10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2014
Commission File Number 1-14174
AGL RESOURCES INC.
Ten Peachtree Place NE, Atlanta, Georgia 30309
404-584-4000
Georgia	58-2210952
(State of incorporation)	(I.R.S. Employer Identification No.)
AGL Resources Inc.: (1) has filed all reports required to be filed by Section 13 of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
AGL Resources Inc. has submitted electronically and posted on its corporate website every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.

AGL Resources Inc. is a large accelerated filer and is not a shell company.

The number of shares of AGL Resources Inc.’s common stock, $5.00 Par Value, outstanding as of April 22, 2014 was 119,257,873.

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended March 31, 2014

TABLE OF CONTENTS

			Page
Glossary of Key Terms				3
Item Number.
		PART I - FINANCIAL INFORMATION
	1	Condensed Consolidated Financial Statements (Unaudited)		4
		Condensed Consolidated Statements of Financial Position		4
		Condensed Consolidated Statements of Income		5
		Condensed Consolidated Statements of Other Comprehensive Income		6
		Condensed Consolidated Statements of Equity		7
		Condensed Consolidated Statements of Cash Flows		8
		Notes to Condensed Consolidated Financial Statements (Unaudited)		9
		Note 1 - Organization and Basis of Presentation		9
		Note 2 - Significant Accounting Policies and Methods of Application		9
		Note 3 - Regulated Operations		13
		Note 4 - Fair Value Measurements		14
		Note 5 - Derivative Instruments		15
		Note 6 - Employee Benefit Plans		17
		Note 7 - Debt and Credit Facilities		17
		Note 8 - Equity		19
		Note 9 - Non-Wholly Owned Entities		20
		Note 10 - Commitments, Guarantees and Contingencies		21
		Note 11 - Segment Information		22
		Note 12 – Subsequent Events		23
	2	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
		Forward-Looking Statements		24
		Executive Summary		25
		Results of Operations		27
		Liquidity and Capital Resources		34
		Critical Accounting Policies and Estimates		37
		Accounting Developments		37
	3	Quantitative and Qualitative Disclosures About Market Risk		38
	4	Controls and Procedures		40
		PART II - OTHER INFORMATION
	1	Legal Proceedings		41
	1A	Risk Factors		41
	2	Unregistered Sales of Equity Securities and Use of Proceeds		41
	6	Exhibits		41
		SIGNATURE		42

2

GLOSSARY OF KEY TERMS

2013 Form 10-K	Our Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on February 6, 2014
AFUDC	Allowance for funds used during construction, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects and is capitalized in PP&E and considered rate base for ratemaking purposes
AGL Capital	AGL Capital Corporation
AGL Credit Facility	$1.3 billion credit agreement entered into by AGL Capital to support its commercial paper program
AGL Resources	AGL Resources Inc., together with its consolidated subsidiaries
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Central Valley	Central Valley Gas Storage, LLC
EBIT	Earnings before interest and taxes, the primary measure of our operating segments’ profit or loss, which includes operating income and other income and excludes financing costs, including interest on debt and income tax expense
ERC	Environmental remediation costs
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Golden Triangle	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of the effects of weather on our businesses, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher
Horizon Pipeline	Horizon Pipeline Company, LLC
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson Island	Jefferson Island Storage & Hub, LLC
LIFO	Last-in, first-out
LNG	Liquefied natural gas
LOCOM	Lower of weighted average cost or current market price
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor	Nicor Inc.
Nicor Gas	Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Gas Credit Facility	$700 million credit facility entered into by Nicor Gas to support its commercial paper program
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense
OTC	Over-the-counter
PBR	Performance-based rate
Piedmont	Piedmont Natural Gas Company, Inc.
Pivotal Home Solutions	Nicor Energy Services Company, doing business as Pivotal Home Solutions
PP&E	Property, plant and equipment
S&P	Standard & Poor’s Ratings Services
Sawgrass Storage	Sawgrass Storage, LLC
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
Seven Seas	Seven Seas Insurance Company, Inc.
SouthStar	SouthStar Energy Services, LLC
STRIDE	Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
TEU	Twenty-foot equivalent unit, a measure of volume in containerized shipping equal to one 20-foot-long container
Triton	Triton Container Investments, LLC
Tropical Shipping	Tropical Shipping and Construction Company Limited
U.S.	United States
VaR	Value-at-risk is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability.
VIE	Variable interest entity
Virginia Commission	Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
Virginia Natural Gas	Virginia Natural Gas, Inc.
WACOG	Weighted average cost of gas

3

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(UNAUDITED)

	As of
In millions, except share amounts	March 31, 2014				December 31, 2013		March 31, 2013
Current assets
Cash and cash equivalents	$	293		$	105		$	149
Short-term investments		52			50			43
Receivables
Energy marketing		1,226			786			627
Gas, unbilled and other		1,109			772			874
Less allowance for uncollectible accounts		49			29			39
Total receivables, net		2,286			1,529			1,462
Regulatory assets		297			162			119
Inventories, net		263			667			393
Derivative instruments		127			99			100
Other		130			121			95
Total current assets		3,448			2,733			2,361
Long-term assets and other deferred debits
Property, plant and equipment		11,220			11,104			10,610
Less accumulated depreciation		2,397			2,323			2,202
Property, plant and equipment, net		8,823			8,781			8,408
Goodwill		1,869			1,888			1,883
Regulatory assets		736			737			878
Intangible assets		170			173			156
Derivative instruments		11			20			11
Other		319			324			243
Total long-term assets and other deferred debits		11,928			11,923			11,579
Total assets	$	15,376		$	14,656		$	13,940
Current liabilities
Energy marketing trade payables	$	1,119		$	671		$	653
Short-term debt		741			1,171			868
Other accounts payable - trade		444			432			314
Accrued expenses		390			210			166
Temporary LIFO liquidation		252			-			179
Current portion of long-term debt and capital leases		200			-			226
Regulatory liabilities		161			183			238
Customer deposits and credit balances		104			136			115
Accrued environmental remediation liabilities		82			70			63
Derivative instruments		63			75			20
Other		197			174			218
Total current liabilities		3,753			3,122			3,060
Long-term liabilities and other deferred credits
Long-term debt		3,610			3,813			3,324
Accumulated deferred income taxes		1,699			1,667			1,568
Regulatory liabilities		1,550			1,518			1,498
Accrued pension and retiree welfare benefits		405			404			509
Accrued environmental remediation liabilities		358			377			362
Derivative instruments		19			5			4
Other		71			74			74
Total long-term liabilities and other deferred credits		7,712			7,858			7,339
Total liabilities and other deferred credits		11,465			10,980			10,399
Commitments, guarantees and contingencies (see Note 10)
Equity
Common stock, $5 par value; 750,000,000 shares authorized: outstanding: 119,247,421 shares at March 31, 2014, 118,888,876 shares at December 31, 2013 and 118,123,770 shares at March 31, 2013		597			595			592
Additional paid-in capital		2,059			2,054			2,019
Retained earnings		1,358			1,126			1,134
Accumulated other comprehensive loss		(135	)		(136	)		(211	)
Treasury shares, at cost: 216,523 shares at March 31, 2014 and December 31, 2013 and March 31, 2013		(8	)		(8	)		(8	)
Total common shareholders’ equity		3,871			3,631			3,526
Noncontrolling interest		40			45			15
Total equity		3,911			3,676			3,541
Total liabilities and equity	$	15,376		$	14,656		$	13,940
See Notes to Condensed Consolidated Financial Statements (Unaudited).

4

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three months ended March 31,
In millions, except per share amounts	2014			2013
Operating revenues (includes revenue taxes of $68 for the three months in 2014 and $50 for the three months in 2013)	$	2,563		$	1,709
Operating expenses
Cost of goods sold		1,454			973
Operation and maintenance		317			259
Depreciation and amortization		98			107
Taxes other than income taxes		89			71
Goodwill impairment loss		19			-
Total operating expenses		1,977			1,410
Operating income		586			299
Other income		3			5
Interest expense, net		(48	)		(46	)
Income before income taxes		541			258
Income tax expense		239			94
Net income		302			164
Less net income attributable to the noncontrolling interest		12			10
Net income attributable to AGL Resources Inc.	$	290		$	154
Per common share data
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	2.44		$	1.31
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	2.44		$	1.31
Cash dividends declared per common share	$	0.49		$	0.47
Weighted average number of common shares outstanding
Basic		118.5			117.4
Diluted		118.9			117.7

See Notes to Condensed Consolidated Financial Statements (Unaudited).

5

AGL RESOURCES INC. AND SUBSIDIARIES

 CONDENSED CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME

(UNAUDITED)

	Three months ended March 31,
In millions	2014			2013
Net income	$	302		$	164
Other comprehensive income, net of tax
Retirement benefit plans
Reclassification of actuarial losses to net benefit cost (net of income tax of $1 for the three months ended March 31, 2014, and $2 for the three months ended March 31, 2013)		1			4
Reclassification of prior service credits to net benefit cost		-			(1	)
Retirement benefit plans		1			3
Cash flow hedges, net of tax
Net derivative instrument gains arising during the period (net of income tax of $1 for the three months ended March 31, 2013)		4			2
Reclassification of realized derivative (gains) losses to net income (net of income tax of $1 for the three months ended March 31, 2013)		(4	)		2
Cash flow hedges, net		-			4
Other comprehensive income, net of tax		1			7
Comprehensive income		303			171
Less comprehensive income attributable to noncontrolling interest		12			10
Comprehensive income attributable to AGL Resources Inc.	$	291		$	161

See Notes to Condensed Consolidated Financial Statements (Unaudited).

6

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

	AGL Resources Inc. Shareholders
	Common stock				Additional paid-in			Retained			Accumulated other comprehensive			Treasury			Noncontrolling
In millions, except per share amounts	Shares		Amount		capital			earnings			loss			shares			interest			Total
Balance as of December 31, 2012		117.9	$	590	$	2,014		$	1,035		$	(218	)	$	(8	)	$	22		$	3,435
Net income		-		-		-			154			-			-			10			164
Other comprehensive income		-		-		-			-			7			-			-			7
Dividends on common stock ($0.47 per share)		-		-		-			(55	)		-			-			-			(55	)
Distributions to noncontrolling interests		-		-		-			-			-			-			(17	)		(17	)
Stock granted, share-based compensation, net of forfeitures		-		-		(6	)		-			-			-			-			(6	)
Stock issued, dividend reinvestment plan		-		1		2			-			-			-			-			3
Stock issued, share-based compensation, net of forfeitures		0.2		1		6			-			-			-			-			7
Stock-based compensation expense, net of tax		-		-		3			-			-			-			-			3
Balance as of March 31, 2013		118.1	$	592	$	2,019		$	1,134		$	(211	)	$	(8	)	$	15		$	3,541

	AGL Resources Inc. Shareholders
	Common stock				Additional  paid-in			Retained			Accumulated other comprehensive			Treasury			Noncontrolling
In millions, except per share amounts	Shares		Amount		capital			earnings			loss			shares			interest			Total
Balance as of December 31, 2013		118.9	$	595	$	2,054		$	1,126		$	(136	)	$	(8	)	$	45		$	3,676
Net income		-		-		-			290			-			-			12			302
Other comprehensive income		-		-		-			-			1			-			-			1
Dividends on common stock ($0.49 per share)		-		-		-			(58	)		-			-			-			(58	)
Distributions to noncontrolling interests		-		-		-			-			-			-			(17	)		(17	)
Stock granted, share-based compensation, net of forfeitures		-		-		(12	)		-			-			-			-			(12	)
Stock issued, dividend reinvestment plan		-		-		2			-			-			-			-			2
Stock issued, share-based compensation, net of forfeitures		0.3		2		12			-			-			-			-			14
Stock-based compensation expense, net of tax		-		-		3			-			-			-			-			3
Balance as of March 31, 2014		119.2	$	597	$	2,059		$	1,358		$	(135	)	$	(8	)	$	40		$	3,911

See Notes to Condensed Consolidated Financial Statements (Unaudited).

7

AGL RESOURCES INC. AND SUBSIDIARIES

 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three months ended March 31,
In millions	2014			2013
Cash flows from operating activities
Net income	$	302		$	164
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		98			107
Deferred income taxes		42			(24	)
Goodwill impairment loss		19			-
Change in derivative instrument assets and liabilities		(17	)		18
Changes in certain assets and liabilities
Inventories, net of temporary LIFO liquidation		656			494
Accrued expenses		180			26
Trade payables, other than energy marketing		51			(6	)
Energy marketing receivables and trade payables, net		8			92
Prepaid taxes		2			76
Receivables, other than energy marketing		(317	)		(172	)
Deferred/accrued natural gas costs		(228	)		43
Other, net		57			32
Net cash flow provided by operating activities		853			850
Cash flows from investing activities
Expenditures for property, plant and equipment		(164	)		(148	)
Acquisitions of assets		-			(122	)
Other, net		-			14
Net cash flow used in investing activities		(164	)		(256	)
Cash flows from financing activities
Net repayments of commercial paper		(430	)		(509	)
Dividends paid on common shares		(58	)		(55	)
Distribution to noncontrolling interest		(17	)		(17	)
Other, net		4			5
Net cash flow used in financing activities		(501	)		(576	)
Net increase in cash and cash equivalents		188			18
Cash and cash equivalents at beginning of period		105			131
Cash and cash equivalents at end of period	$	293		$	149
Cash paid during the period for
Interest	$	58		$	58
Income taxes	$	14		$	26
Non cash financing transaction
Refinancing of gas facility revenue bonds	$	-		$	200

See Notes to Condensed Consolidated Financial Statements (Unaudited).

8

AGL RESOURCES INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Organization and Basis of Presentation

General

AGL Resources Inc. is an energy services holding company that conducts substantially all 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.

The December 31, 2013 Condensed Consolidated Statement of Financial Position data was derived from our audited financial statements, but does not include all disclosures required by GAAP. We have prepared the accompanying unaudited Condensed Consolidated Financial Statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. Our unaudited Condensed Consolidated Financial Statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. These unaudited Condensed Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our 2013 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 and 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 consolidated VIE for which we are the primary beneficiary. For unconsolidated entities that we do not control, but exercise significant influence over, 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.

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 2013 Form 10-K. There were no significant changes to our accounting policies during the three months ended March 31, 2014.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments 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 literature or in the development of estimates that impact our financial statements. The most significant estimates relate to our rate-regulated subsidiaries, uncollectible accounts and other allowances for contingent losses, goodwill and other intangible assets, retirement plan benefit obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates.

Cash and Cash Equivalents

Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of March 31, 2014 and 2013, and December 31, 2013, $75 million, $76 million and $80 million, respectively, of cash and short and long-term investments was held by Tropical Shipping. As of March 31, 2014, in conjunction with negotiating the agreement to sell Tropical Shipping and Seven Seas, we determined that we no longer have the intent to indefinitely reinvest Tropical Shipping’s cash and short and long-term investments offshore. For more information on the sale of Tropical Shipping and Seven Seas, see Income Tax Expense and Goodwill within this note and Note 12.

Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.

9

Our wholesale services segment has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of March 31, 2014 and 2013, and December 31, 2013, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Inventories

For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 10 for information regarding a regulatory filing by Atlanta Gas Light related to natural gas inventory.

Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during interim periods that are expected to be restored prior to year end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO inventory liquidation. Any temporary LIFO liquidation is included as a current liability in our unaudited Condensed Consolidated Statements of Financial Position. Interim inventory decrements that are not expected to be restored prior to year end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of March 31, 2014 is expected to be restored prior to year end. The inventory decrement as of March 31, 2013 was restored prior to December 31, 2013.

Our retail operations, wholesale services and midstream operations segments carry inventory at the lower of cost or market value, 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 adjustments to reduce the weighted average cost of the natural gas inventory to market value. For the three months ended March 31, 2014, wholesale services recorded a $2 million LOCOM adjustment to reduce the value of our inventories to market value. We recorded no LOCOM adjustment for the three months ended March 31, 2013.

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 2013 Form 10-K.

As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). 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 value of the natural gas and weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflects 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 use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 and Note 5 for additional derivative disclosures.

10

Goodwill

During the first quarter of 2014, we completed an engineering study at our storage and fuels reporting unit within midstream operations, which indicated a reduced forecast of working gas capacity from what was projected when our 2013 annual goodwill impairment analysis was performed during the fourth quarter of 2013. Given that the 2013 annual goodwill impairment test indicated that the estimated fair value of this reporting unit exceeded its carrying amount by less than 5%, we considered this reduced storage capacity as an indicator of potential impairment and, accordingly, conducted an interim goodwill impairment analysis during the first quarter of 2014.

The estimated fair value of this reporting unit was determined utilizing the income approach, which estimated the fair value based upon the present value of estimated future cash flows. The forecasts used in the income approach, which were updated during the first quarter of 2014 to reflect the contracting activity that occurred during the quarter, assume discrete period revenue growth through fiscal 2022 to reflect the recovery of subscription rates, stabilization of earnings and establishment of a reasonable base year that was used to estimate the terminal value. Consistent with our 2013 annual goodwill impairment testing, we assumed a long-term earnings growth rate in the terminal year of 2.5%, which we believe is appropriate given the current economic and industry specific expectations. As of the valuation date, we utilized a discount rate of 7.0%, which we believe is appropriate as it reflects the relative risk and the time value of money, and is consistent with the peer group of this reporting unit as well as the discount rates that were utilized in our 2013 annual goodwill impairment tests.

The cash flow forecasts for this reporting unit assumed earnings growth over the next eight years. Should this growth not occur, this reporting unit may fail step one during a future goodwill impairment test. Along with any reductions to our cash flow forecasts, changes in other assumptions used in our impairment analysis may require us to proceed to step two of the goodwill impairment test in a future period.

Our interim goodwill impairment test indicated that the estimated fair value of this reporting unit continues to exceed its carrying amount with a cushion of less than 10%. Continued declines in capacity or subscription rates, a sustained period at the current subscription rates or other changes to the assumptions and factors used in this analysis may result in a future failure of step one of the goodwill impairment test. The risk of impairment of the underlying long-lived assets is not estimated to be significant as the assets have long remaining useful lives and authoritative guidance requires such assets to be tested for impairment on the basis of undiscounted cash flows over their remaining useful lives. We will continue to monitor this reporting unit for potential impairment.

In April 2014 we entered into a definitive agreement to sell Tropical Shipping and Seven Seas. We have determined, based on the agreed-upon sale price, that $19 million of goodwill attributable to cargo shipping was impaired as of March 31, 2014. Accordingly, this impairment expense was recorded as a separate line item in our unaudited Condensed Consolidated Statements of Income. Changes in the amount of goodwill for the three months ended March 31, 2014 and 2013 are provided in the following table.

In millions	Distribution Operations		Retail Operations		Wholesale Services		Midstream Operations		Cargo Shipping			Other		Consolidated
Goodwill - December 31, 2012	$	1,640	$	122	$	-	$	14	$	61		$	-	$	1,837
2013 activity		-		46		-		-		-			-		46
Goodwill - March 31, 2013	$	1,640	$	168	$	-	$	14	$	61		$	-	$	1,883
Goodwill - December 31, 2013	$	1,640	$	173	$	-	$	14	$	61		$	-	$	1,888
Cargo shipping impairment		-		-		-		-		(19	)		-		(19	)
Goodwill - March 31, 2014	$	1,640	$	173	$	-	$	14	$	42		$	-	$	1,869

See Note 2 to our Consolidated Financial Statements included in Item 8 of our 2013 Form 10-K for additional information on impairment of assets.

Other Income

Our other income is detailed in the following table. For more information on our equity investment income, see Note 9.

	Three months ended March 31,
In millions	2014			2013
Equity investment income	$	3		$	3
AFUDC - equity		1			3
Other, net		(1	)		(1	)
Total other income	$	3		$	5

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Income Tax Expense

As a result of our agreement to sell Tropical Shipping and Seven Seas, we have determined that the cumulative foreign earnings of cargo shipping will no longer be indefinitely reinvested offshore, and we recognized tax expense of $31 million in the three months ended March 31, 2014 related to the cumulative earnings for which no tax liabilities previously had been recorded. This resulted in an effective tax rate of 45.2% for the three months ended March 31, 2014 compared to 37.9% for the same period last year. As of March 31, 2014, we have $57 million of deferred income tax liabilities on our unaudited Condensed Consolidated Statements of Financial Position related to the cumulative earnings of our foreign subsidiaries that have not been repatriated.

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our net income attributable to AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. common shareholders reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. common shareholders that occurs when potentially dilutive common shares are added to 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. 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. common shareholders for the periods presented, if performance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised.

	Three months ended March 31,
In millions (except per share amounts)	2014		2013
Net income attributable to AGL Resources Inc.	$	290	$	154
Denominator:
Basic weighted average number of shares outstanding (1)		118.5		117.4
Effect of dilutive securities		0.4		0.3
Diluted weighted average number of shares outstanding		118.9		117.7
Earnings per share:
Basic	$	2.44	$	1.31
Diluted	$	2.44	$	1.31

(1)   Daily weighted average shares outstanding.

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Note 3 - 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 and estimated future expenditures that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs or expenditures 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 are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulatory commissions. The following table summarizes our regulatory assets and liabilities as of the dates presented.

In millions	March 31, 2014		December 31, 2013		March 31, 2013
Regulatory assets
Deferred natural gas costs	$	161	$	1	$	-
Recoverable regulatory infrastructure program costs		48		48		47
Recoverable ERC		38		45		28
Recoverable pension and retiree welfare benefit costs		9		9		19
Other		41		59		25
Total regulatory assets - current		297		162		119
Recoverable ERC		419		433		415
Recoverable pension and retiree welfare benefit costs		97		99		192
Recoverable regulatory infrastructure program costs		96		87		135
Long-term debt fair value adjustment		80		82		88
Other		44		36		48
Total regulatory assets - long-term		736		737		878
Total regulatory assets	$	1,033	$	899	$	997
Regulatory liabilities
Bad debt over collection	$	41	$	41	$	39
Accumulated removal costs		27		27		17
Accrued natural gas costs		24		92		133
Deferred seasonal rates		20		-		20
Other		49		23		29
Total regulatory liabilities - current		161		183		238
Accumulated removal costs		1,456		1,445		1,413
Regulatory income tax liability		27		27		26
Unamortized investment tax credit		25		26		28
Bad debt over collection		14		17		20
Other		28		3		11
Total regulatory liabilities - long-term		1,550		1,518		1,498
Total regulatory liabilities	$	1,711	$	1,701	$	1,736

Base rates are designed to provide the opportunity for both a recovery of cost and 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 believe that we will be able to recover such costs consistent with our historical recoveries.

In the event the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income and be classified as an extraordinary item. Additionally, while some regulatory liabilities would be written off, others would continue to be recorded as liabilities, but not as regulatory liabilities.

Natural Gas Costs We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. We defer or accrue the difference between the actual cost of gas and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. The following table illustrates the change in net position of these costs from March 31, 2013 to March 31, 2014.

In millions	March 31, 2014			March 31, 2013			Change
Deferred natural gas costs	$	161		$	-		$	161
Accrued natural gas costs		(24	)		(133	)		109
Total (1)	$	137		$	(133	)	$	270

(1)   The $270 million change resulted from increased natural gas prices during the first quarter of 2014 compared to the first quarter of 2013, primarily driven by colder weather experienced in the current quarter. These costs will be fully recovered in future periods.

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Environmental Remediation Costs We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites. The ERC assets and liabilities are associated with our distribution operations segment and are generally recoverable through rate mechanisms.

Our ERC liabilities are estimates of future remediation costs for investigation and cleanup of our current and former operating sites that are contaminated. These estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering 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. The following table provides additional information on the costs related to remediation of our current and former operating sites as of March 31, 2014 and reflects minor changes in estimates since we filed our 2013 Form 10-K.

In millions	Probabilistic model cost estimates		Engineering estimates		Amount recorded		Expected costs over next 12 months
Illinois	$	211 - $461	$	42	$	246	$	39
New Jersey		139 - 233		6		144		25
Georgia and Florida		28 - 112		8		39		10
North Carolina		n/a		11		11		8
Total	$	378 - $806	$	67	$	440	$	82

Note 4 - Fair Value Measurements

The methods used to determine the fair values of our assets and liabilities are described within Note 2.

Derivative Instruments

The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value on a recurring basis in our unaudited Consolidated Statements of Financial Position as of the dates presented. See Note 5 for additional derivative instrument information.

	March 31, 2014					December 31, 2013					March 31, 2013
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	18	$	(38	)	$	6	$	(79	)	$	14	$	(38	)
Significant other observable inputs (Level 2)		50		(75	)		67		(79	)		49		(23	)
Netting of cash collateral		69		31			43		78			40		37
Total carrying value (2) (3)	$	137	$	(82	)	$	116	$	(80	)	$	103	$	(24	)
Interest rate derivatives
Significant other observable inputs (Level 2)	$	-	$	-		$	-	$	-		$	6	$	-

(1)   Balances of $1 million at March 31, 2014, $3 million at December 31, 2013 and $2 million at March 31, 2013 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) for any of the dates presented.

(3)   There were no significant transfers between Level 1, Level 2 or Level 3 for any of the dates presented.

Money Market Funds

The fair values of our money market funds were recorded within short-term investments as of the following dates.

In millions	March 31, 2014		December 31, 2013		March 31, 2013
Money market funds (1)	$	48	$	48	$	48

(1)  Carried at fair value and classified as Level 1 within the fair value hierarchy.

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. The fair value adjustment of Nicor Gas’ first mortgage bonds is being amortized over the lives of the bonds. The following table presents the carrying amount and fair value of our long-term debt as of the following dates.

In millions	March 31, 2014		December 31, 2013		March 31, 2013
Long-term debt carrying amount	$	3,810	$	3,813	$	3,550
Long-term debt fair value (1)		4,095		3,956		4,006

(1)   Fair value determined using Level 2 inputs.

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Note 5 - Derivative Instruments

A description of our objectives and strategies for using derivative instruments, related accounting policies and methods used to determine their fair values are described in Note 2. See Note 4 for additional fair value disclosures.

Certain of our derivative instruments contain credit-risk-related or other contingent features that could require us to post collateral in the normal course of business when our financial instruments are in net liability positions. As of March 31, 2014, for agreements with such features, derivative instruments with liability fair values totaled $82 million, for which we had posted no collateral to our counterparties. The maximum collateral that could be required with these features is $15 million. For more information, see “Energy Marketing Receivables and Payables” in Note 2, which also have credit-risk-related or other contingent features. Our derivative instrument activities are included within operating cash flows as an adjustment to net income of ($17) million and $18 million for the three months ended March 31, 2014 and 2013, respectively. See Note 4 for additional derivative instrument information. The following table summarizes the various ways in which we account for our derivative instruments and the impact on our unaudited Condensed Consolidated Financial Statements.

	Recognition and Measurement
Accounting Treatment	Statements of Financial Position	Statements of Income
Cash flow hedge	Derivative carried at fair value	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated OCI (loss)	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated OCI (loss) and into earnings when the hedged transaction affects earnings
Fair value hedge	Derivative carried at fair value	Gains or losses on the derivative instrument and the hedged item are recognized in earnings. As a result, to the extent the hedge is effective, the gains or losses will offset and there is no impact on earnings. Any hedge ineffectiveness will impact earnings
	Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item
Not designated as hedges	Derivative carried at fair value	Realized and unrealized gains or losses on the derivative instrument are recognized in earnings
	Distribution operations’ gains and losses on derivative instruments are deferred as regulatory assets or liabilities until included in cost of goods sold	Gains or losses on these derivative instruments are ultimately included in billings to customers and are recognized in cost of goods sold in the same period as the related revenues

Quantitative Disclosures Related to Derivative Instruments

As of the dates presented, our derivative instruments were comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. We had a net long natural gas contracts position outstanding in the following quantities:

In Bcf (1)	March 31, 2014 (2)			December 31, 2013			March 31, 2013
Hedge designation
Cash flow hedges		6			6			6
Not designated as hedges		277			183			304
Total hedges		283			189			310
Hedge position
Short position		(2,491	)		(2,622	)		(1,902	)
Long position		2,774			2,811			2,212
Net long position		283			189			310

(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 97% of these contracts have durations of two years or less and the remaining 3% expire between 2 and 6 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 Nicor Gas and Elizabethtown Gas are reflected in accrued natural gas costs within our Consolidated Statements of Financial Position until billed to customers. The following amounts represent the net realized gains (losses) related to these natural gas cost hedges for the periods presented.

	Three months ended March 31,
In millions	2014		2013
Nicor Gas	$	2	$	(1	)
Elizabethtown Gas		3		(3	)

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The following table presents the fair values and unaudited Condensed Consolidated Statements of Financial Position classifications of our derivative instruments as of the dates presented.

		March 31,  2014						December 31, 2013						March 31, 2013
In millions	Classification	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges and fair value hedges
Natural gas contracts	Current	$	2		$	-		$	3		$	(1	)	$	3		$	(1	)
Interest rate swap agreements	Current		-			-			-			-			5			-
Total			2			-			3			(1	)		8			(1	)
Not designated as cash flow hedges
Natural gas contracts	Current		675			(703	)		691			(761	)		332			(327	)
Natural gas contracts	Long-term		80			(98	)		206			(220	)		46			(48	)
Total			755			(801	)		897			(981	)		378			(375	)
Gross amount of recognized assets and liabilities (1)			757			(801	)		900			(982	)		386			(376	)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)			(619	)		719			(781	)		902			(275	)		352
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)		$	138		$	(82	)	$	119		$	(80	)	$	111		$	(24	)

(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 above do not include cash collateral held on deposit in broker margin accounts of $100 million as of March 31, 2014, $121 million as of December 31, 2013 and $77 million as of March 31, 2013. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table.

(3)   At March 31, 2014, December 31, 2013 and March 31, 2013 we held letters of credit from counterparties that would offset, under master netting arrangements, 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 in our unaudited Condensed Consolidated Statements of Income for the periods presented.

	Three months ended March 31,
In millions	2014			2013
Designated as cash flow hedges
Natural gas contracts - net gain reclassified from OCI to cost of goods sold	$	3		$	-
Natural gas contracts - net gain reclassified from OCI to operation and maintenance expense		1			-
Interest rate swaps - loss reclassified from OCI to interest expense		-			(3	)
Income tax benefit		-			1
Net of tax		4			(2	)
Not designated as hedges (1)
Natural gas contracts - net fair value adjustments recorded in operating revenues		(30	)		(24	)
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		2			-
Income tax benefit		11			8
Net of tax		(17	)		(16	)
Total losses on derivative instruments, net of tax	$	(13	)	$	(18	)

(1)   Associated with the fair value of derivative instruments held at March 31, 2014 and 2013.

(2)   Excludes losses recorded in cost of goods sold associated with weather derivatives of $5 million for the three months ended March 31, 2014 and $2 million for the three months ended March 31, 2013.

Any amounts recognized in operating income, related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for the three months ended March 31, 2014 and 2013.

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 $3 million. These deferred gains and losses are related to natural gas derivative contracts associated with retail operations and Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at March 31, 2014.

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 2013 Form 10-K.

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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 2013 Form 10-K. Following are the components of our pension costs for the periods indicated.

	Three months ended March 31,
In millions	2014			2013
Service cost	$	6		$	8
Interest cost		12			10
Expected return on plan assets		(16	)		(16	)
Recognized actuarial loss		5			8
Net periodic pension benefit cost	$	7		$	10

Welfare Benefits

The benefits of our Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan) are described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K. Following are the components of our welfare costs for the periods indicated.

	Three months ended March 31,
In millions	2014			2013
Service cost	$	1		$	1
Interest cost		4			3
Expected return on plan assets		(2	)		(1	)
Net amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		1			2
Net periodic welfare benefit cost	$	3		$	4

Note 7 - Debt and Credit Facilities

The following table provides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities for the periods presented. We fully and unconditionally guarantee all debt issued by AGL Capital. For additional information on our debt, see Note 8 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K.

 

			March 31, 2014							March 31, 2013
Dollars in millions	Year(s) due		Weighted average interest rate (1)			Outstanding		Outstanding at December 31, 2013		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper - AGL Capital (2)	2014			0.3	%	$	440	$	857		0.5	%	$	868
Commercial paper - Nicor Gas (2)	2014			0.2			301		314		0.4			-
Total short-term debt				0.3			741		1,171		0.5			868
Current portion of long-term debt and capital leases
Current portion of long-term debt	2015			5.0			200		-		4.5			225
Current portion of capital leases		n/a		-			-		-		5.0			1
Total current portion of long-term debt and capital leases				5.0	%	$	200	$	-		4.5	%	$	226
Long-term debt - excluding current portion
Senior notes		2016-2043		5.0	%	$	2,625	$	2,825		5.1	%	$	2,325
First mortgage bonds		2016-2038		5.6			500		500		5.6			500
Gas facility revenue bonds		2022-2033		0.9			200		200		1.2			200
Medium-term notes		2017-2027		7.8			181		181		7.8			181
Total principal long-term debt				4.9	%		3,506		3,706		5.0	%		3,206
Fair value adjustment of long-term debt (3)		2016-2038		n/a			88		91		n/a			100
Unamortized debt premium, net		n/a		n/a			16		16		n/a			18
Total non-principal long-term debt				n/a			104		107		n/a			118
Total long-term debt						$	3,610	$	3,813				$	3,324
Total debt						$	4,551	$	4,984				$	4,418

(1)   Interest rates are calculated based on the daily weighted average balance outstanding for the three months ended March 31.

(2)   As of March 31, 2014, the effective interest rates on our commercial paper borrowings were 0.3% for AGL Capital and 0.2% for Nicor Gas.

(3)   See Note 4 for additional information on our fair value measurements.

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Commercial Paper Programs

We maintain commercial paper programs at AGL Capital and Nicor Gas that consist of short-term, unsecured promissory notes used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are highest during the injection period in advance of the Heating Season. The Nicor Gas commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in the AGL Capital commercial paper program. During the first quarter of 2014, our commercial paper maturities ranged from 1 to 108 days, and at March 31, 2014, remaining terms to maturity ranged from 1 to 35 days. Total borrowings and repayments netted to a payment of $430 million during the first quarter of 2014. For commercial paper issuances with original maturities over 3 months, borrowings and repayments were $50 million and $145 million, respectively, during the first quarter of 2014.

Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash pension adjustments, welfare benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.

	March 31, 2014			December 31, 2013			March 31, 2013
AGL Credit Facility		53	%		57	%		54	%
Nicor Gas Credit Facility		54	%		55	%		43	%

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:

· a maximum leverage ratio

· insolvency events and 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.

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Note 8 - Equity

Our OCI amounts are aggregated within our accumulated other comprehensive loss. The following table provides changes in the components of our accumulated other comprehensive loss balance, net of the related income tax effects.

In millions (1)	Cash flow hedges			Retirement benefit plans			Total
As of December 31, 2012	$	(3	)	$	(215	)	$	(218	)
OCI, before reclassifications		2			-			2
Amounts reclassified from accumulated OCI		2			3			5
As of March 31, 2013		1			(212	)		(211	)
As of December 31, 2013		1			(137	)		(136	)
OCI, before reclassifications		4			-			4
Amounts reclassified from accumulated OCI		(4	)		1			(3	)
As of March 31, 2014	$	1		$	(136	)	$	(135	)

(1)   All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

The following table provides details of the reclassifications out of accumulated other comprehensive loss and the impact on net income.

	Three months ended March 31,
In millions (1)	2014			2013
Cash flow hedges
Natural gas contracts (2)	$	4		$	-
Interest rate contracts (3)		-			(3	)
Total before income tax		4			(3	)
Income tax benefit		-			1
Total cash flow hedges		4			(2	)
Retirement benefit plan amortization of
Actuarial losses (4)		(2	)		(6	)
Prior service credits (4)		-			1
Total before income tax		(2	)		(5	)
Income tax benefit		1			2
Total retirement benefit plans		(1	)		(3	)
Total reclassification for the period	$	3		$	(5	)

    (1)   Amounts in parentheses indicate debits, or reductions, to profit/loss and credits to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the profit/loss impacts are immediate.

    (2)   Amounts included within cost of goods sold.

    (3)   Amounts included within interest expense, net.

    (4)   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.

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Note 9 - Non-Wholly Owned Entities

Variable Interest Entities

SouthStar, a joint venture owned by us and Piedmont, is our only VIE for which we are the primary beneficiary, which requires us to consolidate its assets, liabilities and statements of income. See Note 10 to our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K. Earnings from SouthStar in 2014 and 2013 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 three months ended March 31, 2014 and $1 million for the three months ended March 31, 2013. 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. Generally, this distribution occurs in the first quarter of each fiscal year. For each of the three months ended March 31, 2014 and 2013, SouthStar distributed $17 million to Piedmont. The following table provides additional information about SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our unaudited Condensed Consolidated Statements of Financial Position.

	March 31, 2014						December 31, 2013							March 31, 2013
In millions	Consolidated		SouthStar (1)		% (2)		Consolidated		SouthStar (1)		% (2)				Consolidated	SouthStar (1)		% (2)
Current assets	$	3,448	$	318	9	%	$	2,733	$	264		10	%	$	2,361	$	143		6	%
Goodwill and other intangible assets		2,039		138	7			2,061		139		7			2,039		-		-
Long-term assets and other deferred debits		9,889		20	-			9,862		12		-			9,540		10		-
Total assets	$	15,376	$	476	3	%	$	14,656	$	415		3	%	$	13,940	$	153		1	%
Current liabilities	$	3,753	$	171	5	%	$	3,122	$	95		3	%	$	3,060	$	51		2	%
Long-term liabilities and other deferred credits		7,712		16	-			7,858		-		-			7,339		-		-
Total Liabilities		11,465		187	2			10,980		95		1			10,399		51		1
Equity		3,911		289	7			3,676		320		9			3,541		102		3
Total liabilities and equity	$	15,376	$	476	3	%	$	14,656	$	415		3	%	$	13,940	$	153		1	%

(1)   These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.

(2)   SouthStar’s percentage of the amount on our Statements of Financial Position.

The following table provides information on SouthStar’s operating revenues and operating expenses for the periods presented, which are consolidated within our unaudited Condensed Consolidated Statements of Income.

	Three months ended March 31,
In millions	2014		2013
Operating revenues	$	374	$	250
Operating expenses
Cost of goods sold		270		164
Operation and maintenance		24		18
Depreciation and amortization		2		1
Total operating expenses		296		183
Operating income	$	78	$	67

Equity Method Investments

Income from our equity method investments is classified as other income in our unaudited Condensed Consolidated Statements of Income. For more information about our equity method investments, see Note 10 to our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K.

The carrying amounts of our investments that are accounted for under the equity method at March 31 were as follows:

In millions	2014		2013
Triton	$	67	$	72
Horizon Pipeline		15		16
Other (1)		1		9
Total	$	83	$	97

(1)   Includes our investment in Sawgrass Storage. In December 2013, the joint venture decided to terminate the development of the Sawgrass storage facility and reduced the carrying amount of the joint venture’s long-lived assets to fair value.

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The following table provides the income from our equity method investments for the three months ended March 31.

In millions	2014		2013
Triton	$	2	$	2
Horizon Pipeline		1		1
Total	$	3	$	3

Note 10 - Commitments, Guarantees and Contingencies

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.

We also are involved in legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. Although we are unable to determine the ultimate outcomes of these other contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable. For more information on these matters, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K.

Contingencies and Guarantees

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur. We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees is remote. No liability has been recorded for such guarantees and indemnifications as the fair value is immaterial.

Regulatory Matters

On December 21, 2012 Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve an imbalance of approximately 4.8 Bcf 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. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. We are currently working with the Marketers to settle this matter, and the resolution of this imbalance will ultimately be decided by the Georgia Commission. We are currently unable to predict the ultimate outcome and recovery.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites. See Note 3 for additional information.

Litigation

We are involved in litigation arising in the normal course of business. Although in some cases the company is unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. Management believes that while the resolution of these contingencies, whether individually or in aggregate, could be material to earnings in a particular period, they will not have a material adverse effect on our consolidated financial position or cash flows. For additional litigation information, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K.

PBR Proceeding Nicor Gas’ PBR plan was a regulatory plan that provided economic incentives based on natural gas cost performance. The PBR plan went into effect in 2000 and was terminated effective January 1, 2003, following allegations that Nicor Gas acted improperly in connection with the plan. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. Since 2002 the amount of the savings and losses required to be shared has been disputed by the Citizens Utility Board (CUB) and others, with the Illinois Attorney General (IAG) intervening, and subject to extensive contested discovery and other regulatory proceedings before administrative law judges and the Illinois Commission. In 2009, the staff of the Illinois Commission, IAG and CUB requested refunds of $85 million, $255 million and $305 million, respectively.

In February 2012 we committed to a stipulation with the staff of the Illinois Commission for a resolution of the dispute through the crediting to Nicor Gas customers of $64 million. On November 5, 2012 the Administrative Law Judges issued a proposed order for a refund of $72 million to ratepayers. In the fourth quarter of 2012, we increased our accrual for this dispute by $8 million for a total of $72 million as a result of these developments and their effect on the estimated liability.

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On June 7, 2013 the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas customers over a 12-month period. On July 1, 2013 we began refunding customers the full $72 million through our purchased gas adjustment mechanism based on natural gas throughput. Of this amount, $35 million was refunded during the first quarter of 2014 and $29 million was refunded in 2013.

CUB appealed the Illinois Commission’s order to the appellate court in Illinois. On February 28, 2014 CUB filed its initial brief with the appellate court requesting refunds consistent with its 2009 request. Nicor Gas’ reply is due May 16, 2014.

Note 11 - Segment Information

Our operating segments comprise revenue-generating components of our company for which we produce separate financial information internally that is regularly used 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 five operating segments - distribution operations, retail operations, wholesale services, midstream operations, cargo shipping - and other, a non-operating segment.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in seven states. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities. Although the operations of our distribution operations segment are geographically dispersed, the operating subsidiaries within the distribution operations segment are regulated utilities, with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.

We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia, as well as various businesses that market retail energy-related products and services to residential and small business customers in Illinois. Additionally, retail operations provide home protection products and services. Our wholesale services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, they provide natural gas asset management and/or related logistics services for each of our utilities except Nicor Gas, as well as for nonaffiliated companies. Our midstream operations segment includes our non-utility storage and pipeline operations, including the operation of high-deliverability natural gas storage assets.

Our cargo shipping segment transports containerized cargo between Florida, the eastern coast of Canada, the Bahamas and the Caribbean region. Our cargo shipping segment also includes amounts related to cargo insurance coverage sold to our customers and other third parties. Our cargo shipping segment’s vessels are under foreign registry, and its containers are considered instruments of international trade. Our other segment includes intercompany eliminations and aggregated subsidiaries that are individually not significant on a stand-alone basis and that do not fit into one of our other five operating segments.

The chief operating decision maker of the company is the Chairman, President and Chief Executive Officer who utilizes EBIT as the primary measure of profit and loss in assessing the results of our segments and 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.

Information by segment on our Statements of Financial Position as of December 31, 2013 is as follows:

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	11,727		$	1,640
Retail operations		694			173
Wholesale services		1,166			-
Midstream operations		713			14
Cargo shipping		445			61
Other (2)		(89	)		-
Consolidated	$	14,656		$	1,888

(1)   Identifiable assets are those assets used in each segment’s operations.

(2)   The assets of our other segment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

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Summarized Statements of Income, Statements of Financial Position and capital expenditure information by segment as of and for the periods presented are shown in the following tables.

Three months ended March 31, 2014

In millions	Distribution operations		Retail operations		Wholesale  services (1)		Midstream  operations			Cargo shipping			Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	1,738	$	406	$	286	$	44		$	89		$	-		$	2,563
Intercompany revenues		75		-		47		-			-			(122	)		-
Total operating revenues		1,813		406		333		44			89			(122	)		2,563
Operating expenses
Cost of goods sold		1,202		280		3		36			55			(122	)		1,454
Operation and maintenance		211		37		36		6			29			(2	)		317
Depreciation and amortization		80		6		-		5			5			2			98
Taxes other than income taxes		82		1		1		1			2			2			89
Goodwill impairment loss		-		-		-		-			19			-			19
Total operating expenses		1,575		324		40		48			110			(120	)		1,977
Operating income (loss)		238		82		293		(4	)		(21	)		(2	)		586
Other income		1		-		-		1			2			(1	)		3
EBIT	$	239	$	82	$	293	$	(3	)	$	(19	)	$	(3	)	$	589
Identifiable and total assets (2)	$	11,923	$	749	$	1,782	$	698		$	419		$	(195	)	$	15,376
Capital expenditures	$	150	$	3	$	1	$	-		$	3		$	7		$	164

Three months ended March 31, 2013

In millions	Distribution operations		Retail operations		Wholesale services (1)		Midstream operations		Cargo  shipping		Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	1,264	$	302	$	39	$	24	$	87	$	(7	)	$	1,709
Intercompany revenues		55		-		-		-		-		(55	)		-
Total operating revenues		1,319		302		39		24		87		(62	)		1,709
Operating expenses
Cost of goods sold		765		195		10		12		53		(62	)		973
Operation and maintenance		185		31		13		6		28		(4	)		259
Depreciation and amortization		90		5		-		4		5		3			107
Taxes other than income taxes		64		1		1		1		1		3			71
Total operating expenses		1,104		232		24		23		87		(60	)		1,410
Operating income (loss)		215		70		15		1		-		(2	)		299
Other income		3		-		-		1		2		(1	)		5
EBIT	$	218	$	70	$	15	$	2	$	2	$	(3	)	$	304
Identifiable and total assets (2)	$	11,258	$	668	$	1,005	$	714	$	459	$	(164	)	$	13,940
Capital expenditures	$	137	$	1	$	-	$	4	$	1	$	5		$	148

(1)   Wholesale services records its energy marketing and risk management revenues on a net basis. 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 ending March 31, 2014	$	4,051	$	298	$	4,349	$	4,016	$	333
Three months ending March 31, 2013		2,094		140		2,234		2,195		39

(2)   Identifiable assets are those used in each segment’s operations.

(3)   The assets of our other segment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

Note 12 - Subsequent Events

Sale of Tropical Shipping and Seven Seas On April 4, 2014 we entered into a definitive agreement to sell Tropical Shipping and Seven Seas after we obtained board approval for the transaction on such date, and we expect to close the transaction during the third quarter of 2014. After-tax cash proceeds and distributions from the transaction are expected to be $220 million, subject to certain defined post-closing adjustments. As discussed in Note 2, we recognized income tax expense of $31 million in the three months ended March 31, 2014 related to the cumulative earnings for which no tax liabilities had previously been recorded and we expect to record additional income tax expense of $29 million in the third quarter of 2014 related to the taxable gain on the sale. Completion of the transaction is conditioned upon, among other things, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the Florida Office of Insurance Regulation.

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As discussed in Note 2, we recorded a $19 million impairment loss related to goodwill that was assigned to cargo shipping in conjunction with our 2011 merger with Nicor. This impairment loss represents one-third of the total goodwill that was assigned to this operating segment in purchase accounting. The goodwill impairment was recognized as of March 31, 2014 since we had indication that the fair value of Tropical Shipping and Seven Seas was below the carrying value.

Tropical Shipping and Seven Seas have operated within our cargo shipping segment. Financial results for these entities will be classified as discontinued operations beginning in the second quarter of 2014. Cargo shipping also includes our investment in Triton, which will be reclassified into the other segment.

Dalton Lateral Pipeline On April 11, 2014 we entered into two arrangements associated with the Dalton Lateral pipeline. The first was a construction and ownership agreement through which we will have a 50% undivided ownership interest in the 106 mile Dalton Lateral pipeline that will be constructed in Georgia and serve as an extension of the Transco natural gas pipeline system into northwest Georgia. Our 50% undivided ownership interest is expected to cost approximately $210 million. We also entered into an agreement to lease our 50% undivided ownership in the Dalton Lateral pipeline once it is placed in-service. The annual lease payments to be received are $26 million for an initial term of 25 years. The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC regulated tariff. Engineering design work has commenced and construction is expected to begin in the second quarter of 2016 with a targeted completion date in the second quarter of 2017. On April 14, 2014, Atlanta Gas Light entered into an agreement with the lessee to acquire firm transportation capacity of 240,000 dekatherms per day associated with the Dalton Lateral pipeline. This capacity will be allocated to the Marketers and will further enhance system reliability as well as provide access to a more diverse supply of natural gas.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the notes to our unaudited Condensed Consolidated Financial Statements in this quarterly filing, as well as our 2013 Form 10-K. Results for the interim periods presented are not necessarily indicative of the results to be expected for the full fiscal period due to seasonal and other factors.

Forward-Looking Statements

Certain expectations and projections regarding our future performance referenced in this section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC or otherwise release to the public and on our website are forward-looking statements and are subject to uncertainties and risks. Senior officers and other employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.

Forward-looking statements often include words such as "anticipate," "assume," “believe,” "can," "could," "estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” “proposed,” "seek," "should," "target," "would," or similar expressions. You are cautioned not to place undue reliance on our forward-looking statements. While we believe that our expectations are reasonable in view of the available information that we currently have, our expectations are subject to future events, risks and uncertainties, and there are numerous factors - many beyond our control - that could cause our actual results to vary from our expectations.

Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation including any changes related to climate change; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, unexpected change in project costs, including the cost of funds to finance these projects and our ability to recover our project costs from our customers; limits on pipeline capacity; the impact of acquisitions and divestitures; our ability to successfully integrate operations that we have or may acquire or develop in the future; direct or indirect effects on our business, financial condition or liquidity resulting from any change in our credit ratings, or any change in the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including disruptions in the capital markets and lending environment; general economic conditions; uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans; the impact of our depreciation study for Nicor Gas and related legislation; conditions to closing the sale of Tropical Shipping and Seven Seas; the capacity of our gas storage caverns; the impact of our construction projects and related capital expenditures; the impact of changes in weather, including climate change, on the temperature-sensitive portions of our business; the impact of natural disasters, such as hurricanes, on the supply and price of natural gas and on our cargo shipping business; acts of war or terrorism; the outcome of litigation; and other factors discussed elsewhere herein and in our other filings with the SEC. There also may be other factors that we do not anticipate or that we do not recognize as material that are not described in this report that could cause our actual results to differ materially from our expectations.

Forward-looking statements speak only as of the date they are made. We expressly disclaim any obligation to publicly update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required under U.S. federal securities law.

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Executive Summary

We are an energy services holding company whose principal business is the distribution of natural gas in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland - through our seven natural gas distribution utilities. We are also involved in several other businesses that are primarily related and complementary to the distribution of natural gas. Our operating segments consist of the following five operating and reporting segments - distribution operations, retail operations, wholesale services, midstream operations and cargo shipping and one non-operating segment - other. These segments are consistent with how management views and operates our business. For additional information on our operating segments, see Note 10 to our unaudited Condensed Consolidated Financial Statements herein and Item 1, “Business” of our 2013 Form 10-K.

In April 2014, we entered into a definitive agreement to sell Tropical Shipping and Seven Seas, and we anticipate closing the transaction in the third quarter of 2014. After-tax cash proceeds and distributions from the transaction are expected to be $220 million, subject to certain defined post-closing adjustments. Completion of the transaction is conditioned upon, among other things, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the Florida Office of Insurance Regulation.

As a result of the sale, we expect to pay income taxes of approximately $60 million. During the first quarter of 2014, we recorded income tax expense of $31 million related to cumulative foreign earnings for which income taxes had not previously been recorded. We also recorded a goodwill impairment charge of $19 million, for which there is no income tax benefit, during the first quarter of 2014 based upon the agreed-upon sale price. Upon closing, we expect to record income tax expense of $29 million associated with the taxable gain on the sale. On a combined basis, this is expected to result in a reported income tax and impairment expense of approximately $0.66 per share, of which $0.42 was recorded in the first quarter of 2014 with the remainder to be recorded upon completion of the sale.

Tropical Shipping and Seven Seas have operated as part of our cargo shipping segment. Financial results for these entities will be classified as discontinued operations beginning in the second quarter of 2014. The cargo shipping segment also includes our investment in Triton, which will be reclassified into our other segment.

In the first three months of 2014, our net income attributable to AGL Resources Inc. was $290 million, an increase of $136 million compared to the same period in 2013, as we benefited from significantly colder-than-normal weather in most of our businesses as compared to slightly colder-than-normal weather in the first quarter of 2013. This cold weather contributed an additional $11 million of operating margin for distribution operations compared to the first quarter of 2013, particularly in Illinois due to the near-record cold. This cold weather also increased the operating margin for retail operations by $11 million, primarily related to Georgia and Illinois, compared to the first quarter of 2013. Additionally, we experienced increased natural gas price volatility that enabled us to capture value in wholesale services. As a result, our operating margin for wholesale services was $301 million higher than the same period in 2013. Wholesale services operating margin for the first quarter 2014 also includes $45 million related to 2013 year-to-date transportation and forward commodity derivative losses associated with 2014 transportation capacity. This is compared to $2 million of similar transportation derivative losses in the first quarter of 2013 related to 2012 year-to-date transportation and forward commodity derivative losses associated with 2013 transportation capacity. Excluding the favorable weather impacts at distribution operations and retail operations, we also achieved growth in our operating margins of $12 million during the first three months of 2014 primarily as a result of our 2013 acquisitions at retail operations.

Our operating expenses in the first quarter of 2014 were higher compared to the same period last year as a result of an increase in incentive compensation, as we experienced a higher concentration of our annual forecasted earnings in the first quarter as compared to last year. Additionally, our operation and maintenance expense increased at Nicor Gas associated with the cold weather. During this significantly colder-than-normal weather, our employees worked extensive hours to ensure the safe and reliable delivery of natural gas to our customers.

As discussed in Note 2 to the unaudited Condensed Consolidated Financial Statements under Part 1, Item 1 herein, our income tax expenses were higher by $31 million as a result of the cumulative foreign earnings of cargo shipping, which will no longer be indefinitely reinvested offshore. This resulted in an effective tax rate of 45.2% for the three months ended March 31, 2014 compared to 37.9% for the same period last year.

Several of our specific business objectives are as follows:

· Distribution Operations: Invest necessary capital to enhance and maintain safety and reliability; remain a low-cost leader within the industry; opportunistically expand the system and capitalize on potential customer conversions. We intend to continue investing in our regulatory infrastructure programs in Georgia, Virginia, New Jersey and Tennessee to minimize regulatory lag and the recovery cycle.

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Nicor Gas In 2013 Illinois enacted legislation that will allow Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customer bills as a result of any infrastructure investments shall not exceed an annual average 4.0% of base rate revenues. In April 2014 we filed for an infrastructure program under this legislation that would allow us to implement rates under the program effective in January 2015. Our filing included qualified infrastructure cost estimates for three years of $171 million in 2015, $173 million in 2016 and $171 million in 2017. We continue to effectively manage costs and leverage our shared services model across our businesses to largely overcome inflationary effects.

Nicor Gas’ collective bargaining agreement expired in February 2014, and a new agreement was ratified in April 2014. During the interim period we operated under a continuity agreement. The new collective bargaining agreement provides for additional operational enhancements and changes to certain benefits, but is not expected to have a material effect on our consolidated financial statements.

In September 2013 Nicor Gas filed its second Energy Efficiency Plan, which outlines program offerings and therm reduction goals with spending of $93 million over a three-year period beginning in June 2014. Nicor Gas’ first Energy Efficiency Program is currently in its third year and will end in May 2014. The new plan must be implemented by June 1, 2014. All testimony in the case has been filed with the Illinois Commission, and evidentiary hearings were held in March 2014. We expect to receive a final ruling by the Illinois Commission in mid-May 2014, to be effective in June 2014.

Atlanta Gas Light In accordance with an order issued by the Georgia Commission, where AGL Resources makes a business acquisition that reduces the costs allocated or charged to Atlanta Gas Light for shared services, the net savings to Atlanta Gas Light will be shared equally between the firm customers of Atlanta Gas Light and our shareholders for a ten-year period. In December 2013 we filed a Report of Synergy Savings with the Georgia Commission in connection with the Nicor acquisition. If and when approved, the net savings are expected to result in annual rate reductions to the firm customers of Atlanta Gas Light of $5 million. We expect the Georgia Commission to rule on the report in the second or third quarter of 2014.

Virginia Natural Gas In April 2014 the Governor of Virginia signed into law legislation that enables the state's natural gas utilities, including Virginia Natural Gas, to acquire long-term supplies of natural gas and make capital investments to facilitate the delivery of low-cost shale and coal-bed methane gas to Virginia homeowners and businesses. Under the terms of the new statute, Virginia Natural Gas could enter into commercial agreements to obtain up to 25% of its annual firm sales demand for natural gas through long-term contracts or investments such as purchases of reserves. Recovery on investments would be based upon the utility's authorized return on rate base, which would flow through the purchased gas adjustment mechanism or similar mechanism, and approval in advance by the Virginia Commission. The new statute will also allow us to build pipelines and other infrastructure that deliver shale and coal-bed methane gas into the state's markets that seek to reduce natural gas supply costs or reduce price volatility for consumers, if approved by the Virginia Commission.

Elizabethtown Gas In March 2013, the New Jersey BPU issued an order inviting the submission of proposals from utilities in New Jersey for infrastructure upgrades designed to protect utility infrastructure from future major storm events. In September 2013, in response to this request, Elizabethtown Gas filed for a Natural Gas Distribution Utility Reinforcement Effort (ENDURE), a program that will improve our distribution system’s resiliency against coastal storms and floods. Under the proposed plan, Elizabethtown Gas will invest $15 million in infrastructure and related facilities and communication planning over a one-year period beginning January 2014. Elizabethtown Gas is proposing to accrue and defer carrying charges on the investment until its next rate case proceeding. According to the procedural order in the case, a ruling by the New Jersey BPU is expected in the third quarter of 2014.

· Retail Operations: Maintain operating margin in Georgia and Illinois while continuing to expand into other profitable retail markets; integrate our warranty businesses and expand our overall market reach through partnership opportunities with our affiliates. With the continued adoption of fixed-price plans, we expect the Georgia retail market to remain highly competitive; however, our operating margins are forecasted to remain stable with modest growth from the acquisitions completed in 2013 and expansion into new markets.

· Wholesale Services: Maximize strong storage and transportation positions, including the creation of additional economic value in 2014; effectively perform on existing asset management agreements and expand customer base and maintain cost structure in line with market fundamentals. We anticipate low volatility in certain areas of our portfolio; however, we expect a continuation of volatility in the supply-constrained Northeast corridor in the near-term. We continue to position our business model to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage.

· Midstream Operations: Optimize storage portfolio, including contracts that have expired or will expire, pursue LNG transportation and natural gas pipeline opportunities and evaluate alternate uses for our storage facilities. In April 2014 we entered into a collaborative arrangement to construct a lateral pipeline in Georgia that will connect with the Transco pipeline system. Also in April 2014 we entered into an agreement to lease our 50% ownership in this lateral pipeline extension once it is placed in-service. For more information on the transactions, see Note 12 to the unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein.

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We will continue to identify opportunities that arise as a result of attractive natural gas pricing relative to other fuel sources. Additionally, the sale of Tropical Shipping and Seven Seas allows us to focus on growing our core business of operating regulated utilities and complementary non-regulated businesses. We will also continue to maintain our strong balance sheet and liquidity profile, solid investment grade ratings and our commitment to sustainable annual dividend growth.

Natural Gas Market Fundamentals Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of retail operations and wholesale services to capture value from location and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of our operations to earnings variability.

While natural gas supply increased during the 2013/2014 Heating Season in the U.S., it was not enough to meet the increased demand, resulting in the lowest storage levels in over a decade. Assuming normal weather during the next year, we expect this will result in higher natural gas prices as storage levels are restored.

Our non-utility businesses principally use physical and financial arrangements to reduce the risks associated with both weather-related seasonal fluctuations in market conditions and changing commodity prices. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs. These economic hedges may not qualify, or may not be designated, for hedge accounting treatment. As a result, our reported earnings for the wholesale services, retail operations and midstream operations segments reflect changes in the fair values of certain derivatives. Accordingly, a decline in natural gas prices or decreases in transportation spreads generally results in derivative gains and corresponding increases in EBIT, while an increase in natural gas prices or a widening of transportation spreads generally results in derivative losses and corresponding decreases in EBIT.These values may change significantly from period to period and are reflected as gains or losses within our operating revenues or our OCI for those derivative instruments that qualify and are designated as accounting hedges.

Results of Operations

We generate the majority of our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed to residential, commercial and industrial customers from the date of the last bill to the end of the reporting period. No individual customer or industry accounts for a significant portion of our revenues.

The operating revenues and EBIT of distribution operations and retail operations are seasonal. During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. Our base operating expenses, excluding cost of gas, revenue taxes, interest expense and certain incentive compensation costs, are generally incurred relatively evenly over any given year. Thus, our operating results vary significantly from quarter to quarter as a result of seasonality.

We evaluate segment performance using the measures of EBIT and operating margin. EBIT includes operating income and other income and expenses. Items that we do not include in EBIT are financing costs (including interest) and income taxes, each of which we evaluate on a consolidated basis. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of goods sold and revenue tax expense in distribution operations. Operating margin excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes, and the gain or loss on the sale of our assets, if any. These items are included in our calculation of operating income as reflected in our unaudited Condensed Consolidated Statements of Income.

We believe operating margin is a better indicator than operating revenues of the contribution resulting from customer growth in distribution operations, since the cost of goods sold and revenue tax expenses can vary significantly and are generally billed directly to our customers. We also consider operating margin to be a better indicator in retail operations, wholesale services, midstream operations and cargo shipping, since it is a direct measure of operating margin generated before overhead costs. You should not consider operating margin an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, our operating margin may not be comparable to similarly titled measures of other companies.

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We also believe presenting the non-GAAP measurement of diluted earnings per share - as adjusted, provides investors with an additional measure of our performance that excludes the impact of goodwill impairment and tax expense due to the sale of Tropical Shipping and Seven Seas and is more indicative of our ongoing performance. Adjusted diluted earnings per share should not be considered an alternative to, or a more meaningful indicator of, our operating performance than our GAAP diluted earnings per share. The following table reconciles operating revenue and operating margin to operating income; EBIT to income before income taxes and net income; and GAAP diluted earnings per common share to non-GAAP diluted earnings per share – as adjusted, together with other consolidated financial information for the periods presented.

	Three months ended March 31,
In millions, except per share amounts	2014			2013			Change
Operating revenues	$	2,563		$	1,709		$	854
Cost of goods sold		(1,454	)		(973	)		(481	)
Revenue tax expense (1)		(67	)		(49	)		(18	)
Operating margin		1,042			687			355
Operating expenses		(523	)		(437	)		(86	)
Revenue tax expense (1)		67			49			18
Operating income		586			299			287
Other income		3			5			(2	)
EBIT		589			304			285
Interest expenses		(48	)		(46	)		(2	)
Income before income taxes		541			258			283
Income tax expenses		(239	)		(94	)		(145	)
Net income		302			164			138
Less net income attributable to the noncontrolling interest		12			10			2
Net income attributable to AGL Resources Inc.	$	290		$	154		$	136
Per common share data
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	2.44		$	1.31		$	1.13
Goodwill impairment and tax expense due to sale of Tropical Shipping and Seven Seas		0.42			-			0.42
Diluted earnings per share – as adjusted	$	2.86		$	1.31		$	1.55

(1)   Adjusted for Nicor Gas’ revenue tax expenses, which are passed directly through to customers.

Operating Metrics

Weather We measure the effects of weather on our business through Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on our distribution systems. With the exception of Nicor Gas and Florida City Gas, we have various regulatory mechanisms, such as weather normalization, which limit our exposure to weather changes within typical ranges in each of our utilities’ respective service areas. However, our customers in Illinois and retail operations’ customers in Georgia can be impacted by warmer or colder-than-normal weather. We have presented the Heating Degree Day information for those locations in the following table.

Weather (Heating Degree Days)			Three months ended March 31,					2014 vs. 2013			2014 vs. normal
	Normal			2014		2013		colder			colder
Illinois (1) (2)		2,985			3,756		3,153		19	%		26	%
Georgia (1)		1,442			1,733		1,461		19	%		20	%

(1)   Normal represents the ten-year average from January 1, 2004 through March 31, 2013, for Illinois at Chicago Midway International Airport, and for Georgia at Atlanta Hartsfield-Jackson International Airport as obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.

(2)   The 10-year average Heating Degree Days for the period, as established by the Illinois Commission in our last rate case, is 2,902 for the first three months from 1998 through 2007.

For our weather risk associated with Nicor Gas, we implemented a corporate weather hedging program in 2013 that utilizes OTC weather derivatives to reduce the risk of lower operating margins potentially resulting from decreased customer usage in the event of significantly warmer-than-normal weather in Illinois. We purchased a put option covering January through April 2014. Since the first three months of 2014 were significantly colder-than-normal, this option was not exercised during the first quarter of 2014. We will continue to evaluate and use available methods to mitigate our exposure to weather in Illinois for future periods.

During the three months ended March 31, 2014 we experienced weather in Illinois that was 26% colder-than-normal and 19% colder than last year. The 2013/2014 Heating Season was one of the coldest on record for Illinois, which positively impacted our operating margin by $17 million in the first quarter of 2014 compared to normal weather. Georgia also experienced 20% colder-than-normal weather, and 19% colder than last year. This colder weather positively impacted our operating margin in Georgia by $18 million in the first quarter of 2014 compared to normal weather.

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Customers Our customer metrics highlight the average number of customers for which we provide services and are provided in the table below. The number of customers at distribution operations and energy customers at retail operations can be impacted by natural gas prices, economic conditions and competition from alternative fuels. Our energy customers at retail operations are primarily located in Georgia and Illinois.

Customers and service contracts (average end-use, in thousands)	Three months ended March 31,						2014 vs.2013
	2014			2013			% change
Distribution operations customers		4,532			4,501			1	%
Retail operations
Energy customers (1)		636			613			4	%
Service contracts (2)		1,197			997			20	%
Market share in Georgia		31	%		32	%		(3	)%

(1)   Increase primarily represents the addition of approximately 33,000 residential and commercial customer relationships acquired in Illinois in June 2013.

(2)   Increase primarily due to acquisition of approximately 500,000 service contracts on January 31, 2013. Prior year amount revised to reflect a change in methodology.

Our year-over-year consolidated utility customer growth rate was 1% for the three months ended March 31, 2014. We anticipate overall utility customer growth trends for 2014 to continue improving based on an expectation of improvement in the economy and relatively low natural gas prices.

Retail operations’ market share in Georgia has decreased slightly primarily as a result of a highly competitive marketing environment, which we expect will continue for the foreseeable future. In 2014 our retail operations segment intends to continue its efforts to enter into targeted markets and expand its energy customers and its service contracts. We anticipate this expansion will provide growth opportunities in future years.

Volumes Our natural gas volume metrics for distribution operations and retail operations, as shown in the following table, present the effects of weather and our customers’ demand for natural gas compared to prior year. The cold weather experienced during this past Heating Season resulted in a decrease in the natural gas inventory in our storage facilities, which has fallen to its lowest level since 2003. This weather contributed to increased revenues as a result of peak market demand for natural gas storage services. However, the storage business remains challenged due to continued oversupply of natural gas.

Wholesale services’ daily physical sales volumes represent the daily average natural gas volumes sold to its customers. Within our midstream operations segment, our natural gas storage businesses seek to have a significant percentage of their working natural gas capacity under firm subscription, but also take into account current and expected market conditions. This allows our natural gas storage business to generate additional revenue during times of peak market demand for natural gas storage services, but retain some consistency with their earnings and maximize the value of the investments. Additionally, cargo shipping measures the volume of shipments during the period in TEUs. We continue to seek opportunities to profitably increase our number of TEUs and maximize the utilization of our containers and vessels.

Our midstream operations storage business is cyclical. The abundant supply of natural gas in recent years and the resulting lack of market and price volatility have negatively impacted the profitability of our storage facilities. Consistent with our expectations, we had contracts expire on March 31, 2014 that were subscribed at lower prices as compared to prior years. We anticipate these lower natural gas prices to continue throughout 2014 as compared to historical averages. The prices for natural gas storage capacity are expected to increase as supply and demand quantities reach equilibrium as the economy improves, expected exports of LNG occur and/or natural gas demand increases in response to low prices and expanded uses for natural gas. As of April 1, 2014 and 2013 the overall monthly average firm subscription rates per facility were as follows:

	Average Monthly Rate per Dekatherm
	April 1, 2014 (1)		April 1, 2013
Jefferson Island (2)	$	0.108	$	0.122
Golden Triangle (2)		0.123		0.240
Central Valley (2)		0.062		0.130

(1)	Includes contracts beginning April 15, 2014 and May 1, 2014.
(2)	Excludes 7.0 Bcf of firm capacity contracted by Sequent as of April 1, 2014 at an average monthly rate of $0.055 and 3.5 Bcf as of April 1, 2013 at an average monthly rate of $0.101.

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Our volume metrics are presented in the following table:

Volumes	Three months ended March 31,				2014 vs. 2013
	2014		2013		% change
Distribution operations (In Bcf)
Firm		362		309		17	%
Interruptible		28		30		(7	)%
Total		390		339		15	%
Retail operations (In Bcf)
Georgia firm		21		18		17	%
Illinois		10		4		150	%
Other (1)		4		3		33	%
Wholesale services
Daily physical sales (Bcf / day)		7.3		6.3		16	%
Cargo shipping (TEU’s - in thousands)
Shipments		46		45		2	%

	As of March 31,
	2014			2013
Midstream operations
Estimated working natural gas capacity (in Bcf)		31.8			31.8
% of firm capacity under subscription by third parties (2)		38	%		46	%

(1)   Includes Florida, Maryland, New York and Ohio.

(2)   The percentage of firm capacity under subscription does not include 4.5 Bcf of capacity under contract with Sequent at March 31, 2014 and 3 Bcf of capacity under contract with Sequent at March 31, 2013.

Segment Information Operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables:

	Three months ended March 31, 2014							Three months ended March 31, 2013
In millions	Operating  margin (1) (2)		Operating expenses (2)		EBIT (1)			Operating margin (1) (2)		Operating expenses (2)		EBIT (1)
Distribution operations	$	544	$	306	$	239		$	505	$	290	$	218
Retail operations		126		44		82			107		37		70
Wholesale services		330		37		293			29		14		15
Midstream operations		8		12		(3	)		12		11		2
Cargo shipping		34		55		(19	)		34		34		2
Other		-		2		(3	)		-		2		(3	)
Consolidated	$	1,042	$	456	$	589		$	687	$	388	$	304

(1)   Operating margin is a non-GAAP measure. A reconciliation of operating revenue and operating margin to operating income, and EBIT to income before income taxes and net income is contained in “Results of Operations” herein. See Note 11 to our unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein for additional segment information.

(2)   Operating margin and operating expenses are adjusted for revenue tax expense for Nicor Gas, which is passed directly through to customers.

Distribution Operations

Our distribution operations segment is the largest component of our business and is subject to regulation and oversight by agencies in each of the seven states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs, such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return for our shareholders.

With the exception of Atlanta Gas Light, our second-largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas and general economic conditions that may impact our customers’ ability to pay for natural gas consumed. Depreciation expense at distribution operations decreased by $10 million, primarily due to Nicor Gas’ new composite depreciation rate that became effective August 30, 2013, partially offset by capital investments. Nicor Gas’ lower composite depreciation rate did not impact customer rates. For the three months ended March 31, 2014 distribution operations’ EBIT increased by $21 million, or 10%, compared to the same period during the prior year, as shown in the following table.

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In millions	Three months ended
EBIT - for March 31, 2013		$	218
Operating margin
Increased operating margin mainly driven by significantly colder-than-normal weather, higher customer usage and customer growth compared to prior year			24
Increased rider revenues primarily as a result of energy efficiency program recoveries at Nicor Gas			11
Increased revenues from regulatory infrastructure replacement programs, primarily at Atlanta Gas Light			4
Increase in operating margin			39
Operating expenses
Increased variable compensation costs as a result of overtime related to colder-than-normal weather, higher earnings and the seasonality of earnings			16
Increased rider expenses primarily as a result of energy efficiency program expenses at Nicor Gas			11
Increased outside services and other expenses primarily from costs related to weather			3
Decreased depreciation expense primarily due to the impact of Nicor Gas’ new composite depreciation rate			(10	)
Decreased pension and health benefits expenses primarily related to retiree health care costs and change in actuarial gains and losses			(4	)
Increase in operating expenses			16
Decreased AFUDC equity from STRIDE projects at Atlanta Gas Light			(2	)
EBIT - for March 31, 2014		$	239

Retail Operations

Our retail operations segment, which consists of SouthStar and Pivotal Home Solutions, is also weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. For the three months ended March 31, 2014 retail operations’ EBIT increased by $12 million, or 17%, compared to the same period during the prior year, as shown in the following table.

In millions	Three months ended
EBIT - for March 31, 2013		$	70
Operating margin
Increased margin primarily due to retail acquisitions in 2013			12
Increased margin primarily related to average customer usage in Georgia due to colder-than-normal weather and increased demand relative to prior year, net of weather hedges			7
Increased margin in Illinois mainly due to favorable gas costs, lower supply agreement fees and timing of hedge gains, partially offset by unfavorable timing of revenue associated with fixed bill products			3
Decrease related to increased gas costs and lower retail price spreads			(5	)
Increased margin for large commercial and industrial customers due to increased peaking sales			2
Increase in operating margin			19
Operating expenses
Increased expenses primarily due to retail acquisitions in 2013			4
Increased customer care and marketing expenses associated with attracting and retaining customers			2
Increased bad debt expense primarily related to colder-than-normal weather and higher natural gas prices			1
Increase in operating expenses			7
EBIT - for March 31, 2014		$	82

Wholesale Services

Our wholesale services segment is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services and wholesale marketing. Sequent has positioned the business to generate positive economic earnings even under low volatility market conditions. However, when market price volatility increases as we experienced in the first quarter of 2014, we believe Sequent is well positioned to capture significant value and generate stronger results. EBIT for our wholesale services segment is impacted by volatility in the natural gas market arising from a number of factors, including weather fluctuations and changes in supply or demand for natural gas in different regions of the country. For the three months ended March 31, 2014, wholesale services’ EBIT increased by $278 million compared to prior year, as shown in the following table.

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In millions	Three months ended
EBIT - for March 31, 2013		$	15
Operating margin
Change in commercial activity associated with the transportation and storage portfolios in the Northeast and Midwest largely driven by price volatility resulting from extremely cold temperatures			331
Change in value on storage derivatives as a result of changes in NYMEX natural gas prices			15
Change in LOCOM adjustment, net of derivative recoveries			(2	)
Decreased operating margin due to sale of Compass Energy in May 2013			(4	)
Change in value on transportation and forward commodity derivatives from price movements related to natural gas transportation positions			(39	)
Increase in operating margin			301
Operating expenses
Increased incentive compensation costs due to higher operating revenues			25
Decreased expenses due to sale of Compass Energy in May 2013			(2	)
Increase in operating expenses			23
EBIT - for March 31, 2014		$	293

The following table illustrates the components of wholesale services’ operating margin for the periods presented.

	Three months ended March 31,
In millions	2014			2013
Commercial activity recognized	$	377		$	50
Loss on storage derivatives		(2	)		(17	)
Inventory LOCOM adjustment, net of estimated current period recoveries		(2	)		-
Loss on transportation and forward commodity derivatives		(43	)		(4	)
Operating margin	$	330		$	29

Change in commercial activity The commercial activity at wholesale services includes recognized storage and transportation values that were generated in prior periods, which reflect the impact of prior period derivative gains and losses as associated physical transactions occur in the period. Additionally, the commercial activity includes significantly higher operating margin generated and recognized in the current period. For the first three months of 2014, commercial activity increased significantly due to:

· the recognition of operating margin associated with our transportation and storage portfolios, particularly in the Northeast and Midwest regions, from price volatility generated by significantly colder-than-normal weather, in part reflecting Sequent’s strategy and focus on providing asset management type services to producers around the major shale producing regions and to gas fired power generators, enabling Sequent to optimize the associated pipeline transportation and storage capacity assets,

· the recognition of operating margin resulting from the withdrawal of storage inventory at the end of 2013 that was included in the storage withdrawal schedule with a value of $28 million as of December 31, 2013,

· the recognition of operating margin resulting from mark-to-market accounting derivative losses at the end of 2013

Change in storage and transportation derivatives The first quarter of 2014 showed a return of significantly higher price volatility benefitting Sequent’s portfolio of pipeline transportation and storage capacity assets throughout the country, primarily in the Northeast and Midwest markets. Although we do not expect this high level of price volatility to continue, we see the potential for market fundamentals indicating some level of increased volatility which would continue to benefit Sequent’s portfolio of pipeline transportation capacity should this occur. Storage derivative losses during the first quarter of 2014 are primarily due to the increase in natural gas prices primarily resulting from colder weather. Losses in our transportation derivative positions during the first quarter of 2014 are the result of widening transportation basis spreads, associated with significantly colder-than-normal weather and higher demand experienced at natural gas receipt and delivery points primarily in the Northeast and the Midwest regions related to natural gas transportation constraints in the region. These losses are temporary and, based on current expectations, will largely be recovered in 2014 through 2016 with the physical flow of natural gas and utilization of the contracted transportation capacity.

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Withdrawal schedule Sequent’s expected natural gas withdrawals from storage and expected recovery of derivative losses associated with Sequent’s transportation portfolio are presented in the following tables, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Sequent’s expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt and delivery charges, but are net of the estimated impact of profit sharing under our asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points and forward natural gas prices at March 31, 2014. A portion of Sequent’s storage inventory and transportation capacity is economically hedged with futures contracts, which results in realization of substantially fixed net operating revenues, timing notwithstanding. For more information on Sequent’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk” of our 2013 Form 10-K.

Withdrawal schedule	Total storage (in Bcf) (WACOG $2.57)		Expected operating revenues (1) (in millions)
2014		4	$	6
2015		5		6
Total at March 31, 2014		9	$	12
Total at December 31, 2013		36	$	28
Total at March 31, 2013		32	$	34

(1)   Represents expected operating revenues from planned storage withdrawals associated with existing inventory positions and could change as Sequent adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.

The following table shows the periods associated with the transportation derivative losses during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative losses recognized in 2013, and during the first quarter of 2014.

In millions	Expected net  operating revenues
2014	$	14
2015		26
2016 and thereafter		3
Total at March 31, 2014	$	43
Total at December 31, 2013	$	73
Total at March 31, 2013	$	4

The unrealized storage and transportation derivative losses do not change the underlying economic value of our storage and transportation positions, and based on current expectations, will largely be reversed in 2014 and 2015 when the related transactions occur and are recognized. For more information on Sequent’s energy marketing and risk management activities, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Natural Gas Price Risk” of our 2013 Form 10-K.

Midstream Operations

Our midstream operations segment’s primary activity is operating non-utility storage and pipeline facilities, including the development and operation of high-deliverability underground natural gas storage assets. While this business can also generate additional revenue during times of peak market demand for natural gas storage services, certain of our storage services are covered under short, medium and long-term contracts at fixed market rates. Based on an engineering study completed in the first quarter of 2014, we identified a potentially lower amount of working natural gas capacity at Jefferson Island. We believe the decrease in working natural gas capacity is a result of naturally occurring salt creep or shrinkage of the storage cavern. We will conduct required mechanical integrity tests of both caverns during the first half of 2014 to more precisely measure the capacity of the facility. For the three months ended March 31, 2014 midstream operations’ EBIT decreased by $5 million compared to prior year, as shown in the following table.

In millions	Three months ended
EBIT - for March 31, 2013		$	2
Operating margin
Decreased margin at Jefferson Island due to changes in estimates for retained fuel, partially offset by higher operating margin at Golden Triangle and Central Valley due to optimizing the facilities during the colder weather in 2014			(3	)
Decreased margin at Jefferson Island, Golden Triangle and Central Valley as a result of lower subscription rates			(1	)
Decrease in operating margin			(4	)
Operating expenses
Increased depreciation expenses and other			1
Increase in operating expenses			1
EBIT - for March 31, 2014		$	(3	)

Cargo Shipping

Our cargo shipping segment’s primary activity is transporting containerized freight in the Bahamas and the Caribbean, a region that has historically been characterized by modest market growth and intense competition. Such shipments consist primarily of southbound cargo such as building materials, food and other necessities for developers, distributors and residents in the region, as well as tourist-related shipments intended for use in hotels and resorts and on cruise ships.

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In April 2014 we signed a definitive agreement to sell Tropical Shipping and Seven Seas, which have operated as part of our cargo shipping operating segment. For more information on the sale, see Note 12 to the unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein. For the three months ended March 31, 2014 cargo shipping’s EBIT decreased by $21 million compared to prior year, as shown in the following table.

In millions	Three months ended
EBIT - for March 31, 2013		$	2
Operating margin
TEU volume increased due to market share expansion and modest improvement in economic conditions in our service regions; leverage effect of volume increases on fuel expense			2
Decreased average TEU rates due to changes in cargo mix and destination, and competitive pressures, partially offset by general ocean freight rate increases			(2	)
Other
Increase in operating margin			-
Operating expenses
Goodwill impairment loss			19
Increased payroll, benefits, vessel charter expense, outside services and other			2
Increase in operating expenses			21
EBIT - for March 31, 2014		$	(19	)

Liquidity and Capital Resources

OverviewThe acquisition of natural gas and pipeline capacity, payment of dividends and funding of working capital needs primarily related to our natural gas inventory are our most significant short-term financing requirements. The liquidity required to fund these short-term needs is primarily provided by our operating activities, and any needs not met are primarily satisfied with short-term borrowings under our commercial paper programs, which are supported by the AGL Credit Facility and the Nicor Gas Credit Facility. The need for long-term capital is driven primarily by capital expenditures and maturities of long-term debt. Periodically, we raise funds supporting our long-term cash needs from the issuance of long-term debt or equity securities. We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner.

Our financing activities, including long-term and short-term debt and equity, are subject to customary approval or review by state and federal regulatory bodies, including the various commissions of the states in which we conduct business. Certain financing activities we undertake may also be subject to approval by state regulatory agencies. A substantial portion of our consolidated assets, earnings and cash flows is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. Nicor Gas is restricted by regulation to the extent of its retained earnings balance in the amount it can dividend and is not permitted to make money pool loans to affiliates.

We believe the amounts available to us under our long-term debt and credit facilities as well as through the issuance of debt and equity securities, combined with cash provided by operating activities, will continue to allow us to meet our needs for working capital, pension and retiree welfare benefits, capital expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years. Our ability to satisfy our working capital requirements and our debt service obligations, or fund planned capital expenditures, will substantially depend upon our future operating performance (which will be affected by prevailing economic conditions), and financial, business and other factors, some of which we are unable to control. These factors include, among others, regulatory changes, the price of and demand for natural gas and operational risks.

Upon closing our sale of Tropical Shipping and Seven Seas, which we anticipate to occur during the third quarter of 2014, we expect to receive after-tax cash proceeds and distributions of $220 million, subject to certain defined post-closing adjustments. During the first quarter of 2014, we decided that we no longer have the intent to indefinitely reinvest Tropical Shipping’s cash and short and long-term investments offshore. See Note 2 to our unaudited Condensed Consolidated Financial Statements under Part 1, Item 1 herein for additional information on our income taxes.

Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of debt securities and equity. This strategy includes active management of the percentage of total debt relative to total capitalization, appropriate mix of debt with fixed to floating interest rates (our variable debt target is 20% to 45% of total debt), as well as the term and interest rate profile of our debt securities. At March 31, 2014, our variable-rate debt was 21% of our total debt, compared to 28% as of December 31, 2013 and 25% as of March 31, 2013. The decrease from December 31, 2013 was primarily due to decreased commercial paper borrowings.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies and other factors. See Item 1A, “Risk Factors,” in our 2013 Form 10-K for additional information on items that could impact our liquidity and capital resource requirements.

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Capital Projects We continue to focus on capital discipline and cost control while moving ahead with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure.The following table and discussions provide updates on some of our larger capital projects under various programs at distribution operations. These programs update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2014 are discussed in “Liquidity and Capital Resources” under the caption ‘Cash Flow from Investing Activities’ under Item 7 in our 2013 Form 10-K.

Dollars in millions	Utility	Expenditures  in 2014		Expenditures since project inception		Miles of pipe installed		Year project began		Scheduled year of completion
STRIDE program
Integrated System Reinforcement Program (i-SRP)	Atlanta Gas Light	$	3	$	254		n/a		2009		2017
Integrated Customer Growth Program (i-CGP)	Atlanta Gas Light		1		40		n/a		2010		2017
Integrated Vintage Plastic Replacement Program (i-VPR)	Atlanta Gas Light		11		16		42		2013		2017
Enhanced infrastructure program	Elizabethtown Gas		2		118		113		2009		2017
Accelerated infrastructure replacement program (SAVE)	Virginia Natural Gas		7		47		95		2012		2017
Total		$	24	$	475		250

Short-term Debt Our short-term debt comprises borrowings under our commercial paper programs and current portions of our senior notes and capital leases. The following table provides additional information on our short-term debt.

In millions	Period end balance outstanding(1)		Daily average balance outstanding(2)		Minimum balance outstanding (2)		Largest balance outstanding(2)
Commercial paper - AGL Capital	$	440	$	756	$	440	$	1,006
Commercial paper - Nicor Gas		301		232		97		344
Senior notes		200		169		-		200
Total short-term debt and current portions of long-term debt and capital leases	$	941	$	1,157	$	537	$	1,550

(1)   As of March 31, 2014.

(2)   For the three months ended March 31, 2014. The minimum and largest balances outstanding for each debt instrument occurred at different times during the period. Consequently, the total balances are not indicative of actual borrowings on any one day during the period.

The largest, minimum and daily average balances borrowed under our commercial paper programs are important when assessing the intra-period fluctuations of our short-term borrowings and potential liquidity risk. The fluctuations are due to our seasonal cash requirements to fund working capital needs, in particular the purchase of natural gas inventory, margin calls and collateral.

Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected injection plan, a $1 NYMEX price increase could result in a $211 million change of working capital requirements during the 2014 injection season. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position. Based on current natural gas prices and our expected purchases during the remainder of the injection season, we believe that we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.

Credit Ratings Our borrowing costs and our ability to obtain adequate and cost-effective financing are directly impacted by our credit ratings, as well as the availability of financial markets. Credit ratings are important to our counterparties when we engage in certain transactions, including OTC derivatives. It is our long-term objective to maintain or improve our credit ratings in order to manage our existing financing costs and enhance our ability to raise additional capital on favorable terms.

Credit ratings and outlooks are opinions subject to ongoing review by the rating agencies and may periodically change. The rating agencies regularly review our performance and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, our corporate ratings and our ratings outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. A credit rating is not a recommendation to buy, sell or hold securities and each rating should be evaluated independently of other ratings.

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Factors we consider important to assessing our credit ratings include our Consolidated Statements of Financial Position, leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any 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 agreements that would require us to issue equity based on credit ratings or other trigger events. The following table summarizes our credit ratings as of March 31, 2014 and reflects no change from what was reported in our 2013 Form 10-K.

AGL Resources

Nicor Gas

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

Corporate rating

BBB+

n/a

BBB+

BBB+

n/a

A

Commercial paper

A-2

P-2

F2

A-2

P-1

F1

Senior unsecured

BBB+

A3

BBB+

BBB+

A2

A+

Senior secured

n/a

n/a

n/a

A

Aa3

AA-

Ratings outlook

Stable

Stable

Stable

Stable

Stable

Stable

A downgrade in our current ratings, particularly below investment grade, would increase our borrowing costs and could limit our access to the commercial paper market. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease.

Default ProvisionsOur debt instruments and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. Our credit facilities contain customary events of default, including, but not limited to, the failure to comply with certain affirmative and negative covenants, cross-defaults to certain other material indebtedness and a change of control.

Our 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.

Our credit facilities each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. However, we typically seek to maintain these ratios at levels between 50% and 60%, except for temporary increases related to the timing of acquisition and financing activities. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed. We were in compliance with all of our debt provisions and covenants, both financial and non-financial, for all periods presented.

	AGL Resources							Nicor Gas
		Mar. 31,		Dec. 31,		Mar. 31,			Mar. 31,		Dec. 31,		Mar. 31,
		2014		2013		2013			2014		2013		2013
Debt-to-capitalization ratio as calculated from our unaudited Condensed Consolidated Statement of Financial Position		54	%	58	%	55	%		53	%	54	%	42	%
Adjustments (1)		(1	)	(1	)	(1	)		1		1		1
Debt-to-capitalization ratio as calculated from our credit facilities		53	%	57	%	54	%		54	%	55	%	43	%

(1)   As defined in credit facilities, includes standby letters of credit, performance/surety bonds and excludes accumulated OCI items related to non-cash pension adjustments, other post-retirement benefits liability adjustments and accounting adjustments for cash flow hedges.

Cash Flows The following table provides a summary of our operating, investing and financing cash flows for the periods presented.

	Three months ended March 31,
In millions	2014			2013			Variance
Net cash provided by (used in):
Operating activities	$	853		$	850		$	3
Investing activities		(164	)		(256	)		92
Financing activities		(501	)		(576	)		75
Net increase in cash and cash equivalents		188			18			170
Cash and cash equivalents at beginning of period		105			131			(26	)
Cash and cash equivalents at end of period	$	293		$	149		$	144

Cash Flow from Operating Activities The $3 million increase in cash from operating activities for the three months ended March 31, 2014 compared to the same period in 2013 was primarily related to increased cash provided by (i) higher earnings year over year largely attributed to significantly colder-than-normal weather in the current year and increased price volatility that enabled us to capture value in wholesale services, (ii) inventories, net of LIFO liquidation, due to increased LIFO liquidation at Nicor Gas and increased withdrawals at our distribution and midstream operations, partially offset by a decrease in withdrawals at Sequent, and (iii) accrued expenses due to higher federal and state income taxes payable as a result of higher earnings in the current year and the utilization of a prior period net operating loss that reduced the tax obligation in 2013. This increase in cash provided by operating activities was largely offset by decreased cash provided by (i) receivables, other than energy marketing, due to colder weather in 2014, which resulted in higher volumes primarily at distribution operations and retail operations that will be collected in future periods, (ii) deferred natural gas costs, due to an increase in the price paid for natural gas in the first quarter of 2014 associated with the extremely cold weather, primarily in Illinois, that led to an under-collected position in the current year, and (iii) net energy marketing receivables and payables, due to higher cash received in 2013 that related to December 2012.

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Cash Flow from Investing ActivitiesThe $92 million decrease in cash flow used in investing activities was primarily the result of our $122 million acquisition of approximately 500,000 service plans during the first quarter of 2013. This decrease was partially offset by increased spending for PP&E expenditures of $16 million.

Cash Flow from Financing Activities The decreased use of cash for our financing activities for the three months ended March 31, 2014 compared to the same period in 2013 was primarily the result of lower commercial paper repayments due to higher working capital needs at distribution operations, partially offset by recovery of working capital at wholesale services. For more information on our debt, see Note 7 to our unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein.

Contractual Obligations and Commitments We have incurred 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 requirements for capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor.

Other than the changes in our debt, see Note 7 to our unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein, there were no significant changes to our contractual obligations described in Note 11 to our Consolidated Financial Statements and related notes as filed in Item 8 of our 2013 Form 10-K.

Critical Accounting Policies and Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts in our unaudited Condensed Consolidated Financial Statements and accompanying notes. Those judgments and estimates have a significant effect on our financial statements, primarily due to the need to make estimates about the effects of matters that are inherently uncertain. Actual results could differ from those estimates. We frequently reevaluate our judgments and estimates that are based upon historical experience and various other assumptions that we believe to be reasonable under the circumstances.

Each of our critical accounting estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. Except as described below, there have been no significant changes to our critical accounting estimates from those disclosed in our Management’s Discussion and Analysis of Financial Condition and Results of Operations as filed on our 2013 Form 10-K. Our critical accounting estimates used in the preparation of our unaudited Condensed Consolidated Financial Statements include the following:

·Accounting for Rate-Regulated Subsidiaries

·Derivatives and Hedging Activities

·Goodwill and Long-Lived Assets, including Other Intangible Assets

·Contingencies

·Pension and Other Retirement Plans

·Provisions for Income Taxes

Goodwill During the first quarter of 2014 we conducted an engineering study that indicated a reduction in our estimated working gas capacity from what was projected when our 2013 annual goodwill impairment analysis was performed in the fourth quarter of 2013. Given that the 2013 annual goodwill impairment test indicated that the estimated fair value of the storage and fuels reporting unit exceeded its carrying amount by less than 5%, we considered this reduced forecast of storage capacity as an indicator of potential impairment and, accordingly, conducted an interim goodwill impairment analysis during the first quarter of 2014. See Note 2 to our unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein for additional information.

Accounting Developments

On April 10, 2014, the FASB issued authoritative guidance related to reporting discontinued operations. The guidance generally raises the threshold for disposals to qualify as discontinued operations and requires new disclosures of both discontinued operations and certain other material disposals that do not meet the definition of a discontinued operation. The guidance will be effective for us prospectively beginning January 1, 2015 and it is not expected to have a material impact on our consolidated financial statements. While permitted, we do not intend to adopt the guidance early.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to risks associated with natural gas prices, interest rates, credit and fuel prices. Natural gas price risk results from changes in the fair value of natural gas. Interest rate risk is caused by fluctuations in interest rates related to our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business. Credit risk results from the extension of credit throughout all aspects of our business, but is particularly concentrated at Atlanta Gas Light in distribution operations and in wholesale services. Fuel price risk, primarily in our cargo shipping segment, is a product of the fluctuation in fuel prices; however, this risk is partially reduced through fuel surcharges. With the exception of fuel price risk in our cargo shipping segment, we use derivative instruments to manage these risks. Our use of derivative instruments is governed by a risk management policy, approved and monitored by our Risk Management Committee (RMC), which prohibits the use of derivatives for speculative purposes.

Our RMC is responsible for establishing the overall risk management policies and monitoring compliance with, and adherence to, the terms within these policies, including approval and authorization levels and delegation of these levels. Our RMC consists of members of senior management who monitor open natural gas price risk positions and other types of risk, corporate exposures, credit exposures and overall results of our risk management activities. It is chaired by our chief risk officer, who is responsible for ensuring that appropriate reporting mechanisms exist for the RMC to perform its monitoring functions. Our risk management activities and related accounting treatment for our derivative instruments are described in further detail in Note 5 of our unaudited Condensed Consolidated Financial Statements included herein.

Natural Gas Price Risk

The following tables include the fair values and average values of our consolidated derivative instruments as of the dates indicated. We base the average values on monthly averages for the three months ended March 31, 2014 and 2013.

	Derivative instruments average values at March 31,(1)
In millions	2014		2013
Asset	$	213	$	114
Liability		183		29

(1)Excludes cash collateral amounts.

	Derivative instruments fair values netted with cash collateral at
In millions	March 31, 2014		December 31, 2013		March 31, 2013
Asset	$	138	$	119	$	111
Liability		82		80		24

The following table illustrates the change in the net fair value of our derivative instruments during the periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.

	Three months ended March 31,
In millions	2014			2013
Net fair value of derivative instruments outstanding at beginning of period	$	(82	)	$	36
Derivative instruments realized or otherwise settled during period		57			(43	)
Change in net fair value of derivative instruments		(19	)		17
Net fair value of derivative instruments outstanding at end of period		(44	)		10
Netting of cash collateral		100			77
Cash collateral and net fair value of derivative instruments outstanding at end of period	$	56		$	87

The sources of our net fair value at March 31, 2014, are as follows.

In millions	Prices actively quoted (Level 1) (1)			Significant other observable inputs  (Level 2) (2)
Mature through 2014	$	8		$	(5	)
Mature 2015 - 2016		(26	)		(19	)
Mature 2017 - 2018		(2	)		-
Total derivative instruments (3)	$	(20	)	$	(24	)

(1)   Valued using NYMEX futures prices.

(2)   Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.

(3)  Excludes cash collateral amounts.

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VaROur VaR may not be comparable to that of other entities due to differences in the factors used to calculate VaR. Our VaR is determined on a 95% confidence interval and a 1-day holding period, which means that 95% of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the chief risk officer. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally mitigated. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of our open positions.

Natural gas markets experienced levels of high volatility and increased prices due to the extended extreme cold weather during the first quarter of 2014, resulting in our VaR to be at elevated levels during the quarter as compared to prior periods. We actively managed and monitored the open positions and exposures that were driving the elevated VaR levels to not only remain in compliance with established policies, but to also mitigate the operational risks of not being able to meet customer needs under these extreme conditions. As conditions moderated at the end of the quarter, our period-end VaR was consistent with historical periods. We actively monitor open commodity positions and the resulting VaR. We also continue to maintain a relatively matched book, where our total buy volume is close to our sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a 1-day holding period, we had the following VaRs.

	Three months ended March 31,
In millions	2014		2013
Period end	$	3.2	$	1.7
Average		6.4		1.9
High		19.7		2.6
Low		3.2		1.6

Fuel Price Risk

Cargo Shipping Tropical Shipping’s objective is to reduce its exposure to higher fuel costs through fuel surcharges. However, these fuel surcharges do not remove our entire risk in periods of increasing fuel prices and volatility, or increased competition, and any relief may not be realized in the same period as the cost incurred. An increase of 10% in Tropical Shipping’s average cost per gallon for vessel fuel would result in $6 million in additional annual fuel expense. Fuel surcharges would be implemented to reduce the impact of the increased fuel expense.

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $0.9 billion of variable-rate debt outstanding at March 31, 2014, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $9 million on an annualized basis.

We utilize interest rate swaps to help us achieve our desired mix of variable to fixed-rate debt. Our variable-rate debt target generally ranges from 20% to 45% of total debt. We also may use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the period of the related hedge interest payments. For additional information, see Note 5 to our unaudited Condensed Consolidated Financial Statements included under Part 1, Item 1 herein.

On May 16, 2013, we issued $500 million of 30-year senior notes with a fixed interest rate of 4.4%. We had entered into $300 million, in notional amount, of fixed-rate forward-starting interest rate swaps to hedge the first ten years of potential interest rate volatility prior to this issuance. The weighted average interest rate of these swaps was a 10-year U.S. Treasury rate of 1.85%. On May 16, 2013, we settled these swaps, which resulted in our receipt of a $6 million cash payment. The $6 million will be amortized to reduce interest expense over the first ten years of the 30-year senior notes.

Credit Risk

Wholesale Services We have established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. We also utilize master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When we are engaged in more than one outstanding derivative transaction with the same counterparty and we also have a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of our credit risk. We also use other netting agreements with certain counterparties with whom we conduct significant transactions. Master netting agreements enable us to net certain assets and liabilities by counterparty. We also net across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions.

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Additionally, we may require counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for a counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not have investment grade ratings.

We have a concentration of credit risk as measured by our 30-day receivable exposure plus forward exposure. As of March 31, 2014, our top 20 counterparties represented 52% of the total counterparty exposure of $822 million, derived by adding together the top 20 counterparties’ exposures, exclusive of customer deposits, and dividing by the total of our counterparties’ exposures.

As of March 31, 2014, our counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of A-, which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. The following table shows our third-party natural gas contracts receivable and payable positions.

	Gross receivables						Gross payables
	Mar. 31,		Dec. 31,		Mar. 31,		Mar. 31,		Dec. 31,		Mar. 31,
In millions	2014		2013		2013		2014		2013		2013
Netting agreements in place:
Counterparty is investment grade	$	737	$	496	$	286	$	453	$	265	$	198
Counterparty is non-investment grade		2		-		4		16		10		13
Counterparty has no external rating		427		260		319		631		393		431
No netting agreements in place:
Counterparty is investment grade		53		29		12		3		2		10
Counterparty is non-investment grade		3		-		-		-		-		-
Counterparty has no external rating		4		1		6		16		1		1
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position	$	1,226	$	786	$	627	$	1,119	$	671	$	653

We have certain trade and credit contracts that have explicit 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, we would need to post collateral to continue transacting business with some of our counterparties. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements with our counterparties would have totaled $15 million at March 31, 2014, which would not have a material impact on our consolidated results of operations, cash flows or financial condition.

There have been no significant changes to our credit risk related to any of our segments other than wholesale services, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our 2013 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of disclosure controls and procedures.Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of March 31, 2014, the end of the period covered by this report. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2014, in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities. In addition, we are party, as both plaintiff and defendant, to a number of lawsuits related to our business on an ongoing basis. Management believes that the outcome of all regulatory proceedings and litigation in which we are currently involved will not have a material adverse effect on our consolidated financial condition. For more information, see Note 10 to our unaudited Condensed Consolidated Financial Statements in this quarterly filing under the caption “Litigation” and Part I, Item 3. Legal Proceedings in our 2013 Form 10-K.

Item 1A. Risk Factors.

For information regarding our risk factors, see the factors discussed in Part I, Item 1A. Risk Factors in our 2013 Form 10-K. These risk factors could materially affect our business, financial condition or future results. There have been no significant changes to our risk factors included in Item 1A of our 2013 Form 10-K. The risks described in the referenced document are not the only risks facing the company. Additional risks and uncertainties not currently known to us or that we currently do not recognize as material also may materially adversely affect our business, financial condition or future results.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

There were no purchases of our common stock by us or any affiliated purchasers during the first quarter of 2014 and no unregistered sales of equity securities were made during this period.

Item 6. Exhibits

Exhibit Number		Description of Exhibit	Filer	The Filings Referenced for Incorporation by Reference
	12	Statement of Computation of Ratio of Earnings to Fixed Charges	AGL Resources	Filed herewith
	31.1	Certification of John W. Somerhalder II	AGL Resources	Filed herewith
	31.2	Certification of Andrew W. Evans	AGL Resources	Filed herewith
	32.1	Certification of John W. Somerhalder II	AGL Resources	Filed herewith
	32.2	Certification of Andrew W. Evans	AGL Resources	Filed herewith
101.INS		XBRL Instance Document	AGL Resources	Filed herewith
101.SCH		XBRL Taxonomy Extension Schema	AGL Resources	Filed herewith
101.CAL		XBRL Taxonomy Extension Calculation Linkbase	AGL Resources	Filed herewith
101.DEF		XBRL Taxonomy Definition Linkbase	AGL Resources	Filed herewith
101.LAB		XBRL Taxonomy Extension Labels Linkbase	AGL Resources	Filed herewith
101.PRE		XBRL Taxonomy Extension Presentation Linkbase	AGL Resources	Filed herewith

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

AGL RESOURCES INC.

(Registrant)

Date: April 29, 2014	/s/ Andrew W. Evans
	Executive Vice President and Chief Financial Officer

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EX-12

Exhibit 12

AGL Resources Inc.

Statement Setting Forth Ratio of Earnings to Fixed Charges

	Three months ended			Fiscal			Fiscal			Fiscal			Fiscal			Fiscal
Dollars in millions	March 31, 2014			2013			2012			2011			2010			2009
Earnings before income taxes	$	541		$	522		$	450		$	311		$	390		$	384
Add:
Fixed charges (see “B” below)		52			200			203			145			123			115
Amortization of capitalized interest (1)		-			-			-			1			-			-
Distributed income of equity investees		3			3			14			-			-			-
Less:
Interest capitalized (1)		-			-			(1	)		(1	)		(5	)		(3	)
Noncontrolling interest in pre-tax income of subsidiaries that have not incurred fixed charges		(12	)		(18	)		(15	)		(14	)		(16	)		(27	)
Adjusted earnings (A)	$	584		$	707		$	651		$	442		$	492		$	469
Fixed charges
Interest on long-term debt	$	47		$	182		$	177		$	101		$	109		$	98
Other interest, including amortized premiums, discounts and capitalized expenses related to indebtedness liability		2			6			13			37			7			10
Estimated interest components of rentals		3			12			13			7			7			7
Total fixed charges (B)	$	52		$	200		$	203		$	145		$	123		$	115
Ratio of earnings to fixed charges (A)/(B)		11.23			3.54			3.21			3.05			4.00			4.08

(1)     Includes interest capitalized and related amortization for our nonregulated segments.

EX-31.1

Exhibit 31.1 – Certification of John W. Somerhalder II pursuant to Rule 13a – 14(a)

CERTIFICATIONS

I, John W. Somerhalder II, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of AGL Resources Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: April 29, 2014	/s/ John W. Somerhalder II
	Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2 – Certification of Andrew W. Evans pursuant to Rule 13a – 14(a)

CERTIFICATIONS

I, Andrew W. Evans, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of AGL Resources Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: April 29, 2014	/s/ Andrew W. Evans
	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1                      Certification of John W. Somerhalder II pursuant to 18 U.S.C. Section 1350

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

The undersigned, as the chief executive officer of AGL Resources Inc., certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1 )   the Form 10-Q for the quarterly period ended March 31, 2014 (the “Report”), which accompanies this certification, fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

(2 )   the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of AGL Resources Inc.

Date: April 29, 2014	/s/ John W. Somerhalder II
	Chairman, President and Chief Executive Officer

EX-32.2

Exhibit 32.2                      Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

The undersigned, as the chief financial officer of AGL Resources Inc., certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1 )   the Form 10-Q for the quarterly period ended March 31, 2014 (the “Report”), which accompanies this certification, fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

(2 )   the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of AGL Resources Inc.

Date: April 29, 2014	/s/ Andrew W. Evans
	Executive Vice President and Chief Financial Officer

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Note 3 - Regulated Operations (Details) - Change in Net Position of Deferred and Accrued Natural Gas Costs (USD $) In Millions, unless otherwise specified	3 Months Ended			12 Months Ended			12 Months Ended				12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Mar. 31, 2014 Accrued natural gas costs [Member]	Dec. 31, 2013 Accrued natural gas costs [Member]	Mar. 31, 2013 Accrued natural gas costs [Member]	Mar. 31, 2014 Natural Gas Costs [Member]		Mar. 31, 2013 Natural Gas Costs [Member]		Mar. 31, 2014 Deferred Natural Gas Costs [Member]	Dec. 31, 2013 Deferred Natural Gas Costs [Member]
Note 3 - Regulated Operations (Details) - Change in Net Position of Deferred and Accrued Natural Gas Costs [Line Items]
Deferred natural gas costs	$ 297	$ 119	$ 162								$ 161	$ 1
Deferred natural gas costs	228	(43)									161
Accrued natural gas costs	(161)	(238)	(183)	(24)	(92)	(133)
Accrued natural gas costs				109
Total (1)							137	[1]	(133)	[1]
Total (1)							$ 270	[1]

[1] The $270 million change resulted from increased natural gas prices during the first quarter of 2014 compared to the first quarter of 2013, primarily driven by colder weather experienced in the current quarter. These costs will be fully recovered in future periods.

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Note 8 - Equity (Details) - Other Comprehensive Income (Loss) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013		Dec. 31, 2012
Other Comprehensive Income (Loss) [Abstract]
Cash flow hedges	$ 1	[1]	$ 1	[1]	$ 1	[1]	$ (3)	[1]
Retirement benefit plans	(136)	[1]	(212)	[1]	(137)	[1]	(215)	[1]
Total	(135)	[1]	(211)	[1]	(136)	[1]	(218)	[1]
Cash flow hedges - OCI, before reclassifications	4	[1]	2	[1]
Total - OCI, before reclassifications	4	[1]	2	[1]
Retirement benefit plans - OCI, before reclassifications		[1]		[1]
Cash flow hedges - Amounts reclassified from accumulated other comprehensive income	(4)	[1]	2	[1]
Retirement benefit plans - Amounts reclassified from accumulated other comprehensive income	1	[1]	3	[1]
Total - Amounts reclassified from accumulated other comprehensive income	$ (3)	[1]	$ 5	[1]

[1] All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

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Note 5 - Derivative Instruments (Details) - Derivative Instruments on the Condensed Consolidated Statements of Financial Position (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Designated as cash flow hedges and fair value hedges
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)	$ (82)
Designated as Hedging Instrument [Member] | Current Natural Gas Contracts [Member]
Designated as cash flow hedges and fair value hedges
Assets	2		3		3
Liabilities			(1)		(1)
Designated as Hedging Instrument [Member] | Current Interest Rate Swap Agreements [Member]
Designated as cash flow hedges and fair value hedges
Assets		[1],[2]		[1],[2]	5
Liabilities		[1],[2]		[1],[2]
Designated as Hedging Instrument [Member] | Long-Term Natural Gas Contracts [Member]
Designated as cash flow hedges and fair value hedges
Assets	757	[1]	900	[1]	386	[1]
Liabilities	(801)	[1]	(982)	[1]	(376)	[1]
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)	(619)	[2]	(781)	[2]	(275)	[2]
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)	719	[2]	902	[2]	352	[2]
Designated as Hedging Instrument [Member]
Designated as cash flow hedges and fair value hedges
Assets	2	[1],[2]	3	[1],[2]	8
Liabilities		[1],[2]	(1)	[1],[2]	(1)
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)	138	[3]	119	[3]	111	[3]
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)	(82)	[3]	(80)	[3]	(24)	[3]
Not Designated as Hedging Instrument [Member] | Current Natural Gas Contracts [Member]
Designated as cash flow hedges and fair value hedges
Assets	675	[1],[2]	691	[1],[2]	332
Liabilities	(703)	[1],[2]	(761)	[1],[2]	(327)
Not Designated as Hedging Instrument [Member] | Long-Term Natural Gas Contracts [Member]
Designated as cash flow hedges and fair value hedges
Assets	80	[1],[2]	206	[1],[2]	46
Liabilities	(98)	[1],[2]	(220)	[1],[2]	(48)
Not Designated as Hedging Instrument [Member]
Designated as cash flow hedges and fair value hedges
Assets	755	[1],[2]	897	[1],[2]	378
Liabilities	$ (801)	[1],[2]	$ (981)	[1],[2]	$ (375)

[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 above do not include cashcollateral held on deposit in broker margin accounts of $100 million as of March 31, 2014, $121 million as of December 31, 2013 and $77 million as of March 31, 2013. Cash collateral is included in the "Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position" line of this table.

[3] At March 31, 2014, December 31, 2013 and March 31, 2013 we held letters of credit from counterparties that would offset, under master netting arrangements, aninsignificant portion of these assets.

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Note 3 - Regulated Operations (Tables)

3 Months Ended

Mar. 31, 2014

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets [Table Text Block]

In millions	March 31, 2014		December 31, 2013		March 31, 2013
Regulatory assets
Deferred natural gas costs	$	161	$	1	$	-
Recoverable regulatory infrastructure program costs		48		48		47
Recoverable ERC		38		45		28
Recoverable pension and retiree welfare benefit costs		9		9		19
Other		41		59		25
Total regulatory assets – current		297		162		119
Recoverable ERC		419		433		415
Recoverable pension and retiree welfare benefit costs		97		99		192
Recoverable regulatory infrastructure program costs		96		87		135
Long-term debt fair value adjustment		80		82		88
Other		44		36		48
Total regulatory assets - long-term		736		737		878
Total regulatory assets	$	1,033	$	899	$	997
Regulatory liabilities
Bad debt over collection	$	41	$	41	$	39
Accumulated removal costs		27		27		17
Accrued natural gas costs		24		92		133
Deferred seasonal rates		20		-		20
Other		49		23		29
Total regulatory liabilities – current		161		183		238
Accumulated removal costs		1,456		1,445		1,413
Regulatory income tax liability		27		27		26
Unamortized investment tax credit		25		26		28
Bad debt over collection		14		17		20
Other		28		3		11
Total regulatory liabilities - long-term		1,550		1,518		1,498
Total regulatory liabilities	$	1,711	$	1,701	$	1,736

Schedule of Net Regulatory Assets [Table Text Block]

In millions	March 31, 2014			March 31, 2013			Change
Deferred natural gas costs	$	161		$	-		$	161
Accrued natural gas costs		(24	)		(133	)		109
Total (1)	$	137		$	(133	)	$	270

Environmental Exit Costs by Cost [Table Text Block]

In millions	Probabilistic model cost estimates			Engineering estimates		Amount recorded		Expected costs over next 12 months
Illinois	$211	-	$461	$	42	$	246	$	39
New Jersey	139	-	233		6		144		25
Georgia and Florida	28	-	112		8		39		10
North Carolina		n/a			11		11		8
Total	$378	-	$806	$	67	$	440	$	82

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Note 6 - Employee Benefit Plans (Details) - Components of Pension and Other Retirement Benefit Costs (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension Plan, Defined Benefit [Member]
Note 6 - Employee Benefit Plans (Details) - Components of Pension and Other Retirement Benefit Costs [Line Items]
Service cost	$ 6	$ 8
Interest cost	12	10
Expected return on plan assets	(16)	(16)
Recognized actuarial loss	5	8
Net periodic benefit cost	7	10
Other Postretirement Benefit Plan, Defined Benefit [Member]
Note 6 - Employee Benefit Plans (Details) - Components of Pension and Other Retirement Benefit Costs [Line Items]
Service cost	1	1
Interest cost	4	3
Expected return on plan assets	(2)	(1)
Net amortization of prior service cost	(1)	(1)
Recognized actuarial loss	1	2
Net periodic benefit cost	$ 3	$ 4

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Note 4 - Fair Value Measurements (Details) - Derivative Assets and Liabilities (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Fair Value, Inputs, Level 1 [Member] | Natural Gas Derivatives [Member]
Natural gas derivatives
Derivative Assets	$ 18	[1]	$ 6	[1]	$ 14	[1]
Derivative Liabilities	(38)		(79)		(38)
Fair Value, Inputs, Level 2 [Member] | Natural Gas Derivatives [Member]
Natural gas derivatives
Derivative Assets	50	[1]	67	[1]	49	[1]
Derivative Liabilities	(75)		(79)		(23)
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]
Natural gas derivatives
Derivative Assets		[1]		[1]	6	[1]
Netting [Member] | Natural Gas Derivatives [Member]
Natural gas derivatives
Derivative Assets	69	[1]	43	[1]	40	[1]
Derivative Liabilities	31		78		37
Natural Gas Derivatives [Member]
Natural gas derivatives
Derivative Assets	137	[1],[2],[3]	116	[1],[2],[3]	103	[1],[2],[3]
Derivative Liabilities	$ (82)	[2],[3]	$ (80)	[2],[3]	$ (24)	[2],[3]

[1] Balances of $1 million at March 31, 2014, $3 million at December 31, 2013 and $2 million at March 31, 2013 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) for any of the dates presented.

[3] There were no significant transfers between Level 1, Level 2 or Level 3 for any of the dates presented.

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Note 3 - Regulated Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Natural Gas Costs [Member]
Note 3 - Regulated Operations (Details) [Line Items]
Increase (Decrease) in Other Regulatory Assets	$ 228	$ (43)	$ 270

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Note 7 - Debt and Credit Facilities (Details) - Debt Schedule (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Weighted average interest rate	5.00%	[1]			4.50%	[1]
Outstanding	$ 200				$ 226
Outstanding	3,610		3,813		3,324
Total debt	4,551		4,984		4,418
Unamortized debt premium, net		[1]				[1]
Unamortized debt premium, net	16		16		18
Commercial Paper [Member] | AGL Capital [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2014	[2]
Weighted average interest rate	0.30%	[1],[2]			0.50%	[1],[2]
Outstanding	440	[2]	857	[2]	868	[2]
Maturity date	2014	[2]
Commercial Paper [Member] | Nicor Gas [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2014	[2]
Weighted average interest rate	0.20%	[1],[2]			0.40%	[1],[2]
Outstanding	301	[2]	314	[2]		[2]
Maturity date	2014	[2]
Commercial Paper [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Weighted average interest rate	0.30%	[1]			0.50%	[1]
Outstanding	741		1,171		868
Current Portion Long-Term Debt [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2015
Weighted average interest rate	5.00%	[1]			4.50%	[1]
Outstanding	200				225
Maturity date	2015
Current Portion of Capital Leases [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	n/a
Weighted average interest rate		[1]			5.00%	[1]
Outstanding					1
Maturity date	n/a
Senior Notes [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Weighted average interest rate	5.00%	[1]			5.10%	[1]
Outstanding	2,625		2,825		2,325
First Mortgage Bonds [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Weighted average interest rate	5.60%	[1]			5.60%	[1]
Outstanding	500		500		500
Gas Facility Revenue Bonds [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Weighted average interest rate	0.90%	[1]			1.20%	[1]
Outstanding	200		200		200
Medium-term Notes [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Weighted average interest rate	7.80%	[1]			7.80%	[1]
Outstanding	181		181		181
Long-Term Debt Principal [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Weighted average interest rate	4.90%	[1]			5.00%	[1]
Outstanding	3,506		3,706		3,206
Fair Value Adjustment [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	-	[3]
Maturity date	-	[3]
Weighted average interest rate		[1],[3]				[1],[3]
Outstanding	88	[3]	91	[3]	100	[3]
Long-Term Debt Non-Principal [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Weighted average interest rate		[1]				[1]
Outstanding	$ 104		$ 107		$ 118
Minimum [Member] | Senior Notes [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2016
Maturity date	2016
Minimum [Member] | First Mortgage Bonds [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2016
Maturity date	2016
Minimum [Member] | Gas Facility Revenue Bonds [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2022
Maturity date	2022
Minimum [Member] | Medium-term Notes [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2017
Maturity date	2017
Minimum [Member] | Fair Value Adjustment [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2016	[3]
Maturity date	2016	[3]
Maximum [Member] | Senior Notes [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2043
Maturity date	2043
Maximum [Member] | First Mortgage Bonds [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2038
Maturity date	2038
Maximum [Member] | Gas Facility Revenue Bonds [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2033
Maturity date	2033
Maximum [Member] | Medium-term Notes [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2027
Maturity date	2027
Maximum [Member] | Fair Value Adjustment [Member]
Note 7 - Debt and Credit Facilities (Details) - Debt Schedule [Line Items]
Maturity date	2038	[3]
Maturity date	2038	[3]

[1] Interest rates are calculated based on the daily weighted average balance outstanding for the three months ended March 31.

[2] As of March 31, 2014, the effective interest rates on our commercial paper borrowings were 0.3% for AGL Capital and 0.2% for Nicor Gas.

[3] See Note 4 for additional information on our fair value measurements.

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Note 11 - Segment Information (Details)	3 Months Ended
	Mar. 31, 2014
Note 11 - Segment Information (Details) [Line Items]
Number of Operating Segments	5
Distribution Operations [Member]
Note 11 - Segment Information (Details) [Line Items]
Number of States in which Entity Operates	7

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Note 5 - Derivative Instruments (Details) - Gains and Losses on Derivative Instruments (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Nicor Gas [Member]
Note 5 - Derivative Instruments (Details) - Gains and Losses on Derivative Instruments [Line Items]
Realized losses related to hedging natural gas costs	$ 2	$ (1)
Elizabethtown Gas [Member]
Note 5 - Derivative Instruments (Details) - Gains and Losses on Derivative Instruments [Line Items]
Realized losses related to hedging natural gas costs	$ 3	$ (3)

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Condensed Consolidated Statements of Equity (Unaudited) (Parentheticals) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Dividends on common stock, per share	$ 0.49	$ 0.47

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Note 11 - Segment Information (Details) - Segment Reporting (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013		Dec. 31, 2012
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Identifiable and total assets	$ 15,376	[1]	$ 14,656	[2]	$ 13,940	[1]
Goodwill	1,869		1,888		1,883		1,837
Distribution Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Identifiable and total assets	11,923	[1]	11,727	[2]	11,258	[1]
Goodwill	1,640		1,640		1,640		1,640
Retail Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Identifiable and total assets	749	[1]	694	[2]	668	[1]
Goodwill	173		173		168		122
Wholesale Services [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Identifiable and total assets	1,782	[1],[3]	1,166	[2]	1,005	[1],[3]
Midstream Operations [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Identifiable and total assets	698	[1]	713	[2]	714	[1]
Goodwill	14		14		14		14
Cargo Shipping [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Identifiable and total assets	419	[1]	445	[2]	459	[1]
Goodwill	42		61		61		61
Other Segments [Member]
Note 11 - Segment Information (Details) - Segment Reporting [Line Items]
Identifiable and total assets	(195)	[1],[4]	(89)	[2],[4]	(164)	[1],[4]
Goodwill				[4]

[1] Identifiable assets are those used in each segment's operations.

[2] Identifiable assets are those assets used in each segment's operations.

[3] Wholesale services records its energy marketing and risk management revenues on a net basis. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.

[4] The assets of our other segment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

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Note 4 - Fair Value Measurements (Details) - Money Market Funds (Fair Value, Inputs, Level 1 [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Fair Value, Inputs, Level 1 [Member]
Note 4 - Fair Value Measurements (Details) - Money Market Funds [Line Items]
Money market funds (1)	$ 48	[1]	$ 48	[1]	$ 48	[1]

[1] Carried at fair value and classified as Level 1 within the fair value hierarchy.

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Note 7 - Debt and Credit Facilities (Tables)

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Schedule of Debt [Table Text Block]

				March 31, 2014							March 31, 2013
Dollars in millions	Year(s) due			Weighted average interest rate (1)			Outstanding		Outstanding at December 31, 2013		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper - AGL Capital (2)		2014			0.3	%	$	440	$	857		0.5	%	$	868
Commercial paper - Nicor Gas (2)		2014			0.2			301		314		0.4			-
Total short-term debt					0.3			741		1,171		0.5			868
Current portion of long-term debt and capital leases
Current portion of long-term debt		2015			5.0			200		-		4.5			225
Current portion of capital leases		n/a			-			-		-		5.0			1
Total current portion of long-term debt and capital leases					5.0	%	$	200	$	-		4.5	%	$	226
Long-term debt - excluding current portion
Senior notes	2016	-	2043		5.0	%	$	2,625	$	2,825		5.1	%	$	2,325
First mortgage bonds	2016	-	2038		5.6			500		500		5.6			500
Gas facility revenue bonds	2022	-	2033		0.9			200		200		1.2			200
Medium-term notes	2017	-	2027		7.8			181		181		7.8			181
Total principal long-term debt					4.9	%		3,506		3,706		5.0	%		3,206
Fair value adjustment of long-term debt (3)	2016	-	2038	n/a				88		91	n/a				100
Unamortized debt premium, net		n/a		n/a				16		16	n/a				18
Total non-principal long-term debt				n/a				104		107	n/a				118
Total long-term debt							$	3,610	$	3,813				$	3,324
Total debt							$	4,551	$	4,984				$	4,418

Schedule of Capitalization [Table Text Block]

	March 31, 2014			December 31, 2013			March 31, 2013
AGL Credit Facility		53	%		57	%		54	%
Nicor Gas Credit Facility		54	%		55	%		43	%

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Note 6 - Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

	Three months ended March 31,
In millions	2014			2013
Service cost	$	6		$	8
Interest cost		12			10
Expected return on plan assets		(16	)		(16	)
Recognized actuarial loss		5			8
Net periodic pension benefit cost	$	7		$	10

	Three months ended March 31,
In millions	2014			2013
Service cost	$	1		$	1
Interest cost		4			3
Expected return on plan assets		(2	)		(1	)
Net amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		1			2
Net periodic welfare benefit cost	$	3		$	4

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Note 9 - Non-Wholly Owned Entities (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Payments to Acquire Property, Plant, and Equipment	$ 164	$ 148
Payments of Ordinary Dividends, Noncontrolling Interest	17	17
South Star [Member] | AGL Resources Inc [Member]
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Equity Method Investment, Ownership Percentage	85.00%
South Star [Member] | Piedmont [Member]
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Payments of Ordinary Dividends, Noncontrolling Interest	17	17
South Star [Member]
Note 9 - Non-Wholly Owned Entities (Details) [Line Items]
Payments to Acquire Property, Plant, and Equipment	$ 2	$ 1

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Note 4 - Fair Value Measurements (Details) - Amortized Cost and Fair Value of Long-Term Debt (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Note 4 - Fair Value Measurements (Details) - Amortized Cost and Fair Value of Long-Term Debt [Line Items]
Long-term debt carrying amount	$ 3,810		$ 3,813		$ 3,550
Fair Value, Inputs, Level 2 [Member]
Note 4 - Fair Value Measurements (Details) - Amortized Cost and Fair Value of Long-Term Debt [Line Items]
Long-term debt fair value (1)	$ 4,095	[1]	$ 3,956	[1]	$ 4,006	[1]

[1] Fair value determined using Level 2 inputs.

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Note 8 - Equity (Tables)

3 Months Ended

Mar. 31, 2014

Stockholders' Equity Note [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

In millions (1)	Cash flow hedges			Retirement benefit plans			Total
As of December 31, 2012	$	(3	)	$	(215	)	$	(218	)
OCI, before reclassifications		2			-			2
Amounts reclassified from accumulated OCI		2			3			5
As of March 31, 2013		1			(212	)		(211	)
As of December 31, 2013		1			(137	)		(136	)
OCI, before reclassifications		4			-			4
Amounts reclassified from accumulated OCI		(4	)		1			(3	)
As of March 31, 2014	$	1		$	(136	)	$	(135	)

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]

	Three months ended March 31,
In millions (1)	2014			2013
Cash flow hedges
Natural gas contracts (2)	$	4		$	-		Cost of goods sold
Interest rate contracts (3)		-			(3	)	Interest expense, net
Total before income tax		4			(3	)
Income tax benefit		-			1
Total cash flow hedges		4			(2	)
Retirement benefit plan amortization of
Actuarial losses (4)		(2	)		(6	)
Prior service credits (4)		-			1
Total before income tax		(2	)		(5	)
Income tax benefit		1			2
Total retirement benefit plans		(1	)		(3	)
Total reclassification for the period	$	3		$	(5	)

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Note 9 - Non-Wholly Owned Entities (Tables)

3 Months Ended

Mar. 31, 2014

Noncontrolling Interest [Abstract]

Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Table Text Block]

	March 31, 2014							December 31, 2013							March 31, 2013
In millions	Consolidated		SouthStar (1)		% (2)			Consolidated		SouthStar (1)		% (2)			Consolidated		SouthStar (1)		% (2)
Current assets	$	3,448	$	318		9	%	$	2,733	$	264		10	%	$	2,361	$	143		6	%
Goodwill and other intangible assets		2,039		138		7			2,061		139		7			2,039		-		-
Long-term assets and other deferred debits		9,889		20		-			9,862		12		-			9,540		10		-
Total assets	$	15,376	$	476		3	%	$	14,656	$	415		3	%	$	13,940	$	153		1	%
Current liabilities	$	3,753	$	171		5	%	$	3,122	$	95		3	%	$	3,060	$	51		2	%
Long-term liabilities and other deferred credits		7,712		16		-			7,858		-		-			7,339		-		-
Total Liabilities		11,465		187		2			10,980		95		1			10,399		51		1
Equity		3,911		289		7			3,676		320		9			3,541		102		3
Total liabilities and equity	$	15,376	$	476		3	%	$	14,656	$	415		3	%	$	13,940	$	153		1	%

Schedule of Variable Interest Entities [Table Text Block]

	Three months ended March 31,
In millions	2014		2013
Operating revenues	$	374	$	250
Operating expenses
Cost of goods sold		270		164
Operation and maintenance		24		18
Depreciation and amortization		2		1
Total operating expenses		296		183
Operating income	$	78	$	67

Equity Method Investments [Table Text Block]

In millions	2014		2013
Triton	$	67	$	72
Horizon Pipeline		15		16
Other (1)		1		9
Total	$	83	$	97

In millions	2014		2013
Triton	$	2	$	2
Horizon Pipeline		1		1
Total	$	3	$	3

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Condensed Consolidated Statements of Equity (Unaudited) (USD $) In Millions, except Share data	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock [Member]	Noncontrolling Interest [Member]	Total
Balance at Dec. 31, 2012	$ 590	$ 2,014	$ 1,035	$ (218)	$ (8)	$ 22	$ 3,435
Balance (in Shares) at Dec. 31, 2012	117,900,000
Net income			154			10	164
Other comprehensive income				7			7
Dividends on common stock			(55)				(55)
Distributions to noncontrolling interest						(17)	(17)
Stock granted, share-based compensation, net of forfeitures		(6)					(6)
Stock issued, dividend reinvestment plan	1	2					3
Stock issued, share-based compensation, net of forfeitures	1	6					7
Stock issued, share-based compensation, net of forfeitures (in Shares)	200,000
Stock-based compensation expense, net of tax		3					3
Balance at Mar. 31, 2013	592	2,019	1,134	(211)	(8)	15	3,541
Balance (in Shares) at Mar. 31, 2013	118,100,000						118,123,770
Balance at Dec. 31, 2013	595	2,054	1,126	(136)	(8)	45	3,676
Balance (in Shares) at Dec. 31, 2013	118,900,000						118,888,876
Net income			290			12	302
Other comprehensive income				1			1
Dividends on common stock			(58)				(58)
Distributions to noncontrolling interest						(17)	(17)
Stock granted, share-based compensation, net of forfeitures		(12)					(12)
Stock issued, dividend reinvestment plan		2					2
Stock issued, share-based compensation, net of forfeitures	2	12					14
Stock issued, share-based compensation, net of forfeitures (in Shares)	300,000
Stock-based compensation expense, net of tax		3					3
Balance at Mar. 31, 2014	$ 597	$ 2,059	$ 1,358	$ (135)	$ (8)	$ 40	$ 3,911
Balance (in Shares) at Mar. 31, 2014	119,200,000						119,247,421

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Note 11 - Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Schedule Of Segment Reporting Information By Segment Total Assets Goodwill [Table Text Block]

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	11,727		$	1,640
Retail operations		694			173
Wholesale services		1,166			-
Midstream operations		713			14
Cargo shipping		445			61
Other (2)		(89	)		-
Consolidated	$	14,656		$	1,888

Schedule of Segment Reporting Information, by Segment [Table Text Block]

In millions	Distributionoperations		Retail operations		Wholesale services (1)		Midstream operations			Cargo shipping			Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	1,738	$	406	$	286	$	44		$	89		$	-		$	2,563
Intercompany revenues		75		-		47		-			-			(122	)		-
Total operating revenues		1,813		406		333		44			89			(122	)		2,563
Operating expenses
Cost of goods sold		1,202		280		3		36			55			(122	)		1,454
Operation and maintenance		211		37		36		6			29			(2	)		317
Depreciation and amortization		80		6		-		5			5			2			98
Taxes other than income taxes		82		1		1		1			2			2			89
Goodwill impairment loss		-		-		-		-			19			-			19
Total operating expenses		1,575		324		40		48			110			(120	)		1,977
Operating income (loss)		238		82		293		(4	)		(21	)		(2	)		586
Other income		1		-		-		1			2			(1	)		3
EBIT	$	239	$	82	$	293	$	(3	)	$	(19	)	$	(3	)	$	589
Identifiable and total assets (2)	$	11,923	$	749	$	1,782	$	698		$	419		$	(195	)	$	15,376
Capital expenditures	$	150	$	3	$	1	$	-		$	3		$	7		$	164

In millions	Distributionoperations		Retail operations		Wholesale services (1)		Midstream operations		Cargo shipping		Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	1,264	$	302	$	39	$	24	$	87	$	(7	)	$	1,709
Intercompany revenues		55		-		-		-		-		(55	)		-
Total operating revenues		1,319		302		39		24		87		(62	)		1,709
Operating expenses
Cost of goods sold		765		195		10		12		53		(62	)		973
Operation and maintenance		185		31		13		6		28		(4	)		259
Depreciation and amortization		90		5		-		4		5		3			107
Taxes other than income taxes		64		1		1		1		1		3			71
Total operating expenses		1,104		232		24		23		87		(60	)		1,410
Operating income (loss)		215		70		15		1		-		(2	)		299
Other income		3		-		-		1		2		(1	)		5
EBIT	$	218	$	70	$	15	$	2	$	2	$	(3	)	$	304
Identifiable and total assets (2)	$	11,258	$	668	$	1,005	$	714	$	459	$	(164	)	$	13,940
Capital expenditures	$	137	$	1	$	-	$	4	$	1	$	5		$	148

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 ending March 31, 2014	$	4,051	$	298	$	4,349	$	4,016	$	333
Three months ending March 31, 2013		2,094		140		2,234		2,195		39

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Note 3 - Regulated Operations (Details) - Costs Related to Remediation of Former Operating Sites (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Environmental Exit Cost [Line Items]
Engineering estimates	$ 67
Amount recorded	440
Expected costs over next 12 months	82	70	63
Illinois Environmental [Member]
Environmental Exit Cost [Line Items]
Engineering estimates	42
Amount recorded	246
Expected costs over next 12 months	39
Illinois Environmental [Member] | Minimum [Member]
Environmental Exit Cost [Line Items]
Probabilistic model cost estimates, low estimate	211
Illinois Environmental [Member] | Maximum [Member]
Environmental Exit Cost [Line Items]
Probabilistic model cost estimates, high estimate	461
New Jersey Environmental [Member]
Environmental Exit Cost [Line Items]
Engineering estimates	6
Amount recorded	144
Expected costs over next 12 months	25
New Jersey Environmental [Member] | Minimum [Member]
Environmental Exit Cost [Line Items]
Probabilistic model cost estimates, low estimate	139
New Jersey Environmental [Member] | Maximum [Member]
Environmental Exit Cost [Line Items]
Probabilistic model cost estimates, high estimate	233
Georgia And Florida [Member]
Environmental Exit Cost [Line Items]
Engineering estimates	8
Amount recorded	39
Expected costs over next 12 months	10
Georgia And Florida [Member] | Minimum [Member]
Environmental Exit Cost [Line Items]
Probabilistic model cost estimates, low estimate	28
Georgia And Florida [Member] | Maximum [Member]
Environmental Exit Cost [Line Items]
Probabilistic model cost estimates, high estimate	112
North Carolina Environmental [Member]
Environmental Exit Cost [Line Items]
Engineering estimates	11
Amount recorded	11
Expected costs over next 12 months	8
Minimum [Member]
Environmental Exit Cost [Line Items]
Probabilistic model cost estimates, low estimate	378
Maximum [Member]
Environmental Exit Cost [Line Items]
Probabilistic model cost estimates, high estimate	$ 806

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Note 7 - Debt and Credit Facilities (Details) - Debt-to-Capitalization Ratios	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
AGL Resources Inc [Member]
Schedule of Capitalization [Line Items]
Debt-to-capitalization ratios	0.53	0.57	0.54
Nicor Gas [Member]
Schedule of Capitalization [Line Items]
Debt-to-capitalization ratios	0.54	0.55	0.43

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Condensed Consolidated Statements of Financial Position (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Current assets
Cash and cash equivalents	$ 293		$ 105		$ 149
Short-term investments	52		50		43
Receivables
Energy marketing	1,226		786		627
Gas, unbilled and other	1,109		772		874
Less allowance for uncollectible accounts	49		29		39
Total receivables, net	2,286		1,529		1,462
Regulatory assets	297		162		119
Inventories, net	263		667		393
Derivative instruments	127		99		100
Other	130		121		95
Total current assets	3,448		2,733		2,361
Long-term assets and other deferred debits
Property, plant and equipment	11,220		11,104		10,610
Less accumulated depreciation	2,397		2,323		2,202
Property, plant and equipment, net	8,823		8,781		8,408
Goodwill	1,869		1,888		1,883
Regulatory assets	736		737		878
Intangible assets	170		173		156
Derivative instruments	11		20		11
Other	319		324		243
Total long-term assets and other deferred debits	11,928		11,923		11,579
Total assets	15,376	[1]	14,656	[2]	13,940	[1]
Current liabilities
Energy marketing trade payables	1,119		671		653
Short-term debt	741		1,171		868
Other accounts payable - trade	444		432		314
Accrued expenses	390		210		166
Temporary LIFO liquidation	252				179
Current portion of long-term debt and capital leases	200				226
Regulatory liabilities	161		183		238
Customer deposits and credit balances	104		136		115
Accrued environmental remediation liabilities	82		70		63
Derivative instruments	63		75		20
Other	197		174		218
Total current liabilities	3,753		3,122		3,060
Long-term liabilities and other deferred credits
Long-term debt	3,610		3,813		3,324
Accumulated deferred income taxes	1,699		1,667		1,568
Regulatory liabilities	1,550		1,518		1,498
Accrued pension and retiree welfare benefits	405		404		509
Accrued environmental remediation liabilities	358		377		362
Derivative instruments	19		5		4
Other	71		74		74
Total long-term liabilities and other deferred credits	7,712		7,858		7,339
Total liabilities and other deferred credits	11,465		10,980		10,399
Equity
Common stock, $5 par value; 750,000,000 shares authorized: outstanding: 119,247,421 shares at March 31, 2014, 118,888,876 shares at December 31, 2013 and 118,123,770 shares at March 31, 2013	597		595		592
Additional paid-in capital	2,059		2,054		2,019
Retained earnings	1,358		1,126		1,134
Accumulated other comprehensive loss	(135)	[3]	(136)	[3]	(211)	[3]
Treasury shares, at cost: 216,523 shares at March 31, 2014 and December 31, 2013 and March 31, 2013	(8)		(8)		(8)
Total common shareholders’ equity	3,871		3,631		3,526
Noncontrolling interest	40		45		15
Total equity	3,911		3,676		3,541
Total liabilities and equity	$ 15,376		$ 14,656		$ 13,940

[1] Identifiable assets are those used in each segment's operations.

[2] Identifiable assets are those assets used in each segment's operations.

[3] All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

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Note 5 - Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 82
Increase (Decrease) in Risk Management Assets and Liabilities	17	(18)
Collateral Already Posted, Aggregate Fair Value	100	77	121
Price Risk Cash Flow Hedge Unrealized Gain (Loss) to be Reclassified During Next 12 Months	3
Less Than Two Years [Member] | Natural Gas Derivatives [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Percent Of Derivative Contracts	97.00%
Less Than Two Years [Member] | Minimum [Member] | Natural Gas Derivatives [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Term of Contract	2 years
Expiring In Two To Six Years [Member] | Natural Gas [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Percent Of Derivative Contracts	3.00%
Expiring In Two To Six Years [Member] | Maximum [Member] | Natural Gas Derivatives [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Term of Contract	6 years
Expiring In Two To Six Years [Member] | Minimum [Member] | Natural Gas Derivatives [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Term of Contract	2 years
Weather Derivatives [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(5)	(2)
Maximum [Member]
Note 5 - Derivative Instruments (Details) [Line Items]
Derivative, Collateral, Obligation to Return Cash	$ 15

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Condensed Consolidated Statements of Other Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Net income	$ 302		$ 164
Retirement benefit plans
Reclassification of actuarial losses to net benefit cost (net of income tax of $1 for the three months ended March 31, 2014, and $2 for the three months ended March 31, 2013)	1		4
Reclassification of prior service credits to net benefit cost			(1)
Retirement benefit plans	1		3
Cash flow hedges, net of tax
Net derivative instrument gains arising during the period (net of income tax of $1 for the three months ended March 31, 2013)	4	[1]	2	[1]
Reclassification of realized derivative (gains) losses to net income (net of income tax of $1 for the three months ended March 31, 2013)	(4)	[1]	2	[1]
Cash flow hedges, net			4
Other comprehensive income, net of tax	1		7
Comprehensive income	303		171
Less comprehensive income attributable to noncontrolling interest	12		10
Comprehensive income attributable to AGL Resources Inc.	$ 291		$ 161

[1] All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

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Note 9 - Non-Wholly Owned Entities (Details) - Equity Method Investments (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 83		$ 97
Income from Equity Method Investments	3		3
Triton [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	67		72
Income from Equity Method Investments	2		2
Horizon Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	15		16
Income from Equity Method Investments	1		1
Other Equity Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 1	[1]	$ 9	[1]

[1] Includes our investment in Sawgrass Storage. In December 2013, the joint venture decided to terminate the development of the Sawgrass storage facility and reduced the carrying amount of the joint venture's long-lived assets to fair value.

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Note 2 - Significant Accounting Policies and Methods of Application (Details) - Other Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Other Income [Abstract]
Equity investment income	$ 3	$ 3
AFUDC - equity	1	3
Other, net	(1)	(1)
Total other income	$ 3	$ 5

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Note 12 - Subsequent Events (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			0 Months Ended					3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Subsequent Event [Member] Cargo Shipping [Member]	Apr. 11, 2014 Subsequent Event [Member] Scenario, Forecast [Member] Dalton Lateral Pipeline [Member]	Apr. 04, 2014 Subsequent Event [Member] Scenario, Forecast [Member]	Apr. 11, 2014 Subsequent Event [Member] Atlanta Gas Light [Member] Dalton Lateral Pipeline [Member]	Apr. 11, 2014 Subsequent Event [Member] Dalton Lateral Pipeline [Member]	Apr. 11, 2014 Subsequent Event [Member] mi	Mar. 31, 2014 Cargo Shipping [Member]	Mar. 31, 2013 Cargo Shipping [Member]
Note 12 - Subsequent Events (Details) [Line Items]
Proceeds from Sales of Business, Affiliate and Productive Assets					$ 220
Income Tax Expense (Benefit)	239	94			29				31
Goodwill, Impairment Loss	19		19						19
Undivided Ownership Interest							50.00%
Dalton Lateral Pipeline Length (in Miles)								106
Payments to Acquire Property, Plant, and Equipment	164	148		210					3	1
Operating Leases, Income Statement, Minimum Lease Revenue							$ 26
Operating Lease Term							25 years
Contracted Firm Capacity						240,000

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Note 12 - Subsequent Events

3 Months Ended

Mar. 31, 2014

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Note 12 - Subsequent Events

Sale of Tropical Shipping and Seven Seas On April 4, 2014 we entered into a definitive agreement to sell Tropical Shipping and Seven Seas after we obtained board approval for the transaction on such date, and we expect to close the transaction during the third quarter of 2014. After-tax cash proceeds and distributions from the transaction are expected to be $220 million, subject to certain defined post-closing adjustments. As discussed in Note 2, we recognized income tax expense of $31 million in the three months ended March 31, 2014 related to the cumulative earnings for which no tax liabilities had previously been recorded and we expect to record additional income tax expense of $29 million in the third quarter of 2014 related to the taxable gain on the sale. Completion of the transaction is conditioned upon, among other things, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the Florida Office of Insurance Regulation.

As discussed in Note 2, we recorded a $19 million impairment loss related to goodwill that was assigned to cargo shipping in conjunction with our 2011 merger with Nicor. This impairment loss represents one-third of the total goodwill that was assigned to this operating segment in purchase accounting. The goodwill impairment was recognized as of March 31, 2014 since we had indication that the fair value of Tropical Shipping and Seven Seas was below the carrying value.

Tropical Shipping and Seven Seas have operated within our cargo shipping segment. Financial results for these entities will be classified as discontinued operations beginning in the second quarter of 2014. Cargo shipping also includes our investment in Triton, which will be reclassified into the other segment.

Dalton Lateral Pipeline On April 11, 2014 we entered into two arrangements associated with the Dalton Lateral pipeline. The first was a construction and ownership agreement through which we will have a 50% undivided ownership interest in the 106 mile Dalton Lateral pipeline that will be constructed in Georgia and serve as an extension of the Transco natural gas pipeline system into northwest Georgia. Our 50% undivided ownership interest is expected to cost approximately $210 million. We also entered into an agreement to lease our 50% undivided ownership in the Dalton Lateral pipeline once it is placed in-service. The annual lease payments to be received are $26 million for an initial term of 25 years. The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC regulated tariff. Engineering design work has commenced and construction is expected to begin in the second quarter of 2016 with a targeted completion date in the second quarter of 2017. On April 14, 2014, Atlanta Gas Light entered into an agreement with the lessee to acquire firm transportation capacity of 240,000 dekatherms per day associated with the Dalton Lateral pipeline. This capacity will be allocated to the Marketers and will further enhance system reliability as well as provide access to a more diverse supply of natural gas.

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Note 2 - Significant Accounting Policies and Methods of Application (Details) - Potentially Dilutive Common Share Calculation (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Potentially Dilutive Common Share Calculation [Abstract]
Net income attributable to AGL Resources Inc. (in Dollars)	$ 290		$ 154
Basic weighted average number of shares outstanding (1)	118.5	[1]	117.4	[1]
Effect of dilutive securities	0.4		0.3
Diluted weighted average number of shares outstanding	118.9		117.7
Earnings per share:
Basic (in Dollars per share)	$ 2.44		$ 1.31
Diluted (in Dollars per share)	$ 2.44		$ 1.31

[1] Daily weighted average shares outstanding.

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Note 2 - Significant Accounting Policies and Methods of Application (Tables)

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Schedule of Goodwill [Table Text Block]

In millions	Distribution Operations		Retail Operations		Wholesale Services		Midstream Operations		Cargo Shipping			Other		Consolidated
Goodwill - December 31, 2012	$	1,640	$	122	$	-	$	14	$	61		$	-	$	1,837
2013 activity		-		46		-		-		-			-		46
Goodwill - March 31, 2013	$	1,640	$	168	$	-	$	14	$	61		$	-	$	1,883
Goodwill - December 31, 2013	$	1,640	$	173	$	-	$	14	$	61		$	-	$	1,888
Cargo shipping impairment		-		-		-		-		(19	)		-		(19	)
Goodwill - March 31, 2014	$	1,640	$	173	$	-	$	14	$	42		$	-	$	1,869

Schedule of Other Nonoperating Income (Expense) [Table Text Block]

	Three months ended March 31,
In millions	2014			2013
Equity investment income	$	3		$	3
AFUDC - equity		1			3
Other, net		(1	)		(1	)
Total other income	$	3		$	5

Schedule of Weighted Average Number of Shares [Table Text Block]

	Three months ended March 31,
In millions (except per share amounts)	2014		2013
Net income attributable to AGL Resources Inc.	$	290	$	154
Denominator:
Basic weighted average number of shares outstanding (1)		118.5		117.4
Effect of dilutive securities		0.4		0.3
Diluted weighted average number of shares outstanding		118.9		117.7
Earnings per share:
Basic	$	2.44	$	1.31
Diluted	$	2.44	$	1.31

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Condensed Consolidated Statements of Other Comprehensive Income (Unaudited) (Parentheticals) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Reclassification of losses to net benefit cost, income tax	$ 1	$ 2
Net derivative instrument gains (losses) arising during the period, income tax		1
Reclassification of realized derivative losses to net income, income tax		$ 1

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Condensed Consolidated Statements of Financial Position (Unaudited) (Parentheticals) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
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	119,247,421	118,888,876	118,123,770
Treasury shares, shares	216,523	216,523	216,523

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Note 7 - Debt and Credit Facilities

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

Note 7 - Debt and Credit Facilities

The following table provides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities for the periods presented. We fully and unconditionally guarantee all debt issued by AGL Capital. For additional information on our debt, see Note 8 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K.

				March 31, 2014							March 31, 2013
Dollars in millions	Year(s) due			Weighted average interest rate (1)			Outstanding		Outstanding at December 31, 2013		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper - AGL Capital (2)		2014			0.3	%	$	440	$	857		0.5	%	$	868
Commercial paper - Nicor Gas (2)		2014			0.2			301		314		0.4			-
Total short-term debt					0.3			741		1,171		0.5			868
Current portion of long-term debt and capital leases
Current portion of long-term debt		2015			5.0			200		-		4.5			225
Current portion of capital leases		n/a			-			-		-		5.0			1
Total current portion of long-term debt and capital leases					5.0	%	$	200	$	-		4.5	%	$	226
Long-term debt - excluding current portion
Senior notes	2016	-	2043		5.0	%	$	2,625	$	2,825		5.1	%	$	2,325
First mortgage bonds	2016	-	2038		5.6			500		500		5.6			500
Gas facility revenue bonds	2022	-	2033		0.9			200		200		1.2			200
Medium-term notes	2017	-	2027		7.8			181		181		7.8			181
Total principal long-term debt					4.9	%		3,506		3,706		5.0	%		3,206
Fair value adjustment of long-term debt (3)	2016	-	2038	n/a				88		91	n/a				100
Unamortized debt premium, net		n/a		n/a				16		16	n/a				18
Total non-principal long-term debt				n/a				104		107	n/a				118
Total long-term debt							$	3,610	$	3,813				$	3,324
Total debt							$	4,551	$	4,984				$	4,418

(1) Interest rates are calculated based on the daily weighted average balance outstanding for the three months ended March 31.

(2) As of March 31, 2014, the effective interest rates on our commercial paper borrowings were 0.3% for AGL Capital and 0.2% 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 Nicor Gas that consist of short-term, unsecured promissory notes used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are highest during the injection period in advance of the Heating Season. The Nicor Gas commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in the AGL Capital commercial paper program. During the first quarter of 2014, our commercial paper maturities ranged from 1 to 108 days, and at March 31, 2014, remaining terms to maturity ranged from 1 to 35 days. Total borrowings and repayments netted to a payment of $430 million during the first quarter of 2014. For commercial paper issuances with original maturities over 3 months, borrowings and repayments were $50 million and $145 million, respectively, during the first quarter of 2014.

Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash pension adjustments, welfare benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.

	March 31, 2014			December 31, 2013			March 31, 2013
AGL Credit Facility		53	%		57	%		54	%
Nicor Gas Credit Facility		54	%		55	%		43	%

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:

● a maximum leverage ratio

● insolvency events and 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.

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Document And Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 22, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	AGL RESOURCES INC.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		119,257,873
Amendment Flag	false
Entity Central Index Key	0001004155
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	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1

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Note 8 - Equity

3 Months Ended

Mar. 31, 2014

Stockholders' Equity Note [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

Note 8 - Equity

Our OCI amounts are aggregated within our accumulated other comprehensive loss. The following table provides changes in the components of our accumulated other comprehensive loss balance, net of the related income tax effects.

In millions (1)	Cash flow hedges			Retirement benefit plans			Total
As of December 31, 2012	$	(3	)	$	(215	)	$	(218	)
OCI, before reclassifications		2			-			2
Amounts reclassified from accumulated OCI		2			3			5
As of March 31, 2013		1			(212	)		(211	)
As of December 31, 2013		1			(137	)		(136	)
OCI, before reclassifications		4			-			4
Amounts reclassified from accumulated OCI		(4	)		1			(3	)
As of March 31, 2014	$	1		$	(136	)	$	(135	)

(1) All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

The following table provides details of the reclassifications out of accumulated other comprehensive loss and the impact on net income.

	Three months ended March 31,
In millions (1)	2014			2013
Cash flow hedges
Natural gas contracts (2)	$	4		$	-		Cost of goods sold
Interest rate contracts (3)		-			(3	)	Interest expense, net
Total before income tax		4			(3	)
Income tax benefit		-			1
Total cash flow hedges		4			(2	)
Retirement benefit plan amortization of
Actuarial losses (4)		(2	)		(6	)
Prior service credits (4)		-			1
Total before income tax		(2	)		(5	)
Income tax benefit		1			2
Total retirement benefit plans		(1	)		(3	)
Total reclassification for the period	$	3		$	(5	)

(1) Amounts in parentheses indicate debits, or reductions, to profit/loss and credits to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the profit/loss impacts are immediate.

(2) Amounts included within cost of goods sold. 

(3) Amounts included within interest expense, net.

(4) 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.

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Condensed Consolidated Statements of Income (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Operating revenues (includes revenue taxes of $68 for the three months in 2014 and $50 for the three months in 2013)	$ 2,563		$ 1,709
Operating expenses
Cost of goods sold	1,454		973
Operation and maintenance	317		259
Depreciation and amortization	98		107
Taxes other than income taxes	89		71
Goodwill impairment loss	19
Total operating expenses	1,977		1,410
Operating income	586		299
Other income	3		5
Interest expense, net	(48)		(46)
Income before income taxes	541		258
Income tax expense	239		94
Net income	302		164
Less net income attributable to the noncontrolling interest	12		10
Net income attributable to AGL Resources Inc.	$ 290		$ 154
Per common share data
Basic earnings per common share attributable to AGL Resources Inc. common shareholders (in Dollars per share)	$ 2.44		$ 1.31
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders (in Dollars per share)	$ 2.44		$ 1.31
Cash dividends declared per common share (in Dollars per share)	$ 0.49		$ 0.47
Weighted average number of common shares outstanding
Basic (in Shares)	118.5	[1]	117.4	[1]
Diluted (in Shares)	118.9		117.7

[1] Daily weighted average shares outstanding.

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Note 2 - Significant Accounting Policies and Methods of Application

3 Months Ended

Mar. 31, 2014

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 2013 Form 10-K. There were no significant changes to our accounting policies during the three months ended March 31, 2014.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments 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 literature or in the development of estimates that impact our financial statements. The most significant estimates relate to our rate-regulated subsidiaries, uncollectible accounts and other allowances for contingent losses, goodwill and other intangible assets, retirement plan benefit obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates.

Cash and Cash Equivalents

Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of March 31, 2014 and 2013, and December 31, 2013, $75 million, $76 million and $80 million, respectively, of cash and short and long-term investments was held by Tropical Shipping. As of March 31, 2014, in conjunction with negotiating the agreement to sell Tropical Shipping and Seven Seas, we determined that we no longer have the intent to indefinitely reinvest Tropical Shipping’s cash and short and long-term investments offshore. For more information on the sale of Tropical Shipping and Seven Seas, see Income Tax Expense and Goodwill within this note and Note 12.

Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.

Our wholesale services segment has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of March 31, 2014 and 2013, and December 31, 2013, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Inventories

For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 10 for information regarding a regulatory filing by Atlanta Gas Light related to natural gas inventory.

Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during interim periods that are expected to be restored prior to year end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO inventory liquidation. Any temporary LIFO liquidation is included as a current liability in our unaudited Condensed Consolidated Statements of Financial Position. Interim inventory decrements that are not expected to be restored prior to year end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of March 31, 2014 is expected to be restored prior to year end. The inventory decrement as of March 31, 2013 was restored prior to December 31, 2013.

Our retail operations, wholesale services and midstream operations segments carry inventory at the lower of cost or market value, 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 adjustments to reduce the weighted average cost of the natural gas inventory to market value. For the three months ended March 31, 2014, wholesale services recorded a $2 million LOCOM adjustment to reduce the value of our inventories to market value. We recorded no LOCOM adjustments for the three months ended March 31, 2013.

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 2013 Form 10-K.

As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). 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 value of the natural gas and weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflects 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 use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 and Note 5 for additional derivative disclosures.

Goodwill

During the first quarter of 2014, we completed an engineering study at our storage and fuels reporting unit within midstream operations, which indicated a reduced forecast of working gas capacity from what was projected when our 2013 annual goodwill impairment analysis was performed during the fourth quarter of 2013. Given that the 2013 annual goodwill impairment test indicated that the estimated fair value of this reporting unit exceeded its carrying amount by less than 5%, we considered this reduced storage capacity as an indicator of potential impairment and, accordingly, conducted an interim goodwill impairment analysis during the first quarter of 2014.

The estimated fair value of this reporting unit was determined utilizing the income approach, which estimated the fair value based upon the present value of estimated future cash flows. The forecasts used in the income approach, which were updated during the first quarter of 2014 to reflect the contracting activity that occurred during the quarter, assume discrete period revenue growth through fiscal 2022 to reflect the recovery of subscription rates, stabilization of earnings and establishment of a reasonable base year that was used to estimate the terminal value. Consistent with our 2013 annual goodwill impairment testing, we assumed a long-term earnings growth rate in the terminal year of 2.5%, which we believe is appropriate given the current economic and industry specific expectations. As of the valuation date, we utilized a discount rate of 7.0%, which we believe is appropriate as it reflects the relative risk and the time value of money, and is consistent with the peer group of this reporting unit as well as the discount rates that were utilized in our 2013 annual goodwill impairment tests.

The cash flow forecasts for this reporting unit assumed earnings growth over the next eight years. Should this growth not occur, this reporting unit may fail step one during a future goodwill impairment test. Along with any reductions to our cash flow forecasts, changes in other assumptions used in our impairment analysis may require us to proceed to step two of the goodwill impairment test in a future period. 

Our interim goodwill impairment test indicated that the estimated fair value of this reporting unit continues to exceed its carrying amount with a cushion of less than 10%. Continued declines in capacity or subscription rates, a sustained period at the current subscription rates or other changes to the assumptions and factors used in this analysis may result in a future failure of step one of the goodwill impairment test. The risk of impairment of the underlying long-lived assets is not estimated to be significant as the assets have long remaining useful lives and authoritative guidance requires such assets to be tested for impairment on the basis of undiscounted cash flows over their remaining useful lives. We will continue to monitor this reporting unit for potential impairment.

In April 2014 we entered into a definitive agreement to sell Tropical Shipping and Seven Seas. We have determined, based on the agreed-upon sale price, that $19 million of goodwill attributable to cargo shipping was impaired as of March 31, 2014. Accordingly, this impairment expense was recorded as a separate line item in our unaudited Condensed Consolidated Statements of Income. Changes in the amount of goodwill for the three months ended March 31, 2014 and 2013 are provided in the following table.

In millions	Distribution Operations		Retail Operations		Wholesale Services		Midstream Operations		Cargo Shipping			Other		Consolidated
Goodwill - December 31, 2012	$	1,640	$	122	$	-	$	14	$	61		$	-	$	1,837
2013 activity		-		46		-		-		-			-		46
Goodwill - March 31, 2013	$	1,640	$	168	$	-	$	14	$	61		$	-	$	1,883
Goodwill - December 31, 2013	$	1,640	$	173	$	-	$	14	$	61		$	-	$	1,888
Cargo shipping impairment		-		-		-		-		(19	)		-		(19	)
Goodwill - March 31, 2014	$	1,640	$	173	$	-	$	14	$	42		$	-	$	1,869

See Note 2 to our Consolidated Financial Statements included in Item 8 of our 2013 Form 10-K for additional information on impairment of assets.

Other Income

Our other income is detailed in the following table. For more information on our equity investment income, see Note 9.

	Three months ended March 31,
In millions	2014			2013
Equity investment income	$	3		$	3
AFUDC - equity		1			3
Other, net		(1	)		(1	)
Total other income	$	3		$	5

Income Tax Expense

As a result of our agreement to sell Tropical Shipping and Seven Seas, we have determined that the cumulative foreign earnings of cargo shipping will no longer be indefinitely reinvested offshore, and we recognized tax expense of $31 million in the three months ended March 31, 2014 related to the cumulative earnings for which no tax liabilities previously had been recorded. This resulted in an effective tax rate of 45.2% for the three months ended March 31, 2014 compared to 37.9% for the same period last year. As of March 31, 2014, we have $57 million of deferred income tax liabilities on our unaudited Condensed Consolidated Statements of Financial Position related to the cumulative earnings of our foreign subsidiaries that have not been repatriated.

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our net income attributable to AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. common shareholders reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. common shareholders that occurs when potentially dilutive common shares are added to 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. 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. common shareholders for the periods presented, if performance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised.

	Three months ended March 31,
In millions (except per share amounts)	2014		2013
Net income attributable to AGL Resources Inc.	$	290	$	154
Denominator:
Basic weighted average number of shares outstanding (1)		118.5		117.4
Effect of dilutive securities		0.4		0.3
Diluted weighted average number of shares outstanding		118.9		117.7
Earnings per share:
Basic	$	2.44	$	1.31
Diluted	$	2.44	$	1.31

(1) Daily weighted average shares outstanding.

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Note 1 - Organization and Basis of Presentation

3 Months Ended

Mar. 31, 2014

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 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.

The December 31, 2013 Condensed Consolidated Statement of Financial Position data was derived from our audited financial statements, but does not include all disclosures required by GAAP. We have prepared the accompanying unaudited Condensed Consolidated Financial Statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. Our unaudited Condensed Consolidated Financial Statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. These unaudited Condensed Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our 2013 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 and 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 consolidated VIE for which we are the primary beneficiary. For unconsolidated entities that we do not control, but exercise significant influence over, 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.

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Accounting Policies, by Policy (Policies)

3 Months Ended

Mar. 31, 2014

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 make estimates and judgments 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 literature or in the development of estimates that impact our financial statements. The most significant estimates relate to our rate-regulated subsidiaries, uncollectible accounts and other allowances for contingent losses, goodwill and other intangible assets, retirement plan benefit obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates.

Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents

Our cash and cash equivalents primarily consist of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of March 31, 2014 and 2013, and December 31, 2013, $75 million, $76 million and $80 million, respectively, of cash and short and long-term investments was held by Tropical Shipping. As of March 31, 2014, in conjunction with negotiating the agreement to sell Tropical Shipping and Seven Seas, we determined that we no longer have the intent to indefinitely reinvest Tropical Shipping’s cash and short and long-term investments offshore. For more information on the sale of Tropical Shipping and Seven Seas, see Income Tax Expense and Goodwill within this note and Note 12.

Energy Marketing Receivables And Payables [Policy Text Block]

Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.

Our wholesale services segment has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of March 31, 2014 and 2013, and December 31, 2013, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Inventory, Policy [Policy Text Block]

Inventories

For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 10 for information regarding a regulatory filing by Atlanta Gas Light related to natural gas inventory.

Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during interim periods that are expected to be restored prior to year end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO inventory liquidation. Any temporary LIFO liquidation is included as a current liability in our unaudited Condensed Consolidated Statements of Financial Position. Interim inventory decrements that are not expected to be restored prior to year end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. The inventory decrement as of March 31, 2014 is expected to be restored prior to year end. The inventory decrement as of March 31, 2013 was restored prior to December 31, 2013.

Our retail operations, wholesale services and midstream operations segments carry inventory at the lower of cost or market value, 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 adjustments to reduce the weighted average cost of the natural gas inventory to market value. For the three months ended March 31, 2014, wholesale services recorded a $2 million LOCOM adjustment to reduce the value of our inventories to market value. We recorded no LOCOM adjustments for the three months ended March 31, 2013.

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 2013 Form 10-K.

As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). 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 value of the natural gas and weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflects 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 use external market quotes and indices to value substantially all of our derivative instruments. See Note 4 and Note 5 for additional derivative disclosures.

Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]

Goodwill

During the first quarter of 2014, we completed an engineering study at our storage and fuels reporting unit within midstream operations, which indicated a reduced forecast of working gas capacity from what was projected when our 2013 annual goodwill impairment analysis was performed during the fourth quarter of 2013. Given that the 2013 annual goodwill impairment test indicated that the estimated fair value of this reporting unit exceeded its carrying amount by less than 5%, we considered this reduced storage capacity as an indicator of potential impairment and, accordingly, conducted an interim goodwill impairment analysis during the first quarter of 2014.

The estimated fair value of this reporting unit was determined utilizing the income approach, which estimated the fair value based upon the present value of estimated future cash flows. The forecasts used in the income approach, which were updated during the first quarter of 2014 to reflect the contracting activity that occurred during the quarter, assume discrete period revenue growth through fiscal 2022 to reflect the recovery of subscription rates, stabilization of earnings and establishment of a reasonable base year that was used to estimate the terminal value. Consistent with our 2013 annual goodwill impairment testing, we assumed a long-term earnings growth rate in the terminal year of 2.5%, which we believe is appropriate given the current economic and industry specific expectations. As of the valuation date, we utilized a discount rate of 7.0%, which we believe is appropriate as it reflects the relative risk and the time value of money, and is consistent with the peer group of this reporting unit as well as the discount rates that were utilized in our 2013 annual goodwill impairment tests.

The cash flow forecasts for this reporting unit assumed earnings growth over the next eight years. Should this growth not occur, this reporting unit may fail step one during a future goodwill impairment test. Along with any reductions to our cash flow forecasts, changes in other assumptions used in our impairment analysis may require us to proceed to step two of the goodwill impairment test in a future period. 

Our interim goodwill impairment test indicated that the estimated fair value of this reporting unit continues to exceed its carrying amount with a cushion of less than 10%. Continued declines in capacity or subscription rates, a sustained period at the current subscription rates or other changes to the assumptions and factors used in this analysis may result in a future failure of step one of the goodwill impairment test. The risk of impairment of the underlying long-lived assets is not estimated to be significant as the assets have long remaining useful lives and authoritative guidance requires such assets to be tested for impairment on the basis of undiscounted cash flows over their remaining useful lives. We will continue to monitor this reporting unit for potential impairment.

In April 2014 we entered into a definitive agreement to sell Tropical Shipping and Seven Seas. We have determined, based on the agreed-upon sale price, that $19 million of goodwill attributable to cargo shipping was impaired as of March 31, 2014. Accordingly, this impairment expense was recorded as a separate line item in our unaudited Condensed Consolidated Statements of Income. Changes in the amount of goodwill for the three months ended March 31, 2014 and 2013 are provided in the following table.

In millions	Distribution Operations		Retail Operations		Wholesale Services		Midstream Operations		Cargo Shipping			Other		Consolidated
Goodwill - December 31, 2012	$	1,640	$	122	$	-	$	14	$	61		$	-	$	1,837
2013 activity		-		46		-		-		-			-		46
Goodwill - March 31, 2013	$	1,640	$	168	$	-	$	14	$	61		$	-	$	1,883
Goodwill - December 31, 2013	$	1,640	$	173	$	-	$	14	$	61		$	-	$	1,888
Cargo shipping impairment		-		-		-		-		(19	)		-		(19	)
Goodwill - March 31, 2014	$	1,640	$	173	$	-	$	14	$	42		$	-	$	1,869

See Note 2 to our Consolidated Financial Statements included in Item 8 of our 2013 Form 10-K for additional information on impairment of assets.

Other Income [Policy Text Block]

Other Income

Our other income is detailed in the following table. For more information on our equity investment income, see Note 9.

	Three months ended March 31,
In millions	2014			2013
Equity investment income	$	3		$	3
AFUDC - equity		1			3
Other, net		(1	)		(1	)
Total other income	$	3		$	5

Income Tax, Policy [Policy Text Block]

Income Tax Expense

As a result of our agreement to sell Tropical Shipping and Seven Seas, we have determined that the cumulative foreign earnings of cargo shipping will no longer be indefinitely reinvested offshore, and we recognized tax expense of $31 million in the three months ended March 31, 2014 related to the cumulative earnings for which no tax liabilities previously had been recorded. This resulted in an effective tax rate of 45.2% for the three months ended March 31, 2014 compared to 37.9% for the same period last year. As of March 31, 2014, we have $57 million of deferred income tax liabilities on our unaudited Condensed Consolidated Statements of Financial Position related to the cumulative earnings of our foreign subsidiaries that have not been repatriated.

Earnings Per Share, Policy [Policy Text Block]

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our net income attributable to AGL Resources Inc. by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. common shareholders reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. common shareholders that occurs when potentially dilutive common shares are added to 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. 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. common shareholders for the periods presented, if performance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised.

	Three months ended March 31,
In millions (except per share amounts)	2014		2013
Net income attributable to AGL Resources Inc.	$	290	$	154
Denominator:
Basic weighted average number of shares outstanding (1)		118.5		117.4
Effect of dilutive securities		0.4		0.3
Diluted weighted average number of shares outstanding		118.9		117.7
Earnings per share:
Basic	$	2.44	$	1.31
Diluted	$	2.44	$	1.31

(1) Daily weighted average shares outstanding.

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Note 9 - Non-Wholly Owned Entities

3 Months Ended

Mar. 31, 2014

Noncontrolling Interest [Abstract]

Noncontrolling Interest Disclosure [Text Block]

Note 9 - Non-Wholly Owned Entities

Variable Interest Entities

SouthStar, a joint venture owned by us and Piedmont, is our only VIE for which we are the primary beneficiary, which requires us to consolidate its assets, liabilities and statements of income. See Note 10 to our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K. Earnings from SouthStar in 2014 and 2013 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 each of the three months ended March 31, 2014 and $1 million for the three months ended March 31, 2013. 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. Generally, this distribution occurs in the first quarter of each fiscal year. For each of the three months ended March 31, 2014 and 2013, SouthStar distributed $17 million to Piedmont. The following table provides additional information about SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our unaudited Condensed Consolidated Statements of Financial Position.

	March 31, 2014							December 31, 2013							March 31, 2013
In millions	Consolidated		SouthStar (1)		% (2)			Consolidated		SouthStar (1)		% (2)			Consolidated		SouthStar (1)		% (2)
Current assets	$	3,448	$	318		9	%	$	2,733	$	264		10	%	$	2,361	$	143		6	%
Goodwill and other intangible assets		2,039		138		7			2,061		139		7			2,039		-		-
Long-term assets and other deferred debits		9,889		20		-			9,862		12		-			9,540		10		-
Total assets	$	15,376	$	476		3	%	$	14,656	$	415		3	%	$	13,940	$	153		1	%
Current liabilities	$	3,753	$	171		5	%	$	3,122	$	95		3	%	$	3,060	$	51		2	%
Long-term liabilities and other deferred credits		7,712		16		-			7,858		-		-			7,339		-		-
Total Liabilities		11,465		187		2			10,980		95		1			10,399		51		1
Equity		3,911		289		7			3,676		320		9			3,541		102		3
Total liabilities and equity	$	15,376	$	476		3	%	$	14,656	$	415		3	%	$	13,940	$	153		1	%

(1) These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar

(2) SouthStar’s percentage of the amount on our Statements of Financial Position.

The following table provides information on SouthStar’s operating revenues and operating expenses for the periods presented, which are consolidated within our unaudited Condensed Consolidated Statements of Income.

	Three months ended March 31,
In millions	2014		2013
Operating revenues	$	374	$	250
Operating expenses
Cost of goods sold		270		164
Operation and maintenance		24		18
Depreciation and amortization		2		1
Total operating expenses		296		183
Operating income	$	78	$	67

Equity Method Investments

Income from our equity method investments is classified as other income in our unaudited Condensed Consolidated Statements of Income. For more information about our equity method investments, see Note 10 to our Consolidated Financial Statements under Item 8 included in our 2013 Form 10-K.

The carrying amounts of our investments that are accounted for under the equity method at March 31 were as follows:

In millions	2014		2013
Triton	$	67	$	72
Horizon Pipeline		15		16
Other (1)		1		9
Total	$	83	$	97

(1) Includes our investment in Sawgrass Storage. In December 2013, the joint venture decided to terminate the development of the Sawgrass storage facility and reduced the carrying amount of the joint venture’s long-lived assets to fair value.

The following table provides the income from our equity method investments for the three months ended March 31.

In millions	2014		2013
Triton	$	2	$	2
Horizon Pipeline		1		1
Total	$	3	$	3

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Note 5 - Derivative Instruments

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

Note 5 - Derivative Instruments

A description of our objectives and strategies for using derivative instruments, related accounting policies and methods used to determine their fair values are described in Note 2. See Note 4 for additional fair value disclosures.

Certain of our derivative instruments contain credit-risk-related or other contingent features that could require us to post collateral in the normal course of business when our financial instruments are in net liability positions. As of March 31, 2014, for agreements with such features, derivative instruments with liability fair values totaled $82 million, for which we had posted no collateral to our counterparties. The maximum collateral that could be required with these features is $15 million. For more information, see “Energy Marketing Receivables and Payables” in Note 2, which also have credit-risk-related or other contingent features. Our derivative instrument activities are included within operating cash flows as an adjustment to net income of ($17) million and $18 million for the three months ended March 31, 2014 and 2013, respectively. See Note 4 for additional derivative instrument information. The following table summarizes the various ways in which we account for our derivative instruments and the impact on our unaudited Condensed Consolidated Financial Statements.

Accounting Treatment	Recognition and Measurement
	Statements of Financial Position	Statements of Income
Cash flow hedge	Derivative carried at fair value	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated OCI (loss)	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated OCI (loss) and into earnings when the hedged transaction affects earnings
Fair value hedge	Derivative carried at fair value	Gains or losses on the derivative instrument and the hedged item are recognized in earnings. As a result, to the extent the hedge is effective, the gains or losses will offset and there is no impact on earnings. Any hedge ineffectiveness will impact earnings
	Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item
Not designated as hedges	Derivative carried at fair value	Realized and unrealized gains or losses on the derivative instrument are recognized in earnings
	Distribution operations’ gains and losses on derivative instruments are deferred as regulatory assets or liabilities until included in cost of goods sold	Gains or losses on these derivative instruments are ultimately included in billings to customers and are recognized in cost of goods sold in the same period as the related revenues

Quantitative Disclosures Related to Derivative Instruments

As of the dates presented, our derivative instruments were comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. We had a net long natural gas contracts position outstanding in the following quantities:

In Bcf (1)	March 31, 2014 (2)			December 31, 2013			March 31, 2013
Hedge designation
Cash flow hedges		6			6			6
Not designated as hedges		277			183			304
Total hedges		283			189			310
Hedge position
Short position		(2,491	)		(2,622	)		(1,902	)
Long position		2,774			2,811			2,212
Net long position		283			189			310

(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 97% of these contracts have durations of two years or less and the remaining 3% expire between 2 and 6 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 Nicor Gas and Elizabethtown Gas are reflected in accrued natural gas costs within our Consolidated Statements of Financial Position until billed to customers. The following amounts represent the net realized gains (losses) related to these natural gas cost hedges for the periods presented.

	Three months ended March 31,
In millions	2014		2013
Nicor Gas	$	2	$	(1	)
Elizabethtown Gas		3		(3	)

The following table presents the fair values and unaudited Condensed Consolidated Statements of Financial Position classifications of our derivative instruments as of the dates presented.

		March 31, 2014						December 31, 2013						March 31, 2013
In millions	Classification	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges and fair value hedges
Natural gas contracts	Current	$	2		$	-		$	3		$	(1	)	$	3		$	(1	)
Interest rate swap agreements	Current		-			-			-			-			5			-
Total			2			-			3			(1	)		8			(1	)
Not designated as cash flow hedges
Natural gas contracts	Current		675			(703	)		691			(761	)		332			(327	)
Natural gas contracts	Long-term		80			(98	)		206			(220	)		46			(48	)
Total			755			(801	)		897			(981	)		378			(375	)
Gross amount of recognized assets and liabilities (1)			757			(801	)		900			(982	)		386			(376	)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)			(619	)		719			(781	)		902			(275	)		352
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)		$	138		$	(82	)	$	119		$	(80	)	$	111		$	(24	)

(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 above do not include cash collateral held on deposit in broker margin accounts of $100 million as of March 31, 2014, $121 million as of December 31, 2013 and $77 million as of March 31, 2013. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table.

(3) At March 31, 2014, December 31, 2013 and March 31, 2013 we held letters of credit from counterparties that would offset, under master netting arrangements, 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 in our unaudited Condensed Consolidated Statements of Income for the periods presented.

	Three months ended March 31,
In millions	2014			2013
Designated as cash flow hedges
Natural gas contracts - net gain reclassified from OCI to cost of goods sold	$	3		$	-
Natural gas contracts - net gain reclassified from OCI to operation and maintenance expense		1			-
Interest rate swaps - loss reclassified from OCI to interest expense		-			(3	)
Income tax benefit		-			1
Net of tax		4			(2	)
Not designated as hedges (1)
Natural gas contracts - net fair value adjustments recorded in operating revenues		(30	)		(24	)
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		2			-
Income tax benefit		11			8
Net of tax		(17	)		(16	)
Total losses on derivative instruments, net of tax	$	(13	)	$	(18	)

(1) Associated with the fair value of derivative instruments held at March 31, 2014 and 2013.

(2) Excludes losses recorded in cost of goods sold associated with weather derivatives of $5 million for the three months ended March 31, 2014 and $2 million for the three months ended March 31, 2013.

Any amounts recognized in operating income, related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for the three months ended March 31, 2014 and 2013.

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 $3 million. These deferred gains and losses are related to natural gas derivative contracts associated with retail operations and Nicor Gas’ system use. The expected gains are based upon the fair values of these financial instruments at March 31, 2014.

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 2013 Form 10-K.

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Note 10 - Commitments, Guarantees and Contingencies (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended		12 Months Ended
	Nov. 30, 2012	Mar. 31, 2014	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2009	Feb. 01, 2012
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Gas Balancing Volume Amount (in Cubic Feet)			4,800,000,000
Illinois Commission [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Loss Contingency, Damages Sought, Value					$ 85
Loss Contingency, Estimate of Possible Loss						64
Loss Contingency, Damages Awarded, Value	72
Loss Contingency Accrual, Period Increase (Decrease)			8
Loss Contingency Accrual			72
Loss Contingency, Damages Paid, Value		35		29
IAGO [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Loss Contingency, Damages Sought, Value					255
CUB [Member]
Note 10 - Commitments, Guarantees and Contingencies (Details) [Line Items]
Loss Contingency, Damages Sought, Value					$ 305

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Note 3 - Regulated Operations

3 Months Ended

Mar. 31, 2014

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities [Text Block]

Note 3 - 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 and estimated future expenditures that would otherwise be charged to expense in the current period are capitalized as regulatory assets when it is probable that such costs or expenditures 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 are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulatory commissions. The following table summarizes our regulatory assets and liabilities as of the dates presented.

In millions	March 31, 2014		December 31, 2013		March 31, 2013
Regulatory assets
Deferred natural gas costs	$	161	$	1	$	-
Recoverable regulatory infrastructure program costs		48		48		47
Recoverable ERC		38		45		28
Recoverable pension and retiree welfare benefit costs		9		9		19
Other		41		59		25
Total regulatory assets – current		297		162		119
Recoverable ERC		419		433		415
Recoverable pension and retiree welfare benefit costs		97		99		192
Recoverable regulatory infrastructure program costs		96		87		135
Long-term debt fair value adjustment		80		82		88
Other		44		36		48
Total regulatory assets - long-term		736		737		878
Total regulatory assets	$	1,033	$	899	$	997
Regulatory liabilities
Bad debt over collection	$	41	$	41	$	39
Accumulated removal costs		27		27		17
Accrued natural gas costs		24		92		133
Deferred seasonal rates		20		-		20
Other		49		23		29
Total regulatory liabilities – current		161		183		238
Accumulated removal costs		1,456		1,445		1,413
Regulatory income tax liability		27		27		26
Unamortized investment tax credit		25		26		28
Bad debt over collection		14		17		20
Other		28		3		11
Total regulatory liabilities - long-term		1,550		1,518		1,498
Total regulatory liabilities	$	1,711	$	1,701	$	1,736

Base rates are designed to provide the opportunity for both a recovery of cost and 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 believe that we will be able to recover such costs consistent with our historical recoveries.

In the event the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income and be classified as an extraordinary item. Additionally, while some regulatory liabilities would be written off, others would continue to be recorded as liabilities, but not as regulatory liabilities.

Natural Gas Costs We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. We defer or accrue the difference between the actual cost of gas and the amount of commodity revenue earned in a given period, such that no operating margin is recognized related to these costs. The deferred or accrued amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. The following table illustrates the change in net position of these costs from March 31, 2013 to March 31, 2014.

In millions	March 31, 2014			March 31, 2013			Change
Deferred natural gas costs	$	161		$	-		$	161
Accrued natural gas costs		(24	)		(133	)		109
Total (1)	$	137		$	(133	)	$	270

(1) The $270 million change resulted from increased natural gas prices during the first quarter of 2014 compared to the first quarter of 2013, primarily driven by colder weather experienced in the current quarter. These costs will be fully recovered in future periods.

Environmental Remediation Costs We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites. The ERC assets and liabilities are associated with our distribution operations segment and are generally recoverable through rate mechanisms.

Our ERC liabilities are estimates of future remediation costs for investigation and cleanup of our current and former operating sites that are contaminated. These estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering 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. The following table provides additional information on the costs related to remediation of our current and former operating sites as of March 31, 2014 and reflects minor changes in estimates since we filed our 2013 Form 10-K.

In millions	Probabilistic model cost estimates			Engineering estimates		Amount recorded		Expected costs over next 12 months
Illinois	$211	-	$461	$	42	$	246	$	39
New Jersey	139	-	233		6		144		25
Georgia and Florida	28	-	112		8		39		10
North Carolina		n/a			11		11		8
Total	$378	-	$806	$	67	$	440	$	82

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Note 4 - Fair Value Measurements

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

Note 4 - Fair Value Measurements

The methods used to determine the fair values of our assets and liabilities are described within Note 2.

Derivative Instruments

The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value on a recurring basis in our unaudited Consolidated Statements of Financial Position as of the dates presented. See Note 5 for additional derivative instrument information.

	March 31, 2014					December 31, 2013					March 31, 2013
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	18	$	(38	)	$	6	$	(79	)	$	14	$	(38	)
Significant other observable inputs (Level 2)		50		(75	)		67		(79	)		49		(23	)
Netting of cash collateral		69		31			43		78			40		37
Total carrying value (2) (3)	$	137	$	(82	)	$	116	$	(80	)	$	103	$	(24	)
Interest rate derivatives
Significant other observable inputs (Level 2)	$	-	$	-		$	-	$	-		$	6	$	-

(1) Balances of $1 million at March 31, 2014, $3 million at December 31, 2013 and $2 million at March 31, 2013 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) for any of the dates presented.

(3) There were no significant transfers between Level 1, Level 2 or Level 3 for any of the dates presented.

Money Market Funds

The fair values of our money market funds were recorded within short-term investments as of the following dates.

In millions	March 31, 2014		December 31, 2013		March 31, 2013
Money market funds (1)	$	48	$	48	$	48

(1) Carried at fair value and classified as Level 1 within the fair value hierarchy.

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. The fair value adjustment of Nicor Gas’ first mortgage bonds is being amortized over the lives of the bonds. The following table presents the carrying amount and fair value of our long-term debt as of the following dates.

In millions	March 31, 2014		December 31, 2013		March 31, 2013
Long-term debt carrying amount	$	3,810	$	3,813	$	3,550
Long-term debt fair value (1)		4,095		3,956		4,006

(1) Fair value determined using Level 2 inputs.

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Note 6 - Employee Benefit Plans

3 Months Ended

Mar. 31, 2014

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 2013 Form 10-K. Following are the components of our pension costs for the periods indicated.

	Three months ended March 31,
In millions	2014			2013
Service cost	$	6		$	8
Interest cost		12			10
Expected return on plan assets		(16	)		(16	)
Recognized actuarial loss		5			8
Net periodic pension benefit cost	$	7		$	10

Welfare Benefits

The benefits of our Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan) are described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2013 Form 10-K. Following are the components of our welfare costs for the periods indicated.

	Three months ended March 31,
In millions	2014			2013
Service cost	$	1		$	1
Interest cost		4			3
Expected return on plan assets		(2	)		(1	)
Net amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		1			2
Net periodic welfare benefit cost	$	3		$	4

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Note 11 - Segment Information (Details) - Operating Revenues (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	$ 2,563		$ 1,709
Thrid Party Gross Costs	1,454		973
Wholesale Services [Member] | Third Party Gross Revenues [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	4,051		2,094
Wholesale Services [Member] | Intercompany Revenues [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	298		140
Wholesale Services [Member] | Total Gross Revenues [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	4,349		2,234
Wholesale Services [Member] | Third Party Gross Costs [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Thrid Party Gross Costs	4,016		2,195
Wholesale Services [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues	333	[1]	39	[1]
Thrid Party Gross Costs	$ 3	[1]	$ 10	[1]

[1] Wholesale services records its energy marketing and risk management revenues on a net basis. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.

XML

Note 11 - Segment Information (Details) - Intersegment Reporting (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 2,563		$ 1,709
Operating expenses
Cost of goods sold	1,454		973
Operation and maintenance	317		259
Depreciation and amortization	98		107
Taxes other than income taxes	89		71
Goodwill impairment loss	19
Total operating expenses	1,977		1,410
Operating income (loss)	586		299
Other income	3		5
EBIT	589		304
Identifiable and total assets	15,376	[1]	13,940	[1]	14,656	[2]
Capital expenditures	164		148
External Parties [Member] | Distribution Operations [Member]
Segment Reporting Information [Line Items]
Revenues	1,738		1,264
External Parties [Member] | Retail Operations [Member]
Segment Reporting Information [Line Items]
Revenues	406		302
External Parties [Member] | Wholesale Services [Member]
Segment Reporting Information [Line Items]
Revenues	286	[3]	39	[3]
External Parties [Member] | Midstream Operations [Member]
Segment Reporting Information [Line Items]
Revenues	44		24
External Parties [Member] | Cargo Shipping [Member]
Segment Reporting Information [Line Items]
Revenues	89		87
External Parties [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues		[4]	(7)	[4]
External Parties [Member]
Segment Reporting Information [Line Items]
Revenues	2,563		1,709
Intersegment Eliminations [Member] | Distribution Operations [Member]
Segment Reporting Information [Line Items]
Revenues	75	[3]	55	[3]
Intersegment Eliminations [Member] | Retail Operations [Member]
Segment Reporting Information [Line Items]
Revenues		[3]		[3]
Intersegment Eliminations [Member] | Wholesale Services [Member]
Segment Reporting Information [Line Items]
Revenues	47	[3]		[3]
Intersegment Eliminations [Member] | Midstream Operations [Member]
Segment Reporting Information [Line Items]
Revenues		[3]		[3]
Intersegment Eliminations [Member] | Cargo Shipping [Member]
Segment Reporting Information [Line Items]
Revenues		[3]		[3]
Intersegment Eliminations [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	(122)	[3],[4]	(55)	[3],[4]
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues		[3]		[3]
Distribution Operations [Member]
Segment Reporting Information [Line Items]
Revenues	1,813		1,319
Operating expenses
Cost of goods sold	1,202		765
Operation and maintenance	211		185
Depreciation and amortization	80		90
Taxes other than income taxes	82		64
Total operating expenses	1,575		1,104
Operating income (loss)	238		215
Other income	1		3
EBIT	239		218
Identifiable and total assets	11,923	[1]	11,258	[1]	11,727	[2]
Capital expenditures	150		137
Retail Operations [Member]
Segment Reporting Information [Line Items]
Revenues	406		302
Operating expenses
Cost of goods sold	280		195
Operation and maintenance	37		31
Depreciation and amortization	6		5
Taxes other than income taxes	1		1
Total operating expenses	324		232
Operating income (loss)	82		70
EBIT	82		70
Identifiable and total assets	749	[1]	668	[1]	694	[2]
Capital expenditures	3		1
Wholesale Services [Member]
Segment Reporting Information [Line Items]
Revenues	333	[3]	39	[3]
Operating expenses
Cost of goods sold	3	[3]	10	[3]
Operation and maintenance	36	[3]	13	[3]
Depreciation and amortization		[3]		[3]
Taxes other than income taxes	1	[3]	1	[3]
Goodwill impairment loss		[3]
Total operating expenses	40	[3]	24	[3]
Operating income (loss)	293	[3]	15	[3]
Other income		[3]		[3]
EBIT	293	[3]	15	[3]
Identifiable and total assets	1,782	[1],[3]	1,005	[1],[3]	1,166	[2]
Capital expenditures	1	[3]		[3]
Midstream Operations [Member]
Segment Reporting Information [Line Items]
Revenues	44		24
Operating expenses
Cost of goods sold	36		12
Operation and maintenance	6		6
Depreciation and amortization	5		4
Taxes other than income taxes	1		1
Total operating expenses	48		23
Operating income (loss)	(4)		1
Other income	1		1
EBIT	(3)		2
Identifiable and total assets	698	[1]	714	[1]	713	[2]
Capital expenditures			4
Cargo Shipping [Member]
Segment Reporting Information [Line Items]
Revenues	89		87
Operating expenses
Cost of goods sold	55		53
Operation and maintenance	29		28
Depreciation and amortization	5		5
Taxes other than income taxes	2		1
Goodwill impairment loss	19
Total operating expenses	110		87
Operating income (loss)	(21)
Other income	2		2
EBIT	(19)		2
Identifiable and total assets	419	[1]	459	[1]	445	[2]
Capital expenditures	3		1
Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	(122)	[4]	(62)	[4]
Operating expenses
Cost of goods sold	(122)	[4]	(62)	[4]
Operation and maintenance	(2)	[4]	(4)	[4]
Depreciation and amortization	2	[4]	3	[4]
Taxes other than income taxes	2	[4]	3	[4]
Goodwill impairment loss		[4]
Total operating expenses	(120)	[4]	(60)	[4]
Operating income (loss)	(2)	[4]	(2)	[4]
Other income	(1)	[4]	(1)	[4]
EBIT	(3)	[4]	(3)	[4]
Identifiable and total assets	(195)	[1],[4]	(164)	[1],[4]	(89)	[2],[4]
Capital expenditures	$ 7	[4]	$ 5	[4]

[1] Identifiable assets are those used in each segment's operations.

[2] Identifiable assets are those assets used in each segment's operations.

[3] Wholesale services records its energy marketing and risk management revenues on a net basis. A reconciliation of our operating revenues and our intercompany revenues is shown in the following table.

[4] The assets of our other segment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

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Note 2 - Significant Accounting Policies and Methods of Application (Details) - Changes in Amount of Goodwill (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013		Dec. 31, 2012
Goodwill [Line Items]
Goodwill	$ 1,869	$ 1,883	$ 1,888		$ 1,837
Activity	(19)	46
Distribution Operations [Member]
Goodwill [Line Items]
Goodwill	1,640	1,640	1,640		1,640
Retail Operations [Member]
Goodwill [Line Items]
Goodwill	173	168	173		122
Activity		46
Midstream Operations [Member]
Goodwill [Line Items]
Goodwill	14	14	14		14
Cargo Shipping [Member]
Goodwill [Line Items]
Goodwill	42	61	61		61
Activity	(19)
Other Segments [Member]
Goodwill [Line Items]
Goodwill				[1]

[1] The assets of our other segment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

XML

Note 7 - Debt and Credit Facilities (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Commercial Paper [Member] AGL Capital [Member]	Mar. 31, 2014 Commercial Paper [Member] Nicor Gas [Member]	Mar. 31, 2014 Commercial Paper [Member]	Mar. 31, 2014 Commercial Paper [Member] Minimum [Member]	Mar. 31, 2014 Commercial Paper [Member] Maximum [Member]	Mar. 31, 2014 Nicor Gas [Member]	Dec. 31, 2013 Nicor Gas [Member]	Mar. 31, 2013 Nicor Gas [Member]	Mar. 31, 2014 Maximum [Member]
Note 7 - Debt and Credit Facilities (Details) [Line Items]
Debt Instrument, Interest Rate, Effective Percentage			0.30%	0.20%
Debt Instrument, Term						1 day	108 days
Debt Instrument, Remaining Maturity Term						1 day	35 days
Proceeds from (Repayments of) Commercial Paper (in Dollars)	$ (430)	$ (509)
Proceeds from Short-term Debt, Maturing in More than Three Months (in Dollars)					50
Repayments of Short-term Debt, Maturing in More than Three Months (in Dollars)					$ 145
Ratio of Indebtedness to Net Capital								0.54	0.55	0.43	0.70

XML

Note 11 - Segment Information

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Segment Reporting Disclosure [Text Block]

Note 11 - Segment Information

Our operating segments comprise revenue-generating components of our company for which we produce separate financial information internally that is regularly used 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 five operating segments - distribution operations, retail operations, wholesale services, midstream operations, cargo shipping - and other, a non-operating segment.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in seven states. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities. Although the operations of our distribution operations segment are geographically dispersed, the operating subsidiaries within the distribution operations segment are regulated utilities, with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.

We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia, as well as various businesses that market retail energy-related products and services to residential and small business customers in Illinois. Additionally, retail operations provide home protection products and services. Our wholesale services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, they provide natural gas asset management and/or related logistics services for each of our utilities except Nicor Gas, as well as for nonaffiliated companies. Our midstream operations segment includes our non-utility storage and pipeline operations, including the operation of high-deliverability natural gas storage assets.

Our cargo shipping segment transports containerized cargo between Florida, the eastern coast of Canada, the Bahamas and the Caribbean region. Our cargo shipping segment also includes amounts related to cargo insurance coverage sold to our customers and other third parties. Our cargo shipping segment’s vessels are under foreign registry, and its containers are considered instruments of international trade. Our other segment includes intercompany eliminations and aggregated subsidiaries that are individually not significant on a stand-alone basis and that do not fit into one of our other five operating segments.

The chief operating decision maker of the company is the Chairman, President and Chief Executive Officer who utilizes EBIT as the primary measure of profit and loss in assessing the results of our segments and 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.

Information by segment on our Statements of Financial Position as of December 31, 2013 is as follows:

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	11,727		$	1,640
Retail operations		694			173
Wholesale services		1,166			-
Midstream operations		713			14
Cargo shipping		445			61
Other (2)		(89	)		-
Consolidated	$	14,656		$	1,888

(1) Identifiable assets are those assets used in each segment’s operations.

(2) The assets of our other segment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

Summarized Statements of Income, Statements of Financial Position and capital expenditure information by segment as of and for the periods presented are shown in the following tables.

Three months ended March 31, 2014

In millions	Distributionoperations		Retail operations		Wholesale services (1)		Midstream operations			Cargo shipping			Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	1,738	$	406	$	286	$	44		$	89		$	-		$	2,563
Intercompany revenues		75		-		47		-			-			(122	)		-
Total operating revenues		1,813		406		333		44			89			(122	)		2,563
Operating expenses
Cost of goods sold		1,202		280		3		36			55			(122	)		1,454
Operation and maintenance		211		37		36		6			29			(2	)		317
Depreciation and amortization		80		6		-		5			5			2			98
Taxes other than income taxes		82		1		1		1			2			2			89
Goodwill impairment loss		-		-		-		-			19			-			19
Total operating expenses		1,575		324		40		48			110			(120	)		1,977
Operating income (loss)		238		82		293		(4	)		(21	)		(2	)		586
Other income		1		-		-		1			2			(1	)		3
EBIT	$	239	$	82	$	293	$	(3	)	$	(19	)	$	(3	)	$	589
Identifiable and total assets (2)	$	11,923	$	749	$	1,782	$	698		$	419		$	(195	)	$	15,376
Capital expenditures	$	150	$	3	$	1	$	-		$	3		$	7		$	164

Three months ended March 31, 2013

In millions	Distributionoperations		Retail operations		Wholesale services (1)		Midstream operations		Cargo shipping		Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	1,264	$	302	$	39	$	24	$	87	$	(7	)	$	1,709
Intercompany revenues		55		-		-		-		-		(55	)		-
Total operating revenues		1,319		302		39		24		87		(62	)		1,709
Operating expenses
Cost of goods sold		765		195		10		12		53		(62	)		973
Operation and maintenance		185		31		13		6		28		(4	)		259
Depreciation and amortization		90		5		-		4		5		3			107
Taxes other than income taxes		64		1		1		1		1		3			71
Total operating expenses		1,104		232		24		23		87		(60	)		1,410
Operating income (loss)		215		70		15		1		-		(2	)		299
Other income		3		-		-		1		2		(1	)		5
EBIT	$	218	$	70	$	15	$	2	$	2	$	(3	)	$	304
Identifiable and total assets (2)	$	11,258	$	668	$	1,005	$	714	$	459	$	(164	)	$	13,940
Capital expenditures	$	137	$	1	$	-	$	4	$	1	$	5		$	148

(1) Wholesale services records its energy marketing and risk management revenues on a net basis. 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 ending March 31, 2014	$	4,051	$	298	$	4,349	$	4,016	$	333
Three months ending March 31, 2013		2,094		140		2,234		2,195		39

(2) Identifiable assets are those used in each segment’s operations.

(3) The assets of our other segment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

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Note 4 - Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2014

Note 4 - Fair Value Measurements (Tables) [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

In millions	March 31, 2014		December 31, 2013		March 31, 2013
Long-term debt carrying amount	$	3,810	$	3,813	$	3,550
Long-term debt fair value (1)		4,095		3,956		4,006

Money Market Funds [Member]

Note 4 - Fair Value Measurements (Tables) [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

In millions	March 31, 2014		December 31, 2013		March 31, 2013
Money market funds (1)	$	48	$	48	$	48

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]

	March 31, 2014					December 31, 2013					March 31, 2013
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	18	$	(38	)	$	6	$	(79	)	$	14	$	(38	)
Significant other observable inputs (Level 2)		50		(75	)		67		(79	)		49		(23	)
Netting of cash collateral		69		31			43		78			40		37
Total carrying value (2) (3)	$	137	$	(82	)	$	116	$	(80	)	$	103	$	(24	)
Interest rate derivatives
Significant other observable inputs (Level 2)	$	-	$	-		$	-	$	-		$	6	$	-

XML

Note 5 - Derivative Instruments (Details) - Derivative Instruments on the Consolidated Statements of Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Designated as cash flow hedges
Income tax benefit			$ 1
Net of tax	4	[1]	(2)	[1]
Not designated as hedges (1)
Total losses on derivative instruments, net of tax	(13)		(18)
Cash Flow Hedging [Member] | Cost of Sales [Member]
Designated as cash flow hedges
Natural gas contracts - gain (loss) reclassified from OCI	3
Cash Flow Hedging [Member] | Operating Expense [Member]
Designated as cash flow hedges
Natural gas contracts - gain (loss) reclassified from OCI	1
Cash Flow Hedging [Member] | Interest Expense [Member]
Designated as cash flow hedges
Natural gas contracts - gain (loss) reclassified from OCI			(3)
Cash Flow Hedging [Member]
Designated as cash flow hedges
Income tax benefit			1
Net of tax	4		(2)
Fair Value Hedging [Member] | Cost of Sales [Member]
Not designated as hedges (1)
Natural gas contracts - net value adjustments	2	[2],[3]		[2],[3]
Fair Value Hedging [Member] | Sales [Member]
Not designated as hedges (1)
Natural gas contracts - net value adjustments	(30)	[2]	(24)	[2]
Fair Value Hedging [Member]
Not designated as hedges (1)
Income tax benefit	11	[2]	8	[2]
Net of tax	$ (17)	[2]	$ (16)	[2]

[1] All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

[2] Associated with the fair value of derivative instruments held at March 31, 2014 and 2013.

[3] Excludes losses recorded in cost of goods sold associated with weather derivatives of $5 million for the three months ended March 31, 2014 and $2 million for the three months ended March 31, 2013.

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Note 4 - Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Fair Value Disclosures [Abstract]
Weather Derivative Premium	$ 1	$ 3	$ 2

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Condensed Consolidated Statements of Income (Unaudited) (Parentheticals) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating revenues, revenue taxes	$ 68	$ 50

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Cash flows from operating activities
Net income	$ 302	$ 164
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization	98	107
Deferred income taxes	42	(24)
Goodwill impairment loss	19
Change in derivative instrument assets and liabilities	(17)	18
Changes in certain assets and liabilities
Inventories, net of temporary LIFO liquidation	656	494
Accrued expenses	180	26
Trade payables, other than energy marketing	51	(6)
Energy marketing receivables and trade payables, net	8	92
Prepaid taxes	2	76
Receivables, other than energy marketing	(317)	(172)
Deferred/accrued natural gas costs	(228)	43
Other, net	57	32
Net cash flow provided by operating activities	853	850
Cash flows from investing activities
Expenditures for property, plant and equipment	(164)	(148)
Acquisitions of assets		(122)
Other, net		14
Net cash flow used in investing activities	(164)	(256)
Cash flows from financing activities
Net repayments of commercial paper	(430)	(509)
Dividends paid on common shares	(58)	(55)
Distribution to noncontrolling interest	(17)	(17)
Other, net	4	5
Net cash flow used in financing activities	(501)	(576)
Net increase in cash and cash equivalents	188	18
Cash and cash equivalents at beginning of period	105	131
Cash and cash equivalents at end of period	293	149
Cash paid during the period for
Interest	58	58
Income taxes	14	26
Non cash financing transaction
Refinancing of gas facility revenue bonds		$ 200

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Note 9 - Non-Wholly Owned Entities (Details) - SouthStar’s Revenues and Expenses (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Variable Interest Entity [Line Items]
Operating revenues	$ 2,563	$ 1,709
Operating income	586	299
Cost of goods sold	1,454	973
Operation and maintenance	317	259
Depreciation and amortization	98	107
Total operating expenses	1,977	1,410
South Star [Member]
Variable Interest Entity [Line Items]
Operating revenues	374	250
Operating income	78	67
Cost of goods sold	270	164
Operation and maintenance	24	18
Depreciation and amortization	2	1
Total operating expenses	$ 296	$ 183

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Note 5 - Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

In Bcf (1)	March 31, 2014 (2)			December 31, 2013			March 31, 2013
Hedge designation
Cash flow hedges		6			6			6
Not designated as hedges		277			183			304
Total hedges		283			189			310
Hedge position
Short position		(2,491	)		(2,622	)		(1,902	)
Long position		2,774			2,811			2,212
Net long position		283			189			310

Loss Recognized In Income [Table Text Block]

	Three months ended March 31,
In millions	2014		2013
Nicor Gas	$	2	$	(1	)
Elizabethtown Gas		3		(3	)

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

		March 31, 2014						December 31, 2013						March 31, 2013
In millions	Classification	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges and fair value hedges
Natural gas contracts	Current	$	2		$	-		$	3		$	(1	)	$	3		$	(1	)
Interest rate swap agreements	Current		-			-			-			-			5			-
Total			2			-			3			(1	)		8			(1	)
Not designated as cash flow hedges
Natural gas contracts	Current		675			(703	)		691			(761	)		332			(327	)
Natural gas contracts	Long-term		80			(98	)		206			(220	)		46			(48	)
Total			755			(801	)		897			(981	)		378			(375	)
Gross amount of recognized assets and liabilities (1)			757			(801	)		900			(982	)		386			(376	)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)			(619	)		719			(781	)		902			(275	)		352
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)		$	138		$	(82	)	$	119		$	(80	)	$	111		$	(24	)

Schedule of Derivative Instruments [Table Text Block]

	Three months ended March 31,
In millions	2014			2013
Designated as cash flow hedges
Natural gas contracts - net gain reclassified from OCI to cost of goods sold	$	3		$	-
Natural gas contracts - net gain reclassified from OCI to operation and maintenance expense		1			-
Interest rate swaps - loss reclassified from OCI to interest expense		-			(3	)
Income tax benefit		-			1
Net of tax		4			(2	)
Not designated as hedges (1)
Natural gas contracts - net fair value adjustments recorded in operating revenues		(30	)		(24	)
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		2			-
Income tax benefit		11			8
Net of tax		(17	)		(16	)
Total losses on derivative instruments, net of tax	$	(13	)	$	(18	)

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Note 3 - Regulated Operations (Details) - Summary of Regulatory Assets and Liabilities (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Regulatory assets
Regulatory assets, current	$ 297	$ 162	$ 119
Regulatory assets, long-term	736	737	878
Total regulatory assets	1,033	899	997
Regulatory liabilities
Regulatory liabilities, current	161	183	238
Regulatory liabilities, long-term	1,550	1,518	1,498
Total regulatory liabilities	1,711	1,701	1,736
Bad debt rider [Member]
Regulatory liabilities
Regulatory liabilities, current	41	41	39
Regulatory liabilities, long-term	14	17	20
Accumulated removal costs [Member]
Regulatory liabilities
Regulatory liabilities, current	27	27	17
Regulatory liabilities, long-term	1,456	1,445	1,413
Accrued natural gas costs [Member]
Regulatory liabilities
Regulatory liabilities, current	24	92	133
Seasonal Rates [Member]
Regulatory liabilities
Regulatory liabilities, current	20		20
Other Regulatory Liabilities [Member]
Regulatory liabilities
Regulatory liabilities, current	49	23	29
Regulatory liabilities, long-term	28	3	11
Regulatory Income Tax Liability [Member]
Regulatory liabilities
Regulatory liabilities, long-term	27	27	26
Unamortized investment tax credit [Member]
Regulatory liabilities
Regulatory liabilities, long-term	25	26	28
Deferred Natural Gas Costs [Member]
Regulatory assets
Regulatory assets, current	161	1
Recoverable regulatory infrastructure program costs [Member]
Regulatory assets
Regulatory assets, current	48	48	47
Regulatory assets, long-term	96	87	135
Recoverable Environmental Remediation Costs [Member]
Regulatory assets
Regulatory assets, current	38	45	28
Regulatory assets, long-term	419	433	415
Recoverable Pension And Other Retirement Benefit Costs [Member]
Regulatory assets
Regulatory assets, current	9	9	19
Regulatory assets, long-term	97	99	192
Other Regulatory Assets [Member]
Regulatory assets
Regulatory assets, current	41	59	25
Regulatory assets, long-term	44	36	48
Long-Term Debt Fair Value Adjustment [Member]
Regulatory assets
Regulatory assets, long-term	$ 80	$ 82	$ 88

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Note 10 - Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

Note 10 - Commitments, Guarantees and Contingencies

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.

We also are involved in legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. Although we are unable to determine the ultimate outcomes of these other contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable. For more information on these matters, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K.

Contingencies and Guarantees

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur. We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees is remote. No liability has been recorded for such guarantees and indemnifications as the fair value is immaterial.

Regulatory Matters

On December 21, 2012 Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve an imbalance of approximately 4.8 Bcf 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. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. We are currently working with the Marketers to settle this matter, and the resolution of this imbalance will ultimately be decided by the Georgia Commission. We are currently unable to predict the ultimate outcome and recovery.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites. See Note 3 for additional information.

Litigation

We are involved in litigation arising in the normal course of business. Although in some cases the company is unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require us to take charges against, or will result in reductions in, future earnings. Management believes that while the resolution of these contingencies, whether individually or in aggregate, could be material to earnings in a particular period, they will not have a material adverse effect on our consolidated financial position or cash flows. For additional litigation information, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K.

PBR Proceeding Nicor Gas’ PBR plan was a regulatory plan that provided economic incentives based on natural gas cost performance. The PBR plan went into effect in 2000 and was terminated effective January 1, 2003, following allegations that Nicor Gas acted improperly in connection with the plan. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. Since 2002 the amount of the savings and losses required to be shared has been disputed by the Citizens Utility Board (CUB) and others, with the Illinois Attorney General (IAG) intervening, and subject to extensive contested discovery and other regulatory proceedings before administrative law judges and the Illinois Commission. In 2009, the staff of the Illinois Commission, IAG and CUB requested refunds of $85 million, $255 million and $305 million, respectively.

In February 2012 we committed to a stipulation with the staff of the Illinois Commission for a resolution of the dispute through the crediting to Nicor Gas customers of $64 million. On November 5, 2012 the Administrative Law Judges issued a proposed order for a refund of $72 million to ratepayers. In the fourth quarter of 2012, we increased our accrual for this dispute by $8 million for a total of $72 million as a result of these developments and their effect on the estimated liability.

On June 7, 2013 the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas customers over a 12-month period. On July 1, 2013 we began refunding customers the full $72 million through our purchased gas adjustment mechanism based on natural gas throughput. Of this amount, $35 million was refunded during the first quarter of 2014 and $29 million was refunded in 2013.

CUB appealed the Illinois Commission’s order to the appellate court in Illinois. On February 28, 2014 CUB filed its initial brief with the appellate court requesting refunds consistent with its 2009 request. Nicor Gas’ reply is due May 16, 2014.