SOUTHERN Co GAS (GAS) 10-Q 29 Jul 15 2015 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 23, 2015
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		120,087,776
Amendment Flag	false
Entity Central Index Key	1,004,155
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2

Condensed Consolidated Statemen

Condensed Consolidated Statements of Financial Position (Unaudited) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Current assets
Cash and cash equivalents	$ 25	$ 31	$ 122
Receivables
Natural gas, unbilled revenues and other	445	797	520
Energy marketing	430	779	677
Less allowance for uncollectible accounts	46	35	51
Total receivables, net	829	1,541	1,146
Inventories
Natural gas	395	694	441
Other	26	22	19
Total inventories	421	716	460
Derivative instruments	158	245	105
Prepaid expenses	51	223	67
Regulatory assets	48	83	165
Assets held for sale			257
Other	40	47	58
Total current assets	1,572	2,886	2,380
Long-term assets and other deferred debits
Property, plant and equipment	11,903	11,552	11,188
Less accumulated depreciation	2,524	2,462	2,400
Property, plant and equipment, net	9,379	9,090	8,788
Goodwill	1,827	1,827	1,827
Regulatory assets	642	631	726
Intangible assets	112	125	135
Other	303	329	303
Total long-term assets and other deferred debits	12,263	12,002	11,779
Total assets	13,835	14,888	14,159
Current liabilities
Short-term debt	459	1,175	448
Energy marketing trade payables	455	777	724
Other accounts payable – trade	272	312	319
Accrued expenses	183	229	213
Regulatory liabilities	154	112	149
Current portion of long-term debt	125	200	200
Customer deposits and credit balances	115	125	107
Accrued environmental remediation liabilities	83	87	90
Derivative instruments	43	88	50
Temporary LIFO liquidation	38		116
Liabilities held for sale			39
Other	120	114	140
Total current liabilities	2,047	3,219	2,595
Long-term liabilities and other deferred credits
Long-term debt	3,452	3,581	3,585
Accumulated deferred income taxes	1,780	1,724	1,675
Regulatory liabilities	1,622	1,601	1,565
Accrued pension and retiree welfare benefits	526	525	405
Accrued environmental remediation liabilities	346	327	379
Other	73	83	95
Total long-term liabilities and other deferred credits	7,799	7,841	7,704
Total liabilities and other deferred credits	$ 9,846	$ 11,060	$ 10,299
Commitments, guarantees and contingencies (see Note 10)
Equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,081,995 shares at June 30, 2015, 119,647,149 shares at December 31, 2014, and 119,464,063 shares at June 30, 2014	$ 601	$ 599	$ 598
Additional paid-in capital	2,099	2,087	2,073
Retained earnings	1,425	1,312	1,288
Accumulated other comprehensive loss	(169)	(206)	(133)
Treasury shares, at cost: 216,523 shares at June 30, 2015, December 31, 2014, and June 30, 2014	(8)	(8)	(8)
Total common shareholders’ equity	3,948	3,784	3,818
Noncontrolling interest	41	44	42
Total equity	3,989	3,828	3,860
Total liabilities and equity	$ 13,835	$ 14,888	$ 14,159

Condensed Consolidated Stateme3

Condensed Consolidated Statements of Financial Position (Unaudited) (Parentheticals) - $ / shares	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
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	120,081,995	119,647,149	119,464,063
Treasury shares, shares	216,523	216,523	216,523

Condensed Consolidated Stateme4

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating revenues (includes revenue taxes of $18 and $74 for the three and six months in 2015 and $26 and $94 for the three and six months in 2014)		$ 674	$ 889	$ 2,395	$ 3,351
Operating expenses
Cost of goods sold		222	402	1,157	1,802
Operation and maintenance		209	211	458	500
Depreciation and amortization		98	95	195	188
Taxes other than income taxes		38	42	114	130
Total operating expenses		567	750	1,924	2,620
Operating income		107	139	471	731
Other income		4	2	7	5
Interest expense, net		(42)	(45)	(86)	(91)
Income before income taxes		69	96	392	645
Income tax expense		25	37	143	240
Income from continuing operations		44	59	249	405
Income (loss) from discontinued operations, net of tax			1		(49)
Net income		44	60	249	356
Less net income attributable to noncontrolling interest		2	2	14	14
Net income attributable to AGL Resources Inc.		42	58	235	342
Net income attributable to AGL Resources Inc.
Income from continuing operations		$ 42	$ 57	$ 235	$ 391
Basic earnings (loss) per common share
Continuing operations (in Dollars per share)		$ 0.35	$ 0.48	$ 1.97	$ 3.30
Discontinued operations (in Dollars per share)			0.01		(0.42)
Basic earnings per common share attributable to AGL Resources Inc. (in Dollars per share)		0.35	0.49	1.97	2.88
Diluted earnings (loss) per common share
Continuing operations (in Dollars per share)		0.35	0.48	1.96	3.29
Discontinued operations (in Dollars per share)			0.01		(0.42)
Diluted earnings per common share attributable to AGL Resources Inc. (in Dollars per share)		0.35	0.49	1.96	2.87
Cash dividends declared per common share (in Dollars per share)		$ 0.51	$ 0.49	$ 1.02	$ 0.98
Weighted average number of common shares outstanding
Basic (in Shares)	[1]	119.5	118.8	119.4	118.7
Diluted (in Shares)	[2]	119.8	119.2	119.7	119.1
[1]	Daily weighted average shares outstanding.
[2]	All outstanding stock options whose effect would have been anti-dilutive were excluded from the computation of diluted earnings per common share.

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Income (Unaudited) (Parentheticals) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating revenues, revenue taxes	$ 18	$ 26	$ 74	$ 94

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net income	$ 44	$ 60	$ 249	$ 356
Retirement benefit plans
Reclassification of actuarial losses to net benefit cost (net of income tax of $2 and $4 for the three and six months ended June 30, 2015, and $2 and $3 for the three and six months ended June 30, 2014)	4	4	7	5
Reclassification of prior service credits to net benefit cost		(1)		(1)
Retirement benefit plans, net	4	3	7	4
Cash flow hedges, net of tax
Net derivative instruments gain arising during the period (net of income tax of $16 and $17 for the three and six months ended June 30, 2015)	25		27	4
Reclassification of realized derivative instruments (gain) loss to net income (net of income tax of $(1) for the three and six months ended June 30, 2014)	4	(1)	4	(5)
Cash flow hedges, net	29	(1)	31	(1)
Other comprehensive income, net of tax	33	2	38	3
Comprehensive income	77	62	287	359
Less comprehensive income attributable to noncontrolling interest	3	2	15	14
Comprehensive income attributable to AGL Resources Inc.	$ 74	$ 60	$ 272	$ 345

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parentheticals) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reclassification of losses to net benefit cost, income tax	$ 2	$ 2	$ 4	$ 3
Net derivative instruments gain arising during the period, income tax	$ 16		$ 17
Reclassification of realized derivative instruments (gain) loss to net income, income tax		$ (1)		$ (1)

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Equity (Unaudited) - USD ($) $ in Millions	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	AOCI Attributable to Parent [Member]	Treasury Stock [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2013	$ 3,613	$ 595	$ 2,054	$ 1,063	$ (136)	$ (8)	$ 45
Balance, shares (in Shares) at Dec. 31, 2013		118,900,000
Net income	356			342			14
Other comprehensive income	3				3
Dividends on common stock	(117)			(117)
Distributions to noncontrolling interest	(17)						(17)
Stock granted, share-based compensation, net of forfeitures	(12)		(12)
Stock issued, dividend reinvestment plan	6		6
Stock issued, share-based compensation, net of forfeitures	20	$ 3	17
Stock issued, share-based compensation, net of forfeitures (in Shares)		600,000
Stock-based compensation expense, net of tax	8		8
Balance at Jun. 30, 2014	$ 3,860	$ 598	2,073	1,288	(133)	(8)	42
Balance, shares (in Shares) at Jun. 30, 2014	119,464,063	119,500,000
Balance at Dec. 31, 2014	$ 3,828	$ 599	2,087	1,312	(206)	(8)	44
Balance, shares (in Shares) at Dec. 31, 2014	119,647,149	119,600,000
Net income	$ 249			235			14
Other comprehensive income	38				37		1
Dividends on common stock	(122)			(122)
Distributions to noncontrolling interest	(18)						(18)
Stock granted, share-based compensation, net of forfeitures	(13)		(13)
Stock issued, dividend reinvestment plan	6	$ 1	5
Stock issued, dividend reinvestment plan (in Shares)		100,000
Stock issued, share-based compensation, net of forfeitures	15	$ 1	14
Stock issued, share-based compensation, net of forfeitures (in Shares)		400,000
Stock-based compensation expense, net of tax	6		6
Balance at Jun. 30, 2015	$ 3,989	$ 601	$ 2,099	$ 1,425	$ (169)	$ (8)	$ 41
Balance, shares (in Shares) at Jun. 30, 2015	120,081,995	120,100,000

Condensed Consolidated Stateme9

Condensed Consolidated Statements of Equity (Unaudited) (Parentheticals) - $ / shares	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Dividends on common stock, per share	$ 1.02	$ 0.98

Condensed Consolidated Statem10

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities
Net income	$ 60	$ 249	$ 356
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization	95	195	188
Change in derivative instrument assets and liabilities		42	(13)
Deferred income taxes		27	13
Loss from discontinued operations, net of tax	(1)		49
Changes in certain assets and liabilities
Receivables, other than energy marketing		363	238
Inventories, net of temporary LIFO liquidation		333	314
Prepaid and miscellaneous taxes		150	(12)
Accrued/deferred natural gas costs		43	(129)
Energy marketing receivables and trade payables, net		27	162
Accrued expenses		(28)	11
Trade payables, other than energy marketing		(41)	(61)
Other, net		125	55
Net cash flow provided by operating activities of discontinued operations			4
Net cash flow provided by operating activities		1,485	1,175
Cash flows from investing activities
Expenditures for property, plant and equipment	(171)	(452)	(332)
Net decrease in short-term investments			41
Other, net		5	4
Net cash flow used in investing activities of discontinued operations			(13)
Net cash flow used in investing activities		(447)	(300)
Cash flows from financing activities
Net repayments of commercial paper		(716)	(723)
Payment of senior notes		(200)
Dividends paid on common shares		(122)	(117)
Distribution to noncontrolling interest		(18)	(17)
Other, net		12	14
Net cash flow used in financing activities		(1,044)	(843)
Net (decrease) increase in cash and cash equivalents – continuing operations		(6)	41
Net decrease in cash and cash equivalents – discontinued operations			(9)
Cash and cash equivalents (including held for sale) at beginning of period		31	105
Cash and cash equivalents (including held for sale) at end of period	137	25	137
Less cash and cash equivalents held for sale at end of period	15		15
Cash and cash equivalents (excluding held for sale) at end of period	$ 122	25	122
Cash paid (received) during the period for
Interest		93	95
Income taxes		$ (57)	$ 207

Note 1 - Organization and Basis

Note 1 - Organization and Basis of Presentation	6 Months Ended
	Jun. 30, 2015
Disclosure Text Block [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Note 1 - Organization and Basis of Presentation General AGL Resources Inc. is an energy services holding company that conducts substantially all of its operations through its subsidiaries. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company ,” or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries. Our Condensed Consolidated Statements of Financial Position as of December 31, 2014 were derived from our audited consolidated financial statements. 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 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 2014 Form 10-K. Due to the seasonal nature of our business and other factors, our results of operations and our financial condition for the periods presented are not necessarily indicative of the results of operations or financial condition to be expected for or as of any other period. Basis of Presentation Our unaudited condensed consolidated financial statements include our accounts, the accounts of our wholly owned subsidiaries, the accounts of our majority owned or otherwise controlled subsidiaries and the accounts of our VIE, SouthStar, for which we are the primary beneficiary. For unconsolidated entities that we do not control, we use the equity method of accounting and our proportionate share of income or loss is recorded on the unaudited Condensed Consolidated Statements of Income. See Note 9 for additional information. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts is probable under the affiliates’ rate regulation process. In November 2014 , we filed a Form 10-Q/A to revise our June 30, 2014 financial statements and other affected disclosures for items related to the recognition of revenues for certain of our regulatory infrastructure programs and the amortization of our intangible assets as originally filed in our Form 10-Q for the period ended June 30, 2014. Our financial statements for the period ended June 30, 2014, reflect the revised amounts reported in our 2014 Form 10-Q/A. In September 2014, we closed on the sale of Tropical Shipping, which operated within our former cargo shipping segment. The assets and liabilities of these businesses as of June 30, 2014 are classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position, and the financial results of these businesses for the three and six months ended June 30, 2014 are reflected as discontinued operations on the unaudited Condensed Consolidated Statements of Income. Amounts shown in the following notes, unless otherwise indicated, exclude assets held for sale and discontinued operations. Cargo shipping also included our investment in Triton, which was not part of the sale and has been reclassified into our “other” non-reportable segments. See Note 12 for additional information on the sale of Tropical Shipping .

Note 2 - Significant Accounting

Note 2 - Significant Accounting Policies and Methods of Application	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Note 2 - Significant Accounting Policies and Methods of Application Our accounting policies are described in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. While we adopted the revised guidance related to debt issuance costs during the second quarter of 2015, there have been no significant changes to our accounting policies during the year . 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. Cash and Cash Equivalents Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of June 30, 2014 , there was $15 million of cash and cash equivalents held by Tropical Shipping that was excluded from cash and cash equivalents within our unaudited Condensed Consolidated Statements of Financial Position and included in assets held for sale. For more information on the sale of Tropical Shipping, see Note 12. Energy Marketing Receivables and Payable s Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing trade payables. Wholesale services has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of June 30, 2015 and 2014, and December 31, 2014, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted. Inventories For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 10 for information regarding an approved regulatory filing to resolve a natural gas inventory imbalance at Atlanta Gas Light. Nicor Gas’ inventory is carried at cost on a LIFO basis . Inventory decrements occurring during the year that are expected to be restored prior to year -end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO inventory liquidation. Any temporary LIFO liquidation is included as a current liability in our unaudited Condensed Consolidated Statements of Financial Position . Interim inventory decrements that are not expected to be restored prior to year -end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of June 30, 2015 is expected to be restored prior to year-end and the inventory decrement as of June 30, 2014 was restored prior to December 31, 2014. Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For these segments, we evaluate the weighted average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, we record pre-tax adjustments to our unaudited Condensed Consolidated Statements of Income to reduce the weighted average cost of the natural gas inventory to market value . For the periods presented, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our inventories to market value . Three months ended June 30, Six months ended June 30, In millions 201 5 201 4 201 5 201 4 LOCOM adjustments $ - $ 4 $ 10 $ 6 We have $12 million of inventory at wholesale services that is currently inaccessible due to operational issues at a third party storage facility. The owner of this storage facility is working to resolve these issues. While we expect this inventory to be accessible in the second half of 2015 and to be fully recovered, the timing of withdrawal of this gas may be impacted by operational issues. Regulated Operations We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for estimated expenditures that have not yet been incurred. Generally, regulatory assets and regulatory liabilities are amortized into our unaudited Condensed Consolidated Statements of Income over the period authorized by the regulatory commissions. Goodwill We perform an annual impairment test on our reporting units that contain goodwill during the fourth quarter of each year, or more frequently if impairment indicators arise. There were no triggering events during the current period that would require us to perform an interim goodwill impairment test. The amounts of goodwill as of June 30, 2015 and 2014, and December 31, 2014 are provided below . In millions Distribution o perations Retail o perations Midstream o perations Consolidated Goodwill $ 1,640 $ 173 $ 14 $ 1,827 Earnings Per Common Share We compute basic earnings per common share attributable to AGL Resources Inc. by dividing our net income attributable to the common shareholders of AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. that occurs when the exercise and/or conversion of all potentially dilutive common shares is added to the common shares outstanding. We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. for the periods presented as if performance units currently earned under the plan ultimately vest and as if stock options currently exercisable at prices below the average market prices are exercised. Three months ended June 30, Six months ended June 30, In millions (except per share amounts) 201 5 201 4 201 5 201 4 Income from continuing operations attributable to AGL Resources Inc. $ 42 $ 57 $ 235 $ 391 Income (loss) from discontinued operations, net of tax - 1 - (49 ) Net income attributable to AGL Resources Inc. $ 42 $ 58 $ 235 $ 342 Denominator: Basic weighted average number of shares outstanding (1) 119.5 118.8 119.4 118.7 Effect of dilutive securities 0.3 0.4 0.3 0.4 Diluted weighted average number of shares outstanding (2) 119.8 119.2 119.7 119.1 Basic earnings (loss) per share Continuing operations $ 0.35 $ 0.48 $ 1.97 $ 3.30 Discontinued operations - 0.01 - (0.42 ) Basic earnings per share attributable to AGL Resources Inc. $ 0.35 $ 0.49 $ 1.97 $ 2.88 Diluted earnings (loss) per share Continuing operations $ 0.35 $ 0.48 $ 1.96 $ 3.29 Discontinued operations - 0.01 - (0.42 ) Diluted earnings per share attributable to AGL Resources Inc. $ 0.35 $ 0.49 $ 1.96 $ 2.87 (1) Daily weighted average shares outstanding. (2) All outstanding stock options whose effect would have been anti-dilutive were excluded from the computation of diluted earnings per common share. Fair Value Measurements We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents, and derivative assets and liabilities. The carrying values of receivables , short - and long-term investments, accounts payable, short-term debt, other current assets and liabilities , and accrued interest approximate fair value. Our nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 4 to our consolidated financial statements and in related notes included in Item 8 of our 2014 Form 10-K . Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observance of those inputs in accordance with the fair value hierarchy. Derivative Instruments The fair values of the natural gas and certain weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflect the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We also use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which time it is amortized to interest expense over the life of the related debt. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 and Note 5 for additional derivative disclosures. Subsequent Events Except as disclosed in Note 3 related to the July 20, 2015 receipt of the second installment of the insurance settlement associated with environmental claims at certain MGP sites, in Note 10 concerning the Administrative Law Judge’s proposed order on the 2003 gas cost prudence review at Nicor Gas and below in Accounting Developments, no events occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial statements. Accounting Developments Accounting standards adopted in 2015 In April 2015, the FASB issued updated authoritative guidance related to debt issuance costs. The amendment modifies the presentation of unamortized debt issuance costs on our consolidated statements of financial position. Under the new guidance, we present such amounts as a direct deduction from the face amount of the debt, similar to unamortized debt discounts and premiums, rather than as an asset. Amortization of the debt issuance costs continues to be reported as interest expense. While the guidance would have been effective for us beginning January 1, 2016 , we elected to adopt its provisions effective April 1, 2015, and have applied its provisions to each prior period presented for comparative purposes. This new guidance did not have a material impact on our unaudited condensed consolidated financial statements. See Note 7 for additional information on the impact of adopting this accounting standard. Other newly issued accounting standards 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. 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 yet determined the impact of this new guidance, nor have we selected a transition method. In February 2015, the FASB issued updated authoritative guidance related to the consolidation of other legal entities into our financial statements. The amendments modify aspects of the consolidation determination that could potentially impact us, including the analysis of limited partnerships and similar legal entities, fee arrangements, and related party relationships . The guidance is effective for us beginning January 1, 2016, and e arly adoption is permitted. We may elect to apply the new guidance either retrospectively to each prior period presented or via a cumulative effect adjustment upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method. In April 2015, the FASB issued authoritative guidance related to the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense of the period incurred. The new guidance may be applied either prospectively or retrospectively, is effective for us beginning January 1, 2016, and early adoption is permitted. We are currently evaluating our software arrangements in light of the new guidance. In May 2015, the FASB issued updated authoritative guidance to reduce the diversity in fair value measurements hierarchy disclosures. This amendment removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share. This guidance is effective for us beginning January 1, 2016, and early adoption is permitted. We have determined that this new guidance will not have a material impact on our unaudited condensed 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.

Note 3 - Regulated Operations

Note 3 - Regulated Operations	6 Months Ended
	Jun. 30, 2015
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets and Liabilities [Text Block]	Note 3 - Regulated Operations Our regulatory assets and liabilities reflected within our unaudited Condensed Consolidated Statements of Financial Position as of the dates presented are summarized in the following table . In millions June 30 , 201 5 December 31, 2014 June 30 , 2014 Regulatory assets Recoverable ERC $ 27 $ 49 $ 33 Recoverable pension and retiree welfare benefit costs 11 12 9 Deferred natural gas costs - 3 79 Other 10 19 44 R egulatory assets – current 48 83 165 Recoverable ERC 350 329 458 Recoverable pension and retiree welfare benefit costs 105 110 94 Recoverable regulatory infrastructure program costs 77 69 65 Long-term debt fair value adjustment 70 74 78 Other 40 49 31 R egulatory assets – long-term 642 631 726 Total regulatory assets $ 690 $ 714 $ 891 Regulatory liabilities Accrued natural gas costs $ 67 $ 27 $ 41 Bad debt over collection 27 33 39 Accumulated removal costs 25 25 27 Deferred seasonal rates 8 - 8 Other 27 27 34 R egulatory liabilities – current 154 112 149 Accumulated removal costs 1,544 1,520 1,478 Regulatory income tax liability 27 34 27 Unamortized investment tax credit 21 22 24 Bad debt over collection 18 12 9 Other 12 13 27 R egulatory liabilities – long-term 1,622 1,601 1,565 Total regulatory liabilities $ 1,776 $ 1,713 $ 1,714 Base rates are designed to provide the opportunity to recover cost and earn a return on investment during the period rates are in effect. As such, all of our regulatory assets recoverable through base rates are subject to review by the respective state regulatory commission during future rate proceedings. We are not aware of evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries. Unrecognized Ratemaking Amounts In millions Atlanta Gas Light Virginia Natural Gas Elizabethtown Gas Nicor Gas Total June 30, 2015 $ 126 $ 11 $ 3 $ 1 $ 141 December 31, 2014 113 12 2 - 127 June 30, 2014 96 12 1 - 109 Natural Gas Costs Environmental Remediation Costs 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 a corresponding regulatory asset until the costs are recovered from customers. We primarily recover these deferred costs through three rate riders that authorize dollar-for-dollar recovery. We expect to collect $27 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 June 30, 2015 . 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 $205 - $463 $ 37 $ 242 $ 37 As incurred New Jersey 6 105 - 177 13 118 9 7 Georgia and Florida 13 34 - 58 25 59 29 5 North Carolina (2) 1 n/a 10 10 8 No recovery Total 46 $344 - $698 $ 85 $ 429 $ 83 (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. In July 2014, we reached a settlement with an insurance company for environmental claims relating to potential contamination at several of our MGP sites in New Jersey and North Carolina. The terms of the settlement required the insurance company to pay us a total of $77 million in two installments. We received the $45 million installment in the third quarter of 2014 and this payment was primarily recorded as a reduction to our recoverable ERC regulatory asset. The remaining $32 million was paid to us in July 2015, and as of June 30, 2015, this amount was recorded as a receivable in our unaudited Condensed Consolidated Statements of Financial Position. We will file for approval with the New Jersey BPU to utilize the insurance proceeds related to the New Jersey sites to reduce the ERC expenditures that otherwise would have been recovered from our customers in future periods. If approved, the settlement is expected to reduce our recoverable ERC regulatory asset and have a favorable impact on the rates for our Elizabethtown Gas customers.

Note 4 - Fair Value Measurement

Note 4 - Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 4 - Fair Value Measurements The methods used to determine the fair values of our assets and liabilities are described within Note 2 . Derivative Instruments The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value, net of counterparty offset and collateral, on a recurring basis in our unaudited Condensed Consolidated Statements of Financial Position as of the dates presented . See Note 5 for additional information on our derivative instruments. June 30 , 201 5 December 31, 2014 June 30 , 2014 In millions Assets (1) Liabilities Assets (1) Liabilities Assets (1) Liabilities Quoted prices in active markets (Level 1) $ 3 $ (53 ) $ 58 $ (80 ) $ 8 $ (38 ) Significant other observable inputs (Level 2) 128 (45 ) 174 (94 ) 57 (60 ) Netting of cash collateral 64 53 52 81 46 36 Total carrying value (2) $ 195 $ (45 ) $ 284 $ (93 ) $ 111 $ (62 ) (1) Balances of $2 million at June 30, 2015, $3 million at December 31, 2014 and $3 million at June 30, 2014, associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value. (2) There were no significant unobservable inputs (Level 3) or significant transfers between Level 1, Level 2 or Level 3 for any of the dates presented. Debt Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which are recorded at their acquisition -date fair value . We amortize the fair value adjustment of Nicor Gas’ first mortgage bonds over the lives of the bonds. The following table lists the carrying amount and fair value of our long-term debt as of the dates presented . In millions June 30 , 201 5 December 31, 2014 June 30 , 2014 Long-term debt carrying amount $ 3,577 $ 3,781 $ 3,785 Long-term debt fair value (1) 3,857 4,231 4,191 (1) Fair value determined using Level 2 inputs.

Note 5 - Derivative Instruments

Note 5 - Derivative Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	Note 5 - Derivative Instruments Our objectives and strategies for using derivative instruments, and the related accounting policies and methods used to determine their fair values are described in Note 2 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K . See Note 4 for additional information on fair value and 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 June 30, 2015, December 31, 2014 and June 30, 2014, for agreements with such features, derivative instruments with liability fair values totaled $45 million, $93 million and $62 million, respectively, for which we had posted no collateral to our counterparties. The maximum collateral that could be required with these features is $7 million. For more information, see “Energy Marketing Receivables and Payables” in Note 2, which also have credit -risk-related contingent features. Our derivative instrument activities are included within operating cash flows as an increase (decrease) to net income of $42 million and $(13) million for the six months ended June 30, 2015 and 2014, respectively . Quantitative Disclosures Related to Derivative Instruments Our derivative instruments are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. As of the dates presented, we had a net long natural gas contracts position outstanding in the following quantities: In Bcf June 30 , 201 5 (2) December 31, 2014 June 30 , 2014 Cash flow hedges 6 9 6 Not designated as hedges 24 75 140 Total volumes 30 84 146 Short position – cash flow hedges (8 ) (7 ) (4 ) Short position – not designated as hedges (2,930 ) (2,825 ) (2,524 ) Long position – cash flow hedges 14 16 10 Long position – not designated as hedges 2,954 2,900 2,664 Net long position 30 84 146 (1) Volumes related to Nicor Gas exclude variable-priced contracts, which are carried at fair value, but whose fair values are not directly impacted by changes in commodity prices. (2) Approximately 96% of these contracts have durations of two years or less and the remaining 4% expire between two and five years. Derivative Instruments in our Unaudited Condensed Consolidated Statements of Financial Position In accordance with regulatory requirements, gains and losses on derivative instruments used to hedge natural gas purchases for customer use at distribution operations are reflected in accrued natural gas costs within our unaudited Condensed Consolidated Statements of Financial Position until billed to customers. The following amounts deferred as a regulatory asset or liability in our unaudited Condensed Consolidated Statements of Financial Position represent the net realized gains (losses) related to these natural gas cost hedges as of the periods presented. Three months ended June 30 , Six months ended June 30 , In millions 201 5 201 4 201 5 201 4 Nicor Gas $ (18 ) $ 10 $ (21 ) $ 12 Elizabethtown Gas (4 ) 2 (8 ) 5 The following table presents the fair values and unaudited Condensed Consolidated Statements of Financial Position classifications of our derivative instruments as of the dates presented. June 30 , 201 5 December 31, 2014 June 30 , 2014 In millions Classification Assets Liabilities Assets Liabilities Assets Liabilities D esignated as cash flow or fair value hedges Natural gas contracts Current $ - $ (4 ) $ 6 $ (11 ) $ 2 $ (1 ) Natural gas contracts Long-term - (1 ) - (1 ) - - Interest rate swap agreements Current 24 - - - - - Interest rate swap agreements Long-term 23 - - - - - Total designated as cash flow or fair value hedges $ 47 $ (5 ) $ 6 $ (12 ) $ 2 $ (1 ) Not designated as hedges Natural gas contracts Current $ 473 $ (481 ) $ 1,061 $ (1,020 ) $ 702 $ (721 ) Natural gas contracts Long-term 92 (91 ) 145 (119 ) 77 (89 ) Total not designated as hedges $ 565 $ (572 ) $ 1,206 $ (1,139 ) $ 779 $ (810 ) Gross amounts of recognized assets and liabilities (1) (2) 612 (577 ) 1,212 (1,151 ) 781 (811 ) Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2) (415 ) 532 (925 ) 1,058 (667 ) 749 Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3) $ 197 $ (45 ) $ 287 $ (93 ) $ 114 $ (62 ) (1) The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Statements of Financial Position to the extent that we have netting arrangements with the counterparties . (2) As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities do not include cash collateral held on deposit in broker margin accounts of $117 million as of June 30, 2015, $133 million as of December 31, 2014, and $82 million as of June 30, 2014. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table. (3) As of June 30, 2015, December 31, 2014, and June 30, 2014, we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets. Derivative Instruments in the 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 June 30, Six months ended June 30, In millions 201 5 201 4 201 5 201 4 Designated as cash flow or fair value hedges Natural gas contracts - net gain (loss) reclassified from OCI into cost of goods sold $ (3 ) $ 2 $ (4 ) $ 5 Natural gas contracts - net gain (loss) reclassified from OCI into operation and maintenance expense (1 ) - (1 ) 1 Interest rate swaps - net loss reclassified from OCI into interest expense - - 1 - Income tax benefit - (1 ) - (1 ) Total designated as cash flow or fair value hedges, n et of tax (4 ) 1 (4 ) 5 Not designated as hedges (1) Natural gas contracts - net gain (loss) recorded in operating revenues 3 30 (21 ) - Natural gas contracts - net gain (loss) recorded in cost of goods sold (2) 1 (1 ) (1 ) 1 Income tax benefit (1 ) (11 ) 9 - Total not designated as hedges, n et of tax 3 18 (13 ) 1 Total gains (losses) on derivative instruments , net of tax $ (1 ) $ 19 $ (17 ) $ 6 (1) Associated with the fair value of derivative instruments held at June 30, 2015 and 2014 . (2) Excludes (gains) losses recorded in cost of goods sold associated with weather derivatives of $(1) million and $1 million for the three and six months ended June 30, 2015 and $1 million and $6 million for the three and six months ended June 30 , 2014 . 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 and six months ended June 30, 2015 and 2014 . Our expected gains to be reclassified from OCI into cost of goods sold, operation and maintenance expense , interest expense and operating revenues and recognized in our unaudited Condensed Consolidated Statements of Income over the next 12 months are $4 million. These deferred gains are related to natural gas derivative contracts associated with retail operations’ and Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at June 30, 2015 . There have been no other significant changes to our derivative instruments, as described in Note 2, Note 4 and Note 5 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K .

Note 6 - Employee Benefit Plans

Note 6 - Employee Benefit Plans	6 Months Ended
	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	Note 6 - Employee Benefit Plans Pension Benefits We sponsor the AGL Resources Inc. Retirement Plan, a tax-qualified defined benefit retirement plan for our eligible employees, which is described in Note 6 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K . Following are the components of our pension costs for the periods indicated . Three months ended June 30 , Six months ended June 30 , In millions 201 5 201 4 201 5 2014 Service cost $ 7 $ 6 $ 14 $ 12 Interest cost 12 11 23 23 Expected return on plan assets (17 ) (16 ) (33 ) (32 ) Net amortization of prior service cost (credit) - (1 ) (1 ) (1 ) Recognized actuarial loss 7 6 15 11 Net periodic pension benefit cost $ 9 $ 6 $ 18 $ 13 Welfare Benefits The benefits of our Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. are described in Note 6 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K . Following are the components of our welfare costs for the periods indicated. Three months ended June 30, Six months ended June 30, In millions 201 5 201 4 201 5 201 4 Service cost $ - $ - $ 1 $ 1 Interest cost 3 3 6 7 Expected return on plan assets (2 ) (1 ) (4 ) (3 ) Net amortization of prior service (credit) cost (1 ) - (1 ) (1 ) Recognized actuarial loss 2 2 3 3 Net periodic welfare benefit cost $ 2 $ 4 $ 5 $ 7

Note 7 - Debt and Credit Facili

Note 7 - Debt and Credit Facilities	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Note 7 - Debt and Credit Facilities Effective April 1, 2015, we adopted new authoritative guidance related to debt issuance costs, which resulted in an adjustment to the presentation of debt issuance costs primarily from other long-term assets to offset the related debt balances in long-term debt totaling $19 million, $21 million and $22 million as of June 30, 2015, December 31, 2014 and June 30, 2014, respectively. See “Accounting Developments” in Note 2 for additional information . The following table provides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities for the periods presented. We fully and unconditionally guarantee all debt issued by AGL Capital. For additional information on our debt , see Note 8 to our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K. June 30 , 201 5 June 30 , 2014 Dollars in millions Year(s) due Weighted average interest rate (1) Outstanding December 31, 2014 Weighted average interest rate (1) Outstanding Short-term debt Commercial paper - AGL Capital (2) 2015 0.5 % $ 269 $ 590 0.3 % $ 236 Commercial paper - Nicor Gas (2) 2015 0.4 190 585 0.2 212 Total short-term debt 0.4 % $ 459 $ 1,175 0.3 % $ 448 C urrent portion of long-term debt 2016 4.6 % $ 125 $ 200 5.0 % $ 200 Long-term debt - excluding current portion Senior notes 2016-2043 5.0 % $ 2,625 $ 2,625 5.0 % $ 2,625 First mortgage bonds 2019-2038 5.9 375 500 5.6 500 Gas facility revenue bonds 2022-2033 0.9 200 200 0.9 200 Medium-term notes 2017-2027 7.8 181 181 7.8 181 Total principal long-term debt 4.9 3,381 3,506 4.9 3,506 Fair value adjustment of long-term debt (3) n/a n/a 74 80 n/a 85 Unamortized debt premium and issuance costs, net n/a n/a (3 ) (5 ) n/a (6 ) Total non-principal long-term debt n/a 71 75 n/a 79 Total long-term debt – excluding current portion $ 3,452 $ 3,581 $ 3,585 Total debt $ 4,036 $ 4,956 $ 4,233 (1) Interest rates are calculated based on the daily weighted average balance outstanding for the six months ended June 30. (2) As of June 30, 2015, the effective interest rates on our commercial paper borrowings were 0.5% for AGL Capital and 0.4% for Nicor Gas. (3) See Note 4 for additional information on our fair value measurements. Commercial Paper Programs We maintain commercial paper programs at AGL Capital and at Nicor Gas that consist of short-term, unsecured promissory notes used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are generally 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 six months of 2015, our commercial paper maturities ranged from 1 to 58 days, and at June 30, 2015, remaining terms to maturity ranged from 1 to 21 days . During the first six months of 2015, we had no commercial paper issuances with original maturities over three months. Total borrowings and repayments during the first six months of 2015 netted to a payment of $716 million. Senior Notes On January 15, 2015, $200 million of senior notes matured and were repaid using the proceeds from commercial paper borrowings. Interest Rate Swaps On January 23, 2015, we executed $800 million in notional value of 10 year and 30 year fixed-rate, forward-starting interest rate swaps to hedge potential interest rate volatility prior to anticipated issuances of senior notes during the second half of 2015 and in 2016. These debt issuances will be used to reduce our commercial paper for the amount that was borrowed to repay our senior notes that matured in January 2015 and to fund upcoming debt maturities as well as increased capital expenditures associated with utility investments, including infrastructure programs, and construction of our new pipeline projects. We have designated the forward-starting interest rate swaps, which will be settled on the debt issuance dates, as cash flow hedges . We performed a qualitative assessment of effectiveness as of June 30, 2015 and concluded that the hedges remain highly effective. Financial and Non-Financial Covenants The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any month; however, our goal is to maintain these ratios at levels between 50% and 60%, except for temporary increases related to the timing of acquisition and financing activities. The following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed. AGL Resources Nicor Gas June 30, Dec. 31, June 30, June 30, Dec. 31, June 30, 201 5 2014 2014 201 5 2014 2014 Debt covenants (1) 49% 55% 51% 49% 62% 52% (1) As defined in our credit facilities, includes standby letters of credit and performance/surety bonds and excludes 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 ● change of control provisions We have no triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other triggering events. We were in compliance with all existing debt provisions and covenants, both financial and non-financial , for all periods presented .

Note 8 - Equity

Note 8 - Equity	6 Months Ended
	Jun. 30, 2015
Stockholders' Equity Note [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	Note 8 - Equity Our OCI (loss) amounts are aggregated within our accumulated other comprehensive loss on our unaudited Condensed Consolidated Statements of Financial Position . The following table provides changes in the components of our accumulated other comprehensive loss balances, net of the related income tax effects. 2015 2014 In millions Cash flow hedges Retirement benefit plans Total Cash flow hedges Retirement benefit plans Total For the three months end ed June 30 As of beginning of period $ (4 ) $ (197 ) $ (201 ) $ 1 $ (136 ) $ (135 ) OCI, before reclassifications 25 - 25 - - - Amounts reclassified from accumulated OCI 3 4 7 (1 ) 3 2 Net current-period other comprehensive income (loss) 28 4 32 (1 ) 3 2 As of end of period $ 24 $ (193 ) $ (169 ) $ - $ (133 ) $ (133 ) For the six months end ed June 30 As of beginning of period $ (6 ) $ (200 ) $ (206 ) $ 1 $ (137 ) $ (136 ) OCI, before reclassifications 27 - 27 4 - 4 Amounts reclassified from accumulated OCI 3 7 10 (5 ) 4 (1 ) Net current-period other comprehensive income (loss) 30 7 37 (1 ) 4 3 As of end of period $ 24 $ (193 ) $ (169 ) $ - $ (133 ) $ (133 ) (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 ultimate favorable (unfavorable) impact on net income for the periods presented. Three months ended June 30, Six months ended June 30, In millions (1) 2015 2014 2015 2014 Cash flow hedges Cost of goods sold (natural gas contracts) $ (3 ) $ 2 $ (4 ) $ 5 Operation and maintenance expense (natural gas contracts) (1 ) - (1 ) 1 Interest expense (interest rate contracts) - - 1 - Total before income tax (4 ) 2 (4 ) 6 Income tax benefit - (1 ) - (1 ) Cash flow hedges, net of income tax (4 ) 1 (4 ) 5 Less noncontrolling Interest (1 ) - (1 ) - Total cash flow hedges, net of income tax (3 ) 1 (3 ) 5 Retirement benefit plan s Operation and maintenance expense (actuarial losses) (2) (6 ) (6 ) (11 ) (8 ) Operation and maintenance expense (prior service credits) (2) - 1 - 1 Total before income tax (6 ) (5 ) (11 ) (7 ) Income tax benefit 2 2 4 3 Total retirement benefit plans (4 ) (3 ) (7 ) (4 ) Total reclassification for the period $ (7 ) $ (2 ) $ (10 ) $ 1 (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 6 for additional details about net periodic benefit cost .

Note 9 - Non-Wholly Owned Entit

Note 9 - Non-Wholly Owned Entities	6 Months Ended
	Jun. 30, 2015
Noncontrolling Interest [Abstract]
Noncontrolling Interest Disclosure [Text Block]	Note 9 - Non-Wholly Owned Entit ies 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 10 to our consolidated financial statements and related notes included in Item 8 of our 2014 Form 10-K. Earnings from SouthStar in 2015 and 2014 were allocated entirely in accordance with the ownership interests. Cash flows used in our investing activities include capital expenditures for SouthStar of $2 million for the six months ended June 30, 2015, and $4 million for the six months ended June 30, 2014. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year, which generally occurs in the first quarter of each fiscal year. For the six months ended June 30, 2015 and 2014, SouthStar distributed $18 million and $17 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. June 30 , 201 5 December 31, 2014 June 30 , 2014 In millions Consolidated SouthStar % Consolidated SouthStar % Consolidated SouthStar % Current assets $ 1,572 $ 192 12 % $ 2,886 $ 236 8 % $ 2,380 $ 195 8 % Goodwill and other intangible assets 1,939 117 6 1,952 125 6 1,962 129 7 Long-term assets and other deferred debits 10,324 17 - 10,050 17 - 9,817 17 - Total assets $ 13,835 $ 326 2 % $ 14,888 $ 378 3 % $ 14,159 $ 341 2 % Current liabilities $ 2,047 $ 40 2 % $ 3,219 $ 71 2 % $ 2,595 $ 55 2 % Long-term liabilities and other deferred credits 7,799 1 - 7,841 - - 7,704 - - Total Liabilities 9,846 41 - 11,060 71 1 10,299 55 1 Equity 3,989 285 7 3,828 307 8 3,860 286 7 Total liabilities and equity $ 13,835 $ 326 2 % $ 14,888 $ 378 3 % $ 14,159 $ 341 2 % (1) These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar . 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 June 30, Six months ended June 30, In millions 201 5 2014 201 5 2014 Operating revenues $ 122 $ 145 $ 433 $ 519 Operating expenses Cost of goods sold 89 111 292 381 Operation and maintenance 18 20 41 43 Depreciation and amortization 3 2 5 5 Taxes other than income taxes - 1 1 1 Total operating expenses 110 134 339 430 Operating income $ 12 $ 11 $ 94 $ 89 Equity Method Investments For more information about our equity method investments, see Note 10 to our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K. The carrying amounts within our unaudited Condensed Consolidated Statements of Financial Position of our investments that are accounted for under the equity method were as follows: June 30, December 31, June 30, In millions 201 5 2014 2014 Triton $ 53 $ 62 $ 65 Horizon Pipeline 14 14 15 Other (1) 8 4 1 Total $ 75 $ 80 $ 81 (1) Primarily includes our current investments of $3 million in PennEast Pipeline and $4 million in Atlantic Coast Pipeline as of June 30, 2015 and $1 million and $2 million, respectively, as of December 31, 2014. Income from our equity method investments is classified as other income in our unaudited Condensed Consolidated Statements of Income. The following table provides the income from our equity method investments for the periods presented . Three months ended June 30, Six months ended June 30, In millions 201 5 201 4 201 5 201 4 Triton $ 1 $ 1 $ 1 $ 3 Horizon Pipeline - - 1 1 In the third quarter of 2014, we entered into partnerships to form two new interstate pipeline companies within our midstream operations segment as described below. The capacity from these pipelines will further enhance system reliability as well as provide access to a more diverse supply of natural gas. We have concluded that, at present, both companies are VIEs. We are not considered the primary beneficiary and, therefore, we have not consolidated the financial statements for these companies in our unaudited condensed consolidated financial statements because we share in the ability to direct the activities that most significantly impact their economic performance with their other member companies. We have accounted for our investments in these companies using the equity method of accounting, and have classified the investments within other noncurrent assets in our unaudited Condensed Consolidated Statements of Financial Position. PennEast Pipeline In August 2014, we entered into a partnership in which we hold a 20% ownership interest in a new interstate pipeline company formed to develop and operate a 108-mile natural gas pipeline between New Jersey and Pennsylvania with initial transportation capacity of 1 Bcf per day, which may be expanded to 1.2 Bcf per day. Subject to FERC approval, construction is scheduled to begin in the first quarter of 2017. Atlantic Coast Pipeline .

Note 10 - Commitments, Guarante

Note 10 - Commitments, Guarantees and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	Note 10 - Commitments, Guarantees and Contingencies We incur various contractual obligations and financial commitments in the normal course of 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. The following table illustrates our expected contractual obligations and commitments as of June 3 0, 2015 . 2020 & In millions Total 2015 2016 2017 2018 2019 thereafter Recorded contractual obligations: Long-term debt $ 3,506 $ - $ 545 $ 22 $ 155 $ 350 $ 2,434 Short-term debt 459 459 - - - - - Environmental remediation liabilities (1) 429 47 86 80 65 44 107 Total $ 4,394 $ 506 $ 631 $ 102 $ 220 $ 394 $ 2,541 Unrecorded contractual obligations and commitments : Pipeline charges, storage capacity and gas supply (3) $ 5,341 $ 527 $ 706 $ 491 $ 369 $ 343 $ 2,905 Interest charges (4) 2,670 87 171 147 146 141 1,978 Operating leases (5) 172 13 26 28 21 16 68 Asset management agreements (6) 33 5 11 9 6 2 - Standby letters of credit, performance/surety bonds (7) 48 37 11 - - - - Other 8 3 3 1 1 - - Total $ 8,272 $ 672 $ 928 $ 676 $ 543 $ 502 $ 4,951 (1) Includes charges recoverable through base rates or rate rider mechanisms. (2) In accordance with GAAP, these items are not reflected in our unaudited condensed Consolidated Statements of Financial Position. (3) Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 87 Bcf at floating gas prices calculated using forward natural gas prices as of June 30, 2015, and is valued at $222 million. As we do for other subsidiaries, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations. (4) Floating rate interest charges are calculated based on the interest rate as of June 30, 2015 and the maturity date of the underlying debt instrument. As of June 30, 2015, we have $48 million of accrued interest on our unaudited Condensed Consolidated Statements of Financial Position that will be paid in the next 12 months. (5) We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with GAAP. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Our operating leases are primarily for real estate. (6) Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements. (7) We provide guarantees to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations. We are also involved in legal or administrative proceedings before various courts and agencies with respect to general claims, environmental remediation and other matters. Although we are unable to determine the ultimate outcomes of these contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable. For more information on these matters, see Note 11 to our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K . Contingencies and Guarantees Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur . We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees is remote. No liabilities have been recorded for such guarantees and indemnifications , as the fair values were inconsequential at inception. Regulatory Matters In December 2012, we filed a petition with the Georgia Commission for approval to resolve a volumetric imbalance of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. In September 2014, we filed a stipulation that was entered between us, staff of the Georgia Commission and several Marketers that included a resolution of the 4.6 Bcf imbalance over a five-year period from January 1, 2015 through December 31, 2019, which was approved by the Georgia Commission in December 2014. During the first half of 2015, discretionary funds available to the Universal Service Fund, which is controlled by the Georgia Commission, were used to resolve their obligation of 25% of the imbalance, or approximately 1.15 Bcf of natural gas. Atlanta Gas Light is also obligated to resolve 25% of the 4.6 Bcf imbalance, or approximately 1.15 Bcf of natural gas, through system injections. As of June 30, 2015, Atlanta Gas Light had replaced substantially its entire obligation. 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. According to the current procedural schedule, we expect a final order to be issued by the Illinois Commission in the second half of 2015, in which the Illinois Commission may accept, reject or modify the proposed order of the Administrative Law Judge. As of June 30, 2015 we have not recorded a liability associated with this contingency. In February 2015, Atlanta Gas Light made a filing with the Georgia Commission for a true-up recovery of $178 million related to our 15-year pipeline replacement program that ended on December 31, 2013. This filing is for unrecovered revenue through December 2014. The filing proposed an initial one-time $2.46 rate increase collected from 2016 through 2025, or an alternative phased-in schedule of four $0.58 cumulative increases in 2017, 2018, 2019 and 2020 collected through 2030. The company believes that all incurred costs deferred for future recovery will be collected in future revenues. T he staff of the Georgia Commission is evaluating this matter; however, no hearing schedule or date of any final order has been established. Additionally, one of the capital projects under Atlanta Gas Light’s pipeline replacement program experienced construction issues on certain segments in late 2013, and prior to these segments being placed into service it was necessary to complete mitigation work. Atlanta Gas Light is pursuing contractual and legal claims against third party contractors responsible for the construction issues. In August 2014, Atlanta Gas Light reached an agreement with the Georgia Commission whereby it would delay recovery of the mitigation costs to a future rate proceeding after completion of litigation and the amount of recoveries from third party contractors was known . The company believes all costs were prudently incurred and intends to seek recovery in a future rate proceeding. Environmental Matters We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. See Note 3 for additional information on our environmental remediation costs. Litigation We are involved in litigation arising in the normal course of business. Although in some cases we are unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. Management believes that while the resolutions of these contingencies, whether individually or in aggregate, could be material to earnings in a particular quarter, they will not have a material adverse effect on our consolidated financial position or cash flows for the year. For additional litigation information , see Note 11 to our consolidated financial statements and related notes in Item 8 of our 2014 Form 10-K . PBR Proceeding , the amount of the savings and losses required to be shared had been disputed by the CUB and others, with the Illinois Attorney General intervening, and had been subject to extensive contested discovery and other regulatory proceedings before administrative law judges and the Illinois Commission. In 2009, the staff of the Illinois Commission, Illinois Attorney General and CUB requested refunds of $85 million, $255 million and $305 million, respectively. On June 7, 2013, the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas customers through our PGA mechanism based upon natural gas throughput. All refunds were completed in the first half of 2014 . The CUB’s February 28, 2014 appeal of the Illinois Commission’s order requesting refunds consistent with its 2009 request was rejected by the appellate court in Illinois on March 18, 2015. The period for the CUB to appeal this decision has expired.

Note 11 - Segment Information

Note 11 - Segment Information	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Segment Reporting Disclosure [Text Block]	Note 11 - Segment Information Our reportable segments comprise revenue-generating components of the company for which we produce separate financial information internally that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through four reportable segments – distribution operations, retail operations, wholesale services and midstream operations. Our non-reportable segments are combined and presented as “other segments.” 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 are regulated utilities with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics. We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, retail operations provides home 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” non-reportable segments include subsidiaries that individually 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 Chairman and Chief Executive Officer, who utilizes EBIT as the primary measure of profit and loss in assessing the results of each segment’s operations. EBIT includes operating income and other income and expenses. Items we do not include in EBIT are income taxes and financing costs, including interest expense, each of which we evaluate on a consolidated basis. Summarized statements of income, statements of financial position and capital expenditure information by segment as of and for the periods presented are shown in the following tables. Three months ended June 30 , 201 5 In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Operating revenues from external parties $ 506 $ 153 $ 4 $ 11 $ 3 $ (3 ) $ 674 Intercompany revenues 40 - - - - (40 ) - Total operating revenues 546 153 4 11 3 (43 ) 674 Operating expenses Cost of goods sold 166 95 - 2 - (41 ) 222 Operation and maintenance 160 34 11 6 - (2 ) 209 Depreciation and amortization 83 6 1 4 4 - 98 Taxes other than income taxes 34 1 - 1 2 - 38 Total operating expenses 443 136 12 13 6 (43 ) 567 Operating income (loss) 103 17 (8 ) (2 ) (3 ) - 107 Other income 3 - - - 1 - 4 EBIT $ 106 $ 17 $ (8 ) $ (2 ) $ (2 ) - $ 111 Capital expenditures $ 248 $ 2 $ - $ 7 $ 7 $ - $ 264 Three months ended June 30, 2014 In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Operating revenues from external parties $ 656 $ 176 $ 47 $ 17 $ 1 $ (8 ) $ 889 Intercompany revenues 43 1 - - - (44 ) - Total operating revenues 699 177 47 17 1 (52 ) 889 Operating expenses Cost of goods sold 315 119 7 11 - (50 ) 402 Operation and maintenance 159 34 13 7 - (2 ) 211 Depreciation and amortization 78 6 1 4 6 - 95 Taxes other than income taxes 40 1 - 2 (1 ) - 42 Total operating expenses 592 160 21 24 5 (52 ) 750 Operating income (loss) 107 17 26 (7 ) (4 ) - 139 Other income (expense) 3 - (2 ) - 1 - 2 EBIT $ 110 $ 17 $ 24 $ (7 ) $ (3 ) $ - $ 141 Capital expenditures $ 158 $ 3 $ - $ 5 $ 5 $ - $ 171 Six months ended June 30, 201 5 In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Operating revenues from external parties $ 1,791 $ 494 $ 94 $ 30 $ 9 $ (23 ) $ 2,395 Intercompany revenues 96 - - - - (96 ) - Total operating revenues 1,887 494 94 30 9 (119 ) 2,395 Operating expenses Cost of goods sold 942 305 9 12 5 (116 ) 1,157 Operation and maintenance 345 71 35 12 (2 ) (3 ) 458 Depreciation and amortization 165 12 1 9 8 - 195 Taxes other than income taxes 105 2 1 2 4 - 114 Total operating expenses 1,557 390 46 35 15 (119 ) 1,924 Operating income (loss) 330 104 48 (5 ) (6 ) - 471 Other income 4 - - 1 2 - 7 EBIT $ 334 $ 104 $ 48 $ (4 ) $ (4 ) - $ 478 Identifiable and total assets (2) $ 11,796 $ 636 $ 806 $ 686 $ 9,190 $ (9,279 ) $ 13,835 Capital expenditures $ 418 $ 4 $ 1 $ 10 $ 19 $ - $ 452 Six months ended June 30, 2014 In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Operating revenues from external parties $ 2,382 $ 582 $ 378 $ 61 $ 4 $ (56 ) $ 3,351 Intercompany revenues 118 1 - - - (119 ) - Total operating revenues 2,500 583 378 61 4 (175 ) 3,351 Operating expenses Cost of goods sold 1,517 399 10 47 - (171 ) 1,802 Operation and maintenance 370 71 49 13 1 (4 ) 500 Depreciation and amortization 156 14 1 9 8 - 188 Taxes other than income taxes 122 2 1 3 2 - 130 Total operating expenses 2,165 486 61 72 11 (175 ) 2,620 Operating income (loss) 335 97 317 (11 ) (7 ) - 731 Other income (expense) 4 - (2 ) 1 2 - 5 EBIT $ 339 $ 97 $ 315 $ (10 ) $ (5 ) $ - $ 736 Identifiable and total assets (2) $ 11,511 $ 671 $ 1,207 $ 699 $ 9,482 $ (9,668 ) $ 13,902 Capital expenditures $ 308 $ 6 $ 1 $ 5 $ 12 $ - $ 332 (1) The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table. In millions Third party gross revenues Intercompany revenues Total gross revenues Less gross gas costs Operating revenues Three months ended June 30, 2015 $ 1,291 $ 89 $ 1,380 $ 1,376 $ 4 Three months ended June 30, 2014 2,379 160 2,539 2,492 47 Six months ended June 30, 2015 3,436 239 3,675 3,581 94 Six months ended June 30, 2014 6,428 458 6,886 6,508 378 (2) Identifiable and total assets exclude assets held for sale . Identifiable assets are those used in each segment’s operations. Information by segment on our Consolidated Statements of Financial Position as of December 31, 2014, is as follows: In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Identifiable and total assets $ 12,037 $ 670 $ 1,402 $ 694 $ 9,706 $ (9,621 ) $ 14,888

Note 12 - Discontinued Operatio

Note 12 - Discontinued Operations	6 Months Ended
	Jun. 30, 2015
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Note 12 - Discontinued Operations On September 1, 2014, we closed on the sale of Tropical Shipping to an unrelated third party. The after-tax cash proceeds and distributions from the transaction were approximately $225 million. We determined that the cumulative foreign earnings of Tropical Shipping would no longer be indefinitely reinvested offshore. Accordingly, we recognized income tax expense of $60 million, of which $31 million was recorded in the first quarter of 2014, and the remaining $29 million was recorded in the third quarter of 2014 related to the cumulative foreign earnings for which no tax liabilities had been previously recorded, resulting in our repatriation of $86 million in cash. During the first quarter of 2014, based upon the negotiated sales price, we also recorded a goodwill impairment charge of $19 million, for which there was no income tax benefit. Additionally, we recognized a total charge of $7 million in the second and third quarters of 2014 related to the suspension of depreciation and amortization for assets that we were not compensated for by the buyer. The assets and liabilities of Tropical Shipping classified as held for sale on the unaudited Condensed Consolidated Statements of Financial Position are as follows: In millions June 30, 2014 Current assets Cash and cash equivalents $ 15 Short-term investments 3 Receivables 35 Inventories 9 Other 2 Total current assets 64 Long-term assets and other deferred debits Property, plant and equipment, net 127 Goodwill 42 Intangible assets 19 Other 5 Total long-term assets and other deferred debits 193 Total assets held for sale $ 257 Current liabilities Other accounts payable – trade $ 9 Accrued expenses 7 Other 23 Total liabilities held for sale $ 39 The financial results of these businesses are reflected as discontinued operations, and the prior period presented has been recast to reflect the discontinued operations. The components of discontinued operations recorded on the unaudited Condensed Consolidated Statements of Income are as follows: Three months ended Six months ended In millions June 30, 2014 June 30, 2014 Operating revenues $ 92 $ 181 Operating expenses Cost of goods sold 57 111 Operation and maintenance 27 55 Depreciation and amortization - 5 Taxes other than income taxes 3 4 Loss on sale and goodwill impairment 4 23 Total operating expenses 91 198 Operating income (loss) 1 (17 ) Income (loss) before income taxes 1 (17 ) Income tax expense - (32 ) Income (loss) from discontinued operations, net of tax $ 1 $ (49 )

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Use of Estimates, Policy [Policy Text Block]	Use of Accounting Estimates The preparation of our financial statements in conformity with GAAP requires us to use judgment and make estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances . Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing accounting literature or in the development of estimates that impact our financial statements. The most significant estimates relate to the accounting for our rate-regulated subsidiaries, goodwill and other intangible assets, 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.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of June 30, 2014 , there was $15 million of cash and cash equivalents held by Tropical Shipping that was excluded from cash and cash equivalents within our unaudited Condensed Consolidated Statements of Financial Position and included in assets held for sale. For more information on the sale of Tropical Shipping, see Note 12.
Energy Marketing Receivables And Payables [Policy Text Block]	Energy Marketing Receivables and Payable s Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing trade payables. Wholesale services has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of June 30, 2015 and 2014, and December 31, 2014, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.
Inventory, Policy [Policy Text Block]	Inventories For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 10 for information regarding an approved regulatory filing to resolve a natural gas inventory imbalance at Atlanta Gas Light. Nicor Gas’ inventory is carried at cost on a LIFO basis . Inventory decrements occurring during the year that are expected to be restored prior to year -end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO inventory liquidation. Any temporary LIFO liquidation is included as a current liability in our unaudited Condensed Consolidated Statements of Financial Position . Interim inventory decrements that are not expected to be restored prior to year -end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of June 30, 2015 is expected to be restored prior to year-end and the inventory decrement as of June 30, 2014 was restored prior to December 31, 2014. Our retail operations, wholesale services and midstream operations segments carry inventory at LOCOM, where cost is determined on a WACOG basis. For these segments, we evaluate the weighted average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, we record pre-tax adjustments to our unaudited Condensed Consolidated Statements of Income to reduce the weighted average cost of the natural gas inventory to market value . For the periods presented, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our inventories to market value . Three months ended June 30, Six months ended June 30, In millions 201 5 201 4 201 5 201 4 LOCOM adjustments $ - $ 4 $ 10 $ 6 We have $12 million of inventory at wholesale services that is currently inaccessible due to operational issues at a third party storage facility. The owner of this storage facility is working to resolve these issues. While we expect this inventory to be accessible in the second half of 2015 and to be fully recovered, the timing of withdrawal of this gas may be impacted by operational issues.
Public Utilities, Policy [Policy Text Block]	Regulated Operations We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for estimated expenditures that have not yet been incurred. Generally, regulatory assets and regulatory liabilities are amortized into our unaudited Condensed Consolidated Statements of Income over the period authorized by the regulatory commissions.
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]	Goodwill We perform an annual impairment test on our reporting units that contain goodwill during the fourth quarter of each year, or more frequently if impairment indicators arise. There were no triggering events during the current period that would require us to perform an interim goodwill impairment test. The amounts of goodwill as of June 30, 2015 and 2014, and December 31, 2014 are provided below . In millions Distribution o perations Retail o perations Midstream o perations Consolidated Goodwill $ 1,640 $ 173 $ 14 $ 1,827
Earnings Per Share, Policy [Policy Text Block]	Earnings Per Common Share We compute basic earnings per common share attributable to AGL Resources Inc. by dividing our net income attributable to the common shareholders of AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. that occurs when the exercise and/or conversion of all potentially dilutive common shares is added to the common shares outstanding. We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options award programs. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance and/or time-based criteria. The future issuance of shares underlying the outstanding stock options depends on whether the market price of the common shares underlying the options exceeds the respective exercise prices of the stock options. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. for the periods presented as if performance units currently earned under the plan ultimately vest and as if stock options currently exercisable at prices below the average market prices are exercised. Three months ended June 30, Six months ended June 30, In millions (except per share amounts) 201 5 201 4 201 5 201 4 Income from continuing operations attributable to AGL Resources Inc. $ 42 $ 57 $ 235 $ 391 Income (loss) from discontinued operations, net of tax - 1 - (49 ) Net income attributable to AGL Resources Inc. $ 42 $ 58 $ 235 $ 342 Denominator: Basic weighted average number of shares outstanding (1) 119.5 118.8 119.4 118.7 Effect of dilutive securities 0.3 0.4 0.3 0.4 Diluted weighted average number of shares outstanding (2) 119.8 119.2 119.7 119.1 Basic earnings (loss) per share Continuing operations $ 0.35 $ 0.48 $ 1.97 $ 3.30 Discontinued operations - 0.01 - (0.42 ) Basic earnings per share attributable to AGL Resources Inc. $ 0.35 $ 0.49 $ 1.97 $ 2.88 Diluted earnings (loss) per share Continuing operations $ 0.35 $ 0.48 $ 1.96 $ 3.29 Discontinued operations - 0.01 - (0.42 ) Diluted earnings per share attributable to AGL Resources Inc. $ 0.35 $ 0.49 $ 1.96 $ 2.87 (1) Daily weighted average shares outstanding. (2) All outstanding stock options whose effect would have been anti-dilutive were excluded from the computation of diluted earnings per common share.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value Measurements We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents, and derivative assets and liabilities. The carrying values of receivables , short - and long-term investments, accounts payable, short-term debt, other current assets and liabilities , and accrued interest approximate fair value. Our nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 4 to our consolidated financial statements and in related notes included in Item 8 of our 2014 Form 10-K . Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We utilize market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observance of those inputs in accordance with the fair value hierarchy.
Derivatives, Policy [Policy Text Block]	Derivative Instruments The fair values of the natural gas and certain weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflect the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We also use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which time it is amortized to interest expense over the life of the related debt. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 and Note 5 for additional derivative disclosures.
Subsequent Events, Policy [Policy Text Block]	Subsequent Events Except as disclosed in Note 3 related to the July 20, 2015 receipt of the second installment of the insurance settlement associated with environmental claims at certain MGP sites, in Note 10 concerning the Administrative Law Judge’s proposed order on the 2003 gas cost prudence review at Nicor Gas and below in Accounting Developments, no events occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial statements.
New Accounting Pronouncements, Policy [Policy Text Block]	Accounting Developments Accounting standards adopted in 2015 In April 2015, the FASB issued updated authoritative guidance related to debt issuance costs. The amendment modifies the presentation of unamortized debt issuance costs on our consolidated statements of financial position. Under the new guidance, we present such amounts as a direct deduction from the face amount of the debt, similar to unamortized debt discounts and premiums, rather than as an asset. Amortization of the debt issuance costs continues to be reported as interest expense. While the guidance would have been effective for us beginning January 1, 2016 , we elected to adopt its provisions effective April 1, 2015, and have applied its provisions to each prior period presented for comparative purposes. This new guidance did not have a material impact on our unaudited condensed consolidated financial statements. See Note 7 for additional information on the impact of adopting this accounting standard. Other newly issued accounting standards 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. 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 yet determined the impact of this new guidance, nor have we selected a transition method. In February 2015, the FASB issued updated authoritative guidance related to the consolidation of other legal entities into our financial statements. The amendments modify aspects of the consolidation determination that could potentially impact us, including the analysis of limited partnerships and similar legal entities, fee arrangements, and related party relationships . The guidance is effective for us beginning January 1, 2016, and e arly adoption is permitted. We may elect to apply the new guidance either retrospectively to each prior period presented or via a cumulative effect adjustment upon the date of initial application. We have not yet determined the impact of this new guidance, nor have we selected a transition method. In April 2015, the FASB issued authoritative guidance related to the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense of the period incurred. The new guidance may be applied either prospectively or retrospectively, is effective for us beginning January 1, 2016, and early adoption is permitted. We are currently evaluating our software arrangements in light of the new guidance. In May 2015, the FASB issued updated authoritative guidance to reduce the diversity in fair value measurements hierarchy disclosures. This amendment removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share. This guidance is effective for us beginning January 1, 2016, and early adoption is permitted. We have determined that this new guidance will not have a material impact on our unaudited condensed 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.

Note 2 - Significant Accounti24

Note 2 - Significant Accounting Policies and Methods of Application (Tables)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Schedule of Inventory, Lower of Cost or Market Adjustment [Table Text Block]	Three months ended June 30, Six months ended June 30, In millions 201 5 201 4 201 5 201 4 LOCOM adjustments $ - $ 4 $ 10 $ 6
Schedule of Goodwill [Table Text Block]	In millions Distribution o perations Retail o perations Midstream o perations Consolidated Goodwill $ 1,640 $ 173 $ 14 $ 1,827
Schedule of Weighted Average Number of Shares [Table Text Block]	Three months ended June 30, Six months ended June 30, In millions (except per share amounts) 201 5 201 4 201 5 201 4 Income from continuing operations attributable to AGL Resources Inc. $ 42 $ 57 $ 235 $ 391 Income (loss) from discontinued operations, net of tax - 1 - (49 ) Net income attributable to AGL Resources Inc. $ 42 $ 58 $ 235 $ 342 Denominator: Basic weighted average number of shares outstanding (1) 119.5 118.8 119.4 118.7 Effect of dilutive securities 0.3 0.4 0.3 0.4 Diluted weighted average number of shares outstanding (2) 119.8 119.2 119.7 119.1 Basic earnings (loss) per share Continuing operations $ 0.35 $ 0.48 $ 1.97 $ 3.30 Discontinued operations - 0.01 - (0.42 ) Basic earnings per share attributable to AGL Resources Inc. $ 0.35 $ 0.49 $ 1.97 $ 2.88 Diluted earnings (loss) per share Continuing operations $ 0.35 $ 0.48 $ 1.96 $ 3.29 Discontinued operations - 0.01 - (0.42 ) Diluted earnings per share attributable to AGL Resources Inc. $ 0.35 $ 0.49 $ 1.96 $ 2.87

Note 3 - Regulated Operations (

Note 3 - Regulated Operations (Tables)	6 Months Ended
	Jun. 30, 2015
Note 3 - Regulated Operations (Tables) [Line Items]
Schedule of Regulatory Assets [Table Text Block]	In millions June 30 , 201 5 December 31, 2014 June 30 , 2014 Regulatory assets Recoverable ERC $ 27 $ 49 $ 33 Recoverable pension and retiree welfare benefit costs 11 12 9 Deferred natural gas costs - 3 79 Other 10 19 44 R egulatory assets – current 48 83 165 Recoverable ERC 350 329 458 Recoverable pension and retiree welfare benefit costs 105 110 94 Recoverable regulatory infrastructure program costs 77 69 65 Long-term debt fair value adjustment 70 74 78 Other 40 49 31 R egulatory assets – long-term 642 631 726 Total regulatory assets $ 690 $ 714 $ 891 Regulatory liabilities Accrued natural gas costs $ 67 $ 27 $ 41 Bad debt over collection 27 33 39 Accumulated removal costs 25 25 27 Deferred seasonal rates 8 - 8 Other 27 27 34 R egulatory liabilities – current 154 112 149 Accumulated removal costs 1,544 1,520 1,478 Regulatory income tax liability 27 34 27 Unamortized investment tax credit 21 22 24 Bad debt over collection 18 12 9 Other 12 13 27 R egulatory liabilities – long-term 1,622 1,601 1,565 Total regulatory liabilities $ 1,776 $ 1,713 $ 1,714
Environmental Exit Costs by Cost [Table Text Block]	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 $205 - $463 $ 37 $ 242 $ 37 As incurred New Jersey 6 105 - 177 13 118 9 7 Georgia and Florida 13 34 - 58 25 59 29 5 North Carolina (2) 1 n/a 10 10 8 No recovery Total 46 $344 - $698 $ 85 $ 429 $ 83
Regulatory Asset Off Balance Sheet [Member]
Note 3 - Regulated Operations (Tables) [Line Items]
Schedule of Regulatory Assets [Table Text Block]	In millions Atlanta Gas Light Virginia Natural Gas Elizabethtown Gas Nicor Gas Total June 30, 2015 $ 126 $ 11 $ 3 $ 1 $ 141 December 31, 2014 113 12 2 - 127 June 30, 2014 96 12 1 - 109

Note 4 - Fair Value Measureme26

Note 4 - Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
Note 4 - Fair Value Measurements (Tables) [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	In millions June 30 , 201 5 December 31, 2014 June 30 , 2014 Long-term debt carrying amount $ 3,577 $ 3,781 $ 3,785 Long-term debt fair value (1) 3,857 4,231 4,191
Natural Gas and Interest Rate Derivatives [Member]
Note 4 - Fair Value Measurements (Tables) [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	June 30 , 201 5 December 31, 2014 June 30 , 2014 In millions Assets (1) Liabilities Assets (1) Liabilities Assets (1) Liabilities Quoted prices in active markets (Level 1) $ 3 $ (53 ) $ 58 $ (80 ) $ 8 $ (38 ) Significant other observable inputs (Level 2) 128 (45 ) 174 (94 ) 57 (60 ) Netting of cash collateral 64 53 52 81 46 36 Total carrying value (2) $ 195 $ (45 ) $ 284 $ (93 ) $ 111 $ (62 )

Note 5 - Derivative Instrumen27

Note 5 - Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	In Bcf June 30 , 201 5 (2) December 31, 2014 June 30 , 2014 Cash flow hedges 6 9 6 Not designated as hedges 24 75 140 Total volumes 30 84 146 Short position – cash flow hedges (8 ) (7 ) (4 ) Short position – not designated as hedges (2,930 ) (2,825 ) (2,524 ) Long position – cash flow hedges 14 16 10 Long position – not designated as hedges 2,954 2,900 2,664 Net long position 30 84 146
Loss Recognized In Income [Table Text Block]	Three months ended June 30 , Six months ended June 30 , In millions 201 5 201 4 201 5 201 4 Nicor Gas $ (18 ) $ 10 $ (21 ) $ 12 Elizabethtown Gas (4 ) 2 (8 ) 5
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	June 30 , 201 5 December 31, 2014 June 30 , 2014 In millions Classification Assets Liabilities Assets Liabilities Assets Liabilities D esignated as cash flow or fair value hedges Natural gas contracts Current $ - $ (4 ) $ 6 $ (11 ) $ 2 $ (1 ) Natural gas contracts Long-term - (1 ) - (1 ) - - Interest rate swap agreements Current 24 - - - - - Interest rate swap agreements Long-term 23 - - - - - Total designated as cash flow or fair value hedges $ 47 $ (5 ) $ 6 $ (12 ) $ 2 $ (1 ) Not designated as hedges Natural gas contracts Current $ 473 $ (481 ) $ 1,061 $ (1,020 ) $ 702 $ (721 ) Natural gas contracts Long-term 92 (91 ) 145 (119 ) 77 (89 ) Total not designated as hedges $ 565 $ (572 ) $ 1,206 $ (1,139 ) $ 779 $ (810 ) Gross amounts of recognized assets and liabilities (1) (2) 612 (577 ) 1,212 (1,151 ) 781 (811 ) Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2) (415 ) 532 (925 ) 1,058 (667 ) 749 Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3) $ 197 $ (45 ) $ 287 $ (93 ) $ 114 $ (62 )
Schedule of Derivative Instruments [Table Text Block]	Three months ended June 30, Six months ended June 30, In millions 201 5 201 4 201 5 201 4 Designated as cash flow or fair value hedges Natural gas contracts - net gain (loss) reclassified from OCI into cost of goods sold $ (3 ) $ 2 $ (4 ) $ 5 Natural gas contracts - net gain (loss) reclassified from OCI into operation and maintenance expense (1 ) - (1 ) 1 Interest rate swaps - net loss reclassified from OCI into interest expense - - 1 - Income tax benefit - (1 ) - (1 ) Total designated as cash flow or fair value hedges, n et of tax (4 ) 1 (4 ) 5 Not designated as hedges (1) Natural gas contracts - net gain (loss) recorded in operating revenues 3 30 (21 ) - Natural gas contracts - net gain (loss) recorded in cost of goods sold (2) 1 (1 ) (1 ) 1 Income tax benefit (1 ) (11 ) 9 - Total not designated as hedges, n et of tax 3 18 (13 ) 1 Total gains (losses) on derivative instruments , net of tax $ (1 ) $ 19 $ (17 ) $ 6

Note 6 - Employee Benefit Pla28

Note 6 - Employee Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Schedule of Net Benefit Costs [Table Text Block]	Three months ended June 30 , Six months ended June 30 , In millions 201 5 201 4 201 5 2014 Service cost $ 7 $ 6 $ 14 $ 12 Interest cost 12 11 23 23 Expected return on plan assets (17 ) (16 ) (33 ) (32 ) Net amortization of prior service cost (credit) - (1 ) (1 ) (1 ) Recognized actuarial loss 7 6 15 11 Net periodic pension benefit cost $ 9 $ 6 $ 18 $ 13 Three months ended June 30, Six months ended June 30, In millions 201 5 201 4 201 5 201 4 Service cost $ - $ - $ 1 $ 1 Interest cost 3 3 6 7 Expected return on plan assets (2 ) (1 ) (4 ) (3 ) Net amortization of prior service (credit) cost (1 ) - (1 ) (1 ) Recognized actuarial loss 2 2 3 3 Net periodic welfare benefit cost $ 2 $ 4 $ 5 $ 7

Note 7 - Debt and Credit Faci29

Note 7 - Debt and Credit Facilities (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Schedule of Debt [Table Text Block]	June 30 , 201 5 June 30 , 2014 Dollars in millions Year(s) due Weighted average interest rate (1) Outstanding December 31, 2014 Weighted average interest rate (1) Outstanding Short-term debt Commercial paper - AGL Capital (2) 2015 0.5 % $ 269 $ 590 0.3 % $ 236 Commercial paper - Nicor Gas (2) 2015 0.4 190 585 0.2 212 Total short-term debt 0.4 % $ 459 $ 1,175 0.3 % $ 448 C urrent portion of long-term debt 2016 4.6 % $ 125 $ 200 5.0 % $ 200 Long-term debt - excluding current portion Senior notes 2016-2043 5.0 % $ 2,625 $ 2,625 5.0 % $ 2,625 First mortgage bonds 2019-2038 5.9 375 500 5.6 500 Gas facility revenue bonds 2022-2033 0.9 200 200 0.9 200 Medium-term notes 2017-2027 7.8 181 181 7.8 181 Total principal long-term debt 4.9 3,381 3,506 4.9 3,506 Fair value adjustment of long-term debt (3) n/a n/a 74 80 n/a 85 Unamortized debt premium and issuance costs, net n/a n/a (3 ) (5 ) n/a (6 ) Total non-principal long-term debt n/a 71 75 n/a 79 Total long-term debt – excluding current portion $ 3,452 $ 3,581 $ 3,585 Total debt $ 4,036 $ 4,956 $ 4,233
Schedule of Capitalization [Table Text Block]	AGL Resources Nicor Gas June 30, Dec. 31, June 30, June 30, Dec. 31, June 30, 201 5 2014 2014 201 5 2014 2014 Debt covenants (1) 49% 55% 51% 49% 62% 52%

Note 8 - Equity (Tables)

Note 8 - Equity (Tables)	6 Months Ended
	Jun. 30, 2015
Stockholders' Equity Note [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	2015 2014 In millions Cash flow hedges Retirement benefit plans Total Cash flow hedges Retirement benefit plans Total For the three months end ed June 30 As of beginning of period $ (4 ) $ (197 ) $ (201 ) $ 1 $ (136 ) $ (135 ) OCI, before reclassifications 25 - 25 - - - Amounts reclassified from accumulated OCI 3 4 7 (1 ) 3 2 Net current-period other comprehensive income (loss) 28 4 32 (1 ) 3 2 As of end of period $ 24 $ (193 ) $ (169 ) $ - $ (133 ) $ (133 ) For the six months end ed June 30 As of beginning of period $ (6 ) $ (200 ) $ (206 ) $ 1 $ (137 ) $ (136 ) OCI, before reclassifications 27 - 27 4 - 4 Amounts reclassified from accumulated OCI 3 7 10 (5 ) 4 (1 ) Net current-period other comprehensive income (loss) 30 7 37 (1 ) 4 3 As of end of period $ 24 $ (193 ) $ (169 ) $ - $ (133 ) $ (133 )
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	Three months ended June 30, Six months ended June 30, In millions (1) 2015 2014 2015 2014 Cash flow hedges Cost of goods sold (natural gas contracts) $ (3 ) $ 2 $ (4 ) $ 5 Operation and maintenance expense (natural gas contracts) (1 ) - (1 ) 1 Interest expense (interest rate contracts) - - 1 - Total before income tax (4 ) 2 (4 ) 6 Income tax benefit - (1 ) - (1 ) Cash flow hedges, net of income tax (4 ) 1 (4 ) 5 Less noncontrolling Interest (1 ) - (1 ) - Total cash flow hedges, net of income tax (3 ) 1 (3 ) 5 Retirement benefit plan s Operation and maintenance expense (actuarial losses) (2) (6 ) (6 ) (11 ) (8 ) Operation and maintenance expense (prior service credits) (2) - 1 - 1 Total before income tax (6 ) (5 ) (11 ) (7 ) Income tax benefit 2 2 4 3 Total retirement benefit plans (4 ) (3 ) (7 ) (4 ) Total reclassification for the period $ (7 ) $ (2 ) $ (10 ) $ 1

Note 9 - Non-Wholly Owned Ent31

Note 9 - Non-Wholly Owned Entities (Tables)	6 Months Ended
	Jun. 30, 2015
Noncontrolling Interest [Abstract]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Table Text Block]	June 30 , 201 5 December 31, 2014 June 30 , 2014 In millions Consolidated SouthStar % Consolidated SouthStar % Consolidated SouthStar % Current assets $ 1,572 $ 192 12 % $ 2,886 $ 236 8 % $ 2,380 $ 195 8 % Goodwill and other intangible assets 1,939 117 6 1,952 125 6 1,962 129 7 Long-term assets and other deferred debits 10,324 17 - 10,050 17 - 9,817 17 - Total assets $ 13,835 $ 326 2 % $ 14,888 $ 378 3 % $ 14,159 $ 341 2 % Current liabilities $ 2,047 $ 40 2 % $ 3,219 $ 71 2 % $ 2,595 $ 55 2 % Long-term liabilities and other deferred credits 7,799 1 - 7,841 - - 7,704 - - Total Liabilities 9,846 41 - 11,060 71 1 10,299 55 1 Equity 3,989 285 7 3,828 307 8 3,860 286 7 Total liabilities and equity $ 13,835 $ 326 2 % $ 14,888 $ 378 3 % $ 14,159 $ 341 2 %
Schedule of Variable Interest Entities [Table Text Block]	Three months ended June 30, Six months ended June 30, In millions 201 5 2014 201 5 2014 Operating revenues $ 122 $ 145 $ 433 $ 519 Operating expenses Cost of goods sold 89 111 292 381 Operation and maintenance 18 20 41 43 Depreciation and amortization 3 2 5 5 Taxes other than income taxes - 1 1 1 Total operating expenses 110 134 339 430 Operating income $ 12 $ 11 $ 94 $ 89
Equity Method Investments [Table Text Block]	June 30, December 31, June 30, In millions 201 5 2014 2014 Triton $ 53 $ 62 $ 65 Horizon Pipeline 14 14 15 Other (1) 8 4 1 Total $ 75 $ 80 $ 81
Schedule of Other Nonoperating Income, by Component [Table Text Block]	Three months ended June 30, Six months ended June 30, In millions 201 5 201 4 201 5 201 4 Triton $ 1 $ 1 $ 1 $ 3 Horizon Pipeline - - 1 1

Note 10 - Commitments, Guaran32

Note 10 - Commitments, Guarantees and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block]	2020 & In millions Total 2015 2016 2017 2018 2019 thereafter Recorded contractual obligations: Long-term debt $ 3,506 $ - $ 545 $ 22 $ 155 $ 350 $ 2,434 Short-term debt 459 459 - - - - - Environmental remediation liabilities (1) 429 47 86 80 65 44 107 Total $ 4,394 $ 506 $ 631 $ 102 $ 220 $ 394 $ 2,541 Unrecorded contractual obligations and commitments : Pipeline charges, storage capacity and gas supply (3) $ 5,341 $ 527 $ 706 $ 491 $ 369 $ 343 $ 2,905 Interest charges (4) 2,670 87 171 147 146 141 1,978 Operating leases (5) 172 13 26 28 21 16 68 Asset management agreements (6) 33 5 11 9 6 2 - Standby letters of credit, performance/surety bonds (7) 48 37 11 - - - - Other 8 3 3 1 1 - - Total $ 8,272 $ 672 $ 928 $ 676 $ 543 $ 502 $ 4,951

Note 11 - Segment Information (

Note 11 - Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Operating revenues from external parties $ 506 $ 153 $ 4 $ 11 $ 3 $ (3 ) $ 674 Intercompany revenues 40 - - - - (40 ) - Total operating revenues 546 153 4 11 3 (43 ) 674 Operating expenses Cost of goods sold 166 95 - 2 - (41 ) 222 Operation and maintenance 160 34 11 6 - (2 ) 209 Depreciation and amortization 83 6 1 4 4 - 98 Taxes other than income taxes 34 1 - 1 2 - 38 Total operating expenses 443 136 12 13 6 (43 ) 567 Operating income (loss) 103 17 (8 ) (2 ) (3 ) - 107 Other income 3 - - - 1 - 4 EBIT $ 106 $ 17 $ (8 ) $ (2 ) $ (2 ) - $ 111 Capital expenditures $ 248 $ 2 $ - $ 7 $ 7 $ - $ 264 In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Operating revenues from external parties $ 656 $ 176 $ 47 $ 17 $ 1 $ (8 ) $ 889 Intercompany revenues 43 1 - - - (44 ) - Total operating revenues 699 177 47 17 1 (52 ) 889 Operating expenses Cost of goods sold 315 119 7 11 - (50 ) 402 Operation and maintenance 159 34 13 7 - (2 ) 211 Depreciation and amortization 78 6 1 4 6 - 95 Taxes other than income taxes 40 1 - 2 (1 ) - 42 Total operating expenses 592 160 21 24 5 (52 ) 750 Operating income (loss) 107 17 26 (7 ) (4 ) - 139 Other income (expense) 3 - (2 ) - 1 - 2 EBIT $ 110 $ 17 $ 24 $ (7 ) $ (3 ) $ - $ 141 Capital expenditures $ 158 $ 3 $ - $ 5 $ 5 $ - $ 171 In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Operating revenues from external parties $ 1,791 $ 494 $ 94 $ 30 $ 9 $ (23 ) $ 2,395 Intercompany revenues 96 - - - - (96 ) - Total operating revenues 1,887 494 94 30 9 (119 ) 2,395 Operating expenses Cost of goods sold 942 305 9 12 5 (116 ) 1,157 Operation and maintenance 345 71 35 12 (2 ) (3 ) 458 Depreciation and amortization 165 12 1 9 8 - 195 Taxes other than income taxes 105 2 1 2 4 - 114 Total operating expenses 1,557 390 46 35 15 (119 ) 1,924 Operating income (loss) 330 104 48 (5 ) (6 ) - 471 Other income 4 - - 1 2 - 7 EBIT $ 334 $ 104 $ 48 $ (4 ) $ (4 ) - $ 478 Identifiable and total assets (2) $ 11,796 $ 636 $ 806 $ 686 $ 9,190 $ (9,279 ) $ 13,835 Capital expenditures $ 418 $ 4 $ 1 $ 10 $ 19 $ - $ 452 In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Operating revenues from external parties $ 2,382 $ 582 $ 378 $ 61 $ 4 $ (56 ) $ 3,351 Intercompany revenues 118 1 - - - (119 ) - Total operating revenues 2,500 583 378 61 4 (175 ) 3,351 Operating expenses Cost of goods sold 1,517 399 10 47 - (171 ) 1,802 Operation and maintenance 370 71 49 13 1 (4 ) 500 Depreciation and amortization 156 14 1 9 8 - 188 Taxes other than income taxes 122 2 1 3 2 - 130 Total operating expenses 2,165 486 61 72 11 (175 ) 2,620 Operating income (loss) 335 97 317 (11 ) (7 ) - 731 Other income (expense) 4 - (2 ) 1 2 - 5 EBIT $ 339 $ 97 $ 315 $ (10 ) $ (5 ) $ - $ 736 Identifiable and total assets (2) $ 11,511 $ 671 $ 1,207 $ 699 $ 9,482 $ (9,668 ) $ 13,902 Capital expenditures $ 308 $ 6 $ 1 $ 5 $ 12 $ - $ 332 In millions Distribution operations Retail operations Wholesale services Midstream operations Other segments Intercompany eliminations Consolidated Identifiable and total assets $ 12,037 $ 670 $ 1,402 $ 694 $ 9,706 $ (9,621 ) $ 14,888
Reconciliation of Revenue from Segments to Consolidated [Table Text Block]	In millions Third party gross revenues Intercompany revenues Total gross revenues Less gross gas costs Operating revenues Three months ended June 30, 2015 $ 1,291 $ 89 $ 1,380 $ 1,376 $ 4 Three months ended June 30, 2014 2,379 160 2,539 2,492 47 Six months ended June 30, 2015 3,436 239 3,675 3,581 94 Six months ended June 30, 2014 6,428 458 6,886 6,508 378

Note 12 - Discontinued Operat34

Note 12 - Discontinued Operations (Tables)	6 Months Ended
	Jun. 30, 2015
Balance Sheet [Member]
Note 12 - Discontinued Operations (Tables) [Line Items]
Disposal Groups, Including Discontinued Operations [Table Text Block]	In millions June 30, 2014 Current assets Cash and cash equivalents $ 15 Short-term investments 3 Receivables 35 Inventories 9 Other 2 Total current assets 64 Long-term assets and other deferred debits Property, plant and equipment, net 127 Goodwill 42 Intangible assets 19 Other 5 Total long-term assets and other deferred debits 193 Total assets held for sale $ 257 Current liabilities Other accounts payable – trade $ 9 Accrued expenses 7 Other 23 Total liabilities held for sale $ 39
Income Statement [Member]
Note 12 - Discontinued Operations (Tables) [Line Items]
Disposal Groups, Including Discontinued Operations [Table Text Block]	Three months ended Six months ended In millions June 30, 2014 June 30, 2014 Operating revenues $ 92 $ 181 Operating expenses Cost of goods sold 57 111 Operation and maintenance 27 55 Depreciation and amortization - 5 Taxes other than income taxes 3 4 Loss on sale and goodwill impairment 4 23 Total operating expenses 91 198 Operating income (loss) 1 (17 ) Income (loss) before income taxes 1 (17 ) Income tax expense - (32 ) Income (loss) from discontinued operations, net of tax $ 1 $ (49 )

Note 2 - Significant Accounti35

Note 2 - Significant Accounting Policies and Methods of Application (Details) - USD ($) $ in Millions	Jun. 30, 2015	Jun. 30, 2014
Tropical Shipping [Member]
Note 2 - Significant Accounting Policies and Methods of Application (Details) [Line Items]
Investments and Cash		$ 15
Inaccessible [Member]
Note 2 - Significant Accounting Policies and Methods of Application (Details) [Line Items]
Inventory, Gross	$ 12

Note 2 - Significant Accounti36

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Lower of Cost or Market Adjustments - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Lower of Cost or Market Adjustments [Abstract]
LOCOM adjustments	$ 4	$ 10	$ 6

Note 2 - Significant Accounti37

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Changes in Amount of Goodwill - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Goodwill [Line Items]
Goodwill	$ 1,827	$ 1,827	$ 1,827
Distribution Operations [Member]
Goodwill [Line Items]
Goodwill	1,640
Retail Operations [Member]
Goodwill [Line Items]
Goodwill	173
Midstream Operations [Member]
Goodwill [Line Items]
Goodwill	$ 14

Note 2 - Significant Accounti38

Note 2 - Significant Accounting Policies and Methods of Application (Details) - Potentially Dilutive Common Share Calculation - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Potentially Dilutive Common Share Calculation [Abstract]
Income from continuing operations attributable to AGL Resources Inc. (in Dollars)		$ 42	$ 57	$ 235	$ 391
Income (loss) from discontinued operations, net of tax (in Dollars)			1		(49)
Net income attributable to AGL Resources Inc. (in Dollars)		$ 42	$ 58	$ 235	$ 342
Denominator:
Basic weighted average number of shares outstanding (1) (in Shares)	[1]	119.5	118.8	119.4	118.7
Effect of dilutive securities (in Shares)		0.3	0.4	0.3	0.4
Diluted weighted average number of shares outstanding (2) (in Shares)	[2]	119.8	119.2	119.7	119.1
Basic earnings (loss) per share
Continuing operations		$ 0.35	$ 0.48	$ 1.97	$ 3.30
Discontinued operations			0.01		(0.42)
Basic earnings per share attributable to AGL Resources Inc.		0.35	0.49	1.97	2.88
Diluted earnings (loss) per share
Continuing operations		0.35	0.48	1.96	3.29
Discontinued operations			0.01		(0.42)
Diluted earnings per share attributable to AGL Resources Inc.		$ 0.35	$ 0.49	$ 1.96	$ 2.87
[1]	Daily weighted average shares outstanding.
[2]	All outstanding stock options whose effect would have been anti-dilutive were excluded from the computation of diluted earnings per common share.

Note 3 - Regulated Operations39

Note 3 - Regulated Operations (Details) $ in Millions	1 Months Ended	3 Months Ended
	Jul. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 30, 2014USD ($)
Note 3 - Regulated Operations (Details) [Line Items]
Regulatory Assets, Current (in Dollars)			$ 48	$ 83	$ 165
Number of Former Operating Sites			46
Increase (Decrease) in Insurance Settlements Receivable (in Dollars)	$ 77
Insurance Settlements Receivable, Number of Installments	2
Proceeds from Insurance Settlement, Operating Activities (in Dollars)		$ 45
Insurance Settlements Receivable, Current (in Dollars)			$ 32
Recoverable ERC Assets [Member]
Note 3 - Regulated Operations (Details) [Line Items]
Regulatory Assets, Current (in Dollars)			$ 27
Nicor Gas [Member]
Note 3 - Regulated Operations (Details) [Line Items]
Number of Former Operating Sites			26
Number of Sites with Completed Cleanups			2
Number of Sites with Cleanup Responsibility			23
Cleanup Costs Allocated Percentage			52.00%

Note 3 - Regulated Operations40

Note 3 - Regulated Operations (Details) - Summary of Regulatory Assets and Liabilities - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Regulatory assets
Regulatory assets - current	$ 48	$ 83	$ 165
Regulatory assets - long-term	642	631	726
Total regulatory assets	690	714	891
Regulatory liabilities
Regulatory liabilities - current	154	112	149
Regulatory liabilities - long-term	1,622	1,601	1,565
Total regulatory liabilities	1,776	1,713	1,714
Recoverable Environmental Remediation Costs [Member]
Regulatory assets
Regulatory assets - current	27	49	33
Regulatory assets - long-term	350	329	458
Recoverable Pension and Other Retirement Benefit Costs [Member]
Regulatory assets
Regulatory assets - current	11	12	9
Regulatory assets - long-term	105	110	94
Deferred Natural Gas Costs [Member]
Regulatory assets
Regulatory assets - current		3	79
Other Regulatory Assets [Member]
Regulatory assets
Regulatory assets - current	10	19	44
Regulatory assets - long-term	40	49	31
Recoverable Regulatory Infrastructure Program Costs [Member]
Regulatory assets
Regulatory assets - long-term	77	69	65
Long-term Debt Fair Value Adjustment [Member]
Regulatory assets
Regulatory assets - long-term	70	74	78
Accrued natural gas costs [Member]
Regulatory liabilities
Regulatory liabilities - current	67	27	41
Bad debt rider [Member]
Regulatory liabilities
Regulatory liabilities - current	27	33	39
Regulatory liabilities - long-term	18	12	9
Accumulated removal costs [Member]
Regulatory liabilities
Regulatory liabilities - current	25	25	27
Regulatory liabilities - long-term	1,544	1,520	1,478
Deferred Seasonal Rates [Member]
Regulatory liabilities
Regulatory liabilities - current	8		8
Other Regulatory Liabilities [Member]
Regulatory liabilities
Regulatory liabilities - current	27	27	34
Regulatory liabilities - long-term	12	13	27
Regulatory Income Tax Liability [Member]
Regulatory liabilities
Regulatory liabilities - long-term	27	34	27
Unamortized investment tax credit [Member]
Regulatory liabilities
Regulatory liabilities - long-term	$ 21	$ 22	$ 24

Note 3 - Regulated Operations41

Note 3 - Regulated Operations (Details) - Estimated Recognition of Rate Making Assets - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Regulatory Assets [Line Items]
Regulatory Asset	$ 690	$ 714	$ 891
Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	141	127	109
Atlanta Gas Light [Member] | Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	126	113	96
Virginia Natural Gas [Member] | Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	11	12	12
Elizabethtown Gas [Member] | Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	3	$ 2	$ 1
Nicor Gas [Member] | Regulatory Asset Off Balance Sheet [Member]
Regulatory Assets [Line Items]
Regulatory Asset	$ 1

Note 3 - Regulated Operations42

Note 3 - Regulated Operations (Details) - Costs Related to Remediation of Former Operating Sites $ in Millions		6 Months Ended
		Jun. 30, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 30, 2014USD ($)
Environmental Exit Cost [Line Items]
# of sites		46
Probabilistic model cost estimates, low estimate		$ 344
Probabilistic model cost estimates, high estimate		698
Engineering estimates		85
Amount recorded		429
Expected costs over next 12 months		$ 83	$ 87	$ 90
Illinois Environmental [Member]
Environmental Exit Cost [Line Items]
# of sites	[1]	26
Probabilistic model cost estimates, low estimate	[1]	$ 205
Probabilistic model cost estimates, high estimate	[1]	463
Engineering estimates	[1]	37
Amount recorded	[1]	242
Expected costs over next 12 months	[1]	$ 37
Cost recovery period	[1]
New Jersey Environmental [Member]
Environmental Exit Cost [Line Items]
# of sites		6
Probabilistic model cost estimates, low estimate		$ 105
Probabilistic model cost estimates, high estimate		177
Engineering estimates		13
Amount recorded		118
Expected costs over next 12 months		$ 9
Cost recovery period		7 years
Georgia And Florida [Member]
Environmental Exit Cost [Line Items]
# of sites		13
Probabilistic model cost estimates, low estimate		$ 34
Probabilistic model cost estimates, high estimate		58
Engineering estimates		25
Amount recorded		59
Expected costs over next 12 months		$ 29
Cost recovery period		5 years
North Carolina Environmental [Member]
Environmental Exit Cost [Line Items]
# of sites	[2]	1
Engineering estimates	[2]	$ 10
Amount recorded	[2]	10
Expected costs over next 12 months	[2]	$ 8
Cost recovery period	[2]
[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 environmentalcondition 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.

Note 4 - Fair Value Measureme43

Note 4 - Fair Value Measurements (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Fair Value Disclosures [Abstract]
Weather Derivative Premium	$ 2	$ 3	$ 3

Note 4 - Fair Value Measureme44

Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities - Natural Gas Derivatives [Member] - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities [Line Items]
Derivative Assets	[1],[2]	$ 195	$ 284	$ 111
Derivative Liabilities	[2]	(45)	(93)	(62)
Netting of cash collateral	[1]	64	52	46
Netting of cash collateral		53	81	36
Fair Value, Inputs, Level 1 [Member]
Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities [Line Items]
Derivative Assets	[1]	3	58	8
Derivative Liabilities		(53)	(80)	(38)
Fair Value, Inputs, Level 2 [Member]
Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities [Line Items]
Derivative Assets	[1]	128	174	57
Derivative Liabilities		$ (45)	$ (94)	$ (60)
[1]	Balances of $2 million at June 30, 2015, $3 million at December 31, 2014 and $3 million at June 30, 2014, associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.
[2]	There were no significant unobservable inputs (Level 3) or significant transfers between Level 1, Level 2 or Level 3 for any of the dates presented.

Note 4 - Fair Value Measureme45

Note 4 - Fair Value Measurements (Details) - Amortized Cost and Fair Value of Long-Term Debt - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Note 4 - Fair Value Measurements (Details) - Amortized Cost and Fair Value of Long-Term Debt [Line Items]
Long-term debt carrying amount		$ 3,577	$ 3,781	$ 3,785
Fair Value, Inputs, Level 2 [Member]
Note 4 - Fair Value Measurements (Details) - Amortized Cost and Fair Value of Long-Term Debt [Line Items]
Long-term debt fair value (1)	[1]	$ 3,857	$ 4,231	$ 4,191
[1]	Fair value determined using Level 2 inputs.

Note 5 - Derivative Instrumen46

Note 5 - Derivative Instruments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 45	$ 62	$ 45	$ 62	$ 93
Increase (Decrease) in Risk Management Assets and Liabilities			(42)	13
Collateral Already Posted, Aggregate Fair Value	117	82	117	82	$ 133
Price Risk Cash Flow Hedge Unrealized Gain (Loss) to be Reclassified During Next 12 Months	4		$ 4
Expiring in Two Years or Less [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Term of Contract			2 years
Expiring in Two to Five Years [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Percent of Derivative Contracts			4.00%
Weather Derivatives [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1	$ 1	$ (1)	$ 6
Natural Gas [Member] | Expiring in Two Years or Less [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Percent of Derivative Contracts			96.00%
Maximum [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Collateral, Obligation to Return Cash	$ 7		$ 7
Maximum [Member] | Natural Gas [Member] | Expiring in Two to Five Years [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Term of Contract			5 years
Minimum [Member] | Natural Gas [Member] | Expiring in Two to Five Years [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Term of Contract			2 years

Note 5 - Derivative Instrumen47

Note 5 - Derivative Instruments (Details) - Net Long Natural Gas Contracts - ft³ ft³ in Billions		Jun. 30, 2015	[1]	Dec. 31, 2014	Jun. 30, 2014
Note 5 - Derivative Instruments (Details) - Net Long Natural Gas Contracts [Line Items]
Cash flow hedges	[2]	6		9	6
Not designated as hedges	[2]	24		75	140
Total volumes	[2]	30		84	146
Net long position	[2]	30		84	146
Designated as Hedging Instrument [Member]
Note 5 - Derivative Instruments (Details) - Net Long Natural Gas Contracts [Line Items]
Short position	[2]	(8)		(7)	(4)
Long position	[2]	14		16	10
Not Designated as Hedging Instrument [Member]
Note 5 - Derivative Instruments (Details) - Net Long Natural Gas Contracts [Line Items]
Short position	[2]	(2,930)		(2,825)	(2,524)
Long position	[2]	2,954		2,900	2,664
[1]	Approximately 96% of these contracts have durations of two years or less and the remaining 4% expire between two and five years.
[2]	Volumes related to Nicor Gas exclude variable-priced contracts, which are carried at fair value, but whose fair values are not directly impacted by changesin commodity prices.

Note 5 - Derivative Instrumen48

Note 5 - Derivative Instruments (Details) - Gains and Losses on Derivative Instruments - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Nicor Gas [Member]
Note 5 - Derivative Instruments (Details) - Gains and Losses on Derivative Instruments [Line Items]
Realized losses related to hedging natural gas costs	$ (18)	$ 10	$ (21)	$ 12
Elizabethtown Gas [Member]
Note 5 - Derivative Instruments (Details) - Gains and Losses on Derivative Instruments [Line Items]
Realized losses related to hedging natural gas costs	$ (4)	$ 2	$ (8)	$ 5

Note 5 - Derivative Instrumen49

Note 5 - Derivative Instruments (Details) - Derivative Instruments on the Condensed Consolidated Statements of Financial Position - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Derivatives, Fair Value [Line Items]
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)		$ (45)	$ (93)	$ (62)
Long-Term Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Assets	[1],[2]	612	1,212	781
Liabilities	[1],[2]	(577)	(1,151)	(811)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)	[1]	(415)	(925)	(667)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)	[1]	532	1,058	749
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets		47	6	2
Liabilities		(5)	(12)	(1)
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)	[3]	197	287	114
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)	[3]	(45)	(93)	(62)
Designated as Hedging Instrument [Member] | Current Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Assets			6	2
Liabilities		(4)	(11)	(1)
Designated as Hedging Instrument [Member] | Long-Term Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Liabilities		(1)	(1)
Designated as Hedging Instrument [Member] | Current Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Assets		24
Designated as Hedging Instrument [Member] | Long-term Interest Rate Swap Agreements [Member]
Derivatives, Fair Value [Line Items]
Assets		23
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets		565	1,206	779
Liabilities		(572)	(1,139)	(810)
Not Designated as Hedging Instrument [Member] | Current Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Assets		473	1,061	702
Liabilities		(481)	(1,020)	(721)
Not Designated as Hedging Instrument [Member] | Long-Term Natural Gas Contracts [Member]
Derivatives, Fair Value [Line Items]
Assets		92	145	77
Liabilities		$ (91)	$ (119)	$ (89)
[1]	As required by the authoritative guidance related to derivatives and hedging, the gross amounts of recognized assets and liabilities do not include cash collateralheld on deposit in broker margin accounts of $117 million as of June 30, 2015, $133 million as of December 31, 2014, and $82 million as of June 30, 2014. Cashcollateral is included in the "Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position" line of this table.
[2]	The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Statements of Financial Position to the extent that we have netting arrangements with the counterparties.
[3]	As of June 30, 2015, December 31, 2014, and June 30, 2014, we held letters of credit from counterparties that under master netting arrangements would offset aninsignificant portion of these assets.

Note 5 - Derivative Instrumen50

Note 5 - Derivative Instruments (Details) - Derivative Instruments on the Consolidated Statements of Income - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Designated as cash flow or fair value hedges
Income tax benefit			$ (1)		$ (1)
Total designated as cash flow or fair value hedges, net of tax		$ (4)	1	$ (4)	5
Not designated as hedges (1)
Total gains (losses) on derivative instruments, net of tax		(1)	19	(17)	6
Cash Flow Hedging [Member]
Designated as cash flow or fair value hedges
Income tax benefit			(1)		(1)
Total designated as cash flow or fair value hedges, net of tax		(4)	1	(4)	$ 5
Fair Value Hedging [Member]
Not designated as hedges (1)
Income tax benefit	[1]	(1)	(11)	9
Total not designated as hedges, net of tax	[1]	3	18	(13)	$ 1
Cost of Sales [Member] | Cash Flow Hedging [Member]
Designated as cash flow or fair value hedges
Natural gas contracts - gain reclassified from OCI		(3)	2	(4)	5
Cost of Sales [Member] | Fair Value Hedging [Member]
Not designated as hedges (1)
Natural gas contracts - net value adjustments	[1],[2]	1	(1)	(1)	1
Operating Expense [Member] | Cash Flow Hedging [Member]
Designated as cash flow or fair value hedges
Natural gas contracts - gain reclassified from OCI		(1)		(1)	$ 1
Interest Expense [Member] | Cash Flow Hedging [Member]
Designated as cash flow or fair value hedges
Interest rate swaps - net loss reclassified from OCI into interest expense				1
Sales [Member] | Fair Value Hedging [Member]
Not designated as hedges (1)
Natural gas contracts - net value adjustments	[1]	$ 3	$ 30	$ (21)
[1]	Associated with the fair value of derivative instruments held at June 30, 2015 and 2014.
[2]	Excludes (gains) losses recorded in cost of goods sold associated with weather derivatives of $(1) million and $1 million for the three and six months ended June30, 2015 and $1 million and $6 million for the three and six months ended June 30, 2014.

Note 6 - Employee Benefit Pla51

Note 6 - Employee Benefit Plans (Details) - Components of Pension and Other Retirement Benefit Costs - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Pension Plan [Member]
Note 6 - Employee Benefit Plans (Details) - Components of Pension and Other Retirement Benefit Costs [Line Items]
Service cost	$ 7	$ 6	$ 14	$ 12
Interest cost	12	11	23	23
Expected return on plan assets	(17)	(16)	(33)	(32)
Net amortization of prior service cost (credit)		(1)	(1)	(1)
Recognized actuarial loss	7	6	15	11
Net periodic pension benefit cost	9	6	18	13
Other Postretirement Benefit Plan [Member]
Note 6 - Employee Benefit Plans (Details) - Components of Pension and Other Retirement Benefit Costs [Line Items]
Service cost			1	1
Interest cost	3	3	6	7
Expected return on plan assets	(2)	(1)	(4)	(3)
Net amortization of prior service cost (credit)	(1)		(1)	(1)
Recognized actuarial loss	2	2	3	3
Net periodic pension benefit cost	$ 2	$ 4	$ 5	$ 7

Note 7 - Debt and Credit Faci52

Note 7 - Debt and Credit Facilities (Details) $ in Millions		Jan. 23, 2015USD ($)	Jan. 15, 2015USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Proceeds from (Repayments of) Commercial Paper				$ (716)	$ (723)
Repayments of Senior Debt			$ 200	$ 200
AGL Capital [Member] | Commercial Paper [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Interest Rate, Effective Percentage				0.50%
Nicor Gas [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Ratio of Indebtedness to Net Capital	[1]			0.49	0.52	0.62
Nicor Gas [Member] | Commercial Paper [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Interest Rate, Effective Percentage				0.40%
Adjustments for New Accounting Principle, Early Adoption [Member] | Other Long-term Assets [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Prior Period Reclassification Adjustment				$ 19	$ 22	$ 21
Adjustments for New Accounting Principle, Early Adoption [Member] | Long-term Debt 1 [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Prior Period Reclassification Adjustment				$ 19	$ 22	$ 21
Interest Rate Swap [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Derivative, Notional Amount		$ 800
Minimum [Member] | Target ratio [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Ratio of Indebtedness to Net Capital				0.50
Minimum [Member] | Commercial Paper [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Term				1 day
Debt Instrument, Remaining Maturity Term				1 day
Minimum [Member] | Interest Rate Swap [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Derivative, Term of Contract		10 years
Maximum [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Ratio of Indebtedness to Net Capital				0.70
Maximum [Member] | Target ratio [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Ratio of Indebtedness to Net Capital				0.60
Maximum [Member] | Commercial Paper [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Term				58 days
Debt Instrument, Remaining Maturity Term				21 days
Maximum [Member] | Interest Rate Swap [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Derivative, Term of Contract		30 years
[1]	As defined in our credit facilities, includes standby letters of credit and performance/surety bonds and excludes accumulated OCI items related to non-cashpension adjustments, welfare benefits liability adjustments and accounting for cash flow hedges.

Note 7 - Debt and Credit Faci53

Note 7 - Debt and Credit Facilities (Details) - Debt Schedule - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Long-term debt - excluding current portion
Total long-term debt – excluding current portion		$ 3,452	$ 3,581	$ 3,585
Total debt		$ 4,036	4,956	$ 4,233
Current Portion Long-Term Debt [Member]
Short-term debt
Maturity Date		2,016
Weighted average interest rate	[1]	4.60%		5.00%
Outstanding		$ 125	200	$ 200
Long-term debt - excluding current portion
Maturity Date		2,016
Senior Notes [Member]
Long-term debt - excluding current portion
Weighted average interest rate	[1]	5.00%		5.00%
Outstanding		$ 2,625	2,625	$ 2,625
First Mortgage Bonds [Member]
Long-term debt - excluding current portion
Weighted average interest rate	[1]	5.90%		5.60%
Outstanding		$ 375	500	$ 500
Gas Facility Revenue Bonds [Member]
Long-term debt - excluding current portion
Weighted average interest rate	[1]	0.90%		0.90%
Outstanding		$ 200	200	$ 200
Medium-term Notes [Member]
Long-term debt - excluding current portion
Weighted average interest rate	[1]	7.80%		7.80%
Outstanding		$ 181	181	$ 181
Long-term Debt Principal [Member]
Long-term debt - excluding current portion
Weighted average interest rate	[1]	4.90%		4.90%
Outstanding		$ 3,381	3,506	$ 3,506
Long-term Debt Fair Value Adjustment [Member]
Short-term debt
Maturity Date		n/a
Long-term debt - excluding current portion
Maturity Date		n/a
Weighted average interest rate	[1],[2]
Outstanding	[2]	$ 74	80	$ 85
Unamortized Debt Premium Discount and Issuance Costs, Net [Member]
Short-term debt
Maturity Date		n/a
Long-term debt - excluding current portion
Maturity Date		n/a
Weighted average interest rate	[1]
Outstanding		$ (3)	(5)	$ (6)
Long-term Debt Non-principal [Member]
Long-term debt - excluding current portion
Weighted average interest rate	[1]
Outstanding		$ 71	75	$ 79
Commercial Paper [Member]
Short-term debt
Weighted average interest rate	[1]	0.40%		0.30%
Outstanding		$ 459	1,175	$ 448
Commercial Paper [Member] | AGL Capital [Member]
Short-term debt
Maturity Date		2,015
Weighted average interest rate	[1],[3]	0.50%		0.30%
Outstanding	[3]	$ 269	590	$ 236
Long-term debt - excluding current portion
Maturity Date		2,015
Commercial Paper [Member] | Nicor Gas [Member]
Short-term debt
Maturity Date		2,015
Weighted average interest rate	[1],[3]	0.40%		0.20%
Outstanding	[3]	$ 190	$ 585	$ 212
Long-term debt - excluding current portion
Maturity Date		2,015
Minimum [Member] | Senior Notes [Member]
Short-term debt
Maturity Date		2,016
Long-term debt - excluding current portion
Maturity Date		2,016
Minimum [Member] | First Mortgage Bonds [Member]
Short-term debt
Maturity Date		2,019
Long-term debt - excluding current portion
Maturity Date		2,019
Minimum [Member] | Gas Facility Revenue Bonds [Member]
Short-term debt
Maturity Date		2,022
Long-term debt - excluding current portion
Maturity Date		2,022
Minimum [Member] | Medium-term Notes [Member]
Short-term debt
Maturity Date		2,017
Long-term debt - excluding current portion
Maturity Date		2,017
Maximum [Member] | Senior Notes [Member]
Short-term debt
Maturity Date		2,043
Long-term debt - excluding current portion
Maturity Date		2,043
Maximum [Member] | First Mortgage Bonds [Member]
Short-term debt
Maturity Date		2,038
Long-term debt - excluding current portion
Maturity Date		2,038
Maximum [Member] | Gas Facility Revenue Bonds [Member]
Short-term debt
Maturity Date		2,033
Long-term debt - excluding current portion
Maturity Date		2,033
Maximum [Member] | Medium-term Notes [Member]
Short-term debt
Maturity Date		2,027
Long-term debt - excluding current portion
Maturity Date		2,027
[1]	Interest rates are calculated based on the daily weighted average balance outstanding for the six months ended June 30.
[2]	See Note 4 for additional information on our fair value measurements.
[3]	As of June 30, 2015, the effective interest rates on our commercial paper borrowings were 0.5% for AGL Capital and 0.4% for Nicor Gas.

Note 7 - Debt and Credit Faci54

Note 7 - Debt and Credit Facilities (Details) - Debt-to-Capitalization Ratios		Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
AGL Resources Inc [Member]
Schedule of Capitalization [Line Items]
Debt covenants (1)	[1]	0.49	0.55	0.51
Nicor Gas [Member]
Schedule of Capitalization [Line Items]
Debt covenants (1)	[1]	0.49	0.62	0.52
[1]	As defined in our credit facilities, includes standby letters of credit and performance/surety bonds and excludes accumulated OCI items related to non-cashpension adjustments, welfare benefits liability adjustments and accounting for cash flow hedges.

Note 8 - Equity (Details) - Oth

Note 8 - Equity (Details) - Other Comprehensive Income (Loss) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
As of beginning of period				$ (206)
OCI, before reclassifications		$ 25		27	$ 4
Amounts reclassified from accumulated OCI		4	$ (1)	4	(5)
Net current-period other comprehensive income (loss)		29	(1)	31	(1)
Net current-period other comprehensive income (loss)		4	3	7	4
Net current-period other comprehensive income (loss)		33	2	38	3
As of end of period		(169)	(133)	(169)	(133)
Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
As of beginning of period	[1]	(4)	1	(6)	1
As of beginning of period	[1]	(197)	(136)	(200)	(137)
As of beginning of period	[1]	(201)	$ (135)	(206)	(136)
OCI, before reclassifications	[1]	$ 25		$ 27	$ 4
OCI, before reclassifications	[1]
OCI, before reclassifications	[1]	$ 25		$ 27	$ 4
Amounts reclassified from accumulated OCI	[1]	3	$ (1)	3	(5)
Amounts reclassified from accumulated OCI	[1]	4	3	7	4
Amounts reclassified from accumulated OCI	[1]	7	2	10	(1)
Net current-period other comprehensive income (loss)	[1]	28	(1)	30	(1)
Net current-period other comprehensive income (loss)	[1]	4	3	7	4
Net current-period other comprehensive income (loss)	[1]	32	$ 2	37	$ 3
As of end of period	[1]	24		24
As of end of period	[1]	(193)	$ (133)	(193)	$ (133)
As of end of period	[1]	$ (169)	$ (133)	$ (169)	$ (133)
[1]	All amounts are net of income taxes and noncontrolling interest. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

Note 8 - Equity (Details) - Rec

Note 8 - Equity (Details) - Reclassifications Out of Accumulated Other Comprehensive Loss - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operation and maintenance expense		$ (209)	$ (211)	$ (458)	$ (500)
Interest expense (interest rate contracts)		(42)	(45)	(86)	(91)
Total before income tax		69	96	392	645
Income tax benefit		(25)	(37)	(143)	(240)
Cash flow hedges, net of income tax		44	60	249	356
Less noncontrolling Interest		(2)	(2)	(14)	(14)
Net of tax		42	58	235	342
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net of tax	[1]	(7)	(2)	(10)	1
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before income tax	[1]	$ (4)	2	$ (4)	6
Income tax benefit	[1]		(1)		(1)
Cash flow hedges, net of income tax	[1]	$ (4)	1	$ (4)	5
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net of tax	[1]	(3)	$ 1	(3)	$ 5
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Less noncontrolling Interest	[1]	(1)		(1)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operation and maintenance expense	[1],[2]	$ (6)	$ (6)	$ (11)	$ (8)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Operation and maintenance expense	[1],[2]		1		1
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total before income tax	[1]	$ (6)	(5)	$ (11)	(7)
Income tax benefit	[1]	2	2	4	3
Net of tax	[1]	(4)	(3)	(7)	(4)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Natural Gas Derivatives [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Cost of goods sold (natural gas contracts)	[1]	(3)	$ 2	(4)	5
Operation and maintenance expense	[1]	$ (1)		(1)	$ 1
Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Contract [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense (interest rate contracts)	[1]			$ 1
[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 6 for additional details about net periodic benefit cost.

Note 9 - Non-Wholly Owned Ent57

Note 9 - Non-Wholly Owned Entities (Details) $ in Millions, ft³ in Billions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)mift³	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)mift³	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Payments to Acquire Property, Plant, and Equipment	$ 264	$ 171	$ 452	$ 332
Payments of Ordinary Dividends, Noncontrolling Interest			18	17
Equity Method Investments	75	$ 81	75	81	$ 80
South Star [Member]
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Payments to Acquire Property, Plant, and Equipment			$ 2	4
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage			85.00%
South Star [Member] | Piedmont [Member]
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Payments of Ordinary Dividends, Noncontrolling Interest			$ 18	$ 17
PennEast Pipeline [Member]
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Equity Method Investments	$ 3		$ 3		1
PennEast Pipeline [Member] | Corporate Joint Venture [Member]
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Equity Method Investment, Ownership Percentage	20.00%		20.00%
Natural Gas Pipeline Length (in Miles) | mi	108		108
Natural Gas Pipeline Capacity (in Cubic Feet) | ft³	1		1
Natural Gas Pipeline Expansion Capacity (in Cubic Feet) | ft³	1.2		1.2
Atlantic Coast Pipeline [Member]
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Equity Method Investments	$ 4		$ 4		$ 2
Atlantic Coast Pipeline [Member] | Corporate Joint Venture [Member]
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Equity Method Investment, Ownership Percentage	5.00%		5.00%
Natural Gas Pipeline Length (in Miles) | mi	550		550
Natural Gas Pipeline Capacity (in Cubic Feet) | ft³	1.5		1.5
Natural Gas Pipeline Expansion Capacity (in Cubic Feet) | ft³	2		2

Note 9 - Non-Wholly Owned Ent58

Note 9 - Non-Wholly Owned Entities (Details) - SouthStar’s Assets and Liabilities - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Current assets		$ 1,572	$ 2,886	$ 2,380
Goodwill and other intangible assets		1,939	1,952	1,962
Long-term assets and other deferred debits		10,324	10,050	9,817
Total assets		13,835	14,888	14,159
Current liabilities		2,047	3,219	2,595
Long-term liabilities and other deferred credits		7,799	7,841	7,704
Total Liabilities		9,846	11,060	10,299
Equity		3,989	3,828	3,860	$ 3,613
Total liabilities and equity		13,835	14,888	14,159
South Star [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Current assets	[1]	192	236	195
Goodwill and other intangible assets	[1]	117	125	129
Long-term assets and other deferred debits	[1]	17	17	17
Total assets	[1]	326	378	341
Current liabilities	[1]	40	$ 71	$ 55
Long-term liabilities and other deferred credits	[1]	1
Total Liabilities	[1]	41	$ 71	$ 55
Equity	[1]	285	307	286
Total liabilities and equity	[1]	$ 326	$ 378	$ 341
South Star Percentage To Consolidated [Member]
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Current assets		12.00%	8.00%	8.00%
Goodwill and other intangible assets		6.00%	6.00%	7.00%
Total assets		2.00%	3.00%	2.00%
Current liabilities		2.00%	2.00%	2.00%
Long-term liabilities and other deferred credits		0.00%	0.00%	0.00%
Total Liabilities			1.00%	1.00%
Equity		7.00%	8.00%	7.00%
Total liabilities and equity		2.00%	3.00%	2.00%
[1]	These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.

Note 9 - Non-Wholly Owned Ent59

Note 9 - Non-Wholly Owned Entities (Details) - SouthStar’s Revenues and Expenses - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Variable Interest Entity [Line Items]
Operating revenues	$ 674	$ 889	$ 2,395	$ 3,351
Operating income	107	139	471	731
Cost of goods sold	222	402	1,157	1,802
Operation and maintenance	209	211	458	500
Depreciation and amortization	98	95	195	188
Taxes other than income taxes	38	42	114	130
Total operating expenses	567	750	1,924	2,620
South Star [Member]
Variable Interest Entity [Line Items]
Operating revenues	122	145	433	519
Operating income	12	11	94	89
Cost of goods sold	89	111	292	381
Operation and maintenance	18	20	41	43
Depreciation and amortization	3	2	5	5
Taxes other than income taxes		1	1	1
Total operating expenses	$ 110	$ 134	$ 339	$ 430

Note 9 - Non-Wholly Owned Ent60

Note 9 - Non-Wholly Owned Entities (Details) - Equity Method Investments - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014
Schedule of Equity Method Investments [Line Items]
Equity method investments		$ 75	$ 80	$ 81
Triton [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments		53	62	65
Horizon Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments		14	14	15
Other Equity Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	[1]	$ 8	$ 4	$ 1
[1]	Primarily includes our current investments of $3 million in PennEast Pipeline and $4 million in Atlantic Coast Pipeline as of June 30, 2015 and $1 million and $2 million, respectively, as of December 31, 2014.

Note 9 - Non-Wholly Owned Ent61

Note 9 - Non-Wholly Owned Entities (Details) - Income from Equity Method Investments - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Triton [Member]
Note 9 - Non-Wholly Owned Entities (Details) - Income from Equity Method Investments [Line Items]
Income from equity method investment	$ 1	$ 1	$ 1	$ 3
Horizon Pipeline [Member]
Note 9 - Non-Wholly Owned Entities (Details) - Income from Equity Method Investments [Line Items]
Income from equity method investment			$ 1	$ 1

Note 10 - Commitments, Guaran62

Note 10 - Commitments, Guarantees and Contingencies (Details) ft³ in Millions, $ in Millions	Jun. 07, 2013USD ($)	Feb. 28, 2015USD ($)$ / item	Sep. 30, 2014ft³	Aug. 31, 2014USD ($)	Jun. 30, 2015USD ($)ft³	Dec. 31, 2009USD ($)
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Long-term Purchase Commitment, Minimum Volume Required (in Cubic Feet) | ft³					87,000
Long-term Purchase Commitment, Amount					$ 222
Interest Payable, Current					48
Guarantor Obligations, Current Carrying Value					$ 0
Gas Balancing Volume Amount (in Cubic Feet) | ft³			4,600
Natural Gas Imbalance Resolution Period			5 years
Georgia Commission [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Gas Balancing Volume Amount (in Cubic Feet) | ft³					1,150
Discretionary Funds Used For Natural Gas Imbalance, Percentage					25.00%
Atlanta Gas Light [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Gas Balancing Volume Amount (in Cubic Feet) | ft³					1,150
Percent of NaturalGas Imbalance Obligated					25.00%
Illinois Commission [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Loss Contingency, Damages Sought, Value				$ 18		$ 85
Loss Contingency, Damages Awarded, Value	$ 72
CUB [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Loss Contingency, Damages Sought, Value				$ 22		305
IAGO [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Loss Contingency, Damages Sought, Value						$ 255
True-up Recovery [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Gain Contingency, Unrecorded Amount		$ 178
Pipeline Replacement Program Period		15 years
Gain Contingency, Unrecorded Amount, Initial One-time Increase (in Dollars per Item) | $ / item		2.46
Gain Contingency, Unrecorded Amount, Alternative Phased-in Cumulative Increases (in Dollars per Item) | $ / item		0.58

Note 10 - Commitments, Guaran63

Note 10 - Commitments, Guarantees and Contingencies (Details) - Recorded and Unrecorded Contractual Obligations $ in Millions		Jun. 30, 2015USD ($)
Recorded contractual obligations:
Recorded contractual obligations		$ 4,394
Recorded contractual obligations, current		506
Recorded contractual obligations, year two		631
Recorded contractual obligations, year three		102
Recorded contractual obligations, year four		220
Recorded contractual obligations, year five		394
Recorded contractual obligations, thereafter		2,541
Unrecorded contractual obligations and commitments (2) (7):
Unrecorded contractual obligations and commitments	[1],[2]	8,272
Unrecorded contractual obligations and commitments, current	[1],[2]	672
Unrecorded contractual obligations and commitments, year two	[1],[2]	928
Unrecorded contractual obligations and commitments, year three	[1],[2]	676
Unrecorded contractual obligations and commitments, year four	[1],[2]	543
Unrecorded contractual obligations and commitments, year five	[1],[2]	502
Unrecorded contractual obligations and commitments, thereafter	[1],[2]	4,951
Pipeline Charges, Storage Capacity and Gas Supply [Member]
Unrecorded contractual obligations and commitments (2) (7):
Unrecorded contractual obligations and commitments	[1],[2],[3]	5,341
Unrecorded contractual obligations and commitments, current	[1],[2],[3]	527
Unrecorded contractual obligations and commitments, year two	[1],[2],[3]	706
Unrecorded contractual obligations and commitments, year three	[1],[2],[3]	491
Unrecorded contractual obligations and commitments, year four	[1],[2],[3]	369
Unrecorded contractual obligations and commitments, year five	[1],[2],[3]	343
Unrecorded contractual obligations and commitments, thereafter	[1],[2],[3]	2,905
Interest Charges [Member]
Unrecorded contractual obligations and commitments (2) (7):
Unrecorded contractual obligations and commitments	[1],[2],[4]	2,670
Unrecorded contractual obligations and commitments, current	[1],[2],[4]	87
Unrecorded contractual obligations and commitments, year two	[1],[2],[4]	171
Unrecorded contractual obligations and commitments, year three	[1],[2],[4]	147
Unrecorded contractual obligations and commitments, year four	[1],[2],[4]	146
Unrecorded contractual obligations and commitments, year five	[1],[2],[4]	141
Unrecorded contractual obligations and commitments, thereafter	[1],[2],[4]	1,978
Operating Leases [Member]
Unrecorded contractual obligations and commitments (2) (7):
Unrecorded contractual obligations and commitments	[1],[2],[5]	172
Unrecorded contractual obligations and commitments, current	[1],[2],[5]	13
Unrecorded contractual obligations and commitments, year two	[1],[2],[5]	26
Unrecorded contractual obligations and commitments, year three	[1],[2],[5]	28
Unrecorded contractual obligations and commitments, year four	[1],[2],[5]	21
Unrecorded contractual obligations and commitments, year five	[1],[2],[5]	16
Unrecorded contractual obligations and commitments, thereafter	[1],[2],[5]	68
Asset Management Agreements [Member]
Unrecorded contractual obligations and commitments (2) (7):
Unrecorded contractual obligations and commitments	[1],[2],[6]	33
Unrecorded contractual obligations and commitments, current	[1],[2],[6]	5
Unrecorded contractual obligations and commitments, year two	[1],[2],[6]	11
Unrecorded contractual obligations and commitments, year three	[1],[2],[6]	9
Unrecorded contractual obligations and commitments, year four	[1],[2],[6]	6
Unrecorded contractual obligations and commitments, year five	[1],[2],[6]	$ 2
Unrecorded contractual obligations and commitments, thereafter	[1],[2],[6]
Standby Letters of Credit, Performance and Surety Bonds [Member]
Unrecorded contractual obligations and commitments (2) (7):
Unrecorded contractual obligations and commitments	[1],[2]	$ 48
Unrecorded contractual obligations and commitments, current	[1],[2]	37
Unrecorded contractual obligations and commitments, year two	[1],[2]	$ 11
Unrecorded contractual obligations and commitments, year three	[1],[2]
Unrecorded contractual obligations and commitments, year four	[1],[2]
Unrecorded contractual obligations and commitments, year five	[1],[2]
Unrecorded contractual obligations and commitments, thereafter	[1],[2]
Other Obligations [Member]
Unrecorded contractual obligations and commitments (2) (7):
Unrecorded contractual obligations and commitments	[1],[2]	$ 8
Unrecorded contractual obligations and commitments, current	[1],[2]	3
Unrecorded contractual obligations and commitments, year two	[1],[2]	3
Unrecorded contractual obligations and commitments, year three	[1],[2]	1
Unrecorded contractual obligations and commitments, year four	[1],[2]	$ 1
Unrecorded contractual obligations and commitments, year five	[1],[2]
Unrecorded contractual obligations and commitments, thereafter	[1],[2]
Recorded Contractual Obligation, Long-term Debt [Member]
Recorded contractual obligations:
Recorded contractual obligations		$ 3,506
Recorded contractual obligations, year two		545
Recorded contractual obligations, year three		22
Recorded contractual obligations, year four		155
Recorded contractual obligations, year five		350
Recorded contractual obligations, thereafter		2,434
Recorded Contractual Obligation, Short-term Debt [Member]
Recorded contractual obligations:
Recorded contractual obligations		459
Recorded contractual obligations, current		459
Environmental Remediation Liabilities [Member]
Recorded contractual obligations:
Recorded contractual obligations	[7]	429
Recorded contractual obligations, current	[7]	47
Recorded contractual obligations, year two	[7]	86
Recorded contractual obligations, year three	[7]	80
Recorded contractual obligations, year four	[7]	65
Recorded contractual obligations, year five	[7]	44
Recorded contractual obligations, thereafter	[7]	$ 107
[1]	In accordance with GAAP, these items are not reflected in our unaudited condensed Consolidated Statements of Financial Position.
[2]	We provide guarantees to certain municipalities and other agencies and certain gas suppliers of SouthStar in support of payment obligations.
[3]	Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 87 Bcf at floating gas prices calculated using forward natural gas prices as of June 30, 2015, and is valued at $222 million. As we do for other subsidiaries, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations.
[4]	Floating rate interest charges are calculated based on the interest rate as of June 30, 2015 and the maturity date of the underlying debt instrument. As of June 30, 2015, we have $48 million of accrued interest on our unaudited Condensed Consolidated Statements of Financial Position that will be paid in the next 12 months.
[5]	We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with GAAP. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Our operating leases are primarily for real estate.
[6]	Represent fixed-fee minimum payments for Sequent's affiliated asset management agreements.
[7]	Includes charges recoverable through base rates or rate rider mechanisms.

Note 11 - Segment Information64

Note 11 - Segment Information (Details) - Jun. 30, 2015	Total
Note 11 - Segment Information (Details) [Line Items]
Number of Reportable Segments	4
Distribution Operations [Member]
Note 11 - Segment Information (Details) [Line Items]
Number of States in which Entity Operates	7

Note 11 - Segment Information65

Note 11 - Segment Information (Details) - Intersegment Reporting - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Operating revenues		$ 674	$ 889	$ 2,395	$ 3,351
Operating expenses
Cost of goods sold		222	402	1,157	1,802
Operation and maintenance		209	211	458	500
Depreciation and amortization		98	95	195	188
Taxes other than income taxes		38	42	114	130
Total operating expenses		567	750	1,924	2,620
Operating income (loss)		107	139	471	731
Other income (expense)		4	2	7	5
EBIT		111	141	478	736
Identifiable and total assets	[1]	13,835	13,902	13,835	13,902
Capital expenditures		264	171	452	332
Identifiable and total assets		13,835	14,159	13,835	14,159	$ 14,888
Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues		674	889	2,395	3,351
Distribution Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues		506	656	1,791	2,382
Operating expenses
Cost of goods sold		166	315	942	1,517
Operation and maintenance		160	159	345	370
Depreciation and amortization		83	78	165	156
Taxes other than income taxes		34	40	105	122
Total operating expenses		443	592	1,557	2,165
Operating income (loss)		103	107	330	335
Other income (expense)		3	3	4	4
EBIT		106	110	334	339
Identifiable and total assets	[1]	11,796	11,511	11,796	11,511
Capital expenditures		248	158	418	308
Identifiable and total assets						12,037
Distribution Operations [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues		40	43	96	118
Distribution Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues		546	699	1,887	2,500
Retail Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues		153	176	494	582
Operating expenses
Cost of goods sold		95	119	305	399
Operation and maintenance		34	34	71	71
Depreciation and amortization		6	6	12	14
Taxes other than income taxes		1	1	2	2
Total operating expenses		136	160	390	486
Operating income (loss)		17	17	104	97
EBIT		17	17	104	97
Identifiable and total assets	[1]	636	671	636	671
Capital expenditures		2	3	4	6
Identifiable and total assets						670
Retail Operations [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues			1		1
Retail Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues		153	177	494	583
Wholesale Services [Member]
Segment Reporting Information [Line Items]
Operating revenues	[2]	$ 4	47	94	378
Operating expenses
Cost of goods sold	[2]		7	9	10
Operation and maintenance	[2]	$ 11	13	35	49
Depreciation and amortization	[2]	$ 1	$ 1	1	1
Taxes other than income taxes	[2]			1	1
Total operating expenses	[2]	$ 12	$ 21	46	61
Operating income (loss)	[2]	$ (8)	26	$ 48	317
Other income (expense)	[2]		(2)		(2)
EBIT	[2]	$ (8)	24	$ 48	315
Identifiable and total assets	[1],[2]	$ 806	$ 1,207	806	1,207
Capital expenditures	[2]			$ 1	$ 1
Identifiable and total assets						1,402
Wholesale Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	[2]
Wholesale Services [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues	[2]	$ 4	$ 47	$ 94	$ 378
Midstream Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues		11	17	30	61
Operating expenses
Cost of goods sold		2	11	12	47
Operation and maintenance		6	7	12	13
Depreciation and amortization		4	4	9	9
Taxes other than income taxes		1	2	2	3
Total operating expenses		13	24	35	72
Operating income (loss)		(2)	(7)	(5)	(11)
Other income (expense)				1	1
EBIT		(2)	(7)	(4)	(10)
Identifiable and total assets	[1]	686	699	686	699
Capital expenditures		7	5	10	5
Identifiable and total assets						694
Midstream Operations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues		11	17	30	61
Other Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues		3	1	9	4
Operating expenses
Cost of goods sold				5
Operation and maintenance				(2)	1
Depreciation and amortization		4	6	8	8
Taxes other than income taxes		2	(1)	4	2
Total operating expenses		6	5	15	11
Operating income (loss)		(3)	(4)	(6)	(7)
Other income (expense)		1	1	2	2
EBIT		(2)	(3)	(4)	(5)
Identifiable and total assets	[1]	9,190	9,482	9,190	9,482
Capital expenditures		7	5	19	12
Identifiable and total assets						9,706
Other Segments [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues		3	1	9	4
Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues		(3)	(8)	(23)	(56)
Operating expenses
Cost of goods sold		(41)	(50)	(116)	(171)
Operation and maintenance		(2)	(2)	(3)	(4)
Total operating expenses		(43)	(52)	(119)	(175)
Identifiable and total assets	[1]	(9,279)	(9,668)	(9,279)	(9,668)
Identifiable and total assets						$ (9,621)
Intercompany Eliminations [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues		(40)	(44)	(96)	(119)
Intercompany Eliminations [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Operating revenues		$ (43)	$ (52)	$ (119)	$ (175)
[1]	Identifiable and total assets exclude assets held for sale.
[2]	The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.

Note 11 - Segment Information66

Note 11 - Segment Information (Details) - Operating Revenues - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues		$ 674	$ 889	$ 2,395	$ 3,351
Third Party Gross Costs		222	402	1,157	1,802
Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	[1]	$ 4	47	94	378
Third Party Gross Costs	[1]		7	9	10
Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues		$ 674	889	2,395	3,351
Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	[1]	4	47	94	378
Third Party Gross Revenues [Member] | Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues		1,291	2,379	3,436	6,428
Intercompany Revenues [Member] | Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues		89	160	239	458
Total Gross Revenues [Member] | Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues		1,380	2,539	3,675	6,886
Third Party Gross Costs [Member] | Operating Segments [Member] | Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Third Party Gross Costs		$ 1,376	$ 2,492	$ 3,581	$ 6,508
[1]	The revenues for wholesale services are netted with costs associated with its energy and risk management activities. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.

Note 12 - Discontinued Operat67

Note 12 - Discontinued Operations (Details) - USD ($)	Sep. 01, 2014	Jun. 30, 2015	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Sep. 30, 2014	Jun. 30, 2014	Sep. 30, 2014
Note 12 - Discontinued Operations (Details) [Line Items]
Discontinued Operation, Tax Effect of Discontinued Operation								$ (32,000,000)
Income Tax Expense (Benefit)		$ 25,000,000		$ 37,000,000		$ 143,000,000		$ 240,000,000
Distributed Earnings Of Foreign Subsidiaries [Member]
Note 12 - Discontinued Operations (Details) [Line Items]
Effective Income Tax Rate Reconciliation, Repatriation of Foreign Earnings, Amount			$ 86,000,000
Tropical Shipping [Member]
Note 12 - Discontinued Operations (Details) [Line Items]
Proceeds from Divestiture of Businesses	$ 225,000,000
Discontinued Operation, Tax Effect of Discontinued Operation			$ 29,000,000		$ 31,000,000
Goodwill, Impairment Loss, Net of Tax					19,000,000
Income Tax Expense (Benefit)					$ 0
Depreciation And Amortization Suspension							$ 7,000,000
Tropical Shipping [Member] | Distributed Earnings Of Foreign Subsidiaries [Member]
Note 12 - Discontinued Operations (Details) [Line Items]
Discontinued Operation, Tax Effect of Discontinued Operation									$ 60,000,000

Note 12 - Discontinued Operat68

Note 12 - Discontinued Operations (Details) - Assets and Liabilities of Tropical Shipping $ in Millions	Jun. 30, 2014USD ($)
Current assets
Cash and cash equivalents	$ 15
Total current assets	257
Current liabilities
Total liabilities held for sale	39
Tropical Shipping [Member]
Current assets
Cash and cash equivalents	15
Short-term investments	3
Receivables	35
Inventories	9
Other	2
Total current assets	64
Long-term assets and other deferred debits
Property, plant and equipment, net	127
Goodwill	42
Intangible assets	19
Other	5
Total long-term assets and other deferred debits	193
Total assets held for sale	257
Current liabilities
Other accounts payable – trade	9
Accrued expenses	7
Other	23
Total liabilities held for sale	$ 39

Note 12 - Discontinued Operat69

Note 12 - Discontinued Operations (Details) - Discontinued Operations from Statement of Income - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating revenues		$ 92		$ 181
Operating expenses
Cost of goods sold		57		111
Operation and maintenance		27		55
Depreciation and amortization				5
Taxes other than income taxes		3		4
Total operating expenses		91		198
Operating income (loss)		1		(17)
Income (loss) before income taxes		1		(17)
Income tax expense				(32)
Income (loss) from discontinued operations, net of tax		1		(49)
Tropical Shipping [Member]
Operating expenses
Loss on sale and goodwill impairment		$ 4		$ 23
Income tax expense	$ 29		$ 31