit cost	6	9
Health and Welfare Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1
Interest cost	3	3
Expected return on plan assets	(2)	(2)
Net amortization of prior service credit	(1)	0
Recognized actuarial loss	1	1
Net periodic pension benefit cost	$ 2	$ 3

Debt and Credit Facilities (Det

Debt and Credit Facilities (Details) $ in Millions	Feb. 01, 2016USD ($)	Jan. 23, 2015USD ($)	Mar. 31, 2016	Dec. 31, 2015	Nov. 18, 2015USD ($)	Mar. 31, 2015
AGL Capital [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Effective interest rate (as a percent)			0.80%
Nicor Gas [Member]
Debt Instrument [Line Items]
Repayments of first mortgage bond	$ 75
Ratio of total debt to total capitalization, no more than (as a percent)			0.47	0.56		0.54
Nicor Gas [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Effective interest rate (as a percent)			0.60%
Interest Rate Swaps [Member]
Debt Instrument [Line Items]
Notional amount		$ 800			$ 200
Minimum [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Debt term			1 day
Remaining maturity term			1 day
Minimum [Member] | Interest Rate Swaps [Member]
Debt Instrument [Line Items]
Derivative term		10 years
Maximum [Member]
Debt Instrument [Line Items]
Ratio of total debt to total capitalization, no more than (as a percent)			0.7
Maximum [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Debt term			59 days
Remaining maturity term			46 days
Maximum [Member] | Interest Rate Swaps [Member]
Debt Instrument [Line Items]
Derivative term		30 years

Debt and Credit Facilities - De

Debt and Credit Facilities - Debt Schedule (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Long-term debt - excluding current portion
Unamortized debt premium, net	$ 16	$ 16	$ 16
Unamortized debt issuance costs	(20)	(20)	(19)
Total long-term debt - excluding current portion	3,273	3,275	3,505
Total debt	$ 4,300	4,830	$ 4,106
Current Portion Long-Term Debt [Member]
Short-term debt
Weighted average interest rate	5.20%		2.90%
Outstanding	$ 470	545	$ 75
Senior Notes [Member]
Long-term debt - excluding current portion
Weighted average interest rate	4.90%		5.00%
Outstanding	$ 2,455	2,455	$ 2,625
First Mortgage Bonds [Member]
Long-term debt - excluding current portion
Weighted average interest rate	5.90%		6.00%
Outstanding	$ 375	375	$ 425
Gas Facility Revenue Bonds [Member]
Long-term debt - excluding current portion
Weighted average interest rate	1.10%		0.80%
Outstanding	$ 200	200	$ 200
Medium-term Notes [Member]
Long-term debt - excluding current portion
Weighted average interest rate	7.80%		7.80%
Outstanding	$ 181	181	$ 181
Principal Long-term Debt [Member]
Long-term debt - excluding current portion
Weighted average interest rate	4.80%		4.90%
Outstanding	$ 3,211	3,211	$ 3,431
Long-term Debt Fair Value Adjustment [Member]
Long-term debt - excluding current portion
Outstanding	66	68	77
Long-term Debt Non-principal [Member]
Long-term debt - excluding current portion
Outstanding	$ 62	64	$ 74
Commercial Paper [Member]
Short-term debt
Weighted average interest rate	0.70%		0.40%
Outstanding	$ 557	1,010	$ 526
Commercial Paper [Member] | AGL Capital [Member]
Short-term debt
Weighted average interest rate	0.80%		0.50%
Outstanding	$ 204	471	$ 176
Commercial Paper [Member] | Nicor Gas [Member]
Short-term debt
Weighted average interest rate	0.60%		0.40%
Outstanding	$ 353	$ 539	$ 350

Debt and Credit Facilities - 52

Debt and Credit Facilities - Debt-to-Capitalization Ratios (Details)	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
AGL Resources Inc [Member]
Schedule of Capitalization [Line Items]
Debt covenants (as a percent)	0.50	0.54	0.50
Nicor Gas [Member]
Schedule of Capitalization [Line Items]
Debt covenants (as a percent)	0.47	0.56	0.54

Equity - Other Comprehensive In

Equity - Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance	$ 3,975	$ 3,828
Other comprehensive (loss) income, net of tax	(27)	5
Balance	4,032	3,964
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance	2	(6)
OCI, before reclassifications	(29)	2
Amounts reclassified from accumulated OCI	(1)	0
Other comprehensive (loss) income, net of tax	(30)	2
Balance	(28)	(4)
Retirement Benefit Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance	(188)	(200)
OCI, before reclassifications	0	0
Amounts reclassified from accumulated OCI	3	3
Other comprehensive (loss) income, net of tax	3	3
Balance	(185)	(197)
Total [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance	(186)	(206)
OCI, before reclassifications	(29)	2
Amounts reclassified from accumulated OCI	2	3
Other comprehensive (loss) income, net of tax	(27)	5
Balance	$ (213)	$ (201)

Equity - Reclassifications Out

Equity - Reclassifications Out of Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense (interest rate contracts)	$ (47)	$ (44)
Operation and maintenance expense	(241)	(249)
Income before income taxes	304	323
Income tax benefit	(111)	(118)
Net income attributable to AGL Resources	182	193
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income attributable to AGL Resources	(2)	(3)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income attributable to AGL Resources	1	0
Reclassification out of Accumulated Other Comprehensive Income [Member] | Actuarial Losses [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operation and maintenance expense	(5)	(5)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Retirement Benefit Plans [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income before income taxes	(5)	(5)
Income tax benefit	2	2
Net income attributable to AGL Resources	(3)	(3)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Natural Gas Derivatives [Member] | Cash Flow Hedges [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Cost of goods sold (natural gas contracts)	0	(1)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Contract [Member] | Cash Flow Hedges [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense (interest rate contracts)	$ 1	$ 1

Non-Wholly Owned Entities and55

Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest - Redeemable Noncontrolling Interest (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Increase (Decrease) in Redeemable Noncontrolling Interest [Roll Forward]
Balance as of December 31, 2015	$ 0
Reclassification of noncontrolling interest	46
Net income attributable to noncontrolling interest	11	$ 12
Distribution to noncontrolling interest	(19)	(18)
Balance as of March 31, 2016	$ 38	$ 0

Non-Wholly Owned Entities and56

Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Feb. 12, 2016
Schedule of Equity Method Investments [Line Items]
Expenditures for property, plant and equipment	$ 235	$ 188
Distribution to noncontrolling interest	19	18
South Star [Member]
Schedule of Equity Method Investments [Line Items]
Expenditures for property, plant and equipment	$ 1	1
Ownership interest in variable interest entity (as a percent)	85.00%
South Star [Member] | Piedmont [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest to be sold (as a percent)			15.00%
Letter of agreement for sale of ownership interest			$ 160
Distribution to noncontrolling interest	$ 19	$ 18

Non-Wholly Owned Entities and57

Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest - SouthStar's Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Current assets	$ 1,537	$ 2,115	$ 2,079
Goodwill and other intangible assets	1,918	1,922	1,943
Long-term assets and other deferred debits	10,881	10,717	10,097
Total assets	14,336	14,754	14,119
Current liabilities	2,489	3,000	2,371
Long-term liabilities and other deferred credits	7,777	7,779	7,784
Total liabilities and other deferred credits	10,266	10,779	10,155
Contingently redeemable noncontrolling interest	38	0	0
Equity	4,032	3,975	3,964	$ 3,828
Total liabilities, redeemable noncontrolling interest and equity	14,336	14,754	14,119
South Star [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Current assets	$ 177	$ 245	$ 182
Current assets (as a percent of consolidated)	12.00%	12.00%	9.00%
Goodwill and other intangible assets	$ 113	$ 114	$ 119
Goodwill and other intangible assets (as a percent of consolidated)	6.00%	6.00%	6.00%
Long-term assets and other deferred debits	$ 17	$ 16	$ 17
Long-term assets and other deferred debits (as a percent of consolidated)	0.00%	0.00%	0.00%
Total assets	$ 307	$ 375	$ 318
Total assets (as a percent of consolidated)	2.00%	3.00%	2.00%
Current liabilities	$ 41	$ 54	$ 46
Current liabilities (as a percent of consolidated)	2.00%	2.00%	2.00%
Long-term liabilities and other deferred credits	$ 1	$ 0	$ 1
Long-term liabilities and other deferred credits (as a percent of consolidated)	0.00%	0.00%	0.00%
Total liabilities and other deferred credits	$ 42	$ 54	$ 47
Total Liabilities (as a percent of consolidated)	0.00%	1.00%	0.00%
Contingently redeemable noncontrolling interest	$ 0	$ 0	$ 0
Contingently redeemable noncontrolling interest (as a percent of consolidated)	0.00%	0.00%	0.00%
Equity	$ 265	$ 321	$ 271
Equity (as a percent of consolidated)	7.00%	8.00%	7.00%
Total liabilities, redeemable noncontrolling interest and equity	$ 307	$ 375	$ 318
Total liabilities and equity (as a percent of consolidated)	2.00%	3.00%	2.00%

Non-Wholly Owned Entities and58

Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest - SouthStar's Revenues and Expenses (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Variable Interest Entity [Line Items]
Operating revenues	$ 1,334	$ 1,721
Cost of goods sold	578	935
Operation and maintenance	241	249
Depreciation and amortization	102	97
Taxes other than income taxes	62	76
Total operating expenses	986	1,357
Operating income	348	364
South Star [Member]
Variable Interest Entity [Line Items]
Operating revenues	254	311
Cost of goods sold	157	203
Operation and maintenance	22	23
Depreciation and amortization	2	2
Taxes other than income taxes	0	1
Total operating expenses	181	229
Operating income	$ 73	$ 82

Non-Wholly Owned Entities and59

Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest - Equity Method Investments (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 84	$ 80	$ 76
Triton [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	48	49	57
Horizon Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	14	14	14
PennEast Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	12	9	2
Atlantic Coast Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	9	7	3
Other [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 1	$ 1	$ 0

Non-Wholly Owned Entities and60

Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest - Income from Equity Method Investments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Horizon Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Income from equity method investment	$ 1	$ 1

Commitments, Guarantees and C61

Commitments, Guarantees and Contingencies (Details) - USD ($)	1 Months Ended
	Sep. 30, 2015	Aug. 31, 2014	Mar. 31, 2016
Gain Contingencies [Line Items]
Guarantees and indemnifications liability, carrying value			$ 0
Illinois Commission [Member]
Gain Contingencies [Line Items]
Loss contingency, damages sought		$ 18,000,000
CUB [Member]
Gain Contingencies [Line Items]
Loss contingency, damages sought		$ 22,000,000
Unfavorable Regulatory Action [Member] | Nicor Gas [Member]
Gain Contingencies [Line Items]
Loss contingency, damages sought	$ 300,000

Segment Information (Details)

Segment Information (Details)	3 Months Ended
	Mar. 31, 2016statesegment
Segment Reporting Information [Line Items]
Number of reportable segments | segment	4
Distribution Operations [Member]
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	7

Segment Information - Intersegm

Segment Information - Intersegment Reporting (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 1,334	$ 1,721
Operating expenses
Cost of goods sold	578	935
Operation and maintenance	241	249
Depreciation and amortization	102	97
Taxes other than income taxes	62	76
Merger-related expenses	3	0
Total operating expenses	986	1,357
Operating income	348	364
Other income	3	3
EBIT	351	367
Total assets	14,336	14,119	$ 14,754
Capital expenditures	235	188
Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(60)	(76)
Operating expenses
Cost of goods sold	(57)	(75)
Operation and maintenance	(2)	(1)
Depreciation and amortization	0	0
Taxes other than income taxes	0	0
Merger-related expenses	0
Total operating expenses	(59)	(76)
Operating income	(1)	0
Other income	0	0
EBIT	(1)	0
Total assets	(9,566)	(9,304)	(9,740)
Capital expenditures	0	0
Distribution Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	1,028	1,341
Operating expenses
Cost of goods sold	464	776
Operation and maintenance	185	185
Depreciation and amortization	89	82
Taxes other than income taxes	56	71
Merger-related expenses	0
Total operating expenses	794	1,114
Operating income	234	227
Other income	0	1
EBIT	234	228
Total assets	12,405	11,896	12,517
Capital expenditures	204	170
Retail Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	286	341
Operating expenses
Cost of goods sold	162	210
Operation and maintenance	37	37
Depreciation and amortization	6	6
Taxes other than income taxes	1	1
Merger-related expenses	0
Total operating expenses	206	254
Operating income	80	87
Other income	0	0
EBIT	80	87
Total assets	717	698	686
Capital expenditures	2	2
Wholesale Services [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	63	90
Operating expenses
Cost of goods sold	3	9
Operation and maintenance	16	24
Depreciation and amortization	0	0
Taxes other than income taxes	1	1
Merger-related expenses	0
Total operating expenses	20	34
Operating income	43	56
Other income	1	0
EBIT	44	56
Total assets	723	1,100	935
Capital expenditures	0	1
Midstream Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	15	19
Operating expenses
Cost of goods sold	6	10
Operation and maintenance	7	6
Depreciation and amortization	4	5
Taxes other than income taxes	1	1
Merger-related expenses	0
Total operating expenses	18	22
Operating income	(3)	(3)
Other income	2	1
EBIT	(1)	(2)
Total assets	715	693	692
Capital expenditures	18	3
Other [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	2	6
Operating expenses
Cost of goods sold	0	5
Operation and maintenance	(2)	(2)
Depreciation and amortization	3	4
Taxes other than income taxes	3	2
Merger-related expenses	3
Total operating expenses	7	9
Operating income	(5)	(3)
Other income	0	1
EBIT	(5)	(2)
Total assets	9,342	9,036	$ 9,664
Capital expenditures	11	12
Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Operating revenues	1,334	1,721
Reportable Subsegments [Member] | Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(15)	(20)
Reportable Subsegments [Member] | Distribution Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	983	1,285
Reportable Subsegments [Member] | Retail Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	286	341
Reportable Subsegments [Member] | Wholesale Services [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	63	90
Reportable Subsegments [Member] | Midstream Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	15	19
Reportable Subsegments [Member] | Other [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	2	6
Intercompany revenues [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Intercompany revenues [Member] | Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(45)	(56)
Intercompany revenues [Member] | Distribution Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	45	56
Intercompany revenues [Member] | Retail Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Intercompany revenues [Member] | Wholesale Services [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Intercompany revenues [Member] | Midstream Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Intercompany revenues [Member] | Other [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	$ 0	$ 0

Segment Information - Operating

Segment Information - Operating Revenues (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating revenues	$ 1,334	$ 1,721
Less gross gas costs	578	935
Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating revenues	63	90
Less gross gas costs	3	9
Third Party Gross Revenues [Member] | Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating revenues	1,443	2,146
Intercompany Revenues [Member] | Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating revenues	81	150
Total Gross Revenues [Member] | Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Operating revenues	1,524	2,296
Third Party Gross Costs [Member] | Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Less gross gas costs	$ 1,461	$ 2,206

Uncategorized Items - gas-20160

Label	Element	Value
Distribution Operations [Member]
Goodwill	us-gaap_Goodwill	$ 1,640,000,000
Goodwill	us-gaap_Goodwill	1,640,000,000
Midstream Operations [Member]
Goodwill	us-gaap_Goodwill	14,000,000
Goodwill	us-gaap_Goodwill	0
Retail Operations [Member]
Goodwill	us-gaap_Goodwill	173,000,000
Goodwill	us-gaap_Goodwill	$ 173,000,000