10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2013
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from        to
Commission File Number 1-14174
AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)
Georgia	58-2210952
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Ten Peachtree Place NE, Atlanta, Georgia 30309
(Address and zip code of principal executive offices)
404-584-4000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) 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. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” ”accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ	Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)	Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No þ
Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.
Class	Outstanding as of April 24, 2013
Common Stock, $5.00 Par Value	118,180,688

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended March 31, 2013

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 - Fair Value Measurements	14
	Note 4 - Derivative Instruments	15
	Note 5 - Employee Benefit Plans	17
	Note 6 - Debt and Credit Facilities	18
	Note 7 - Equity	19
	Note 8 - Non-Wholly Owned Entities	20
	Note 9 - Commitments, Guarantees and Contingencies	21
	Note 10 - Segment Information	23
2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
	Forward-Looking Statements	26
	Executive Summary	26
	Results of Operations	28
	Liquidity and Capital Resources	34
	Critical Accounting Policies and Estimates	39
3	Quantitative and Qualitative Disclosures About Market Risk	40
4	Controls and Procedures	42
	PART II - OTHER INFORMATION
1	Legal Proceedings	43
1A	Risk Factors	43
2	Unregistered Sales of Equity Securities and Use of Proceeds	43
4	Mine Safety Disclosures	43
6	Exhibits	43
	SIGNATURE	44

2

GLOSSARY OF KEY TERMS

2012 Form 10-K	Our Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 6, 2013
AGL Capital	AGL Capital Corporation
AGL Credit Facility	$1.3 billion credit agreement entered into by AGL Capital to support the AGL Capital commercial paper program
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Central Valley	Central Valley Gas Storage, LLC
Chattanooga Gas	Chattanooga Gas Company
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes financing costs, including interest on debt and income tax expense, each of which we evaluate on a consolidated level.
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 Storage	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of the effects of weather on our businesses, calculated as the extent to which the average daily temperature is less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher because weather is colder
Horizon Pipeline	Horizon Pipeline Company, LLC
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
LIBOR	London Inter-Bank Offered Rate
LIFO	Last-in, first-out, an accounting method used to value inventory
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. - an acquisition completed in December 2011 and former holding company of Nicor Gas
Nicor Advanced Energy	Prairie Point Energy, LLC, doing business as Nicor Advanced Energy
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
Nicor Services	Nicor Energy Services Company
Nicor Solutions	Nicor Solutions, LLC
NUI	NUI Corporation – acquired in November 2004
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, that excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes, Nicor merger expenses and gains or losses on the sale of our assets, if any.
OTC	Over-the-counter
PBR	Performance-based rate, a regulatory plan at Nicor Gas that provided economic incentives based on natural gas cost performance. The plan terminated in 2003.
Piedmont	Piedmont Natural Gas Company, Inc.
PP&E	Property, plant and equipment
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
Seven Seas	Seven Seas Insurance Company, Inc.
SNG	Substitute natural gas, a synthetic form of gas manufactured from coal
SouthStar	SouthStar Energy Services, LLC
STRIDE	Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
Tennessee Authority	Tennessee Regulatory Authority, the state regulatory agency for Chattanooga Gas
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, a Cayman Islands company. A wholly owned business and a carrier of containerized freight in the Bahamas and the Caribbean region
VaR	Value at risk is defined as 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 1 - 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, 2013			December 31, 2012			March 31, 2012
Current assets
Cash and cash equivalents	$	149		$	131		$	71
Short-term investments		43			58			57
Receivables
Gas, unbilled and other receivables		874			686			577
Energy marketing receivables		627			677			386
Less allowance for uncollectible accounts		39			28			19
Total receivables		1,462			1,335			944
Inventories, net		393			708			464
Regulatory assets		119			145			137
Derivative instruments		100			130			218
Other current assets		95			161			131
Total current assets		2,361			2,668			2,022
Long-term assets and other deferred debits
Property, plant and equipment		10,610			10,478			9,920
Less accumulated depreciation		2,202			2,131			1,947
Property, plant and equipment, net		8,408			8,347			7,973
Goodwill		1,883			1,837			1,813
Regulatory assets		878			944			1,057
Intangible assets		156			96			102
Derivative instruments		11			14			48
Other		243			235			224
Total long-term assets and other deferred debits		11,579			11,473			11,217
Total assets	$	13,940		$	14,141		$	13,239
Current liabilities
Short-term debt	$	868		$	1,377		$	730
Energy marketing trade payable		653			611			425
Accounts payable - trade		314			334			205
Current portion of long-term debt and capital leases		226			226			17
Regulatory liabilities		238			161			173
Accrued expenses		166			140			145
Temporary LIFO liquidation		179			-			89
Customer deposit and credit balances		115			143			130
Accrued regulatory infrastructure program costs		83			121			149
Accrued environmental remediation liabilities		63			57			39
Derivative instruments		20			33			93
Other current liabilities		135			135			153
Total current liabilities		3,060			3,338			2,348
Long-term liabilities and other deferred credits
Long-term debt		3,324			3,327			3,558
Accumulated deferred income taxes		1,568			1,588			1,447
Regulatory liabilities		1,498			1,477			1,431
Accrued environmental remediation liabilities		362			387			289
Accrued retiree welfare benefits		266			268			318
Accrued pension obligations		243			240			228
Derivative instruments		4			6			10
Other long-term liabilities and other deferred credits		74			75			184
Total long-term liabilities and other deferred credits		7,339			7,368			7,465
Total liabilities and other deferred credits		10,399			10,706			9,813
Commitments, guarantees and contingencies (see Note 9)
Equity
Common stock, $5 par value; 750,000,000 shares authorized: outstanding: 118,123,770 shares at March 31, 2013, 117,855,075 shares at December 31, 2012 and 117,282,844 shares at March 31, 2012		592			590			587
Additional paid in capital		2,019			2,014			1,994
Retained earnings		1,134			1,035			1,055
Accumulated other comprehensive loss		(211	)		(218	)		(218	)
Treasury shares, at cost: 216,523 shares at March 31, 2013 and December 31, 2012 and 213,341 shares at March 31, 2012		(8	)		(8	)		(8	)
Total common shareholders’ equity		3,526			3,413			3,410
Noncontrolling interest		15			22			16
Total equity		3,541			3,435			3,426
Total liabilities and equity	$	13,940		$	14,141		$	13,239
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	2013			2012
Operating revenues (includes revenue taxes of $50 in 2013 and $41 in 2012)	$	1,709		$	1,404
Operating expenses
Cost of goods sold		973			719
Operation and maintenance		259			245
Depreciation and amortization		107			104
Taxes other than income taxes		71			64
Nicor merger expenses		-			10
Total operating expenses		1,410			1,142
Operating income		299			262
Other income		5			4
Interest expense, net		(46	)		(47	)
Earnings before income taxes		258			219
Income tax expense		94			80
Net income		164			139
Less net income attributable to the noncontrolling interest		10			9
Net income attributable to AGL Resources Inc.	$	154		$	130
Per common share data
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	1.31		$	1.12
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	1.31		$	1.11
Cash dividends declared per common share	$	0.47		$	0.36
Weighted average number of common shares outstanding
Basic		117.4			116.7
Diluted		117.7			117.0

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	2013			2012
Net income	$	164		$	139
Other comprehensive income (loss), net of tax
Retirement benefit plans
Reclassification of actuarial losses to net benefit cost (net of income tax of $2 and $1)		4			1
Reclassification of prior service credits to net benefit cost		(1	)		-
Retirement benefit plans		3			1
Cash flow hedges, net of tax
Net derivative instrument gains (losses) arising during the period (net of income tax of $1 and $1)		2			(2	)
Reclassification of realized derivative instrument losses to net income (net of income tax of $1)		2			-
Cash flow hedges, net		4			(2	)
Other comprehensive income (loss), net of tax		7			(1	)
Comprehensive income		171			138
Less comprehensive income attributable to noncontrolling interest		10			9
Comprehensive income attributable to AGL Resources Inc.	$	161		$	129

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, 2011		117.0	$	586	$	1,989	$	967		$	(217	)	$	(7	)	$	21		$	3,339
Net income		-		-		-		130			-			-			9			139
Other comprehensive loss		-		-		-		-			(1	)		-			-			(1	)
Dividends on common stock ($0.36 per share)		-		-		-		(42	)		-			-			-			(42	)
Distributions to noncontrolling interest		-		-		-		-			-			-			(14	)		(14	)
Stock issued, dividend reinvestment plan		0.2		1		3		-			-			(1	)		-			3
Stock-based compensation expense (net of tax)		-		-		2		-			-			-			-			2
Balance as of March 31, 2012		117.2	$	587	$	1,994	$	1,055		$	(218	)	$	(8	)	$	16		$	3,426

	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 interest		-		-		-			-			-			-			(17	)		(17	)
Stock granted, share-based compensation, net of forfeitures		-		-		(6	)		-			-			-			-			(6	)
Stock issued, dividend reinvestment plans		-		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

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	2013			2012
Cash flows from operating activities
Net income	$	164		$	139
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		107			104
Change in derivative instrument assets and liabilities		18			15
Deferred income taxes		(24	)		-
Changes in certain assets and liabilities
Inventories, net of temporary LIFO liquidation		494			375
Energy marketing receivables and trade payables, net		92			56
Prepaid taxes		76			90
Accrued natural gas costs		43			37
Trade payables, other than energy marketing		(6	)		(61	)
Receivables, other than energy marketing		(172	)		119
Other - net		58			(39	)
Net cash flow provided by operating activities		850			835
Cash flows from investing activities
Expenditures for property, plant and equipment		(148	)		(171	)
Acquisitions of assets		(122	)		-
Other		14			(4	)
Net cash flow used in investing activities		(256	)		(175	)
Cash flows from financing activities
Net payments and borrowings of short-term debt		(509	)		(591	)
Dividends paid on common shares		(55	)		(42	)
Distribution to noncontrolling interest		(17	)		(14	)
Other		5			(11	)
Net cash flow used in financing activities		(576	)		(658	)
Net increase in cash and cash equivalents		18			2
Cash and cash equivalents at beginning of period		131			69
Cash and cash equivalents at end of period	$	149		$	71
Cash paid during the period for
Interest	$	58		$	54
Income taxes	$	26		$	-
Non cash financing transaction
Refinancing of gas facility revenue bonds	$	200		$	-

See Notes to Condensed Consolidated Financial Statements (Unaudited).

8

EAGL 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, 2012 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 2012 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 as of or for 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 and 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 8 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.

Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation. The reclassifications and revisions had no material impact on prior periods.

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 2012 Form 10-K. There were no significant changes to our accounting policies during the three months ended March 31, 2013.

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 regulatory infrastructure program accruals, environmental liability accruals, 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.

Inventories

Except for Nicor Gas, our gas inventories and the inventories we hold for Marketers are accounted for using the WACOG. In Georgia’s competitive environment, Marketers, including SouthStar, 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. Atlanta Gas Light assigns, on a monthly basis, 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 9 for information regarding a regulatory filing by Atlanta Gas Light related to gas inventory.

9

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. This inventory decrement is included 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, 2013 is expected to be restored prior to year-end. The inventory decrement as of March 31, 2012 was restored prior to December 31, 2012.

Our retail operations, wholesale services and midstream operations segments 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 price. For the three months ended March 31, 2013 and 2012, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our inventories to market value.

In millions	2013		2012
Retail operations	$	-	$	3
Wholesale services		-		18
Midstream operations		-		1

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, which enable our wholesale services segment to net receivables and payables by counterparty. 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 some 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, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of March 31, 2013, December 31, 2012 and March 31, 2012, 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.

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measures. The financial assets and liabilities measured and carried at fair value include cash equivalents, receivables, and derivative assets and liabilities. The carrying values of cash and cash equivalents, short and long-term investments, derivative assets and liabilities, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate fair value. The 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 2012 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 derivative instruments that we use to manage exposures arising from changing natural gas prices 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 3 and Note 4 for additional derivative disclosures.

10

Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. Such derivative instruments are carried at fair value each reporting period in our unaudited Condensed Consolidated Statements of Financial Position. In accordance with regulatory requirements, any realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. Thus, hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized.

Nicor Gas also enters into derivative instruments to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for company use. These derivative instruments are carried at fair value. To the extent hedge accounting is not elected, changes in such fair values are recorded in the current period as operation and maintenance expenses.

Retail OperationsWe have designated a portion of our derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges under the authoritative guidance related to derivatives and hedging. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period that the underlying hedged item is recognized in earnings.

We currently have minimal hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not completely offset the losses or gains on the hedged item. This cash flow hedge ineffectiveness is recorded in cost of goods sold in our unaudited Condensed Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges for accounting purposes, and we record changes in the fair value of such instruments within cost of goods sold in our unaudited Condensed Consolidated Statements of Income in the period of change.

We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange –traded options are carried at fair value in our unaudited Condensed Consolidated Statements of Financial Position, with changes reflected in operating revenues in our unaudited Condensed Consolidated Statements of Income. Non exchange-traded options are accounted for using the intrinsic value method and do not qualify for hedge accounting designation. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our unaudited Condensed Consolidated Statements of Income.

Wholesale ServicesWe purchase natural gas for storage when the current market price we pay to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures and OTC contracts to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is sold. We also enter into transactions to secure transportation capacity between two delivery points in order to serve our customers and various markets. We use NYMEX futures and OTC contracts to capture the price differential or spread between the locations served by the capacity in order to substantially lock in the operating margin we will ultimately realize when we physically flow natural gas between the two delivery points. These contracts generally meet the definition of derivatives and are carried at fair value in our unaudited Condensed Consolidated Statements of Financial Position, with changes in fair value recorded in operating revenues in our unaudited Condensed Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes.

The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage and transportation portfolio. We incur monthly demand charges for the contracted storage and transportation capacity, and payments associated with asset management agreements, and recognize these demand charges and payments in our unaudited Condensed Consolidated Statements of Income in the period they are incurred. This difference in accounting can result in volatility in our reported earnings, even though the economic margin is essentially unchanged from the date the transactions were consummated.

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Regulatory Assets and Liabilities

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. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries. In the event that 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.

Our regulatory assets and liabilities are summarized in the following table.

In millions	March 31, 2013		December 31, 2012		March 31, 2012
Regulatory assets
Recoverable regulatory infrastructure program costs	$	47	$	47	$	48
Recoverable environmental remediation costs		28		38		7
Recoverable pension and retiree welfare benefit costs		19		19		29
Other regulatory assets		25		41		53
Total regulatory assets - current		119		145		137
Recoverable environmental remediation costs		415		438		349
Recoverable pension and retiree welfare benefit costs		192		196		256
Recoverable regulatory infrastructure program costs		135		167		291
Long-term debt fair value adjustment		88		90		97
Other regulatory assets		48		53		64
Total regulatory assets - long-term		878		944		1,057
Total regulatory assets	$	997	$	1,089	$	1,194
Regulatory liabilities
Accrued natural gas costs	$	133	$	93	$	97
Bad debt rider		39		37		32
Accumulated removal costs		17		16		14
Other regulatory liabilities		49		15		30
Total regulatory liabilities - current		238		161		173
Accumulated removal costs		1,413		1,393		1,339
Unamortized investment tax credit		28		29		32
Regulatory income tax liability		26		27		26
Bad debt rider		20		17		20
Other regulatory liabilities		11		11		14
Total regulatory liabilities - long-term		1,498		1,477		1,431
Total regulatory liabilities	$	1,736	$	1,638	$	1,604

There have been no significant new types of regulatory assets or liabilities from those discussed in Note 2 to our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.

Other income

Our other income is detailed in the following table for the periods presented. For more information on our equity investment income, see Note 8.

	For the three months ended
	March 31,
In millions	2013			2012
Equity investment income	$	3		$	3
Allowance for funds used during construction (AFUDC) - equity		3			1
Other, net		(1	)		-
Total other income	$	5		$	4

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our 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 could occur when potentially dilutive common shares are added to common shares outstanding.

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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 criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods.

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)	2013		2012
Net income attributable to AGL Resources Inc.	$	154	$	130
Denominator:
Basic weighted average number of shares outstanding (1)		117.4		116.7
Effect of dilutive securities		0.3		0.3
Diluted weighted average number of shares outstanding		117.7		117.0
Earnings per share:
Basic	$	1.31	$	1.12
Diluted	$	1.31	$	1.11
(1) Daily weighted average shares outstanding.

Acquisition

On January 31, 2013, our retail operations segment acquired approximately 500,000 service plans and certain other assets from NiSource Inc. for $120 million, plus $2 million of working capital. These service plans provide home warranty protection solutions and energy efficiency leasing solutions for residential and small business utility customers and complements the retail services business acquired in the Nicor merger. The preliminary allocation of the purchase price is as follows:

In millions
Current assets	$	5
PP&E		11
Goodwill		46
Intangible assets		64
Current liabilities		(4	)
Total	$	122

Intangible assets related to this acquisition are primarily customer relationships of $47 million and trade names of $17 million. The amortization periods are estimated to be 14 years for customer relationships and 10 years for trade names.

Accounting Developments

On January 1, 2013, we adopted ASU 2013-01, Disclosures about Offsetting Assets and Liabilities, which requires disclosure about offsetting and related arrangements in order to help financial statement users to better understand the effect of those arrangements on our financial position. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 4 for additional disclosures about our offsetting of derivative assets and liabilities.

On January 1, 2013, we adopted ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 7 for additional disclosures relating to accumulated other comprehensive income.

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Note 3 - 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 Consolidated Statements of Financial Position as of the periods presented. See Note 4 for additional derivative instrument information.

	Recurring fair values - Derivative instruments
	March 31, 2013					December 31, 2012					March 31, 2012
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	14	$	(38	)	$	8	$	(45	)	$	7	$	(187	)
Significant other observable inputs (Level 2)		49		(23	)		96		(30	)		203		(68	)
Netting of cash collateral		40		37			33		36			47		162
Total carrying value (2) (3)	$	103	$	(24	)	$	137	$	(39	)	$	257	$	(93	)
Interest rate derivatives
Significant other observable inputs (Level 2)	$	6	$	-		$	3	$	-		$	9	$	(10	)

(1)   $2 million of premium at March 31, 2013, $4 million at December 31, 2012 and less than $1 million at March 31, 2012 associated with weather derivatives have been excluded, as they are not material and some are accounted for based on intrinsic value.

(2)   There were no material unobservable inputs (Level 3) for any of the periods presented.

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

Money Market Funds

The fair values of our money market funds were recorded within short-term and long-term investments as follows:

In millions	At March 31, 2013		At December 31, 2012		At March 31, 2012
Money market funds (1)	$	48	$	66	$	68

(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 were recorded at their acquisition date fair value. The fair value adjustment is being amortized over the life of the bonds. We estimate the fair value of our debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. The following table presents the amortized cost and fair value of our long-term debt as of the following periods.

In millions	March 31, 2013		December 31, 2012		March 31, 2012
Long-term debt amortized cost	$	3,550	$	3,553	$	3,575
Long-term debt fair value (1)	$	4,006	$	4,057	$	3,922

(1)   Fair value determined using Level 2 inputs.

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Note 4 - 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 3 for additional fair value disclosures.

Certain of our derivative instruments contain credit-risk-related or other contingent features that could increase the payments for collateral we post in the normal course of business when our financial instruments are in net liability positions. As of March 31, 2013, for agreements with such features, derivative instruments with liability fair values totaled $24 million, for which we had posted no collateral to our counterparties. In addition, our energy marketing receivables and payables, which also have credit-risk-related or other contingent features, are discussed in Note 2. Our derivative instrument activities are included within operating cash flows as an adjustment to net income of $18 million and $15 million for the three months ended March 31, 2013 and 2012, respectively. See Note 3 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	Income Statement
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 Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item	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
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	The gain or loss on these derivative instruments is reflected in natural gas costs and is ultimately included in billings to customers

Distribution Operations

The following amounts represent realized losses related to hedging natural gas costs for the three months ended March 31.

In millions	2013		2012
Nicor Gas	$	1	$	1
Elizabethtown Gas	$	3	$	9

Quantitative Disclosures Related to Derivative Instruments

As of the periods 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 net long natural gas contracts outstanding in the following quantities:

In Bcf (1)	March 31, 2013 (2)			December 31, 2012			March 31, 2012
Hedge designation
Cash flow hedges		6			6			7
Not designated as hedges		304			96			116
Total hedges		310			102			123
Hedge position
Short position		(1,902	)		(1,955	)		(1,942	)
Long position		2,212			2,057			2,065
Net long position		310			102			123

(1)   Volumes related to Nicor Gas exclude variable-priced contracts, which are accounted for as derivatives, but whose fair values are not directly impacted by changes in commodity prices.

(2)   Approximately 98% of these contracts have durations of two years or less and the remaining 2% expire between 2 and 6 years.

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Derivative Instruments in our Unaudited Condensed Consolidated Statements of Financial Position

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

	Unaudited Condensed Consolidated Statements of Financial	March 31, 2013						December 31, 2012						March 31, 2012
In millions	Position Location (1) (2)	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges and fair value hedges
Natural gas contracts	Current	$	3		$	(1	)	$	1		$	(2	)	$	5		$	(11	)
Natural gas contracts	Long-term		-			-			3			-			-			-
Interest rate swap agreements	Current		5			-			-			-			-			-
Interest rate swap agreements	Long-term		-			-			-			-			9			(11	)
Total			8			(1	)		4			(2	)		14			(22	)
Not designated as cash flow hedges
Natural gas contracts	Current		332			(327	)		394			(355	)		683			(718	)
Natural gas contracts	Long-term		46			(48	)		45			(50	)		82			(85	)
Total			378			(375	)		439			(405	)		765			(803	)
Gross amount of recognized assets and liabilities			386			(376	)		443			(407	)		779			(825	)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position			(275	)		352			(299	)		368			(513	)		722
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position		$	111		$	(24	)	$	144		$	(39	)	$	266		$	(103	)

(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 $77 million as of March 31, 2013, $69 million as of December 31, 2012 and $209 million as of March 31, 2012. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table.

Derivative Instruments Impacts in our Unaudited Condensed Consolidated Statements of Income

The following table presents the amounts of our derivative instruments in our unaudited Condensed Consolidated Statements of Income for the three months ended March 31, 2013 and 2012.

In millions	2013			2012
Designated as cash flow hedges
Natural gas contracts - loss reclassified from OCI into cost of goods sold for settlement of hedged item	$	-		$	(1	)
Interest rate swaps - ineffectiveness recorded as an offset to interest expense		(3	)		2
Not designated as hedges
Natural gas contracts - net fair value adjustments recorded in operating revenues (1)		(24	)		4
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		-			(2	)
Natural gas contracts - net value adjustments recorded in operation and maintenance expense		-			(1	)
Total (losses) gains on derivative instruments	$	(27	)	$	2

(1)   Associated with the fair value of existing derivative instruments at March 31, 2013 and 2012.

(2)   Excludes losses recorded in cost of goods sold associated with weather derivatives of $2 million for the three months ended March 31, 2013 and gains of $14 million for the three months ended March 31, 2012.

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, 2013 and 2012.

Our expected pre-tax net income (loss) to be reclassified from OCI and recognized in cost of goods sold, operation and maintenance expenses, operating revenues and interest expense in our unaudited Condensed Consolidated Statements of Income over the next 12 months is $2 million. These pre-tax deferred losses are recorded in OCI related to natural gas derivative contracts associated with retail operations and Nicor Gas. The expected losses are based upon the fair values of these financial instruments at March 31, 2013.

There have been no other significant changes to our derivative instruments, as described in Note 2 and Note 4 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.

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Note 5 - Employee Benefit Plans

Pension Benefits

On December 31, 2012, the AGL Resources Inc. Retirement Plan (AGL Plan), the Nicor Companies Pension and Retirement Plan (Nicor Plan) and the Employees’ Retirement Plan of NUI Corporation (NUI Plan) were merged with, and into, the AGL Plan. The eligibility and benefit terms for participants under the Nicor Plan and the NUI Plan were not changed as a result of the plan merger. The AGL Plan is described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.

Following are the components of our pension benefit costs for the periods indicated.

	Three months ended March 31,
In millions	2013			2012
Service cost	$	8		$	7
Interest cost		10			11
Expected return on plan assets		(16	)		(16	)
Net amortization of prior service cost		-			(1	)
Recognized actuarial loss		8			9
Net periodic pension benefit cost	$	10		$	10

Retiree Welfare Benefits

On December 31, 2012, the Nicor Gas Welfare Benefit Plan (Nicor Welfare Plan) was terminated and as of January 1, 2013, all participants under that plan became eligible to participate in the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan). This change in plan participation eligibility did not affect the benefit terms under the predecessor plans. The Nicor Welfare Plan benefits are now being offered to such participants under the AGL Welfare Plan. The benefits of the AGL Welfare Plan are described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.

Following are the components of our retiree welfare benefit costs for the periods indicated.

	Three months ended March 31,
In millions	2013			2012
Service cost	$	1		$	1
Interest cost		3			4
Expected return on plan assets		(1	)		(1	)
Net amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		2			3
Net periodic welfare benefit cost	$	4		$	6

Capitalized Costs

A portion of the net pension benefit and net periodic welfare benefit costs have been capitalized as a cost of constructing natural gas distribution facilities and the remainder is included in operation and maintenance expenses, net of amounts charged to affiliates.

Contributions

Our employees generally do not contribute to these pension and retiree welfare plans. We fund the qualified pension plan by contributing at least the minimum amounts required by applicable regulations and as recommended by our actuary. However, we may contribute in excess of the minimum required amounts.

As a result of merging the pension plans, there were no contributions required during the three months ended March 31, 2013. We contributed a combined $17 million to the AGL Plan and the NUI Plan during the same period last year. For more information on our pension plans, see Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.

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Note 6 - 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 that are included in our unaudited Condensed Consolidated Statements of Financial Position. For additional information on our debt, see Note 8 in our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.

			March 31, 2013							March 31, 2012
Dollars in millions	Year(s) due		Weighted average interest rate (1)			Outstanding		Outstanding at December 31, 2012		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper- AGL Capital (2)	2013			0.5	%	$	868	$	1,063		0.5	%	$	625
Commercial paper- Nicor Gas (2)	2013			0.4			-		314		0.5			105
Total short-term debt				0.5	%	$	868	$	1,377		0.5	%	$	730
Current portion of long-term debt and capital leases
Current portion of long-term debt	2013			4.5	%	$	225	$	225		8.3	%	$	15
Current portion of capital leases	2013			5.0			1		1		4.9			2
Total current portion of long-term debt and capital leases				4.5	%	$	226	$	226		8.0	%	$	17
Long-term debt - excluding current portion
Senior notes		2015-2041		5.1	%	$	2,325	$	2,325		5.1	%	$	2,550
First mortgage bonds		2016-2038		5.6			500		500		5.6			500
Gas facility revenue bonds		2022-2033		0.3			200		200		1.1			200
Medium-term notes		2017-2027		7.8			181		181		7.8			181
Total principal long-term debt				4.9	%	$	3,206	$	3,206		4.9	%	$	3,431
Fair value adjustment of long-term debt (3)		2016-2038		n/a		$	100	$	103		n/a		$	109
Unamortized debt premium, net		n/a		n/a			18		18		n/a			18
Total non-principal long-term debt				n/a		$	118	$	121		n/a		$	127
Total long-term debt						$	3,324	$	3,327				$	3,558
Total debt						$	4,418	$	4,930				$	4,305

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

(2)   As of March 31, 2013, the weighted average interest rate on our AGL Capital commercial paper borrowings was 0.5%.

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

Long-Term Debt

During the first quarter of 2013, we refinanced $200 million of our outstanding tax-exempt gas facility revenue bonds, $180 million of which were previously issued by the New Jersey Economic Development Authority and $20 million of which were issued by Brevard County, Florida. The refinancing involved a combination of the issuance of $60 million of refunding bonds to and the purchase of $140 million of existing bonds by a syndicate of banks. Our relationship with the syndicate of banks regarding the bonds is governed by an agreement that contains representations, warranties, covenants and default consistent with those contained in similar financing documents of ours. All of the bonds remain floating-rate instruments. AGL Resources had no cash receipts or payments in connection with the refinancing. The letters of credit providing credit support for the refinanced bonds along with other related agreements were terminated as a result of the refinancing.

Interest Rate Swaps

In April, 2013, we entered into two ten-year, $50 million fixed-rate forward-starting interest rate swaps to hedge any potential interest rate volatility prior to our anticipated issuance of senior notes during the second quarter 2013. The average interest rate on these swaps was 1.98%. Including existing forward-starting interest rate swap hedges, which were executed last year, we have fixed-rate swaps totaling $300 million in notional value at an average interest rate of 1.85%. We have designated the forward-starting interest rate swaps as cash flow hedges of our anticipated second quarter 2013 debt issuance.

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Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month; however, our goal is to maintain these ratios at levels between 50% and 60%. These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash OCI pension adjustments, other post-retirement 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 periods presented, which are within our required and targeted ranges.

	March 31, 2013			December 31, 2012			March 31, 2012
AGL Credit Facility		54	%		58	%		54	%
Nicor Gas Credit Facility		43	%		55	%		47	%

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.

Note 7 - Equity

Our other comprehensive income 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
Balance as of December 31, 2012	$	(6	)	$	(212	)	$	(218	)
Other comprehensive income, before reclassifications		2			-			2
Amounts reclassified from accumulated other comprehensive income		2			3			5
Net current-period other comprehensive income		4			3			7
Balance as of March 31, 2013	$	(2	)	$	(209	)	$	(211	)

(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 for the period ended March 31, 2013, and the ultimate impact on net income.

In millions	Amount reclassified from Accumulated Other Comprehensive Loss (1)			Affected line item in the Income Statement
Cash flow hedges
Interest rate contracts	$	(3	)	Interest expense, net
Income tax benefit		1
Total cash flow hedges		(2	)
Retirement benefit plan amortization of
Actuarial losses		(6	)	See (2), below
Prior service credits		1		See (2), below
Total before income tax		(5	)
Income tax benefit		2
Total retirement benefit plans		(3	)
Total reclassification for the period	$	(5	)

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

(2)   These accumulated OCI components are included in the computation of net periodic benefit cost. See Note 5, Employee Benefit Plans, for additional details about net periodic benefit cost.

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Note 8 - Non-Wholly Owned Entities

Variable Interest Entities

On a quarterly basis, we evaluate all of our ownership interests to determine if they represent a VIE as defined by the authoritative accounting guidance on consolidation, and if so, which party is the primary beneficiary. We have determined that 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 2012 Form 10-K. Earnings from SouthStar in 2013 and 2012 were allocated entirely in accordance with the ownership interests.

SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to retail customers primarily in Georgia, under various other trade names to retail customers in Ohio, Florida and New York and to commercial and industrial customers in the southeastern United States.

During the three months ended March 31, 2013, there have been no significant changes to the primary risks associated with SouthStar as discussed in our risk factors included in Item 1A of our 2012 Form 10-K.

SouthStar’s financial results are seasonal in nature, with business depending to a great extent on the first and fourth quarters of each year. SouthStar’s current assets consist primarily of natural gas inventory, derivative instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in AGL Capital’s commercial paper program. See Note 2 for additional discussions of SouthStar’s inventories. SouthStar’s restricted assets consist of customer deposits and were immaterial as of March 31, 2013 and 2012. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative instruments and payables to us from its participation in AGL Capital’s commercial paper program.

SouthStar’s other contractual commitments and obligations, including operating leases and agreements with third party providers, do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. As a result, our maximum exposure to a loss at SouthStar is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. With the exception of our corporate guarantees, we have not entered into any arrangements that could require us to provide financial support to SouthStar.

Price and volume fluctuations of SouthStar’s natural gas inventories can cause significant variations in our working capital and cash flow from operations. Changes in our operating cash flows are also attributable to SouthStar’s working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas purchases and cash collateral amounts that SouthStar maintains to facilitate its derivative instruments.

Cash flows used in our investing activities include capital expenditures for SouthStar of $1 million for the three months ended March 31, 2013 and 2012, and $1 million for the year ended December 31, 2012. 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 the three months ended March 31, 2013, SouthStar distributed $17 million to Piedmont and $14 million during the same period last year. The increase of $3 million was primarily the result of increased earnings year-over-year.

The following table provides additional information on SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our unaudited Condensed Consolidated Statements of Financial Position. The SouthStar balances do not include intercompany eliminations or the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.

	March 31, 2013						December 31, 2012						March 31, 2012
In millions	Consolidated		SouthStar				Consolidated		SouthStar				Consolidated		SouthStar
Current assets	$	2,361	$	143	6	%	$	2,668	$	201	8	%	$	2,022	$	149	7	%
Long-term assets and other deferred debits		11,579		10	-			11,473		10	-			11,217		9	-
Total assets	$	13,940	$	153	1	%	$	14,141	$	211	1	%	$	13,239	$	158	1	%
Current liabilities	$	3,060	$	51	2	%	$	3,338	$	62	2	%	$	2,348	$	52	2	%
Long-term liabilities and other deferred credits		7,339		-	-			7,368		-	-			7,465		-	-
Total Liabilities		10,399		51	1			10,706		62	1			9,813		52	1
Equity		3,541		102	3			3,435		149	4			3,426		106	3
Total liabilities and equity	$	13,940	$	153	1	%	$	14,141	$	211	1	%	$	13,239	$	158	1	%

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The following table provides additional information on SouthStar’s revenues and expenses for the three months ended March 31, 2013 and 2012, which are consolidated within our unaudited Condensed Consolidated Statements of Income.

In millions	2013		2012
Operating revenues	$	250	$	215
Operating expenses
Cost of goods sold		164		133
Operation and maintenance		18		19
Depreciation and amortization		1		-
Taxes other than income taxes		-		1
Total operating expenses		183		153
Operating income	$	67	$	62

Equity Method Investments

Income from our equity method investments is classified as other income in our unaudited Condensed Consolidated Statements of Income. For the three months ended March 31, 2013, this included investment income from Triton of $2 million and $1 million of investment income from our other equity method investments. For the three months ended March 31, 2012, this included $3 million of investment income from Triton and an immaterial amount of investment income from our other equity method investments. For more information about our equity method investments, see Note 10 to our Consolidated Financial Statements under Item 8 included in our 2012 Form 10-K.

Note 9 - Commitments, Guarantees and Contingencies

There were no significant changes to our contractual obligations described in Note 11 of our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.

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.

Contingencies and Guarantees

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. 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 and indemnities is remote. No liability has been recorded for such guarantees and indemnifications.

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 market. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. The resolution of this imbalance will be decided by the Georgia Commission and we are unable to predict the ultimate outcome.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations 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 following table provides more information on the costs related to remediation of our former operating sites as of March 31, 2013.

In millions	Probabilistic model cost estimates (1)		Engineering estimates (1)		Amount recorded		Expected costs over next twelve months
Illinois	$	193 - $439	$	50	$	239	$	35
New Jersey		116 - 203		6		121		14
Georgia and Florida		49 - 107		12		54		6
North Carolina		n/a		11		11		8
Total	$	358 - $749	$	79	$	425	$	63

(1)   There were events during first quarter 2013 that resulted in changes to the estimates disclosed in, and the amounts recorded in, our December 31, 2012 Form 10-K. These changes are reflected in the table above.

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Our environmental remediation cost liabilities are estimates of future remediation costs for our former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, which is generally the case when remediation has not commenced or during the early years of a remediation effort. For those elements of the program where we cannot perform engineering estimates, there remains considerable variability in future cost estimates. Accordingly, we have established a probabilistic model to determine a range of potential expenditures to remediate and monitor our former operating sites. We cannot, at this time, identify any single number within this range as a better estimate of likely future costs, and we generally have recorded the low end of the range for our probabilistic cost estimates.

As we conduct the actual remediation and enter into cleanup contracts, 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. With the exception of our North Carolina site, these costs are recoverable from our customers as they are paid and, accordingly, we have recorded a regulatory asset associated with the recorded liabilities. For more information on our environmental remediation costs, see Note 2 herein and Note 11 of our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.

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 the company to take charges against, or will result in reductions in, future earnings. It is the opinion of management that the resolution of these contingencies, either individually or in aggregate, could be material to earnings in a particular period but 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 2012 Form 10-K.

PBR Proceeding Nicor Gas’ PBR plan for natural gas costs went into effect in 2000 and was terminated effective January 1, 2003. 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. The PBR plan is currently under review by the Illinois Commission as there are allegations that Nicor Gas acted improperly in connection with the plan. On June 27, 2002, the Citizens Utility Board (CUB) filed a motion to reopen the record in the Illinois Commission’s proceedings to review the PBR plan (the “Illinois Commission Proceedings”). As a result of the motion to reopen, Nicor Gas entered into a stipulation with the staff of the Illinois Commission and CUB providing for additional discovery. The Illinois Attorney General’s Office (IAGO) has also intervened in this matter. In addition, the IAGO issued Civil Investigation Demands (CIDs) to CUB and the Illinois Commission staff. The CIDs ordered that CUB and the Illinois Commission staff produce all documents relating to any claims that Nicor Gas may have presented, or caused to be presented, regarding false information related to its PBR plan. We have committed to cooperate fully in the reviews of the PBR plan.

The Nicor Board of Directors directed management to, among other things, make appropriate adjustments to account for, and fully address, the adverse consequences to ratepayers, and conduct a detailed study of the adequacy of internal accounting and regulatory controls. The adjustments were made in prior years’ financial statements resulting in a $25 million liability. Included in this $25 million liability is a $4 million loss contingency. A $2 million adjustment to the previously recorded liability, which is discussed below, was made in 2004 increasing the recorded liability to $27 million. By the end of 2003, Nicor Gas completed steps to correct the weaknesses and deficiencies identified in the detailed study of the adequacy of internal controls.

On February 5, 2003, CUB filed a motion for $27 million in sanctions against Nicor Gas in the Illinois Commission Proceedings. In that motion, CUB alleged that Nicor Gas’ responses to certain CUB data requests were false. Also on February 5, 2003, CUB stated in a press release that, in addition to $27 million in sanctions, it would seek additional refunds to consumers. On March 5, 2003, the Illinois Commission staff filed a response brief in support of CUB’s motion for sanctions. On May 1, 2003, the Administrative Law Judges assigned to the proceeding issued a ruling denying CUB’s motion for sanctions. CUB has filed an appeal of the motion for sanctions with the Illinois Commission, and the Illinois Commission has indicated that it will not rule on the appeal until the final disposition of the Illinois Commission Proceedings. It is not possible to determine how the Illinois Commission will resolve the claims of CUB or other parties to the Illinois Commission Proceedings.

In 2004, Nicor Gas became aware of additional information relating to the activities of individuals affecting the PBR plan for the period from 1999 through 2002, including information consisting of third party documents and recordings of telephone conversations from Entergy-Koch Trading, LP (EKT), a natural gas, storage and transportation trader and consultant with whom Nicor Gas did business under the PBR plan. Review of additional information completed in 2004 resulted in the $2 million adjustment to the previously recorded liability referenced above.

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The evidentiary hearings on this matter were stayed in 2004 in order to permit the parties to undertake additional third party discovery from EKT. In December 2006, the additional third party discovery from EKT was obtained and the Administrative Law Judge issued a scheduling order that provided for Nicor Gas to submit direct testimony by April 13, 2007. Nicor Gas submitted direct testimony in April 2007, rebuttal testimony in April 2011 and surrebuttal testimony in December 2011. In surrebuttal testimony, we sought$6 million, which included interest due to us of $2 million, as of December 31, 2011. The staff of the Illinois Commission, IAGO and CUB submitted direct testimony to the Illinois Commission in April 2009 and rebuttal testimony in October 2011. In rebuttal testimony, the staff of the Illinois Commission, IAGO and CUB requested refunds of $85 million, $255 million and $305 million, respectively. 

In February 2012, we committed to a stipulated resolution of issues with the staff of the Illinois Commission, which would include crediting Nicor Gas customers $64 million. This resulted in a $37 million adjustment to the previously recorded $27 million liability referenced above and is reflected in the purchase price allocation. The stipulated resolution does not constitute an admission of fault, and it is not final and is subject to review and approval by the Illinois Commission. The CUB and IAGO are not parties to the stipulated resolution and continue to pursue their claims in this proceeding. Evidentiary hearings before the Administrative Law Judges were held during the first quarter of 2012 and post-trial legal briefs from the parties were submitted during the second quarter of 2012. Following the submission of legal briefs, on November 5, 2012, the Administrative Law Judges issued a proposed order for a refund of $72 million to ratepayers. During the fourth quarter of 2012, we increased our accrual by $8 million for a total of $72 million as a result of these developments and its effect on the estimated liability. We do not agree with the additional $8 million proposed by the Administrative Law Judges and will consider all legal recourse available should the Illinois Commission authorize a refund greater than the $64 million stipulation amount between Nicor Gas and the staff of the Illinois Commission.

Nicor Services Warranty Product Actions In the first quarter of 2011, three putative class actions were filed against Nicor Services and Nicor Gas, and in one case against Nicor. In September 2011, the three cases were consolidated into a single class action pending in state court in Cook County, Illinois. The plaintiffs purport to represent a class of customers of Nicor Gas who purchased the Gas Line Comfort Guard product from Nicor Services. In the consolidated action, the plaintiffs variously allege that the marketing, sale and billing of the Nicor Services Gas Line Comfort Guard violate the Illinois Consumer Fraud and Deceptive Business Practices Act, constitute common law fraud and result in unjust enrichment of Nicor Services and Nicor Gas. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees and injunctive relief. While we are unable to predict the outcome of these matters or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with this contingency, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition.

Other We are also involved in litigation relating to estimated billing practices and an investigation by the United States Environmental Protection Agency regarding the applicable regulatory requirements for polychlorinated biphenyl in the Nicor Gas distribution system. While we are unable to predict the outcome of these matters or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with these contingencies. The final disposition of these matters is not expected to have a material adverse impact on our liquidity or financial condition. For additional litigation information on these matters, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.

In addition to the matters set forth above, we 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.

Note 10 - Segment Information

Our operating segments comprise revenue-generating components of our company for which we produce separate financial information internally that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through five operating segments - distribution operations, retail operations, wholesale services, midstream operations, cargo shipping and one non-operating segment, other.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland. 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.

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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, our retail operations segment provides warranty protection solutions to customers and customer move connection services for utilities. Our wholesale services segment includes natural gas asset management and related logistics activities for each of our utilities, except Nicor Gas, as well as for nonaffiliated companies, natural gas storage arbitrage and related activities. Our midstream operations segment includes our non-utility storage and pipeline operations, including the development and operation of high-deliverability natural gas storage assets.

Our cargo shipping segment transports containerized freight 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. Although the majority of its long-lived assets are foreign owned and its revenues are derived from foreign operations, the functional currency is generally the United States dollar. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. Profits and losses are generally allocated to investors’ capital accounts in proportion to their capital contributions. Our investment in Triton is accounted for under the equity method, and our share of earnings is reported within other income in our unaudited Condensed Consolidated Statements of Income.

Our other segment includes intercompany eliminations and aggregated subsidiaries that are not significant enough on a stand-alone basis and that do not meet the criteria in one of our other five operating segments.

We evaluate segment performance using the non-GAAP measure of EBIT that includes operating income, other income and expenses, and equity investment income. Items we do not include in EBIT are income taxes and financing costs, including interest and debt expense, each of which we evaluate on a consolidated basis. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

You should not consider EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income, earnings before income taxes and net income for the three months ended March 31, 2013 and, 2012 are presented below.

In millions	2013		2012
Operating income	$	299	$	262
Other income		5		4
EBIT		304		266
Interest expense		46		47
Earnings before income taxes		258		219
Income taxes		94		80
Net income	$	164	$	139

Information by segment on our Statements of Financial Position as of December 31, 2012, is as follows:

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	11,320		$	1,640
Retail operations		511			122
Wholesale services		1,218			-
Midstream operations		720			14
Cargo shipping		464			61
Other (2)		(92	)		-
Consolidated	$	14,141		$	1,837

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

(2)   Our other segment’s assets 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, 2013

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping		Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	1,264	$	302	$	39	$	24	$	87	$	(7	)	$	1,709
Intercompany revenues (1)		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 (3)	$	11,258	$	668	$	1,005	$	714	$	459	$	(164	)	$	13,940
Goodwill	$	1,640	$	168	$	-	$	14	$	61	$	-		$	1,883
Capital expenditures	$	137	$	1	$	-	$	4	$	1	$	5		$	148

Three months ended March 31,2012

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping			Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	994	$	263	$	64	$	16	$	84		$	(17	)	$	1,404
Intercompany revenues (1)		46		-		-		-		-			(46	)		-
Total operating revenues		1,040		263		64		16		84			(63	)		1,404
Operating expenses
Cost of goods sold		529		166		30		5		50			(61	)		719
Operation and maintenance		173		32		13		5		28			(6	)		245
Depreciation and amortization		88		4		1		2		6			3			104
Taxes other than income taxes		57		1		1		1		2			2			64
Nicor merger expenses (2)		-		-		-		-		-			10			10
Total operating expenses		847		203		45		13		86			(52	)		1,142
Operating income (loss)		193		60		19		3		(2	)		(11	)		262
Other income		1		-		-		-		3			-			4
EBIT	$	194	$	60	$	19	$	3	$	1		$	(11	)	$	266
Identifiable and total assets (3)	$	10,785	$	471	$	917	$	665	$	477		$	(76	)	$	13,239
Goodwill	$	1,586	$	124	$	2	$	16	$	77		$	8		$	1,813
Capital expenditures	$	122	$	2	$	-	$	42	$	-		$	5		$	171

(1)   Intercompany revenues - wholesale services records its energy marketing and risk management revenues on a net basis and its total operating revenues include intercompany revenues of $140 million for the three months ended March 31, 2013 and $88 million for the three months ended March 31, 2012.

(2)   Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.

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

(4)   Our other segment’s assets consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

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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 2012 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 within the meaning of the United States federal securities laws 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 involve matters that are not historical facts, and because these statements involve anticipated events or conditions, 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. Our expectations are not guarantees and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations are reasonable in view of currently available information, 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 significantly 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; limits on pipeline capacity; the impact of acquisitions and divestitures; our ability to successfully fully 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; 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.

We caution readers that the important factors described elsewhere in this report, among others, could cause our business, results of operations or financial condition to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or that are not described in this report that could cause our actual results to differ significantly from our expectations.

Forward-looking statements are only as of the date they are made. We undertake no 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 United States federal securities law.

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 segments, see Note 10.

Distribution Operations At March 31, 2013, our seven utilities within distribution operations served approximately 4.5 million end-use customers with its primary focus being the safe and reliable delivery of natural gas.

Nicor Gas We are currently performing a depreciation study for Nicor Gas that we expect to complete later this year. The composite, straight-line rate for Nicor Gas is currently 4.1% and a 10 basis point shift in this rate, in either direction, is estimated to change our annual depreciation expense by $4 million to $6 million. Any change to our depreciation rates would be subject to regulatory approval.

Atlanta Gas Light 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 market. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. The resolution of this imbalance will be decided by the Georgia Commission and we are unable to predict the ultimate outcome.

Virginia Natural Gas In April 2013, the hearing examiner in charge of Virginia Natural Gas’ Conservation and Ratemaking Efficiency (CARE) plan issued a report recommending approval of a stipulation between Virginia Natural Gas and the staff of the Virginia Commission. The stipulation proposed a modified CARE plan that included a more limited set of conservation programs and measures at a reduced cost of $2 million over a three-year period. A decision by the Virginia Commission is expected by June 1, 2013.

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Chattanooga Gas In April 2013, legislation was passed into law that gives the Tennessee Authority the ability to approve alternative regulatory mechanisms. The law allows the Tennessee Authority to implement: (1) separate rate adjustment mechanisms that track specific costs; (2) annual rate reviews in lieu of traditional rate cases and (3) adopt other policies or procedures that permit a more timely review and revision of rates, streamline the regulatory process, and reduce the cost and time associated with the traditional ratemaking processes.

In April 2013, Chattanooga Gas filed with the Tennessee Authority a proposal to extend its energy conservation programs and associated rate adjustment mechanism that adjusts rates to recover revenue lost as a result of customers usage changes from the level used to set base rates.

Retail Operations Our retail operations businesses serve approximately 600 thousand energy customers and approximately 1.2 million customer service contracts in Florida, Georgia, Illinois, Indiana, Kentucky, Ohio, Maryland, Massachusetts, New York, Pennsylvania and West Virginia. SouthStar, Nicor Advanced Energy and Nicor Solutions generate earnings through the sale of natural gas to residential, commercial and industrial customers, primarily in Georgia and Illinois where we capture spreads between wholesale and retail natural gas prices. Additionally, these businesses offer our customers energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder-than-normal weather and/or changes in natural gas prices. We charge a fee or premium for these services. Our retail operations businesses also provide warranty protection and home solutions that include gas and electric line repair, equipment repair, insurance and maintenance through Nicor Services and represent customers who are on monthly service contracts or warranty products billed at a fixed monthly amount.

On January 31, 2013, our retail operations segment acquired approximately 500 thousand service plans and certain other assets from NiSource Inc. for $120 million, plus $2 million of working capital. We believe this acquisition will provide an enhanced platform for growth and continued expansion of this business into a number of key markets.

Wholesale Services Our wholesale services segment consists of our wholly owned subsidiaries Sequent and Compass Energy Services Inc. (Compass) and engages in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing of natural gas across the United States and in Canada. Additionally, it provides natural gas asset management and/or related logistics services for most of our utilities, as well as for non-affiliated companies. In April 2013, the Tennessee Authority authorized an extension of the asset management agreement between Chattanooga Gas and Sequent. The terms of the agreement remain unchanged, except the expiration date is now March 2015.

Additionally, Sequent manages Nicor Solutions’ and Nicor Advanced Energy’s product risks, including the purchase of natural gas supplies. Compass provides natural gas supply and services to commercial, industrial and governmental customers primarily in Kentucky, Ohio, Pennsylvania, Virginia and West Virginia.

Midstream Operations Our midstream operations segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops, acquires and operates high-deliverability underground natural gas storage assets primarily in the Gulf Coast region of the United States and in northern California. While this business can generate additional revenue during times of peak market demand for natural gas storage services, a portion of our natural gas storage facilities are covered under a portfolio of short, medium and long-term contracts at fixed market rates.

Golden Triangle Storage’s Cavern 1 began commercial operations in September 2010 and Cavern 2 began commercial operations in September 2012. Cavern 1 is currently going through a process to assess the cavern’s working gas capacity that is expected to slightly increase the size of the facility. This process began in early 2013 and will continue through the third quarter of 2013. Cavern 2 will cover the obligations of Cavern 1 during this process. Central Valley, located in northern California, began commercial operations and providing services to firm customers during the second quarter 2012.

Cargo Shipping Our cargo shipping segment consists of Tropical Shipping, multiple wholly owned foreign subsidiaries of Tropical Shipping that are treated as disregarded entities for United States income tax purposes, Seven Seas, a wholly owned domestic cargo insurance company, and an equity investment in Triton, a cargo container leasing business. For additional information on our operating segments, see Item 1, “Business” of our 2012 Form 10-K.

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 our retail operations and wholesale services segments to capture value from location and seasonal spreads. Additionally, these changes in commodity prices subject a significant portion of our operations to earnings variability. Since 2011, the volatility of the daily Henry Hub spot market prices for natural gas in the United States has been significantly lower than it had been in previous years. This is the result of a robust natural gas supply, the weak economy and ample natural gas storage.

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Our utility natural gas acquisition strategy is designed to secure sufficient supplies of natural gas and the rights to physically flow natural gas between delivery points in order to meet the needs of our utility customers and to hedge gas prices and location spreads to effectively manage costs, reduce price volatility for our utility customers and maintain a competitive advantage. 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 are not 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. 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.

It is possible that natural gas prices will remain low for an extended period based on current levels of excess supply relative to market demand for natural gas, in part due to abundant sources of new shale natural gas reserves and the lack of demand by commercial and industrial enterprises. However, as economic conditions continue to improve, the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets. Consequently, we are working to reposition our wholesale services business model with respect to fixed costs, and the types of contracts pursued and executed.

The market fundamentals of midstream operations storage business are cyclical, and as discussed above, 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. In 2013, expiring storage capacity contracts were re-subscribed at lower prices and we anticipate lower natural gas prices to continue in 2013 as compared to historical averages. Due to the current market storage rates, we did not re-contract 2.0 Bcf at Golden Triangle Storage and intend to provide other services until market conditions improve to support term contracts. As of April 1, 2013, the overall average firm subscription rate per facility is as follows:

	Average Monthly Rate per Dekatherm
Jefferson Island (1)	$	0.122
Golden Triangle (1)	$	0.240
Central Valley	$	0.130

(1)   Excludes firm capacity contracted by Sequent.

While the average monthly rates were lower than prior years and we did not re-contract all of the available capacity during the first quarter 2013, our current projections remain consistent with those from our most recent annual impairment assessment given the revenues that are expected to be earned from other storage services. We will continue to monitor all of our reporting units for impairment indicators throughout the year, but as of March 31, 2013, we believe there are no indications of potential impairment.

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 our distribution operations and retail operations segments 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 incurred relatively equally over any given year. Additionally, the revenues of our cargo shipping business are generally higher in the fourth quarter, as our customers require more tourist-related shipments as the hotels, resorts, and cruise ships typically have increased occupancy rates commencing in the fourth quarter and increasing further into the first quarter and consumer spending increases during traditional holiday periods. Revenues are impacted during the fourth quarter by Peak Season Surcharges. Thus, our operating results vary significantly from quarter to quarter as a result of seasonality.

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We evaluate segment performance using the measures of operating margin and EBIT, which include the effects of corporate expense allocations. 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. EBIT is also a non-GAAP measure that includes operating income and other income and expenses. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated basis.

We believe operating margin is a better indicator than operating revenues of the contribution resulting from customer growth in our distribution operations segment, 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 our retail operations, wholesale services, midstream operations and cargo shipping segments, since it is a direct measure of operating margin before overhead costs.

We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations. You should not consider operating margin or EBIT 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 and EBIT measures may not be comparable to similarly titled measures of other companies.

We believe presenting the non-GAAP measurements of basic and diluted earnings per share - as adjusted, which excludes Nicor merger-related expenses, provides investors with an additional measure of our performance. Adjusted basic and diluted earnings per share should not be considered an alternative to, or a more meaningful indicator of, our operating performance than our GAAP basic and diluted earnings per share. The following table reconciles operating revenue and operating margin to operating income, and EBIT to earnings before income taxes and net income, and our GAAP basic and diluted earnings per common share to our non-GAAP basic and 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	2013			2012			Change
Operating revenues	$	1,709		$	1,404		$	305
Cost of goods sold		(973	)		(719	)		(254	)
Revenue tax expense (1)		(49	)		(41	)		(8	)
Operating margin		687			644			43
Operating expenses (2)		(437	)		(413	)		(24	)
Revenue tax expense (1)		49			41			8
Nicor merger expenses (3)		-			(10	)		10
Operating income		299			262			37
Other income		5			4			1
EBIT		304			266			38
Interest expenses		46			47			(1	)
Earnings before income taxes		258			219			39
Income tax expenses		94			80			14
Net income		164			139			25
Less net income attributable to the noncontrolling interest		10			9			1
Net income attributable to AGL Resources Inc.	$	154		$	130		$	24
Per common share data
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	1.31		$	1.12		$	0.19
Transaction costs of Nicor merger		-			0.05			(0.05	)
Basic earnings per share – as adjusted	$	1.31		$	1.17		$	0.14
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	1.31		$	1.11		$	0.20
Transaction costs of Nicor merger		-			0.05			(0.05	)
Diluted earnings per share – as adjusted	$	1.31		$	1.16		$	0.15

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

(2)   Excludes expenses associated with the merger with Nicor of $10 million ($6 million net of tax) for the three months ended March 31, 2012.

(3)   Expenses associated with the Nicor merger are part of operating expenses, but are shown separately to better compare year-over-year results.

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For the first quarter of 2013, our net income attributable to AGL Resources Inc. increased by $24 million or 18% compared to last year. The increase was primarily the result of increased operating margin at distribution operations and retail operations due to colder weather and increased average customer usage compared to prior year, and increased regulatory infrastructure program revenues at Atlanta Gas Light. The increases were slightly offset by lower margins at wholesale services resulting from mark-to-market accounting hedge losses. Additionally, during the three months ended March 31, 2012, we recorded $10 million ($6 million net of tax) of Nicor merger related expenses.

Our income tax expense increased by $14 million or 18% compared to the first quarter of 2012. The increase was primarily due to higher consolidated earnings, as previously discussed. Our income tax expense is determined from earnings before income taxes less net income attributable to noncontrolling interest.

Operating Metrics

Weather We measure the effects of weather on our business through Heating Degree Days. Generally, increased Heating Degree Days result in greater demand for gas on our distribution systems. With the exception of Nicor Gas and Florida City Gas, we have various mechanisms, such as weather normalization mechanisms, at all of our utilities, which limit our exposure to weather changes within typical ranges in all 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,						2013 vs. 2012			2013 vs. normal
	Normal		2013		2012		colder			colder
Illinois (1) (2)		2,991		3,153		2,358		34	%		5	%
Georgia (1)		1,452		1,461		983		49	%		1	%

(1)   Normal represents the ten-year average from Jan 1, 2003 through March 31, 2012, 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. The 10-year average for the period, as established by the Illinois Commission in our last rate case, is 2,902 from 1998 through 2007.

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

During the three months ended March 31, 2013, we experienced weather in Illinois that was 5% colder-than-normal and 34% colder than last year. Georgia also experienced 1% colder-than-normal weather, and 49% colder than last year. This colder weather positively impacted our operating margin by $24 million compared to last year. However, the 2011/2012 Heating Season was one of the warmest on record and was 18% - 40% warmer-than-normal across our service territory, which negatively impacted our operating margin by $21 million in the first quarter of 2012.

Customers Our customer metrics highlight the average number of customers for which we provide services and are provided in the following table. This 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 year-over-year consolidated utility customer growth rate was 0.3% for the three months ended March 31, 2013 and we anticipate overall competition and utility customer growth trends for 2013 to be similar to that experienced in 2012.

Our energy customers at retail operations are principally located in Georgia and Illinois. The number of customers within these locations remained consistent for the three months ended March 31, 2013 and 2012; however, the market in Georgia remains very competitive. In 2013 our retail operations segment intends on continuing its efforts of entering and expanding within targeted markets to increase its energy customers and expanding our service contracts to include our service territories in Georgia, Virginia and Tennessee.

Customers and service contracts (average end-use - in thousands)	Three months ended March 31,						2013 vs.2012
	2013			2012			% change
Distribution Operations customers		4,501			4,487			0.3	%
Retail Operations
Energy Customers (1)		613			675			(9	)%
Service Contracts (2)		1,183			711			66	%
Market share in Georgia		32	%		32	%		-	%

(1)   A portion of the customers represents customer equivalents in Ohio, which are computed by the actual delivered volumes divided by the expected average customer usage.Decrease primarily due to our contract to serve approximately 50,000 customer equivalents that ended on April 1, 2012.

(2)   Increase primarily due to acquisition of approximately 500,000 contracts on January 31, 2013. These contracts are as of March 31, 2013 and 2012.

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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. 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, our cargo shipping segment measures the volume of shipments during the period in TEUs and is presented in the following table. We continue to seek opportunities to profitably increase our number of TEUs and maximize the utilization of our containers and vessels.

Volumes	Three months ended March 31,						2013 vs. 2012
	2013			2012			% change
Distribution Operations (In Bcf)
Firm		309			240			29	%
Interruptible		30			27			11	%
Total		339			267			27	%
Retail Operations (In Bcf)
Georgia firm		18			14			29	%
Illinois		4			4			-	%
Expanded markets (1)		3			4			(25	)%
Wholesale Services
Daily physical sales (Bcf / day)		6.3			6.0			5	%
Cargo Shipping (TEU’s - in thousands)
Shipments		45			41			10	%
	As of March 31,
		2013			2012
Midstream Operations
Working natural gas capacity (in Bcf) (2)		31.8			13.3
% of firm capacity under subscription by third parties (3)		46	%		68	%

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

(2)   Includes Central Valley Storage that was acquired in connection with the Nicor merger, which began commercial operations in the second quarter of 2012. Additionally, Golden Triangle Storage’s Cavern 1 is going through a process to assess the cavern’s working gas capacity and to slightly increase the size of the facility. The process began in January 2013 and is expected to continue through the third quarter of 2013. Cavern 2 will cover the obligations of Cavern 1 during this process.

(3)   The percentage of capacity under subscription does not include 3 Bcf of capacity under contract with Sequent at March 31, 2013, and 4 Bcf of capacity under contract with Sequent at March 31, 2012.

First quarter 2013 compared to first quarter 2012

Operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables for the three months ended March 31, 2013 and 2012.

	2013							2012
In millions	Operating margin (1) (2)		Operating expenses (2)		EBIT (1)			Operating margin (1) (2)			Operating expenses (2) (3)		EBIT (1)
Distribution operations	$	505	$	290	$	218		$	470		$	277	$	194
Retail operations		107		37		70			97			37		60
Wholesale services		29		14		15			34			15		19
Midstream operations		12		11		2			11			8		3
Cargo shipping		34		34		2			34			36		1
Other		-		2		(3	)		(2	)		9		(11	)
Consolidated	$	687	$	388	$	304		$	644		$	382	$	266

(1)   These are non-GAAP measures. A reconciliation of operating margin to operating income and EBIT to earnings before income taxes and net income is contained in “Results of Operations” herein. See Note 10 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein for additional segment information.

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

(3)   Includes $10 million in transaction expenses associated with the merger with Nicor for the first quarter of 2012.

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.

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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 gas consumed. Distribution operations’ EBIT increased by $24 million or 12% compared to last year, as shown in the following table.

In millions
EBIT - for first quarter of 2012	$	194
Operating margin
Increased operating margin mainly driven by higher customer usage at Nicor Gas due to colder weather compared to prior year		14
Increased operating margin as a result of energy efficiency programs at Nicor Gas		10
Increased revenues from regulatory infrastructure programs at Atlanta Gas Light		8
Increased operating margin from higher usage at Florida City Gas due to colder weather compared to prior year		2
Increased operating margin from higher usage at Elizabethtown Gas compared to prior year		1
Increase in operating margin		35
Operating expenses
Increased expenses as a result of energy efficiency program expenses at Nicor Gas		10
Increased incentive compensation costs due to amounts returning to targeted levels		5
Increased depreciation expense as a result of increased PP&E from infrastructure additions and improvements		2
Decreased retirement benefits expenses primarily as a result of change in actuarial assumptions		(3	)
Other		(1	)
Increase in operating expenses		13
Increased AFUDC equity primarily from STRIDE projects at Atlanta Gas Light		2
EBIT - for first quarter of 2013	$	218

Retail Operations

Our retail operations segment, which consists of SouthStar and several businesses that provide energy-related products and services to retail markets, also is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. Retail operations’ EBIT increased by $10 million or 17% compared to last year, as shown in the following table.

In millions
EBIT - for first quarter of 2012	$	60
Operating margin
Increased average customer usage in Georgia due to colder weather relative to prior year, net of weather derivatives		10
Increased margin at retail services primarily due to acquired NiSource Inc. retail service contracts		4
Inventory write-down (LOCOM) in 2012		3
Increased margin in Illinois mainly due to timing of revenue recognition associated with fixed bill products and favorable weather		2
Decrease related to increase in transportation and gas costs and lower retail price spreads, partially offset by favorable customer portfolio		(10	)
Other		1
Increase in operating margin		10
Operating expenses
Increased expenses at retail services primarily due to acquisition of NiSource Inc’s retail service contracts		3
Decreased payroll, benefits, outside services and other		(3	)
Increase in operating expenses		-
EBIT - for first quarter of 2013	$	70

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. 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. Wholesale services’ EBIT decreased by $4 million compared to last year, as shown in the following table.

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In millions
EBIT - for first quarter of 2012	$	19
Operating margin
Change in commercial activity largely driven by the withdrawal of a portion of the storage inventory hedged at the end of 2012 and colder weather		26
Storage inventory write-down (LOCOM) in 2012		18
Change in value on storage hedges as a result of increase in NYMEX natural gas prices		(36	)
Change in value on transportation and forward commodity hedges from price movements related to natural gas transportation positions		(13	)
Decrease in operating margin		(5	)
Operating expenses
Decreased incentive compensation, outside services costs and other		(1	)
Decrease in operating expenses		(1	)
EBIT - for first quarter of 2013	$	15

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

	March 31,
In millions	2013			2012
Commercial activity recognized	$	50		$	24
(Loss) gain on storage hedges		(17	)		19
(Loss) gain on transportation and forward commodity hedges		(4	)		9
Inventory LOCOM adjustment, net of estimated recoveries		-			(18	)
Operating margin	$	29		$	34

Change in commercial activity The commercial activity at wholesale services includes recognized storage and transportation values which were generated in prior periods, and the impact of prior period hedge gains and losses. Additionally, the commercial activity includes operating margin generated and recognized in the current period. The increase in commercial activity reflects the recognition of operating margin resulting from the withdrawal of storage inventory hedged at the end of 2012 that was included in the storage withdrawal schedule with a value of $27 million as of December 31, 2012 as well as the effect of colder weather on certain of our transportation portfolio positions, particularly in the Northeastern United States. As previously discussed, our operating margin opportunities are expected to be lower in 2013 due to continued lower volatility and lower seasonal price spreads associated with our storage portfolio.

Change in storage and transportation hedges Seasonal (storage) and geographical location (transportation) spreads and overall natural gas price volatility continued to remain low relative to historical periods. However, during the current year quarter, natural gas prices moved higher resulting in storage hedge losses as compared to storage hedge gains last year resulting from a downward movement in natural gas prices. Gains from our transportation position in 2012 were primarily due to large transportation spreads at the time our transportation positions were executed and the subsequent narrowing of regional transportation spreads. However, similar to the fourth quarter of 2012, significant volatility continued during the current quarter at natural gas delivery points throughout the northeast corridor relative to natural gas delivery constraints in the region, resulting in losses on our transportation positions.

Withdrawal schedule Sequent’s expected natural gas withdrawals from storage are presented in the following table along with the operating revenues expected at the time of withdrawal. Sequent’s expected operating revenues exclude storage demand charges but are net of the estimated impact of profit sharing under our asset management agreements and reflect the amounts that are realizable in future periods based on the inventory withdrawal schedule and forward natural gas prices at March 31, 2013 and 2012. A portion of Sequent’s storage inventory is economically hedged with futures contracts, which results in realization of substantially fixed 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 2012 Form 10-K.

Withdrawal schedule	Total storage (in Bcf) (WACOG $2.85)		Expected operating revenues (1) (in millions)
2013
Second quarter		15	$	16
Third quarter		12		13
Fourth quarter		4		4
2014		1		1
Total at March 31, 2013		32	$	34
Total at December 31, 2012		51	$	27
Total at March 31, 2012		47	$	19

(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.

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Midstream Operations

Our midstream operations segment’s primary activity is operating non-utility storage and pipeline facilities including the development, acquisition 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, the majority of our storage services are covered under medium to long-term contracts at fixed market rates. Midstream operations’ EBIT decreased by $1 million compared to last year, as shown in the following table.

In millions
EBIT - for first quarter of 2012	$	3
Operating margin
Increased revenues at Golden Triangle as a result of Cavern 2 beginning commercial service in third quarter 2012		2
Decreased margin at Jefferson Island as a result of lower subscription rates		(1	)
Increase in operating margin		1
Operating expenses
Increased depreciation, property taxes, storage expenses and outside services largely due to Central Valley and Cavern 2 at Golden Triangle beginning commercial service in 2012		3
Increase in operating expenses		3
Increase from equity investment in Horizon Pipeline		1
EBIT - for first quarter of 2013	$	2

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. The balance of the cargo consists primarily of interisland shipments of consumer staples and northbound shipments of apparel, rum and agricultural products. Other related services, such as inland transportation and cargo insurance, are also provided within the cargo shipping segment. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. For more information about our investment in Triton, see Note 10 to our Consolidated Financial Statements under Item 8 included in our 2012 Form 10-K.

Cargo shipping’s EBIT increased by $1 million compared to last year, as shown in the following table.

In millions
EBIT - for first quarter of 2012	$	1
Operating margin
TEU volume increased due to market share expansion and modest improvement in economic conditions in our service regions		5
Decreased TEU rates due to ongoing overcapacity, changes in cargo mix and competitive pressures		(4	)
Other		(1	)
Increase in operating margin		-
Operating expenses
Decreased depreciation expense		(1	)
Decreased payroll, benefits, outside services and other		(1	)
Decrease in operating expenses		(2	)
Decrease from equity investment income in Triton		(1	)
EBIT - for first quarter of 2013	$	2

Liquidity and Capital Resources

OverviewThe acquisition of natural gas and pipeline capacity, payment of dividends and funding of working capital needs are our most significant short-term financing requirements. The need for long-term capital is driven primarily by capital expenditures and maturities of long-term debt. The liquidity required to fund our working capital, capital expenditures and other cash needs is primarily provided by our operating activities. Our short-term cash requirements not met with cash from operations 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. 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. Consistent with this, we anticipate issuing approximately $500 million of senior notes in the second quarter of 2013. We have hedged the underlying interest rate associated with $300 million in principal amount of the anticipated proceeds, with the remaining un-hedged principal amount subject to fluctuations in interest rates until the financing is completed.

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Our capital market strategy is focused on maintaining strong Consolidated Statements of Financial Position, ensuring ample cash resources and daily liquidity, accessing capital markets at favorable times as necessary, managing critical business risks and maintaining a balanced capital structure through the appropriate issuance of equity or long-term debt securities.

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 in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Dividends to AGL Resources are allowed only to the extent of Nicor Gas’ retained earnings balance, which was $502 million at March 31, 2013.

We believe the amounts available to us under our senior notes, AGL Credit Facility and Nicor Gas Credit Facility, 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 contributions, 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.

As of March 31, 2013 and 2012, and December 31, 2012, we had $76 million, $74 million and $80 million, respectively, of cash and short and long-term investments in our unaudited Condensed Consolidated Statements of Financial Position that were generated from Tropical Shipping. This cash and the investments are not available for use by our other operations unless we repatriate a portion of Tropical Shipping’s earnings in the form of a dividend that would be subject to a significant amount of United States income tax. See Note 12 to our Consolidated Financial Statements under Item 8 included in our 2012 Form 10-K for additional information on our income taxes.

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 2012 Form 10-K for additional information on items that could impact our liquidity and capital resource requirements.

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 at our distribution operations segment. 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 2013 are discussed in “Liquidity and Capital Resources” under the caption ‘Cash Flows from Financing Activities’ in our 2012 Form 10-K.

Dollars in millions	Utility	Expenditures in 2013		Expenditures since project inception		Miles of pipe replaced		Year project began		Anticipated year of completion
STRIDE program
Pipeline replacement program	Atlanta Gas Light	$	35	$	717		2,632		1998		2013
Integrated System Reinforcement Program	Atlanta Gas Light		2		226		n/a		2009		2013
Integrated Customer Growth Program	Atlanta Gas Light		10		39		n/a		2010		2013
Enhanced infrastructure program	Elizabethtown Gas		1		109		96		2009		(1	)
Accelerated infrastructure program	Virginia Natural Gas		4		20		52		2012		2017
Total		$	52	$	1,111		2,780

(1)   In July 2012, we filed a request to extend this program for five years and are currently waiting to hear from the New Jersey BPU Rate Counsel. If approved, the program is expected to be completed in 2017.

Atlanta Gas Light Our STRIDE program is comprised of the ongoing pipeline replacement program, the Integrated System Reinforcement Program (i-SRP), and the Integrated Customer Growth Program (i-CGP). The purpose of the i-SRP is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Our i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission. The deadline for filing our next STRIDE construction plan was extended by the Georgia Commission to August 2013 to allow additional time to complete the installation of the initial i-SRP construction program. These programs remain on track for completion in 2013.

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On November 21, 2012 we filed the Integrated Vintage Plastic Replacement Program (i-VPR) with the Georgia Commission, as a new component of STRIDE. If approved, this program would replace aging plastic pipe that was installed primarily in the mid-1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for expedited replacement over the next 15 - 20 years as it reaches the end of its useful life. However, the initial request to the Georgia Commission is to replace approximately 756 miles over the next three to four years. The estimated cost of the first tranche of pipe to be replaced under construction activity under i-VPR is $275 million. Based on the procedural schedule issued by the Georgia Commission, a decision on the program is expected to be made on June 18, 2013.

Elizabethtown Gas The New Jersey BPU approved the accelerated enhanced infrastructure program in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. On May 16, 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates. In July 2012, we filed for an extension of the program for up to $135 million in additional spend over five years. A ruling is expected from the New Jersey BPU in the second half of 2013.

Virginia Natural Gas On January 31, 2012, Virginia Natural Gas filed SAVE, an accelerated infrastructure replacement program, with the Virginia Commission, which involves replacing aging infrastructure as prioritized through Virginia Natural Gas’ distribution integrity management program. SAVE was filed in accordance with a Virginia statute providing a regulatory cost recovery mechanism to recover the costs associated with certain infrastructure replacement programs. The Virginia Commission approved SAVE on June 25, 2012, for a five-year period which includes a maximum allowance for capital expenditure of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. We began recovering costs based on this program through a rate rider that became effective August 1, 2012.

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, prospects 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.

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, 2013, and reflects no change from December 31, 2012.

	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-2	F1
Senior unsecured	BBB+	Baa1	BBB+	BBB+	A3	A+
Senior secured	n/a	n/a	n/a	A	A1	AA-
Ratings outlook	Stable	Stable	Stable	Stable	Stable	Stable

Our credit ratings depend largely on our financial performance, and 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.

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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 pay any interest or principal when due, the failure to furnish financial statements within the timeframe established by each debt facility, the failure to comply with certain affirmative and negative covenants, cross-defaults to certain other material indebtedness in excess of specified amounts, incorrect or misleading representations or warranties, insolvency or bankruptcy, fundamental change of control, the occurrence of certain Employee Retirement Income Security Act events, judgments in excess of specified amounts and certain impairments to the guarantee.

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. This ratio, as defined within our debt agreements, 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. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the periods presented.

	AGL Resources						Nicor Gas
	March 31,						March 31,
	2013			2012			2013			2012
Debt-to-capitalization ratio		54	%		54	%		43	%		47	%

We were in compliance with all of our debt provisions and covenants, both financial and non-financial, for all periods presented.

Our ratio of total debt to total capitalization, on a consolidated basis, is typically greater at the beginning of the Heating Season, as we make additional short-term borrowings to fund our natural gas purchases and meet our working capital requirements. We intend to maintain our ratio of total debt to total capitalization in a target range of 50% to 60%. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings. For more information on our default provisions, see Note 6 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein. The components of our capital structure, as calculated from our unaudited Condensed Consolidated Statements of Financial Position, as of the dates indicated are provided in the following table.

	March 31, 2013			December 31, 2012			March 31, 2012
Short-term debt		11	%		16	%		10	%
Long-term debt		45			43			46
Total debt		56			59			56
Equity		44			41			44
Total capitalization		100	%		100	%		100	%

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	2013			2012			Variance
Net cash provided by (used in):
Operating activities	$	850		$	835		$	15
Investing activities		(256	)		(175	)		(81	)
Financing activities		(576	)		(658	)		82
Net increase in cash and cash equivalents		18			2			16
Cash and cash equivalent at beginning of period		131			69			62
Cash and cash equivalent at end of period	$	149		$	71		$	78

Cash Flow from Operating Activities The $15 million increase in cash from operating activities is primarily related to increased cash provided by (i) inventories, net of LIFO liquidation, due to increased LIFO liquidation at Nicor gas and increased withdrawals at Sequent, (ii) trade payables, other than energy marketing due to increased gas purchase volumes at Nicor Gas resulting from colder weather in March and (iii) energy marketing receivables and payables, net, due to higher cash received in the current period related to higher sales volumes in December 2012 versus the same period last year. This was offset by decreased cash provided by receivables, other than energy marketing, due to colder weather in March 2013, which resulted in higher volumes primarily at distribution operations and retail operations, which will be collected in future periods.

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Cash Flow from Investing ActivitiesThe $81 million, or 46%, increase in cash flow used in investing activities was a result of $122 million spent to acquire approximately 500,000 service plans during the first quarter of 2013. This increase was partially offset by decreased spending for property, plant and equipment expenditures of $23 million and a net increase in short term investments of $19 million.

Cash Flow from Financing Activities The decreased use of cash for our financing activities for the three months ended March 31, 2013 compared to the same period in 2012 was primarily a result of lower short-term debt payments of $82 million due to funding requirements in January 2013 related to the NiSource acquisition.

As of March 31, 2013, our variable-rate debt was 25% of our total debt, compared to 32%, as of December 31, 2012 and 26% as of March 31, 2012. The decrease from December 31, 2012 was primarily due to decreased commercial paper borrowings. As of March 31, 2013, our commercial paper borrowings of $868 million were 37% lower than as of December 31, 2012, primarily a result of lower working capital requirements and no commercial paper borrowings under the Nicor Gas Credit Facility. For more information on our debt, see Note 6 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein.

On April 15, 2013, our $225 million 4.45% senior notes were redeemed. This redemption was funded through our commercial paper program and will be refinanced as part of our anticipated issuance of senior notes during the second quarter of 2013.

Short-term DebtOur short-term debt is comprised of borrowings under our commercial paper programs and current portions of our senior notes and capital leases.

In millions	Period end balance outstanding(1)		Daily average balance outstanding(2)		Minimum balance outstanding (2)		Largest balance outstanding(2)
Commercial paper - AGL Capital	$	868	$	980	$	846	$	1,064
Commercial paper - Nicor Gas		-		148		-		314
Senior notes		225		225		225		225
Capital leases		1		1		1		1
Total short-term debt and current portion of long-term debt and capital leases	$	1,094	$	1,354	$	1,072	$	1,604

(1)   As of March 31, 2013.

(2)   For the three months ended March 31, 2013. The minimum and largest balances outstanding for each short-term debt instrument occurred at different times during the period and, thus, the total balances are not indicative of actual borrowings on any one day during the quarter.

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.

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 increase NYMEX price change could result in a $145 million change of working capital requirements during the 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 upcoming injection season, we believe that we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.

The lenders under our credit facilities and lines of credit are major financial institutions with $2.2 billion of committed balances and all have investment grade credit ratings as of March 31, 2013. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

Long-term DebtOur long-term debt matures more than one year from March 31, 2013, and consists of medium-term notes: Series A, Series B, and Series C, which we issued under an indenture during December 1989, senior notes, first mortgage bonds and gas facility revenue bonds.

During the first quarter of 2013, we refinanced $200 million of our outstanding tax-exempt gas facility revenue bonds, $180 million of which were previously issued by the New Jersey Economic Development Authority and $20 million of which were issued by Brevard County, Florida. The refinancing involved a combination of the issuance of $60 million of refunding bonds to and the purchase of $140 million of existing bonds by a syndicate of banks. Our relationship with the syndicate of banks regarding the bonds is governed by an agreement that contains representations, warranties, covenants and default consistent with those contained in similar financing documents of ours. All of the bonds remain floating-rate instruments and we anticipate annual interest expense savings of approximately $2 million annually over the 5.5 year term of the agreement. AGL Resources had no cash receipts or payments in connection with the refinancing. The letters of credit providing credit support for the retired bonds along with other related agreements were terminated as a result of the refinancing. Costs associated with these refinancings will be amortized over the remaining life of the bonds.

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Noncontrolling Interest We recorded cash distributions for SouthStar’s dividend distributions to Piedmont of $17 million for the three months ended March 31, 2013 and $14 million for the same period in 2012. The primary reason for the increase in the distribution to Piedmont during the current year is due to increased earnings for 2012 compared to 2011.

Dividends on Common Stock Our common stock dividend payments were $55 million for the three months ended March 31, 2013 and $42 million for the same period in 2012. The increase is primarily due to the $0.10 stub period dividend paid in December 2011, which reduced the dividend paid in the first quarter of 2012 by the same amount and the annual dividend increase of $0.04 per share.

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.

There were no significant changes to our contractual obligations described in Note 11 of our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.

Pension and retiree welfare plan obligationsAs a result of merging the pension plans, there were no contributions required during the first quarter of 2013. In 2012, we contributed $17 million to these qualified pension plans and an additional $7 million in April 2012 for a total of $24 million through April of 2012. Based on the current funding status of these plans, we do not believe that we will be required to make a minimum contribution to the plans during 2013. We may make additional contributions in 2013 in order to preserve the current level of benefits under these plans and in accordance with the funding requirements of the Pension Protection Act.

During the three months ended March 31, 2013, we recorded net periodic benefit costs of $14 million related to our defined benefit plans compared to $16 million during the same period last year. During the first quarter of 2013, we received an updated estimate of the 2013 expense that indicated a range of $55 million to $60 million. As such, we estimate that during the remainder of 2013 we will record net periodic benefit costs in the range of $41 million to $46 million, as compared to actual 2012 expense of $61 million. We expect a revised estimate by the end of the second quarter of 2013, which we do not anticipate will be materially different than our current estimate.

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. 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 2012 Form 10-K. Our critical accounting estimates used in the preparation of our unaudited Condensed Consolidated Financial Statements include the following:

·Environmental Remediation Liabilities

·Derivatives and Hedging Activities

·Goodwill and Intangible Assets

·Contingencies

·Pension and Retiree Welfare Plans

·Income Taxes

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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 is defined as the potential loss that we may incur as a result of changes in the fair value of natural gas. Interest rate risk results from 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. Our fuel price risk is primarily in cargo shipping, which is partially reduced through fuel surcharges. Our use of derivative instruments is governed by a risk management policy, approved and monitored by our Risk Management Committee (RMC).

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 4 of our unaudited Condensed Consolidated Financial Statements.

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, 2013 and 2012.

	Derivative instruments average values (1) at March 31,
In millions	2013		2012
Asset	$	114	$	279
Liability		29		117

(1)Excludes cash collateral amounts.

	Derivative instruments fair values netted with cash collateral at
In millions	March 31, 2013		December 31, 2012		March 31, 2012
Asset	$	111	$	144	$	266
Liability		24		39		103

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	2013			2012
Net fair value of derivative instruments outstanding at beginning of period	$	36		$	31
Derivative instruments realized or otherwise settled during period		(43	)		(82	)
Change in net fair value of derivative instruments		17			5
Net fair value of derivative instruments outstanding at end of period		10			(46	)
Netting of cash collateral		77			209
Cash collateral and net fair value of derivative instruments outstanding at end of period	$	87		$	163

The sources of our net fair value at March 31, 2013, are as follows.

In millions	Prices actively quoted (Level 1) (1)			Significant other observable inputs (Level 2) (2)
Mature through 2013	$	(15	)	$	29
Mature 2014 - 2015		(5	)		1
Mature 2016 - 2017		(2	)		2
Total derivative instruments (3)	$	(22	)	$	32

  (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.

Value-at-riskOur 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 immaterial, permitting us to operate within relatively low VaR limits. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of our open positions. Our VaR is determined on a 95% confidence interval and a 1-day holding period. In simple terms, this means that 95% of the time, the risk of loss from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated.

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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 for all positions, our portfolio positions for the periods presented had the following VaRs.

	Three months ended March 31,
In millions	2013		2012
Period end	$	1.7	$	2.2
Average		1.9		2.5
High		2.6		4.8
Low		1.6		1.9

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 $1.1 billion of variable-rate debt outstanding at March 31, 2013, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $11 million on an annualized basis.

We have $300 million of 6.4% senior notes due in July 2016. In May 2011, we entered into interest rate swaps related to these senior notes to effectively convert $250 million from a fixed-rate to a variable-rate obligation. On September 6, 2012, we settled this $250 million interest rate swap, which resulted in our receipt of a $17 million cash payment. 

We use 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.

We anticipate issuing approximately $500 million of senior notes in the second quarter of 2013. As of April 30, 2013, we had entered into $300 million, in notional amount, of fixed-rate forward-starting interest rate swaps to hedge any potential interest rate volatility prior to this anticipated issuance. The weighted average interest rate of these swaps is a 10-year United States Treasury rate of 1.85%. The remaining un-hedged principal amount of the planned debt issuance currently remains subject to the risk of increases in near-term interest rates. We have designated the forward-starting interest rate swaps as cash flow hedges, which will mature on the debt issuance date.

The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the life of the related debt. For additional information, see Note 4 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein.

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.

Additionally, we may require counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for each 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, 2013, our top 20 counterparties represented approximately 49% of the total counterparty exposure of $370 million, derived by adding together the top 20 counterparties’ exposures, exclusive of customer deposits, and dividing by the total of our counterparties’ exposures.

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As of March 31, 2013, our counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of A-, which is an improvement from 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
	March 31,		December 31,		March 31,		March 31,		December 31,		March 31,
In millions	2013		2012		2012		2013		2012		2012
Netting agreements in place:
Counterparty is investment grade	$	286	$	485	$	252	$	198	$	282	$	192
Counterparty is non-investment grade		4		9		11		13		13		20
Counterparty has no external rating		319		175		121		431		315		212
No netting agreements in place:
Counterparty is investment grade		12		7		2		10		1		1
Counterparty has no external rating		6		1		-		1		-		-
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position	$	627	$	677	$	386	$	653	$	611	$	425

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 $13 million at March 31, 2013, which would not have a material impact to our consolidated results of operations, cash flows or financial condition.

There have been no other significant changes to our credit risk related to our other segments, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our 2012 Form 10-K.

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 entirely remove our risk in periods of increasing fuel prices and volatility, or increased competition. An increase of 10% in Tropical Shipping’s average cost per gallon for vessel fuel results in approximately $6 million in additional annual fuel expense. The aforementioned fuel surcharges would be implemented to reduce the impact of the increased fuel expense.

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, 2013, 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, 2013, 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 first quarter ended March 31, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

42

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 regarding some of these proceedings, see Note 9 to our unaudited Condensed Consolidated Financial Statements under the caption “Litigation.”

Item 1A. Risk Factors

For information regarding our risk factors, see the factors discussed in Part I, "Item 1A. Risk Factors" in our 2012 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2012 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial 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 2013 and no unregistered sales of equity securities were made during this period.

Item 4. Mine Safety Disclosures

Not applicable.

Item 6. Exhibits

10.1	Bank Rate Mode Covenants Agreement, dated as of February 26, 2013, among AGL Resources Inc., Pivotal Utility Holdings, Inc., the several purchasers from time to time parties thereto and SunTrust Bank, as administrative agent (Exhibit 10.1, AGL Resources Inc. Form 8-K filed March 1, 2013).
10.2	Loan Agreement, dated as of February 1, 2013, between Brevard County, Florida and Pivotal Utility Holdings, Inc. (Exhibit 10.2, AGL Resources Inc. Form 8-K filed March 1, 2013).
10.3	Loan Agreement, dated as of March 1, 2013, between New Jersey Economic Development Board and Pivotal Utility Holdings, Inc., relating to $40 million New Jersey Economic Development Authority Gas Facilities Refunding Revenue Bonds (Pivotal Utilities Holdings, Inc. Project), Series 2013 (Exhibit 10.1, AGL Resources Inc. Form 8-K filed March 27, 2013).
10.4	Amended and Restated Loan Agreement, dated as of March 1, 2013, between Brevard County, Florida and Pivotal Utility Holdings, Inc., relating to $39 million New Jersey Economic Development Authority Gas Facilities Refunding Revenue Bonds (NUI Corporation Project), 1996 Series A (Exhibit 10.2, AGL Resources Inc. Form 8-K filed March 27, 2013).
10.5	Amended and Restated Loan Agreement, dated as of March 1, 2013, between Brevard County, Florida and Pivotal Utility Holdings, Inc., relating to $46.5 million New Jersey Economic Development Authority Gas Facilities Refunding Revenue Bonds (Pivotal Utility Holdings, Inc. Project), Series 2005 (Exhibit 10.3, AGL Resources Inc. Form 8-K filed March 27, 2013).
10.6	Amended and Restated Loan Agreement, dated as of March 1, 2013, between Brevard County, Florida and Pivotal Utility Holdings, Inc., relating to $54.6 million New Jersey Economic Development Authority Gas Facilities Refunding revenue Bonds (Pivotal Utility Holdings, Inc. Project), Series 2007 (Exhibit 10.4, AGL Resources Inc. Form 8-K filed March 27, 2013).
12	Statement of Computation of Ratio of Earnings to Fixed Charges.
31.1	Certification of John W. Somerhalder II pursuant to Rule 13a - 14(a).
31.2	Certification of Andrew W. Evans pursuant to Rule 13a - 14(a).
32.1	Certification of John W. Somerhalder II pursuant to 18 U.S.C. Section 1350.
32.2	Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF	XBRL Taxonomy Definition Linkbase.
101.LAB	XBRL Taxonomy Extension Labels Linkbase.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.

43

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 30, 2013                                                                /s/ Andrew W. Evans

Executive Vice President and Chief Financial Officer

44

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, 2013			2012			2011			2010			2009			2008
Earnings before income taxes	$	258		$	450		$	311		$	390		$	384		$	369
Add:
Fixed charges (see “B” below)		51			203			145			123			115			127
Amortization of capitalized interest (1)		-			-			1			-			-			-
Distributed income of equity investees		3			14			-			-			-			-
Less:
Interest capitalized (1)		-			(1	)		(1	)		(5	)		(3	)		(2	)
Noncontrolling interest in pre-tax income of subsidiaries that have not incurred fixed charges		(10	)		(15	)		(14	)		(16	)		(27	)		(20	)
Adjusted Earnings (A)	$	302		$	651		$	442		$	492		$	469		$	474
Fixed charges
Interest on long-term debt	$	44		$	177		$	101		$	109		$	98		$	96
Other interest, including amortized premiums, discounts and capitalized expenses related to indebtedness liability		4			13			37			7			10			24
Estimated interest components of rentals		3			13			7			7			7			7
Total fixed charges (B)	$	51		$	203		$	145		$	123		$	115		$	127
Ratio of earnings to fixed charges (A)/(B)		5.92			3.21			3.05			4.00			4.08			3.73

(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 30, 2013	/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 30, 2013	/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, 2013 (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 30, 2013	/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, 2013 (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 30, 2013	/s/ Andrew W. Evans
	Executive Vice President and Chief Financial Officer

XML

Note 3 - Fair Value Measurements (Detail) - Money Market Funds (Fair Value, Inputs, Level 1 [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012		Mar. 31, 2012
Fair Value, Inputs, Level 1 [Member]
Money market funds (1)	$ 48	[1]	$ 66	[1]	$ 68	[1]

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

XML

Note 8 - Non-Wholly Owned Entities (Detail) - Variable Interest Entities (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012		Mar. 31, 2012		Dec. 31, 2011
Current assets	$ 2,361		$ 2,668		$ 2,022
Long-term assets and other deferred debits	11,579		11,473		11,217
Total assets	13,940	[1]	14,141	[2]	13,239	[3]
Current liabilities	3,060		3,338		2,348
Long-term liabilities and other deferred credits	7,339		7,368		7,465
Total Liabilities	10,399		10,706		9,813
Equity	3,541		3,435		3,426		3,339
Total liabilities and equity	13,940		14,141		13,239
South Star [Member]
Current assets	143		201		149
Long-term assets and other deferred debits	10		10		9
Total assets	153		211		158
Current liabilities	51		62		52
Total Liabilities	51		62		52
Equity	102		149		106
Total liabilities and equity	$ 153		$ 211		$ 158
South Star Percentage To Consolidated [Member]
Current assets	6.00%		8.00%		7.00%
Total assets	1.00%		1.00%		1.00%
Current liabilities	2.00%		2.00%		2.00%
Total Liabilities	1.00%		1.00%		1.00%
Equity	3.00%		4.00%		3.00%
Total liabilities and equity	1.00%		1.00%		1.00%

[1] Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.

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

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

XML

Note 6 - Debt and Credit Facilities (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012
Long-term Debt	$ 3,324	$ 3,327	$ 3,558
Notional Amount of Interest Rate Derivatives	50
Derivative, Average Swaption Interest Rate	1.98%
Refinanced [Member] | Refunding Bonds [Member] | Gas Facility Revenue Bonds [Member]
Long-term Debt	60
Refinanced [Member] | Purchase of Existing Bonds [Member] | Gas Facility Revenue Bonds [Member]
Long-term Debt	140
Refinanced [Member] | Gas Facility Revenue Bonds [Member] | Debt Issued By New Jersey Economic Development Authority [Member]
Long-term Debt	180
Refinanced [Member] | Gas Facility Revenue Bonds [Member] | Debt Issued by Brevard County Florida [Member]
Long-term Debt	20
Refinanced [Member] | Gas Facility Revenue Bonds [Member]
Long-term Debt	200
Interest Rate Swap [Member]
Notional Amount of Interest Rate Derivatives	300
Derivative, Average Swaption Interest Rate	1.85%
AGL Capital [Member]
Debt, Weighted Average Interest Rate	0.50%
Gas Facility Revenue Bonds [Member]
Long-term Debt	$ 200	$ 200	$ 200

XML

Note 8 - Non-Wholly Owned Entities (Detail) - SouthStar’s Revenues and Expenses (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating revenues	$ 1,709	$ 1,404
Operating expenses
Cost of goods sold	973	719
Operation and maintenance	259	245
Depreciation and amortization	107	104
Taxes other than income taxes	71	64
Total operating expenses	1,410	1,142
Operating income	299	262
South Star [Member]
Operating revenues	250	215
Operating expenses
Cost of goods sold	164	133
Operation and maintenance	18	19
Depreciation and amortization	1
Taxes other than income taxes		1
Total operating expenses	183	153
Operating income	$ 67	$ 62

XML

Note 5 - Employee Benefit Plans (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Defined Benefit Plan, Contributions by Employer	$ 17

XML

Note 2 - Significant Accounting Policies and Methods of Application (Detail) - Summary of Regulatory Assets and Liabilities (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012
Regulatory assets
Regulatory assets - current	$ 119	$ 145	$ 137
Regulatory assets - noncurrent	878	944	1,057
Total regulatory assets	997	1,089	1,194
Regulatory liabilities
Regulatory liabilities - current	238	161	173
Regulatory liabilities - noncurrent	1,498	1,477	1,431
Total regulatory liabilities	1,736	1,638	1,604
Accrued natural gas costs [Member]
Regulatory liabilities
Regulatory liabilities - current	133	93	97
Bad debt rider [Member]
Regulatory liabilities
Regulatory liabilities - current	39	37	32
Regulatory liabilities - noncurrent	20	17	20
Accumulated removal costs [Member]
Regulatory liabilities
Regulatory liabilities - current	17	16	14
Regulatory liabilities - noncurrent	1,413	1,393	1,339
Other Regulatory Liabilities [Member]
Regulatory liabilities
Regulatory liabilities - current	49	15	30
Regulatory liabilities - noncurrent	11	11	14
Unamortized investment tax credit [Member]
Regulatory liabilities
Regulatory liabilities - noncurrent	28	29	32
Regulatory income tax liability [Member]
Regulatory liabilities
Regulatory liabilities - noncurrent	26	27	26
Recoverable regulatory infrastructure program costs [Member]
Regulatory assets
Regulatory assets - current	47	47	48
Regulatory assets - noncurrent	135	167	291
Recoverable Environmental Remediation Costs [Member]
Regulatory assets
Regulatory assets - current	28	38	7
Regulatory assets - noncurrent	415	438	349
Recoverable Pension And Other Retirement Benefit Costs [Member]
Regulatory assets
Regulatory assets - current	19	19	29
Regulatory assets - noncurrent	192	196	256
Other Regulatory Assets [Member]
Regulatory assets
Regulatory assets - current	25	41	53
Regulatory assets - noncurrent	48	53	64
Long-Term Debt Fair Value Adjustment [Member]
Regulatory assets
Regulatory assets - noncurrent	$ 88	$ 90	$ 97

XML

Note 9 - Commitments, Guarantees and Contingencies (Detail) - Environmental Matters (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Dec. 31, 2012	Mar. 31, 2012
Probabilistic model cost estimate range	$ 358	[1]
Probabilistic model cost estimate range	749	[1]
Expected costs over next twelve months	63		57	39
Illinois [Member] | Engineering Estimates [Member]
Environmental matters	50	[1]
Illinois [Member] | Amount Recorded [Member]
Environmental matters	239
Illinois [Member]
Probabilistic model cost estimate range	193	[1]
Probabilistic model cost estimate range	439	[1]
Expected costs over next twelve months	35
New Jersey [Member] | Engineering Estimates [Member]
Environmental matters	6	[1]
New Jersey [Member] | Amount Recorded [Member]
Environmental matters	121
New Jersey [Member]
Probabilistic model cost estimate range	116	[1]
Probabilistic model cost estimate range	203	[1]
Expected costs over next twelve months	14
Georgia And Florida [Member] | Engineering Estimates [Member]
Environmental matters	12	[1]
Georgia And Florida [Member] | Amount Recorded [Member]
Environmental matters	54
Georgia And Florida [Member]
Probabilistic model cost estimate range	49	[1]
Probabilistic model cost estimate range	107	[1]
Expected costs over next twelve months	6
North Carolina [Member] | Engineering Estimates [Member]
Environmental matters	11	[1]
North Carolina [Member] | Amount Recorded [Member]
Environmental matters	11
North Carolina [Member]
Expected costs over next twelve months	8
Engineering Estimates [Member]
Environmental matters	79	[1]
Amount Recorded [Member]
Environmental matters	$ 425

[1] There were events during first quarter 2013 that resulted in changes to the estimates disclosed in, and the amounts recorded in, our December 31, 2012 Form 10-K. These changes are reflected in the table above.

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Note 5 - Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2013

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

	Three months ended March 31,
In millions	2013			2012
Service cost	$	8		$	7
Interest cost		10			11
Expected return on plan assets		(16	)		(16	)
Net amortization of prior service cost		-			(1	)
Recognized actuarial loss		8			9
Net periodic pension benefit cost	$	10		$	10

	Three months ended March 31,
In millions	2013			2012
Service cost	$	1		$	1
Interest cost		3			4
Expected return on plan assets		(1	)		(1	)
Net amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		2			3
Net periodic welfare benefit cost	$	4		$	6

XML

Note 6 - Debt and Credit Facilities (Detail) - Debt to Capitalization Ratios	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012
AGL Capital [Member]
Debt-to-capitalization ratio	0.54	0.58	0.54
Nicor Gas [Member]
Debt-to-capitalization ratio	0.43	0.55	0.47

XML

Note 4 - Derivative Instruments (Detail) - Gains and Losses on Derivative Instruments (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Nicor Gas [Member]
RealizedLossesHedgingNaturalGasCosts	$ 1	$ 1
Elizabethtown Gas [Member]
RealizedLossesHedgingNaturalGasCosts	$ 3	$ 9

XML

Note 3 - Fair Value Measurements (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012
Weather Derivative Premium	$ 2	$ 4	$ 1

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Note 7 - Equity (Detail) - Reclassifications Out of Accumulated Other Comprehensive Loss (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Cash flow hedges
Interest rate contracts	$ 46		$ 47
Total cash flow hedges	164		139
Retirement benefit plan amortization of
Total retirement benefit plans	3	[1]
Total reclassification for the period	5	[1]
Reclassification Out Of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | Interest Rate Swap [Member]
Cash flow hedges
Interest rate contracts	(3)	[2]
Reclassification Out Of Accumulated Other Comprehensive Income [Member]
Cash flow hedges
Income tax benefit	1	[2]
Total cash flow hedges	(2)	[2]
Retirement benefit plan amortization of
Actuarial losses	(6)	[2],[3]
Prior service credits	1	[2],[3]
Total before income tax	(5)	[2]
Income tax benefit	2	[2]
Total retirement benefit plans	(3)	[2]
Total reclassification for the period	$ (5)	[2]

[1] All amounts are net of income taxes. Amounts in parentheses indicate debits to Accumulated Other Comprehensive Loss.

[2] Amounts in parentheses indicate debits, or reductions, to profit/loss and credits to Accumulated Other Comprehensive Income. Except for retirement benefit plan amounts, the profit/loss impacts are immediate.

[3] These accumulated OCI components are included in the computation of net periodic benefit cost. See Note 5, Employee Benefit Plans, for additional details about net periodic benefit cost.

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Note 10 - Segment Information (Detail) - Intersegment Reporting (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012		Dec. 31, 2012
Operating revenues from external parties	$ 1,709		$ 1,404
Intercompany revenues		[1]		[1]
Total operating revenues	1,709		1,404
Operating expenses
Cost of goods sold	973		719
Operation and maintenance	259		245
Depreciation and amortization	107		104
Taxes other than income taxes	71		64
Total operating expenses	1,410		1,142
Nicor merger expenses (2)			10	[2]
Operating income (loss)	299		262
Other income	5		4
EBIT	304		266
Identifiable and total assets	13,940	[2]	13,239	[3]	14,141	[4]
Goodwill	1,883		1,813		1,837
Capital expenditures	148		171
Distribution Operations [Member]
Operating revenues from external parties	1,264		994
Intercompany revenues	55	[1]	46	[1]
Total operating revenues	1,319		1,040
Operating expenses
Cost of goods sold	765		529
Operation and maintenance	185		173
Depreciation and amortization	90		88
Taxes other than income taxes	64		57
Total operating expenses	1,104		847
Nicor merger expenses (2)				[2]
Operating income (loss)	215		193
Other income	3		1
EBIT	218		194
Identifiable and total assets	11,258	[2]	10,785	[3]	11,320	[4]
Goodwill	1,640		1,586		1,640
Capital expenditures	137		122
Retail Operations [Member]
Operating revenues from external parties	302		263
Intercompany revenues		[1]		[1]
Total operating revenues	302		263
Operating expenses
Cost of goods sold	195		166
Operation and maintenance	31		32
Depreciation and amortization	5		4
Taxes other than income taxes	1		1
Total operating expenses	232		203
Nicor merger expenses (2)				[2]
Operating income (loss)	70		60
EBIT	70		60
Identifiable and total assets	668	[2]	471	[3]	511	[4]
Goodwill	168		124		122
Capital expenditures	1		2
Wholesale Services [Member]
Operating revenues from external parties	39		64
Intercompany revenues		[1]		[1]
Total operating revenues	39		64
Operating expenses
Cost of goods sold	10		30
Operation and maintenance	13		13
Depreciation and amortization			1
Taxes other than income taxes	1		1
Total operating expenses	24		45
Nicor merger expenses (2)				[2]
Operating income (loss)	15		19
EBIT	15		19
Identifiable and total assets	1,005	[2]	917	[3]	1,218	[4]
Goodwill			2
Midstream Operations [Member]
Operating revenues from external parties	24		16
Intercompany revenues		[1]		[1]
Total operating revenues	24		16
Operating expenses
Cost of goods sold	12		5
Operation and maintenance	6		5
Depreciation and amortization	4		2
Taxes other than income taxes	1		1
Total operating expenses	23		13
Nicor merger expenses (2)				[2]
Operating income (loss)	1		3
Other income	1
EBIT	2		3
Identifiable and total assets	714	[2]	665	[3]	720	[4]
Goodwill	14		16		14
Capital expenditures	4		42
Cargo Shipping [Member]
Operating revenues from external parties	87		84
Intercompany revenues		[1]		[1]
Total operating revenues	87		84
Operating expenses
Cost of goods sold	53		50
Operation and maintenance	28		28
Depreciation and amortization	5		6
Taxes other than income taxes	1		2
Total operating expenses	87		86
Nicor merger expenses (2)				[2]
Operating income (loss)			(2)
Other income	2		3
EBIT	2		1
Identifiable and total assets	459	[2]	477	[3]	464	[4]
Goodwill	61		77		61
Capital expenditures	1
All Other Segments [Member]
Operating revenues from external parties	(7)	[5]	(17)	[5]
Intercompany revenues	(55)	[1],[5]	(46)	[1],[5]
Total operating revenues	(62)	[5]	(63)	[5]
Operating expenses
Cost of goods sold	(62)	[5]	(61)	[5]
Operation and maintenance	(4)	[5]	(6)	[5]
Depreciation and amortization	3	[5]	3	[5]
Taxes other than income taxes	3	[5]	2	[5]
Total operating expenses	(60)	[5]	(52)	[5]
Nicor merger expenses (2)			10	[2],[5]
Operating income (loss)	(2)	[5]	(11)	[5]
Other income	(1)	[5]		[5]
EBIT	(3)	[5]	(11)	[5]
Identifiable and total assets	(164)	[2],[5]	(76)	[3],[5]	(92)	[4],[6]
Goodwill		[5]	8	[5]		[6]
Capital expenditures	$ 5	[5]	$ 5	[5]

[1] Intercompany revenues - wholesale services records its energy marketing and risk management revenues on a net basis and its total operating revenues include intercompany revenues of $140 million for the three months ended March 31, 2013 and $88 million for the three months ended March 31, 2012.

[2] Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.

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

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

[5] Our other segment's assets consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

[6] Our other segment's assets consist primarily of cash and cash equivalents and PP&E and reflect the effect of intercompany eliminations.

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Note 5 - Employee Benefit Plans (Detail) - Employee Benefit Plans (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pension Plans, Defined Benefit [Member]
Service cost	$ 8	$ 7
Interest cost	10	11
Expected return on plan assets	(16)	(16)
Net amortization of prior service cost		(1)
Recognized actuarial loss	8	9
Net pension benefit cost	10	10
Other Postretirement Benefit Plans, Defined Benefit [Member]
Service cost	1	1
Interest cost	3	4
Expected return on plan assets	(1)	(1)
Net amortization of prior service cost	(1)	(1)
Recognized actuarial loss	2	3
Net pension benefit cost	$ 4	$ 6

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Condensed Consolidated Statements of Equity (Unaudited) (Parentheticals) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Dividends on common stock, per share	$ 0.47	$ 0.36

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Note 4 - Derivative Instruments (Detail) - Net Long Natural Gas Contracts	Mar. 31, 2013 ft3		Dec. 31, 2012 ft3		Mar. 31, 2012 ft3
Hedge designation
Cash flow hedges	6,000,000,000	[1],[2]	6,000,000,000	[1],[2]	7,000,000,000	[1],[2]
Not designated as hedges	304,000,000,000	[1],[2]	96,000,000,000	[1],[2]	116,000,000,000	[1],[2]
Total hedges	310,000,000,000	[1],[2]	102,000,000,000	[1],[2]	123,000,000,000	[1],[2]
Hedge position
Short position	(1,902,000,000,000)	[1],[2]	(1,955,000,000,000)	[1],[2]	(1,942,000,000,000)	[1],[2]
Long position	2,212,000,000,000	[1],[2]	2,057,000,000,000	[1],[2]	2,065,000,000,000	[1],[2]
Net long position	310,000,000,000	[1],[2]	102,000,000,000	[1],[2]	123,000,000,000	[1],[2]

[1] Volumes related to Nicor Gas exclude variable-priced contracts, which are accounted for as derivatives, but whose fair values are not directly impacted by changes in commodity prices.

[2] Approximately 98% of these contracts have durations of two years or less and the remaining 2% expire between 2 and 6 years.

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Note 9 - Commitments, Guarantees and Contingencies (Tables)

3 Months Ended

Mar. 31, 2013

Environmental Exit Costs by Cost [Table Text Block]

In millions	Probabilistic model cost estimates (1)			Engineering estimates (1)		Amount recorded		Expected costs over next twelve months
Illinois	$193	-	$439	$	50	$	239	$	35
New Jersey	116	-	203		6		121		14
Georgia and Florida	49	-	107		12		54		6
North Carolina		n/a			11		11		8
Total	$358	-	$749	$	79	$	425	$	63

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Note 8 - Non-Wholly Owned Entities (Tables)

3 Months Ended

Mar. 31, 2013

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

	March 31, 2013						December 31, 2012						March 31, 2012
In millions	Consolidated		SouthStar				Consolidated		SouthStar				Consolidated		SouthStar
Current assets	$	2,361	$	143	6	%	$	2,668	$	201	8	%	$	2,022	$	149	7	%
Long-term assets and other deferred debits		11,579		10	-			11,473		10	-			11,217		9	-
Total assets	$	13,940	$	153	1	%	$	14,141	$	211	1	%	$	13,239	$	158	1	%
Current liabilities	$	3,060	$	51	2	%	$	3,338	$	62	2	%	$	2,348	$	52	2	%
Long-term liabilities and other deferred credits		7,339		-	-			7,368		-	-			7,465		-	-
Total Liabilities		10,399		51	1			10,706		62	1			9,813		52	1
Equity		3,541		102	3			3,435		149	4			3,426		106	3
Total liabilities and equity	$	13,940	$	153	1	%	$	14,141	$	211	1	%	$	13,239	$	158	1	%

Schedule of Variable Interest Entities [Table Text Block]

In millions	2013		2012
Operating revenues	$	250	$	215
Operating expenses
Cost of goods sold		164		133
Operation and maintenance		18		19
Depreciation and amortization		1		-
Taxes other than income taxes		-		1
Total operating expenses		183		153
Operating income	$	67	$	62

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Note 9 - Commitments, Guarantees and Contingencies (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended				12 Months Ended		3 Months Ended	12 Months Ended			12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2004	Dec. 21, 2012 ft3	Dec. 31, 2011 Interest Due [Member]	Dec. 31, 2003 Adverse Consequences To Ratepayers [Member]	Dec. 31, 2012 Illinois Commission [Member]	Dec. 31, 2011 Illinois Commission [Member]	Mar. 31, 2013 Illinois Commission [Member]	Mar. 31, 2012 Illinois Commission [Member]	Dec. 31, 2011 IAGO [Member]	Dec. 31, 2011 CUB [Member]
Gas Balancing Volume Amount (in Cubic Feet)				4,800,000,000
Prior Period Reclassification Adjustment						$ 25
Loss Contingency, Estimate of Possible Loss			27			4				64
Adjustment To Previously Recorded Pbr Reserve	37		2
Loss Contingency, Damages Sought, Value		6			2		72	85			255	305
Loss Contingency Accrual, Carrying Value, Period Increase (Decrease)							8
Loss Contingency Accrual, at Carrying Value									$ 72

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Note 4 - Derivative Instruments (Detail) - Derivative Instruments on the Condensed Consolidated Statements of Financial Position (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012		Mar. 31, 2012
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	$ 111	[1],[2]	$ 144	[1],[2]	$ 266	[1],[2]
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position	(24)	[1],[2]	(39)	[1],[2]	(103)	[1],[2]
Designated as Hedging Instrument [Member] | Current Natural Gas Contracts [Member]
Designated as cash flow hedges and fair value hedges
Assets	3	[1],[2]	1	[1],[2]	5	[1],[2]
Liabilities	(1)	[1],[2]	(2)	[1],[2]	(11)	[1],[2]
Designated as Hedging Instrument [Member] | Long-Term Natural Gas Contracts [Member]
Designated as cash flow hedges and fair value hedges
Assets		[1],[2]	3	[1],[2]		[1],[2]
Liabilities		[1],[2]		[1],[2]		[1],[2]
Designated as Hedging Instrument [Member] | Current Interest Rate Swap Agreements [Member]
Designated as cash flow hedges and fair value hedges
Assets	5	[1],[2]		[1],[2]		[1],[2]
Liabilities		[1],[2]		[1],[2]		[1],[2]
Designated as Hedging Instrument [Member] | Long-Term Interest Rate Swap Agreements [Member]
Designated as cash flow hedges and fair value hedges
Assets		[1],[2]		[1],[2]	9	[1],[2]
Liabilities		[1],[2]		[1],[2]	(11)	[1],[2]
Designated as Hedging Instrument [Member]
Designated as cash flow hedges and fair value hedges
Assets	8	[1],[2]	4	[1],[2]	14	[1],[2]
Liabilities	(1)	[1],[2]	(2)	[1],[2]	(22)	[1],[2]
Not Designated as Hedging Instrument [Member] | Current Natural Gas Contracts [Member]
Designated as cash flow hedges and fair value hedges
Assets	332	[1],[2]	394	[1],[2]	683	[1],[2]
Liabilities	(327)	[1],[2]	(355)	[1],[2]	(718)	[1],[2]
Not Designated as Hedging Instrument [Member] | Long-Term Natural Gas Contracts [Member]
Designated as cash flow hedges and fair value hedges
Assets	46	[1],[2]	45	[1],[2]	82	[1],[2]
Liabilities	(48)	[1],[2]	(50)	[1],[2]	(85)	[1],[2]
Not Designated as Hedging Instrument [Member]
Designated as cash flow hedges and fair value hedges
Assets	378	[1],[2]	439	[1],[2]	765	[1],[2]
Liabilities	(375)	[1],[2]	(405)	[1],[2]	(803)	[1],[2]
Long-Term Natural Gas Contracts [Member]
Designated as cash flow hedges and fair value hedges
Assets	386	[1],[2]	443	[1],[2]	779	[1],[2]
Liabilities	(376)	[1],[2]	(407)	[1],[2]	(825)	[1],[2]
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position	(275)	[1],[2]	(299)	[1],[2]	(513)	[1],[2]
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position	$ 352	[1],[2]	$ 368	[1],[2]	$ 722	[1],[2]

[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 $77 million as of March 31, 2013, $69 million as of December 31, 2012 and $209 million as of March 31, 2012. Cash collateral is included in the "Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position" line of this table.

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Note 10 - Segment Information (Tables)

3 Months Ended

Mar. 31, 2013

In millions	2013		2012
Operating income	$	299	$	262
Other income		5		4
EBIT		304		266
Interest expense		46		47
Earnings before income taxes		258		219
Income taxes		94		80
Net income	$	164	$	139

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

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	11,320		$	1,640
Retail operations		511			122
Wholesale services		1,218			-
Midstream operations		720			14
Cargo shipping		464			61
Other (2)		(92	)		-
Consolidated	$	14,141		$	1,837

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

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping		Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	1,264	$	302	$	39	$	24	$	87	$	(7	)	$	1,709
Intercompany revenues (1)		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 (3)	$	11,258	$	668	$	1,005	$	714	$	459	$	(164	)	$	13,940
Goodwill	$	1,640	$	168	$	-	$	14	$	61	$	-		$	1,883
Capital expenditures	$	137	$	1	$	-	$	4	$	1	$	5		$	148

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping			Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	994	$	263	$	64	$	16	$	84		$	(17	)	$	1,404
Intercompany revenues (1)		46		-		-		-		-			(46	)		-
Total operating revenues		1,040		263		64		16		84			(63	)		1,404
Operating expenses
Cost of goods sold		529		166		30		5		50			(61	)		719
Operation and maintenance		173		32		13		5		28			(6	)		245
Depreciation and amortization		88		4		1		2		6			3			104
Taxes other than income taxes		57		1		1		1		2			2			64
Nicor merger expenses (2)		-		-		-		-		-			10			10
Total operating expenses		847		203		45		13		86			(52	)		1,142
Operating income (loss)		193		60		19		3		(2	)		(11	)		262
Other income		1		-		-		-		3			-			4
EBIT	$	194	$	60	$	19	$	3	$	1		$	(11	)	$	266
Identifiable and total assets (3)	$	10,785	$	471	$	917	$	665	$	477		$	(76	)	$	13,239
Goodwill	$	1,586	$	124	$	2	$	16	$	77		$	8		$	1,813
Capital expenditures	$	122	$	2	$	-	$	42	$	-		$	5		$	171

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Note 2 - Significant Accounting Policies and Methods of Application (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Jan. 31, 2013
NiSource Inc. [Member]
Service Plans Acquired	500,000
Business Acquisition, Cost of Acquired Entity, Cash Paid (in Dollars)	$ 120
Business Acquisition, Cost of Acquired Entity, Other Noncash Consideration (in Dollars)	2
Customer Relationships [Member]
Acquired Finite-lived Intangible Asset, Amount (in Dollars)	47
Finite-Lived Intangible Asset, Useful Life	14 years
Trade Names [Member]
Acquired Finite-lived Intangible Asset, Amount (in Dollars)	$ 17
Finite-Lived Intangible Asset, Useful Life	10 years

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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, 2011	$ 586	$ 1,989	$ 967	$ (217)	$ (7)	$ 21	$ 3,339
Balance (in Shares) at Dec. 31, 2011	117,000,000
Net income			130			9	139
Other comprehensive loss				(1)			(1)
Dividends on common stock			(42)				(42)
Distributions to noncontrolling interest						(14)	(14)
Stock issued, dividend reinvestment plan	1	3			(1)		3
Stock issued, dividend reinvestment plan (in Shares)	200,000
Stock-based compensation expense (net of tax)		2					2
Balance at Mar. 31, 2012	587	1,994	1,055	(218)	(8)	16	3,426
Balance (in Shares) at Mar. 31, 2012	117,200,000						117,282,844
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						117,855,075
Net income			154			10	164
Other comprehensive loss				7			7	[1]
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

[1] All amounts are net of income taxes. Amounts in parentheses indicate debits to Accumulated Other Comprehensive Loss.

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Note 2 - Significant Accounting Policies and Methods of Application (Detail) - Cost Of Goods Sold Adjustments (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Retail Operations [Member]
LOCOM Adjustments	$ 3
Wholesale Services [Member]
LOCOM Adjustments	18
Midstream Operations [Member]
LOCOM Adjustments	$ 1

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Note 3 - Fair Value Measurements (Detail) - Amortized Cost and Fair Value of Long-Term Debt (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012		Mar. 31, 2012
Long-term debt amortized cost	$ 3,550		$ 3,553		$ 3,575
Fair Value, Inputs, Level 2 [Member]
Long-term debt fair value (1)	$ 4,006	[1]	$ 4,057	[1]	$ 3,922	[1]

[1] Fair value determined using Level 2 inputs.

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Note 8 - Non-Wholly Owned Entities (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Payments to Acquire Property, Plant, and Equipment	$ 148	$ 171
Payments of Ordinary Dividends, Noncontrolling Interest	17	14
Increase Decrease In Payments Of Dividends Minority Interest	3
Triton [Member]
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	2	3
Other Equity Investments [Member]
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	1
South Star [Member]
Payments to Acquire Property, Plant, and Equipment	$ 1	$ 1	$ 1

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Condensed Consolidated Statement of Financial Position (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012		Mar. 31, 2012
Current assets
Cash and cash equivalents	$ 149		$ 131		$ 71
Short-term investments	43		58		57
Receivables
Gas, unbilled and other receivables	874		686		577
Energy marketing receivables	627		677		386
Less allowance for uncollectible accounts	39		28		19
Total receivables	1,462		1,335		944
Inventories, net	393		708		464
Regulatory assets	119		145		137
Derivative instruments	100		130		218
Other current assets	95		161		131
Total current assets	2,361		2,668		2,022
Long-term assets and other deferred debits
Property, plant and equipment	10,610		10,478		9,920
Less accumulated depreciation	2,202		2,131		1,947
Property, plant and equipment, net	8,408		8,347		7,973
Goodwill	1,883		1,837		1,813
Regulatory assets	878		944		1,057
Intangible assets	156		96		102
Derivative instruments	11		14		48
Other	243		235		224
Total long-term assets and other deferred debits	11,579		11,473		11,217
Total assets	13,940	[1]	14,141	[2]	13,239	[3]
Current liabilities
Short-term debt	868		1,377		730
Energy marketing trade payable	653		611		425
Accounts payable - trade	314		334		205
Current portion of long-term debt and capital leases	226		226		17
Regulatory liabilities	238		161		173
Accrued expenses	166		140		145
Temporary LIFO liquidation	179				89
Customer deposit and credit balances	115		143		130
Accrued regulatory infrastructure program costs	83		121		149
Accrued environmental remediation liabilities	63		57		39
Derivative instruments	20		33		93
Other current liabilities	135		135		153
Total current liabilities	3,060		3,338		2,348
Long-term liabilities and other deferred credits
Long-term debt	3,324		3,327		3,558
Accumulated deferred income taxes	1,568		1,588		1,447
Regulatory liabilities	1,498		1,477		1,431
Accrued environmental remediation liabilities	362		387		289
Accrued retiree welfare benefits	266		268		318
Accrued pension obligations	243		240		228
Derivative instruments	4		6		10
Other long-term liabilities and other deferred credits	74		75		184
Total long-term liabilities and other deferred credits	7,339		7,368		7,465
Total liabilities and other deferred credits	10,399		10,706		9,813
Equity
Common stock, $5 par value; 750,000,000 shares authorized: outstanding: 118,123,770 shares at March 31, 2013, 117,855,075 shares at December 31, 2012 and 117,282,844 shares at March 31, 2012	592		590		587
Additional paid in capital	2,019		2,014		1,994
Retained earnings	1,134		1,035		1,055
Accumulated other comprehensive loss	(211)	[4]	(218)	[4]	(218)
Treasury shares, at cost: 216,523 shares at March 31, 2013 and December 31, 2012 and 213,341 shares at March 31, 2012	(8)		(8)		(8)
Total common shareholders’ equity	3,526		3,413		3,410
Noncontrolling interest	15		22		16
Total equity	3,541		3,435		3,426
Total liabilities and equity	$ 13,940		$ 14,141		$ 13,239

[1] Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.

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

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

[4] All amounts are net of income taxes. Amounts in parentheses indicate debits to Accumulated Other Comprehensive Loss.

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Note 4 - Derivative Instruments (Detail) - Derivative Instruments on the Consolidated Statements of Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Not designated as hedges
Total (losses) gains on derivative instruments	$ (27)		$ 2
Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member]
Designated as cash flow hedges
Natural gas contracts - loss reclassified from OCI into cost of goods sold for settlement of hedged item			(1)
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]
Designated as cash flow hedges
Interest rate swaps - ineffectiveness recorded as an offset to interest expense	(3)		2
Not Designated as Hedging Instrument [Member] | Natural Gas Contracts [Member]
Not designated as hedges
Natural gas contracts - net fair value adjustments recorded in operating revenues (1)	(24)	[1]	4	[1]
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		[2]	(2)	[2]
Natural gas contracts - net value adjustments recorded in operation and maintenance expense			$ (1)

[1] Associated with the fair value of existing derivative instruments at March 31, 2013 and 2012

[2] Excludes losses recorded in cost of goods sold associated with weather derivatives of $2 million for the three months ended March 31, 2013 and gains of $14 million for the three months ended March 31, 2012

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Condensed Consolidated Statementa of Other Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Net income	$ 164		$ 139
Retirement benefit plans
Reclassification of actuarial losses to net benefit cost (net of income tax of $2 and $1)	4		1
Reclassification of prior service credits to net benefit cost	(1)
Retirement benefit plans	3		1
Cash flow hedges, net of tax
Net derivative instrument gains (losses) arising during the period (net of income tax of $1 and $1)	2	[1]	(2)
Reclassification of realized derivative instrument losses to net income (net of income tax of $1)	2	[1]
Cash flow hedges, net	4	[1]	(2)
Other comprehensive income (loss), net of tax	7	[1]	(1)
Comprehensive income	171		138
Less comprehensive income attributable to noncontrolling interest	10		9
Comprehensive income attributable to AGL Resources Inc.	$ 161		$ 129

[1] All amounts are net of income taxes. Amounts in parentheses indicate debits to Accumulated Other Comprehensive Loss.

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Note 10 - Segment Information (Detail) - Reconciliation of EBIT to Operating Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating income	$ 299	$ 262
Other income	5	4
EBIT	304	266
Interest expense	46	47
Earnings before income taxes	258	219
Income taxes	94	80
Net income	$ 164	$ 139

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Note 2 - Significant Accounting Policies and Methods of Application (Detail) - Potentially Dilutive Common Share Calculation (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Net income attributable to AGL Resources Inc. (in Dollars)	$ 154		$ 130
Basic weighted average number of shares outstanding (1)	117.4	[1]	116.7	[1]
Effect of dilutive securities	0.3		0.3
Diluted weighted average number of shares outstanding	117.7		117.0
Basic (in Dollars per share)	$ 1.31		$ 1.12
Diluted (in Dollars per share)	$ 1.31		$ 1.11

[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, 2013

In millions	2013		2012
Retail operations	$	-	$	3
Wholesale services		-		18
Midstream operations		-		1

Schedule of Regulatory Assets [Table Text Block]

In millions	March 31, 2013		December 31, 2012		March 31, 2012
Regulatory assets
Recoverable regulatory infrastructure program costs	$	47	$	47	$	48
Recoverable environmental remediation costs		28		38		7
Recoverable pension and retiree welfare benefit costs		19		19		29
Other regulatory assets		25		41		53
Total regulatory assets - current		119		145		137
Recoverable environmental remediation costs		415		438		349
Recoverable pension and retiree welfare benefit costs		192		196		256
Recoverable regulatory infrastructure program costs		135		167		291
Long-term debt fair value adjustment		88		90		97
Other regulatory assets		48		53		64
Total regulatory assets - long-term		878		944		1,057
Total regulatory assets	$	997	$	1,089	$	1,194
Regulatory liabilities
Accrued natural gas costs	$	133	$	93	$	97
Bad debt rider		39		37		32
Accumulated removal costs		17		16		14
Other regulatory liabilities		49		15		30
Total regulatory liabilities - current		238		161		173
Accumulated removal costs		1,413		1,393		1,339
Unamortized investment tax credit		28		29		32
Regulatory income tax liability		26		27		26
Bad debt rider		20		17		20
Other regulatory liabilities		11		11		14
Total regulatory liabilities - long-term		1,498		1,477		1,431
Total regulatory liabilities	$	1,736	$	1,638	$	1,604

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

	For the three months ended March 31,
In millions	2013			2012
Equity investment income	$	3		$	3
Allowance for funds used during construction (AFUDC) - equity		3			1
Other, net		(1	)		-
Total other income	$	5		$	4

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

	Three months ended March 31,
In millions (except per share amounts)	2013		2012
Net income attributable to AGL Resources Inc.	$	154	$	130
Denominator:
Basic weighted average number of shares outstanding (1)		117.4		116.7
Effect of dilutive securities		0.3		0.3
Diluted weighted average number of shares outstanding		117.7		117.0
Earnings per share:
Basic	$	1.31	$	1.12
Diluted	$	1.31	$	1.11

Schedule of Purchase Price Allocation [Table Text Block]

In millions
Current assets	$	5
PP&E		11
Goodwill		46
Intangible assets		64
Noncurrent liabilities		(4	)
Total	$	122

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Note 2 - Significant Accounting Policies and Methods of Application (Detail) - Purchase Price Allocation (NiSource Inc. [Member], USD $) In Millions, unless otherwise specified	Jan. 31, 2013
NiSource Inc. [Member]
Current assets	$ 5
PP&E	11
Goodwill	46
Intangible assets	64
Noncurrent liabilities	(4)
Total	$ 122

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Note 4 - Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2013

In millions	2013		2012
Nicor Gas	$	1	$	1
Elizabethtown Gas	$	3	$	9

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

In Bcf (1)	March 31, 2013 (2)			December 31, 2012			March 31, 2012
Hedge designation
Cash flow hedges		6			6			7
Not designated as hedges		304			96			116
Total hedges		310			102			123
Hedge position
Short position		(1,902	)		(1,955	)		(1,942	)
Long position		2,212			2,057			2,065
Net long position		310			102			123

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

	Unaudited Condensed Consolidated Statements of Financial	March 31,  2013						December 31, 2012						March 31,  2012
In millions	Position Location (1) (2)	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges and fair value hedges
Natural gas contracts	Current	$	3		$	(1	)	$	1		$	(2	)	$	5		$	(11	)
Natural gas contracts	Long-term		-			-			3			-			-			-
Interest rate swap agreements	Current		5			-			-			-			-			-
Interest rate swap agreements	Long-term		-			-			-			-			9			(11	)
Total			8			(1	)		4			(2	)		14			(22	)
Not designated as cash flow hedges
Natural gas contracts	Current		332			(327	)		394			(355	)		683			(718	)
Natural gas contracts	Long-term		46			(48	)		45			(50	)		82			(85	)
Total			378			(375	)		439			(405	)		765			(803	)
Gross amount of recognized assets and liabilities			386			(376	)		443			(407	)		779			(825	)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position			(275	)		352			(299	)		368			(513	)		722
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position		$	111		$	(24	)	$	144		$	(39	)	$	266		$	(103	)

Schedule of Derivative Instruments [Table Text Block]

In millions	2013			2012
Designated as cash flow hedges
Natural gas contracts - loss reclassified from OCI into cost of goods sold for settlement of hedged item	$	-		$	(1	)
Interest rate swaps - ineffectiveness recorded as an offset to interest expense		(3	)		2
Not designated as hedges
Natural gas contracts - net fair value adjustments recorded in operating revenues (1)		(24	)		4
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		-			(2	)
Natural gas contracts - net value adjustments recorded in operation and maintenance expense		-			(1	)
Total (losses) gains on derivative instruments	$	(27	)	$	2

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Condensed Consolidated Statementa of Other Comprehensive Income (Unaudited) (Parentheticals) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Tax on reclassification of (gains) losses to net benefit cost	$ 2	$ 1
Derivative instrument unrealized losses arising during the period, tax	1	1
Tax on reclassification of realized derivative gains (losses) to net income	$ 1

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Condensed Consolidated Statement of Financial Position (Unaudited) (Parentheticals) (USD $)	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012
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	118,123,770	117,855,075	117,282,844
Treasury shares, number of shares	216,523	216,523	213,341

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Note 7 - Equity

3 Months Ended

Mar. 31, 2013

Other Comprehensive Income, Noncontrolling Interest [Text Block]

Note 7 - Equity

Our other comprehensive income 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
Balance as of December 31, 2012	$	(6	)	$	(212	)	$	(218	)
Other comprehensive income, before reclassifications		2			-			2
Amounts reclassified from accumulated other comprehensive income		2			3			5
Net current-period other comprehensive income		4			3			7
Balance as of March 31, 2013	$	(2	)	$	(209	)	$	(211	)

(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 for the period ended March 31, 2013, and the ultimate impact on net income.

In millions	Amount reclassified from Accumulated Other Comprehensive Loss (1)			Affected line item in the Income Statement
Cash flow hedges
Interest rate contracts	$	(3	)	Interest expense, net
Income tax benefit		1
Total cash flow hedges		(2	)
Retirement benefit plan amortization of
Actuarial losses		(6	)	See (2), below
Prior service credits		1		See (2), below
Total before income tax		(5	)
Income tax benefit		2
Total retirement benefit plans		(3	)
Total reclassification for the period	$	(5	)

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

(2) These accumulated OCI components are included in the computation of net periodic benefit cost. See Note 5, Employee Benefit Plans, for additional details about net periodic benefit cost.

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Document And Entity Information	3 Months Ended
	Mar. 31, 2013	Apr. 24, 2013
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		118,180,688
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, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1

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Note 8 - Non-Wholly Owned Entities

3 Months Ended

Mar. 31, 2013

Noncontrolling Interest Disclosure [Text Block]

Note 8 - Non-Wholly Owned Entities

Variable Interest Entities

On a quarterly basis, we evaluate all of our ownership interests to determine if they represent a VIE as defined by the authoritative accounting guidance on consolidation, and if so, which party is the primary beneficiary. We have determined that 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 2012 Form 10-K. Earnings from SouthStar in 2013 and 2012 were allocated entirely in accordance with the ownership interests.

SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to retail customers primarily in Georgia, under various other trade names to retail customers in Ohio, Florida and New York and to commercial and industrial customers in the southeastern United States.

During the three months ended March 31, 2013, there have been no significant changes to the primary risks associated with SouthStar as discussed in our risk factors included in Item 1A of our 2012 Form 10-K.

SouthStar’s financial results are seasonal in nature, with business depending to a great extent on the first and fourth quarters of each year. SouthStar’s current assets consist primarily of natural gas inventory, derivative instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in AGL Capital’s commercial paper program. See Note 2 for additional discussions of SouthStar’s inventories. SouthStar’s restricted assets consist of customer deposits and were immaterial as of March 31, 2013 and 2012. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative instruments and payables to us from its participation in AGL Capital’s commercial paper program.

SouthStar’s other contractual commitments and obligations, including operating leases and agreements with third party providers, do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. As a result, our maximum exposure to a loss at SouthStar is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. With the exception of our corporate guarantees, we have not entered into any arrangements that could require us to provide financial support to SouthStar.

Price and volume fluctuations of SouthStar’s natural gas inventories can cause significant variations in our working capital and cash flow from operations. Changes in our operating cash flows are also attributable to SouthStar’s working capital changes resulting from the impact of weather, the timing of customer collections, payments for natural gas purchases and cash collateral amounts that SouthStar maintains to facilitate its derivative instruments.

Cash flows used in our investing activities include capital expenditures for SouthStar of $1 million for the three months ended March 31, 2013 and 2012, and $1 million for the year ended December 31, 2012. 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 the three months ended March 31, 2013, SouthStar distributed $17 million to Piedmont and $14 million during the same period last year. The increase of $3 million was primarily the result of increased earnings year-over-year.

The following table provides additional information on SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our unaudited Condensed Consolidated Statements of Financial Position. The SouthStar balances do not include intercompany eliminations or the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.

	March 31, 2013						December 31, 2012						March 31, 2012
In millions	Consolidated		SouthStar				Consolidated		SouthStar				Consolidated		SouthStar
Current assets	$	2,361	$	143	6	%	$	2,668	$	201	8	%	$	2,022	$	149	7	%
Long-term assets and other deferred debits		11,579		10	-			11,473		10	-			11,217		9	-
Total assets	$	13,940	$	153	1	%	$	14,141	$	211	1	%	$	13,239	$	158	1	%
Current liabilities	$	3,060	$	51	2	%	$	3,338	$	62	2	%	$	2,348	$	52	2	%
Long-term liabilities and other deferred credits		7,339		-	-			7,368		-	-			7,465		-	-
Total Liabilities		10,399		51	1			10,706		62	1			9,813		52	1
Equity		3,541		102	3			3,435		149	4			3,426		106	3
Total liabilities and equity	$	13,940	$	153	1	%	$	14,141	$	211	1	%	$	13,239	$	158	1	%

The following table provides additional information on SouthStar’s revenues and expenses for the three months ended March 31, 2013 and 2012, which are consolidated within our unaudited Condensed Consolidated Statements of Income.

In millions	2013		2012
Operating revenues	$	250	$	215
Operating expenses
Cost of goods sold		164		133
Operation and maintenance		18		19
Depreciation and amortization		1		-
Taxes other than income taxes		-		1
Total operating expenses		183		153
Operating income	$	67	$	62

Equity Method Investments

Income from our equity method investments is classified as other income in our unaudited Condensed Consolidated Statements of Income. For the three months ended March 31, 2013, this included investment income from Triton of $2 million and $1 million of investment income from our other equity method investments. For the three months ended March 31, 2012, this included $3 million of investment income from Triton and an immaterial amount of investment income from our other equity method investments. For more information about our equity method investments, see Note 10 to our Consolidated Financial Statements under Item 8 included in our 2012 Form 10-K.

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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, 2013		Mar. 31, 2012
Operating revenues (includes revenue taxes of $50 in 2013 and $41 in 2012)	$ 1,709		$ 1,404
Operating expenses
Cost of goods sold	973		719
Operation and maintenance	259		245
Depreciation and amortization	107		104
Taxes other than income taxes	71		64
Nicor merger expenses			10	[1]
Total operating expenses	1,410		1,142
Operating income	299		262
Other income	5		4
Interest expense, net	(46)		(47)
Earnings before income taxes	258		219
Income tax expense	94		80
Net income	164		139
Less net income attributable to the noncontrolling interest	10		9
Net income attributable to AGL Resources Inc.	$ 154		$ 130
Per common share data
Basic earnings per common share attributable to AGL Resources Inc. common shareholders (in Dollars per share)	$ 1.31		$ 1.12
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders (in Dollars per share)	$ 1.31		$ 1.11
Cash dividends declared per common share (in Dollars per share)	$ 0.47		$ 0.36
Weighted average number of common shares outstanding
Basic (in Shares)	117.4	[2]	116.7	[2]
Diluted (in Shares)	117.7		117.0

[1] Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.

[2] Daily weighted average shares outstanding.

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Note 2 - Significant Accounting Policies and Methods of Application

3 Months Ended

Mar. 31, 2013

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 2012 Form 10-K. There were no significant changes to our accounting policies during the three months ended March 31, 2013.

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 regulatory infrastructure program accruals, environmental liability accruals, 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.

Inventories

Except for Nicor Gas, our gas inventories and the inventories we hold for Marketers are accounted for using the WACOG. In Georgia’s competitive environment, Marketers, including SouthStar, 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. Atlanta Gas Light assigns, on a monthly basis, 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 9 for information regarding a regulatory filing by Atlanta Gas Light related to 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. This inventory decrement is included 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, 2013 is expected to be restored prior to year-end. The inventory decrement as of March 31, 2012 was restored prior to December 31, 2012.

Our retail operations, wholesale services and midstream operations segments 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 price. For the three months ended March 31, 2013 and 2012, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our inventories to market value.

In millions	2013		2012
Retail operations	$	-	$	3
Wholesale services		-		18
Midstream operations		-		1

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, which enable our wholesale services segment to net receivables and payables by counterparty. 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 some 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, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of March 31, 2013, December 31, 2012 and March 31, 2012, 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.

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measures. The financial assets and liabilities measured and carried at fair value include cash equivalents, receivables, and derivative assets and liabilities. The carrying values of cash and cash equivalents, short and long-term investments, derivative assets and liabilities, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate fair value. The 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 2012 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 derivative instruments that we use to manage exposures arising from changing natural gas prices 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 3 and Note 4 for additional derivative disclosures.

Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. Such derivative instruments are carried at fair value each reporting period in our unaudited Condensed Consolidated Statements of Financial Position. In accordance with regulatory requirements, any realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. Thus, hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized.

Nicor Gas also enters into derivative instruments to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for company use. These derivative instruments are carried at fair value. To the extent hedge accounting is not elected, changes in such fair values are recorded in the current period as operation and maintenance expenses.

Retail OperationsWe have designated a portion of our derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges under the authoritative guidance related to derivatives and hedging. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period that the underlying hedged item is recognized in earnings.

We currently have minimal hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not completely offset the losses or gains on the hedged item. This cash flow hedge ineffectiveness is recorded in cost of goods sold in our unaudited Condensed Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges for accounting purposes, and we record changes in the fair value of such instruments within cost of goods sold in our unaudited Condensed Consolidated Statements of Income in the period of change.

We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange –traded options are carried at fair value in our unaudited Condensed Consolidated Statements of Financial Position, with changes reflected in operating revenues in our unaudited Condensed Consolidated Statements of Income. Non exchange-traded options are accounted for using the intrinsic value method and do not qualify for hedge accounting designation. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our unaudited Condensed Consolidated Statements of Income.

Wholesale ServicesWe purchase natural gas for storage when the current market price we pay to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures and OTC contracts to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is sold. We also enter into transactions to secure transportation capacity between two delivery points in order to serve our customers and various markets. We use NYMEX futures and OTC contracts to capture the price differential or spread between the locations served by the capacity in order to substantially lock in the operating margin we will ultimately realize when we physically flow natural gas between the two delivery points. These contracts generally meet the definition of derivatives and are carried at fair value in our unaudited Condensed Consolidated Statements of Financial Position, with changes in fair value recorded in operating revenues in our unaudited Condensed Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes.

The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage and transportation portfolio. We incur monthly demand charges for the contracted storage and transportation capacity, and payments associated with asset management agreements, and recognize these demand charges and payments in our unaudited Condensed Consolidated Statements of Income in the period they are incurred. This difference in accounting can result in volatility in our reported earnings, even though the economic margin is essentially unchanged from the date the transactions were consummated.

Regulatory Assets and Liabilities

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. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries. In the event that 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.

Our regulatory assets and liabilities are summarized in the following table.

In millions	March 31, 2013		December 31, 2012		March 31, 2012
Regulatory assets
Recoverable regulatory infrastructure program costs	$	47	$	47	$	48
Recoverable environmental remediation costs		28		38		7
Recoverable pension and retiree welfare benefit costs		19		19		29
Other regulatory assets		25		41		53
Total regulatory assets - current		119		145		137
Recoverable environmental remediation costs		415		438		349
Recoverable pension and retiree welfare benefit costs		192		196		256
Recoverable regulatory infrastructure program costs		135		167		291
Long-term debt fair value adjustment		88		90		97
Other regulatory assets		48		53		64
Total regulatory assets - long-term		878		944		1,057
Total regulatory assets	$	997	$	1,089	$	1,194
Regulatory liabilities
Accrued natural gas costs	$	133	$	93	$	97
Bad debt rider		39		37		32
Accumulated removal costs		17		16		14
Other regulatory liabilities		49		15		30
Total regulatory liabilities - current		238		161		173
Accumulated removal costs		1,413		1,393		1,339
Unamortized investment tax credit		28		29		32
Regulatory income tax liability		26		27		26
Bad debt rider		20		17		20
Other regulatory liabilities		11		11		14
Total regulatory liabilities - long-term		1,498		1,477		1,431
Total regulatory liabilities	$	1,736	$	1,638	$	1,604

There have been no significant new types of regulatory assets or liabilities from those discussed in Note 2 to our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.

Other income

Our other income is detailed in the following table for the periods presented. For more information on our equity investment income, see Note 8.

	For the three months ended March 31,
In millions	2013			2012
Equity investment income	$	3		$	3
Allowance for funds used during construction (AFUDC) - equity		3			1
Other, net		(1	)		-
Total other income	$	5		$	4

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our 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 could occur 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 criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods.

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)	2013		2012
Net income attributable to AGL Resources Inc.	$	154	$	130
Denominator:
Basic weighted average number of shares outstanding (1)		117.4		116.7
Effect of dilutive securities		0.3		0.3
Diluted weighted average number of shares outstanding		117.7		117.0
Earnings per share:
Basic	$	1.31	$	1.12
Diluted	$	1.31	$	1.11

(1) Daily weighted average shares outstanding.

Acquisition

On January 31, 2013, our retail operations segment acquired approximately 500,000 service plans and certain other assets from NiSource Inc. for $120 million, plus $2 million of working capital. These service plans provide home warranty protection solutions and energy efficiency leasing solutions for residential and small business utility customers and complements the retail services business acquired in the Nicor merger. The preliminary allocation of the purchase price is as follows:

In millions
Current assets	$	5
PP&E		11
Goodwill		46
Intangible assets		64
Noncurrent liabilities		(4	)
Total	$	122

Intangible assets related to this acquisition are primarily customer relationships of $47 million and trade names of $17 million. The amortization periods are estimated to be 14 years for customer relationships and 10 years for trade names.

Accounting Developments

On January 1, 2013, we adopted ASU 2013-01, Disclosures about Offsetting Assets and Liabilities, which requires disclosure about offsetting and related arrangements in order to help financial statement users to better understand the effect of those arrangements on our financial position. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 4 for additional disclosures about our offsetting of derivative assets and liabilities.

On January 1, 2013, we adopted ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 7 for additional disclosures relating to accumulated other comprehensive income.

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Note 1 - Organization and Basis of Presentation

3 Months Ended

Mar. 31, 2013

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, 2012 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 2012 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 as of or for 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 and 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 8 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.

Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation. The reclassifications and revisions had no material impact on prior periods.

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Note 3 - Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2013

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

In millions	March 31, 2013		December 31, 2012		March 31, 2012
Long-term debt amortized cost	$	3,550	$	3,553	$	3,575
Long-term debt fair value (1)	$	4,006	$	4,057	$	3,922

Natural Gas Derivatives [Member]

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

	Recurring fair values - Derivative instruments
	March 31, 2013					December 31, 2012					March 31, 2012
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	14	$	(38	)	$	8	$	(45	)	$	7	$	(187	)
Significant other observable inputs (Level 2)		49		(23	)		96		(30	)		203		(68	)
Netting of cash collateral		40		37			33		36			47		162
Total carrying value (2) (3)	$	103	$	(24	)	$	137	$	(39	)	$	257	$	(93	)
Interest rate derivatives
Significant other observable inputs (Level 2)	$	6	$	-		$	3	$	-		$	9	$	(10	)

Money Market Funds [Member]

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

In millions	At March 31, 2013		At December 31, 2012		At March 31, 2012
Money market funds (1)	$	48	$	66	$	68

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Note 9 - Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Text Block]

Note 9 - Commitments, Guarantees and Contingencies

There were no significant changes to our contractual obligations described in Note 11 of our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.

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.

Contingencies and Guarantees

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. 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 and indemnities is remote. No liability has been recorded for such guarantees and indemnifications.

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 market. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. The resolution of this imbalance will be decided by the Georgia Commission and we are unable to predict the ultimate outcome.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations 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 following table provides more information on the costs related to remediation of our former operating sites as of March 31, 2013.

In millions	Probabilistic model cost estimates (1)			Engineering estimates (1)		Amount recorded		Expected costs over next twelve months
Illinois	$193	-	$439	$	50	$	239	$	35
New Jersey	116	-	203		6		121		14
Georgia and Florida	49	-	107		12		54		6
North Carolina		n/a			11		11		8
Total	$358	-	$749	$	79	$	425	$	63

(1) There were events during first quarter 2013 that resulted in changes to the estimates disclosed in, and the amounts recorded in, our December 31, 2012 Form 10-K. These changes are reflected in the table above.

Our environmental remediation cost liabilities are estimates of future remediation costs for our former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, which is generally the case when remediation has not commenced or during the early years of a remediation effort. For those elements of the program where we cannot perform engineering estimates, there remains considerable variability in future cost estimates. Accordingly, we have established a probabilistic model to determine a range of potential expenditures to remediate and monitor our former operating sites. We cannot, at this time, identify any single number within this range as a better estimate of likely future costs, and we generally have recorded the low end of the range for our probabilistic cost estimates.

As we conduct the actual remediation and enter into cleanup contracts, 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. With the exception of our North Carolina site, these costs are recoverable from our customers as they are paid and, accordingly, we have recorded a regulatory asset associated with the recorded liabilities. For more information on our environmental remediation costs, see Note 2 herein and Note 11 of our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.

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 the company to take charges against, or will result in reductions in, future earnings. It is the opinion of management that the resolution of these contingencies, either individually or in aggregate, could be material to earnings in a particular period but 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 2012 Form 10-K.

PBR Proceeding Nicor Gas’ PBR plan for natural gas costs went into effect in 2000 and was terminated effective January 1, 2003. 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. The PBR plan is currently under review by the Illinois Commission as there are allegations that Nicor Gas acted improperly in connection with the plan. On June 27, 2002, the Citizens Utility Board (CUB) filed a motion to reopen the record in the Illinois Commission’s proceedings to review the PBR plan (the “Illinois Commission Proceedings”). As a result of the motion to reopen, Nicor Gas entered into a stipulation with the staff of the Illinois Commission and CUB providing for additional discovery. The Illinois Attorney General’s Office (IAGO) has also intervened in this matter. In addition, the IAGO issued Civil Investigation Demands (CIDs) to CUB and the Illinois Commission staff. The CIDs ordered that CUB and the Illinois Commission staff produce all documents relating to any claims that Nicor Gas may have presented, or caused to be presented, regarding false information related to its PBR plan. We have committed to cooperate fully in the reviews of the PBR plan.

The Nicor Board of Directors directed management to, among other things, make appropriate adjustments to account for, and fully address, the adverse consequences to ratepayers, and conduct a detailed study of the adequacy of internal accounting and regulatory controls. The adjustments were made in prior years’ financial statements resulting in a $25 million liability. Included in this $25 million liability is a $4 million loss contingency. A $2 million adjustment to the previously recorded liability, which is discussed below, was made in 2004 increasing the recorded liability to $27 million. By the end of 2003, Nicor Gas completed steps to correct the weaknesses and deficiencies identified in the detailed study of the adequacy of internal controls.

On February 5, 2003, CUB filed a motion for $27 million in sanctions against Nicor Gas in the Illinois Commission Proceedings. In that motion, CUB alleged that Nicor Gas’ responses to certain CUB data requests were false. Also on February 5, 2003, CUB stated in a press release that, in addition to $27 million in sanctions, it would seek additional refunds to consumers. On March 5, 2003, the Illinois Commission staff filed a response brief in support of CUB’s motion for sanctions. On May 1, 2003, the Administrative Law Judges assigned to the proceeding issued a ruling denying CUB’s motion for sanctions. CUB has filed an appeal of the motion for sanctions with the Illinois Commission, and the Illinois Commission has indicated that it will not rule on the appeal until the final disposition of the Illinois Commission Proceedings. It is not possible to determine how the Illinois Commission will resolve the claims of CUB or other parties to the Illinois Commission Proceedings.

In 2004, Nicor Gas became aware of additional information relating to the activities of individuals affecting the PBR plan for the period from 1999 through 2002, including information consisting of third party documents and recordings of telephone conversations from Entergy-Koch Trading, LP (EKT), a natural gas, storage and transportation trader and consultant with whom Nicor Gas did business under the PBR plan. Review of additional information completed in 2004 resulted in the $2 million adjustment to the previously recorded liability referenced above.

The evidentiary hearings on this matter were stayed in 2004 in order to permit the parties to undertake additional third party discovery from EKT. In December 2006, the additional third party discovery from EKT was obtained and the Administrative Law Judge issued a scheduling order that provided for Nicor Gas to submit direct testimony by April 13, 2007. Nicor Gas submitted direct testimony in April 2007, rebuttal testimony in April 2011 and surrebuttal testimony in December 2011. In surrebuttal testimony, we sought $6 million, which included interest due to us of $2 million, as of December 31, 2011. The staff of the Illinois Commission, IAGO and CUB submitted direct testimony to the Illinois Commission in April 2009 and rebuttal testimony in October 2011. In rebuttal testimony, the staff of the Illinois Commission, IAGO and CUB requested refunds of $85 million, $255 million and $305 million, respectively. 

In February 2012, we committed to a stipulated resolution of issues with the staff of the Illinois Commission, which would include crediting Nicor Gas customers $64 million. This resulted in a $37 million adjustment to the previously recorded $27 million liability referenced above and is reflected in the purchase price allocation. The stipulated resolution does not constitute an admission of fault, and it is not final and is subject to review and approval by the Illinois Commission. The CUB and IAGO are not parties to the stipulated resolution and continue to pursue their claims in this proceeding. Evidentiary hearings before the Administrative Law Judges were held during the first quarter of 2012 and post-trial legal briefs from the parties were submitted during the second quarter of 2012. Following the submission of legal briefs, 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 by $8 million for a total of $72 million as a result of these developments and its effect on the estimated liability. We do not agree with the additional $8 million proposed by the Administrative Law Judges and will consider all legal recourse available should the Illinois Commission authorize a refund greater than the $64 million stipulation amount between Nicor Gas and the staff of the Illinois Commission.

Nicor Services Warranty Product Actions In the first quarter of 2011, three putative class actions were filed against Nicor Services and Nicor Gas, and in one case against Nicor. In September 2011, the three cases were consolidated into a single class action pending in state court in Cook County, Illinois. The plaintiffs purport to represent a class of customers of Nicor Gas who purchased the Gas Line Comfort Guard product from Nicor Services. In the consolidated action, the plaintiffs variously allege that the marketing, sale and billing of the Nicor Services Gas Line Comfort Guard violate the Illinois Consumer Fraud and Deceptive Business Practices Act, constitute common law fraud and result in unjust enrichment of Nicor Services and Nicor Gas. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees and injunctive relief. While we are unable to predict the outcome of these matters or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with this contingency, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition.

Other We are also involved in litigation relating to estimated billing practices and an investigation by the United States Environmental Protection Agency regarding the applicable regulatory requirements for polychlorinated biphenyl in the Nicor Gas distribution system. While we are unable to predict the outcome of these matters or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with these contingencies. The final disposition of these matters is not expected to have a material adverse impact on our liquidity or financial condition. For additional litigation information on these matters, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.

In addition to the matters set forth above, we 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.

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Note 5 - Employee Benefit Plans

3 Months Ended

Mar. 31, 2013

Pension and Other Postretirement Benefits Disclosure [Text Block]

Note 5 - Employee Benefit Plans

Pension Benefits

On December 31, 2012, the AGL Resources Inc. Retirement Plan (AGL Plan), the Nicor Companies Pension and Retirement Plan (Nicor Plan) and the Employees’ Retirement Plan of NUI Corporation (NUI Plan) were merged with, and into, the AGL Plan. The eligibility and benefit terms for participants under the Nicor Plan and the NUI Plan were not changed as a result of the plan merger. The AGL Plan is described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.

Following are the components of our pension benefit costs for the periods indicated.

	Three months ended March 31,
In millions	2013			2012
Service cost	$	8		$	7
Interest cost		10			11
Expected return on plan assets		(16	)		(16	)
Net amortization of prior service cost		-			(1	)
Recognized actuarial loss		8			9
Net periodic pension benefit cost	$	10		$	10

Retiree Welfare Benefits

On December 31, 2012, the Nicor Gas Welfare Benefit Plan (Nicor Welfare Plan) was terminated and as of January 1, 2013, all participants under that plan became eligible to participate in the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan). This change in plan participation eligibility did not affect the benefit terms under the predecessor plans. The Nicor Welfare Plan benefits are now being offered to such participants under the AGL Welfare Plan. The benefits of the AGL Welfare Plan are described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.

Following are the components of our retiree welfare benefit costs for the periods indicated.

	Three months ended March 31,
In millions	2013			2012
Service cost	$	1		$	1
Interest cost		3			4
Expected return on plan assets		(1	)		(1	)
Net amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		2			3
Net periodic welfare benefit cost	$	4		$	6

Capitalized Costs

A portion of the net pension benefit and net periodic welfare benefit costs have been capitalized as a cost of constructing natural gas distribution facilities and the remainder is included in operation and maintenance expenses, net of amounts charged to affiliates.

Contributions

Our employees generally do not contribute to these pension and retiree welfare plans. We fund the qualified pension plan by contributing at least the minimum amounts required by applicable regulations and as recommended by our actuary. However, we may contribute in excess of the minimum required amounts.

As a result of merging the pension plans, there were no contributions required during the three months ended March 31, 2013. We contributed a combined $17 million to the AGL Plan and the NUI Plan during the same period last year. For more information on our pension plans, see Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.

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Note 10 - Segment Information (Detail) - Segment Reporting (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012		Mar. 31, 2012
Identifiable and Total Assets	$ 13,940	[1]	$ 14,141	[2]	$ 13,239	[3]
Goodwill	1,883		1,837		1,813
Distribution Operations [Member]
Identifiable and Total Assets	11,258	[1]	11,320	[2]	10,785	[3]
Goodwill	1,640		1,640		1,586
Retail Operations [Member]
Identifiable and Total Assets	668	[1]	511	[2]	471	[3]
Goodwill	168		122		124
Wholesale Services [Member]
Identifiable and Total Assets	1,005	[1]	1,218	[2]	917	[3]
Goodwill					2
Midstream Operations [Member]
Identifiable and Total Assets	714	[1]	720	[2]	665	[3]
Goodwill	14		14		16
Cargo Shipping [Member]
Identifiable and Total Assets	459	[1]	464	[2]	477	[3]
Goodwill	61		61		77
All Other Segments [Member]
Identifiable and Total Assets	(164)	[1],[4]	(92)	[2],[5]	(76)	[3],[4]
Goodwill		[4]		[5]	$ 8	[4]

[1] Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.

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

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

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

[5] Our other segment's assets consist primarily of cash and cash equivalents and PP&E and reflect the effect of intercompany eliminations.

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Note 3 - Fair Value Measurements

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Text Block]

Note 3 - 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 Consolidated Statements of Financial Position as of the periods presented. See Note 4 for additional derivative instrument information.

	Recurring fair values - Derivative instruments
	March 31, 2013					December 31, 2012					March 31, 2012
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)	$	14	$	(38	)	$	8	$	(45	)	$	7	$	(187	)
Significant other observable inputs (Level 2)		49		(23	)		96		(30	)		203		(68	)
Netting of cash collateral		40		37			33		36			47		162
Total carrying value (2) (3)	$	103	$	(24	)	$	137	$	(39	)	$	257	$	(93	)
Interest rate derivatives
Significant other observable inputs (Level 2)	$	6	$	-		$	3	$	-		$	9	$	(10	)

(1) $2 million of premium at March 31, 2013, $4 million at December 31, 2012 and less than $1 million at March 31, 2012 associated with weather derivatives have been excluded, as they are not material and some are accounted for based on intrinsic value.

(2) There were no material unobservable inputs (Level 3) for any of the periods presented.

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

Money Market Funds

The fair values of our money market funds were recorded within short-term and long-term investments as follows:

In millions	At March 31, 2013		At December 31, 2012		At March 31, 2012
Money market funds (1)	$	48	$	66	$	68

(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 were recorded at their acquisition date fair value. The fair value adjustment is being amortized over the life of the bonds. We estimate the fair value of our debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. The following table presents the amortized cost and fair value of our long-term debt as of the following periods.

In millions	March 31, 2013		December 31, 2012		March 31, 2012
Long-term debt amortized cost	$	3,550	$	3,553	$	3,575
Long-term debt fair value (1)	$	4,006	$	4,057	$	3,922

(1) Fair value determined using Level 2 inputs.

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Note 4 - Derivative Instruments

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Text Block]

Note 4 - 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 3 for additional fair value disclosures.

Certain of our derivative instruments contain credit-risk-related or other contingent features that could increase the payments for collateral we post in the normal course of business when our financial instruments are in net liability positions. As of March 31, 2013, for agreements with such features, derivative instruments with liability fair values totaled $24 million, for which we had posted no collateral to our counterparties. In addition, our energy marketing receivables and payables, which also have credit-risk-related or other contingent features, are discussed in Note 2. Our derivative instrument activities are included within operating cash flows as an adjustment to net income of $18 million and $15 million for the three months ended March 31, 2013 and 2012, respectively. See Note 3 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	Income Statement
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 Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item	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
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	The gain or loss on these derivative instruments is reflected in natural gas costs and is ultimately included in billings to customers

Distribution Operations

The following amounts represent realized losses related to hedging natural gas costs for the three months ended March 31.

In millions	2013		2012
Nicor Gas	$	1	$	1
Elizabethtown Gas	$	3	$	9

Quantitative Disclosures Related to Derivative Instruments

As of the periods 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 net long natural gas contracts outstanding in the following quantities:

In Bcf (1)	March 31, 2013 (2)			December 31, 2012			March 31, 2012
Hedge designation
Cash flow hedges		6			6			7
Not designated as hedges		304			96			116
Total hedges		310			102			123
Hedge position
Short position		(1,902	)		(1,955	)		(1,942	)
Long position		2,212			2,057			2,065
Net long position		310			102			123

(1) Volumes related to Nicor Gas exclude variable-priced contracts, which are accounted for as derivatives, but whose fair values are not directly impacted by changes in commodity prices.

(2) Approximately 98% of these contracts have durations of two years or less and the remaining 2% expire between 2 and 6 years.

Derivative Instruments in our Unaudited Condensed Consolidated Statements of Financial Position

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

	Unaudited Condensed Consolidated Statements of Financial	March 31,  2013						December 31, 2012						March 31,  2012
In millions	Position Location (1) (2)	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges and fair value hedges
Natural gas contracts	Current	$	3		$	(1	)	$	1		$	(2	)	$	5		$	(11	)
Natural gas contracts	Long-term		-			-			3			-			-			-
Interest rate swap agreements	Current		5			-			-			-			-			-
Interest rate swap agreements	Long-term		-			-			-			-			9			(11	)
Total			8			(1	)		4			(2	)		14			(22	)
Not designated as cash flow hedges
Natural gas contracts	Current		332			(327	)		394			(355	)		683			(718	)
Natural gas contracts	Long-term		46			(48	)		45			(50	)		82			(85	)
Total			378			(375	)		439			(405	)		765			(803	)
Gross amount of recognized assets and liabilities			386			(376	)		443			(407	)		779			(825	)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position			(275	)		352			(299	)		368			(513	)		722
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position		$	111		$	(24	)	$	144		$	(39	)	$	266		$	(103	)

(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 $77 million as of March 31, 2013, $69 million as of December 31, 2012 and $209 million as of March 31, 2012. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table.

Derivative Instruments Impacts in our Unaudited Condensed Consolidated Statements of Income

The following table presents the amounts of our derivative instruments in our unaudited Condensed Consolidated Statements of Income for the three months ended March 31, 2013 and 2012.

In millions	2013			2012
Designated as cash flow hedges
Natural gas contracts - loss reclassified from OCI into cost of goods sold for settlement of hedged item	$	-		$	(1	)
Interest rate swaps - ineffectiveness recorded as an offset to interest expense		(3	)		2
Not designated as hedges
Natural gas contracts - net fair value adjustments recorded in operating revenues (1)		(24	)		4
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)		-			(2	)
Natural gas contracts - net value adjustments recorded in operation and maintenance expense		-			(1	)
Total (losses) gains on derivative instruments	$	(27	)	$	2

(1) Associated with the fair value of existing derivative instruments at March 31, 2013 and 2012

(2) Excludes losses recorded in cost of goods sold associated with weather derivatives of $2 million for the three months ended March 31, 2013 and gains of $14 million for the three months ended March 31, 2012

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, 2013 and 2012.

Our expected pre-tax net income (loss) to be reclassified from OCI and recognized in cost of goods sold, operation and maintenance expenses, operating revenues and interest expense in our unaudited Condensed Consolidated Statements of Income over the next 12 months is $2 million. These pre-tax deferred losses are recorded in OCI related to natural gas derivative contracts associated with retail operations and Nicor Gas. The expected losses are based upon the fair values of these financial instruments at March 31, 2013.

There have been no other significant changes to our derivative instruments, as described in Note 2 and Note 4 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.

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Note 6 - Debt and Credit Facilities

3 Months Ended

Mar. 31, 2013

Debt Disclosure [Text Block]

Note 6 - 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 that are included in our unaudited Condensed Consolidated Statements of Financial Position. For additional information on our debt, see Note 8 in our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.

				March 31, 2013							March 31, 2012
Dollars in millions	Year(s) due			Weighted average interest rate (1)			Outstanding		Outstanding at December 31, 2012		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper- AGL Capital (2)		2013			0.5	%	$	868	$	1,063		0.5	%	$	625
Commercial paper- Nicor Gas (2)		2013			0.4			-		314		0.5			105
Total short-term debt					0.5	%	$	868	$	1,377		0.5	%	$	730
Current portion of long-term debt and capital leases
Current portion of long-term debt		2013			4.5	%	$	225	$	225		8.3	%	$	15
Current portion of capital leases		2013			5.0			1		1		4.9			2
Total current portion of long-term debt and capital leases					4.5	%	$	226	$	226		8.0	%	$	17
Long-term debt - excluding current portion
Senior notes	2015	-	2041		5.1	%	$	2,325	$	2,325		5.1	%	$	2,550
First mortgage bonds	2016	-	2038		5.6			500		500		5.6			500
Gas facility revenue bonds	2022	-	2033		0.3			200		200		1.1			200
Medium-term notes	2017	-	2027		7.8			181		181		7.8			181
Total principal long-term debt					4.9	%	$	3,206	$	3,206		4.9	%	$	3,431
Fair value adjustment of long-term debt (3)	2016	-	2038		n/a		$	100	$	103		n/a		$	109
Unamortized debt premium, net		n/a			n/a			18		18		n/a			18
Total non-principal long-term debt					n/a		$	118	$	121		n/a		$	127
Total long-term debt							$	3,324	$	3,327				$	3,558
Total debt							$	4,418	$	4,930				$	4,305

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

(2) As of March 31, 2013, the weighted average interest rate on our AGL Capital commercial paper borrowings was 0.5%.

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

Long-Term Debt

During the first quarter of 2013, we refinanced $200 million of our outstanding tax-exempt gas facility revenue bonds, $180 million of which were previously issued by the New Jersey Economic Development Authority and $20 million of which were issued by Brevard County, Florida. The refinancing involved a combination of the issuance of $60 million of refunding bonds to and the purchase of $140 million of existing bonds by a syndicate of banks. Our relationship with the syndicate of banks regarding the bonds is governed by an agreement that contains representations, warranties, covenants and default consistent with those contained in similar financing documents of ours. All of the bonds remain floating-rate instruments. AGL Resources had no cash receipts or payments in connection with the refinancing. The letters of credit providing credit support for the refinanced bonds along with other related agreements were terminated as a result of the refinancing.

Interest Rate Swaps

In April, 2013, we entered into two ten-year, $50 million fixed-rate forward-starting interest rate swaps to hedge any potential interest rate volatility prior to our anticipated issuance of senior notes during the second quarter 2013. The average interest rate on these swaps was 1.98%. Including existing forward-starting interest rate swap hedges, which were executed last year, we have fixed-rate swaps totaling $300 million in notional value at an average interest rate of 1.85%. We have designated the forward-starting interest rate swaps as cash flow hedges of our anticipated second quarter 2013 debt issuance.

Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month; however, our goal is to maintain these ratios at levels between 50% and 60%. These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash OCI pension adjustments, other post-retirement 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 periods presented, which are within our required and targeted ranges.

	March 31, 2013			December 31, 2012			March 31, 2012
AGL Credit Facility		54	%		58	%		54	%
Nicor Gas Credit Facility		43	%		55	%		47	%

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 2 - Significant Accounting Policies and Methods of Application (Detail) - Other Income (Expense), Net (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Equity investment income	$ 3	$ 3
Allowance for funds used during construction (AFUDC) - equity	3	1
Other, net	(1)
Total other income	$ 5	$ 4

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Note 7 - Equity (Detail) - Other Comprehensive Income (Loss) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Cash flow hedges	$ (6)	[1]
Retirement benefit plans	(212)	[1]
Total	(218)	[1]
Net current-period other comprehensive income	4	[1]	(2)
Net current-period other comprehensive income	3	[1]
Net current-period other comprehensive income	7	[1]	(1)
Other comprehensive income, before reclassifications	2	[1]	(2)
Other comprehensive income, before reclassifications		[1]
Other comprehensive income, before reclassifications	2	[1]
Amounts reclassified from accumulated other comprehensive income	2	[1]
Amounts reclassified from accumulated other comprehensive income	3	[1]
Amounts reclassified from accumulated other comprehensive income	5	[1]
Cash flow hedges	(2)	[1]
Retirement benefit plans	(209)	[1]
Total	$ (211)	[1]	$ (218)

[1] All amounts are net of income taxes. Amounts in parentheses indicate debits to Accumulated Other Comprehensive Loss.

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Accounting Policies, by Policy (Policies)

3 Months Ended

Mar. 31, 2013

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 regulatory infrastructure program accruals, environmental liability accruals, 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.

Inventory, Policy [Policy Text Block]

Inventories

Except for Nicor Gas, our gas inventories and the inventories we hold for Marketers are accounted for using the WACOG. In Georgia’s competitive environment, Marketers, including SouthStar, 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. Atlanta Gas Light assigns, on a monthly basis, 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 9 for information regarding a regulatory filing by Atlanta Gas Light related to 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. This inventory decrement is included 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, 2013 is expected to be restored prior to year-end. The inventory decrement as of March 31, 2012 was restored prior to December 31, 2012.

Our retail operations, wholesale services and midstream operations segments 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 price. For the three months ended March 31, 2013 and 2012, we recorded LOCOM adjustments to cost of goods sold in the following amounts to reduce the value of our inventories to market value.

In millions	2013		2012
Retail operations	$	-	$	3
Wholesale services		-		18
Midstream operations		-		1

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, which enable our wholesale services segment to net receivables and payables by counterparty. 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 some 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, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of March 31, 2013, December 31, 2012 and March 31, 2012, 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.

Fair Value of Financial Instruments, Policy [Policy Text Block]

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measures. The financial assets and liabilities measured and carried at fair value include cash equivalents, receivables, and derivative assets and liabilities. The carrying values of cash and cash equivalents, short and long-term investments, derivative assets and liabilities, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate fair value. The 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 2012 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 derivative instruments that we use to manage exposures arising from changing natural gas prices 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 3 and Note 4 for additional derivative disclosures.

Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. Such derivative instruments are carried at fair value each reporting period in our unaudited Condensed Consolidated Statements of Financial Position. In accordance with regulatory requirements, any realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. Thus, hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized.

Nicor Gas also enters into derivative instruments to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for company use. These derivative instruments are carried at fair value. To the extent hedge accounting is not elected, changes in such fair values are recorded in the current period as operation and maintenance expenses.

Retail OperationsWe have designated a portion of our derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges under the authoritative guidance related to derivatives and hedging. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period that the underlying hedged item is recognized in earnings.

We currently have minimal hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not completely offset the losses or gains on the hedged item. This cash flow hedge ineffectiveness is recorded in cost of goods sold in our unaudited Condensed Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges for accounting purposes, and we record changes in the fair value of such instruments within cost of goods sold in our unaudited Condensed Consolidated Statements of Income in the period of change.

We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange –traded options are carried at fair value in our unaudited Condensed Consolidated Statements of Financial Position, with changes reflected in operating revenues in our unaudited Condensed Consolidated Statements of Income. Non exchange-traded options are accounted for using the intrinsic value method and do not qualify for hedge accounting designation. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our unaudited Condensed Consolidated Statements of Income.

Wholesale ServicesWe purchase natural gas for storage when the current market price we pay to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures and OTC contracts to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is sold. We also enter into transactions to secure transportation capacity between two delivery points in order to serve our customers and various markets. We use NYMEX futures and OTC contracts to capture the price differential or spread between the locations served by the capacity in order to substantially lock in the operating margin we will ultimately realize when we physically flow natural gas between the two delivery points. These contracts generally meet the definition of derivatives and are carried at fair value in our unaudited Condensed Consolidated Statements of Financial Position, with changes in fair value recorded in operating revenues in our unaudited Condensed Consolidated Statements of Income in the period of change. These contracts are not designated as hedges for accounting purposes.

The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage and transportation portfolio. We incur monthly demand charges for the contracted storage and transportation capacity, and payments associated with asset management agreements, and recognize these demand charges and payments in our unaudited Condensed Consolidated Statements of Income in the period they are incurred. This difference in accounting can result in volatility in our reported earnings, even though the economic margin is essentially unchanged from the date the transactions were consummated.

Public Utilities, Policy [Policy Text Block]

Regulatory Assets and Liabilities

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. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries. In the event that 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.

Our regulatory assets and liabilities are summarized in the following table.

In millions	March 31, 2013		December 31, 2012		March 31, 2012
Regulatory assets
Recoverable regulatory infrastructure program costs	$	47	$	47	$	48
Recoverable environmental remediation costs		28		38		7
Recoverable pension and retiree welfare benefit costs		19		19		29
Other regulatory assets		25		41		53
Total regulatory assets - current		119		145		137
Recoverable environmental remediation costs		415		438		349
Recoverable pension and retiree welfare benefit costs		192		196		256
Recoverable regulatory infrastructure program costs		135		167		291
Long-term debt fair value adjustment		88		90		97
Other regulatory assets		48		53		64
Total regulatory assets - long-term		878		944		1,057
Total regulatory assets	$	997	$	1,089	$	1,194
Regulatory liabilities
Accrued natural gas costs	$	133	$	93	$	97
Bad debt rider		39		37		32
Accumulated removal costs		17		16		14
Other regulatory liabilities		49		15		30
Total regulatory liabilities - current		238		161		173
Accumulated removal costs		1,413		1,393		1,339
Unamortized investment tax credit		28		29		32
Regulatory income tax liability		26		27		26
Bad debt rider		20		17		20
Other regulatory liabilities		11		11		14
Total regulatory liabilities - long-term		1,498		1,477		1,431
Total regulatory liabilities	$	1,736	$	1,638	$	1,604

There have been no significant new types of regulatory assets or liabilities from those discussed in Note 2 to our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.

Other Income and Other Expense Disclosure [Text Block]

Other income

Our other income is detailed in the following table for the periods presented. For more information on our equity investment income, see Note 8.

	For the three months ended March 31,
In millions	2013			2012
Equity investment income	$	3		$	3
Allowance for funds used during construction (AFUDC) - equity		3			1
Other, net		(1	)		-
Total other income	$	5		$	4

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 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 could occur 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 criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods.

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)	2013		2012
Net income attributable to AGL Resources Inc.	$	154	$	130
Denominator:
Basic weighted average number of shares outstanding (1)		117.4		116.7
Effect of dilutive securities		0.3		0.3
Diluted weighted average number of shares outstanding		117.7		117.0
Earnings per share:
Basic	$	1.31	$	1.12
Diluted	$	1.31	$	1.11

(1) Daily weighted average shares outstanding.

Business Combinations Policy [Policy Text Block]

Acquisition

On January 31, 2013, our retail operations segment acquired approximately 500,000 service plans and certain other assets from NiSource Inc. for $120 million, plus $2 million of working capital. These service plans provide home warranty protection solutions and energy efficiency leasing solutions for residential and small business utility customers and complements the retail services business acquired in the Nicor merger. The preliminary allocation of the purchase price is as follows:

In millions
Current assets	$	5
PP&E		11
Goodwill		46
Intangible assets		64
Noncurrent liabilities		(4	)
Total	$	122

Intangible assets related to this acquisition are primarily customer relationships of $47 million and trade names of $17 million. The amortization periods are estimated to be 14 years for customer relationships and 10 years for trade names.

New Accounting Pronouncements, Policy [Policy Text Block]

Accounting Developments

On January 1, 2013, we adopted ASU 2013-01, Disclosures about Offsetting Assets and Liabilities, which requires disclosure about offsetting and related arrangements in order to help financial statement users to better understand the effect of those arrangements on our financial position. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 4 for additional disclosures about our offsetting of derivative assets and liabilities.

On January 1, 2013, we adopted ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 7 for additional disclosures relating to accumulated other comprehensive income.

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Note 6 - Debt and Credit Facilities (Tables)

3 Months Ended

Mar. 31, 2013

Schedule of Debt [Table Text Block]

				March 31, 2013							March 31, 2012
Dollars in millions	Year(s) due			Weighted average interest rate (1)			Outstanding		Outstanding at December 31, 2012		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper- AGL Capital (2)		2013			0.5	%	$	868	$	1,063		0.5	%	$	625
Commercial paper- Nicor Gas (2)		2013			0.4			-		314		0.5			105
Total short-term debt					0.5	%	$	868	$	1,377		0.5	%	$	730
Current portion of long-term debt and capital leases
Current portion of long-term debt		2013			4.5	%	$	225	$	225		8.3	%	$	15
Current portion of capital leases		2013			5.0			1		1		4.9			2
Total current portion of long-term debt and capital leases					4.5	%	$	226	$	226		8.0	%	$	17
Long-term debt - excluding current portion
Senior notes	2015	-	2041		5.1	%	$	2,325	$	2,325		5.1	%	$	2,550
First mortgage bonds	2016	-	2038		5.6			500		500		5.6			500
Gas facility revenue bonds	2022	-	2033		0.3			200		200		1.1			200
Medium-term notes	2017	-	2027		7.8			181		181		7.8			181
Total principal long-term debt					4.9	%	$	3,206	$	3,206		4.9	%	$	3,431
Fair value adjustment of long-term debt (3)	2016	-	2038		n/a		$	100	$	103		n/a		$	109
Unamortized debt premium, net		n/a			n/a			18		18		n/a			18
Total non-principal long-term debt					n/a		$	118	$	121		n/a		$	127
Total long-term debt							$	3,324	$	3,327				$	3,558
Total debt							$	4,418	$	4,930				$	4,305

Schedule of Capitalization [Table Text Block]

	March 31, 2013			December 31, 2012			March 31, 2012
AGL Credit Facility		54	%		58	%		54	%
Nicor Gas Credit Facility		43	%		55	%		47	%

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Note 6 - Debt and Credit Facilities (Detail) - Debt Schedule (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Dec. 31, 2012		Mar. 31, 2012
Short-term debt
Weighted average interest rate	4.50%	[1]			8.00%	[1]
Outstanding	$ 226		$ 226		$ 17
Long-term debt - excluding current portion
Outstanding	3,324		3,327		3,558
Total debt	4,418		4,930		4,305
Commercial Paper [Member] | AGL Capital [Member]
Short-term debt
Maturity Date	2013	[2]
Weighted average interest rate	0.50%	[1],[2]			0.50%	[1],[2]
Outstanding	868	[2]	1,063	[2]	625	[2]
Long-term debt - excluding current portion
Maturity Date	2013	[2]
Commercial Paper [Member] | Nicor Gas [Member]
Short-term debt
Maturity Date	2013	[2]
Weighted average interest rate	0.40%	[1],[2]			0.50%	[1],[2]
Outstanding		[2]	314	[2]	105	[2]
Long-term debt - excluding current portion
Maturity Date	2013	[2]
Commercial Paper [Member]
Short-term debt
Weighted average interest rate	0.50%	[1]			0.50%	[1]
Outstanding	868		1,377		730
Minimum [Member] | Senior Notes [Member]
Short-term debt
Maturity Date	2015
Long-term debt - excluding current portion
Maturity Date	2015
Minimum [Member] | First Mortgage Bonds [Member]
Short-term debt
Maturity Date	2016
Long-term debt - excluding current portion
Maturity Date	2016
Minimum [Member] | Gas Facility Revenue Bonds [Member]
Short-term debt
Maturity Date	2022
Long-term debt - excluding current portion
Maturity Date	2022
Minimum [Member] | Medium-term Notes [Member]
Short-term debt
Maturity Date	2017
Long-term debt - excluding current portion
Maturity Date	2017
Minimum [Member] | Fair Value Adjustment [Member]
Short-term debt
Maturity Date	2016	[3]
Long-term debt - excluding current portion
Maturity Date	2016	[3]
Maximum [Member] | Senior Notes [Member]
Short-term debt
Maturity Date	2041
Long-term debt - excluding current portion
Maturity Date	2041
Maximum [Member] | First Mortgage Bonds [Member]
Short-term debt
Maturity Date	2038
Long-term debt - excluding current portion
Maturity Date	2038
Maximum [Member] | Gas Facility Revenue Bonds [Member]
Short-term debt
Maturity Date	2033
Long-term debt - excluding current portion
Maturity Date	2033
Maximum [Member] | Medium-term Notes [Member]
Short-term debt
Maturity Date	2027
Long-term debt - excluding current portion
Maturity Date	2027
Maximum [Member] | Fair Value Adjustment [Member]
Short-term debt
Maturity Date	2038	[3]
Long-term debt - excluding current portion
Maturity Date	2038	[3]
Current Portion Long-Term Debt [Member]
Short-term debt
Maturity Date	2013
Weighted average interest rate	4.50%	[1]			8.30%	[1]
Outstanding	225		225		15
Long-term debt - excluding current portion
Maturity Date	2013
Current Portion of Capital Leases [Member]
Short-term debt
Maturity Date	2013
Weighted average interest rate	5.00%				4.90%
Outstanding	1		1	[1]	2
Long-term debt - excluding current portion
Maturity Date	2013
Senior Notes [Member]
Short-term debt
Maturity Date	-
Long-term debt - excluding current portion
Maturity Date	-
Weighted average interest rate	5.10%	[1]			5.10%	[1]
Outstanding	2,325		2,325		2,550
First Mortgage Bonds [Member]
Short-term debt
Maturity Date	-
Long-term debt - excluding current portion
Maturity Date	-
Weighted average interest rate	5.60%	[1]			5.60%	[1]
Outstanding	500		500		500
Gas Facility Revenue Bonds [Member]
Short-term debt
Maturity Date	-
Long-term debt - excluding current portion
Maturity Date	-
Weighted average interest rate	0.30%	[1]			1.10%	[1]
Outstanding	200		200		200
Medium-term Notes [Member]
Short-term debt
Maturity Date	-
Long-term debt - excluding current portion
Maturity Date	-
Weighted average interest rate	7.80%	[1]			7.80%	[1]
Outstanding	181		181		181
Long-Term Debt Principal [Member]
Long-term debt - excluding current portion
Weighted average interest rate	4.90%	[1]			4.90%	[1]
Outstanding	3,206		3,206		3,431
Fair Value Adjustment [Member]
Short-term debt
Maturity Date	-	[3]
Long-term debt - excluding current portion
Maturity Date	-	[3]
Weighted average interest rate		[1],[3]				[1],[3]
Outstanding	100	[3]	103	[3]	109	[3]
Unamortized Debt Premium Discount Net [Member]
Short-term debt
Maturity Date	n/a
Long-term debt - excluding current portion
Maturity Date	n/a
Weighted average interest rate		[1]				[1]
Outstanding	18		18		18
Long-Term Debt Non-Principal [Member]
Long-term debt - excluding current portion
Weighted average interest rate		[1]				[1]
Outstanding	$ 118		$ 121		$ 127

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

[2] As of March 31, 2013, the weighted average interest rate on our AGL Capital commercial paper borrowings was 0.5%.

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

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Note 4 - Derivative Instruments (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012		Dec. 31, 2012
Derivative Liability, Fair Value, Net	$ (24)	[1],[2]	$ (103)	[1],[2]	$ (39)	[1],[2]
Increase (Decrease) in Risk Management Assets and Liabilities	(18)		(15)
Collateral Already Posted, Aggregate Fair Value	77		209		69
Price Risk Cash Flow Hedge Unrealized Gain (Loss) to be Reclassified During Next 12 Months	2
Less Than Two Years [Member] | Natural Gas [Member]
Percent Of Derivative Contracts	98.00%
ExpiringIn Two To Six Years [Member] | Natural Gas [Member]
Percent Of Derivative Contracts	2.00%
Weather Derivatives [Member]
Derivative Instruments, Loss Recognized in Income	$ 2		$ 14
Minimum [Member]
Natural Gas Derivative Term	2
Maximum [Member]
Natural Gas Derivative Term	6

[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 $77 million as of March 31, 2013, $69 million as of December 31, 2012 and $209 million as of March 31, 2012. Cash collateral is included in the "Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position" line of this table.

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Condensed Consolidated Statements of Income (Unaudited) (Parentheticals) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenue taxes	$ 50	$ 41

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Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Cash flows from operating activities
Net income	$ 164	$ 139
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization	107	104
Change in derivative instrument assets and liabilities	18	15
Deferred income taxes	(24)
Changes in certain assets and liabilities
Inventories, net of temporary LIFO liquidation	494	375
Energy marketing receivables and trade payables, net	92	56
Prepaid taxes	76	90
Accrued natural gas costs	43	37
Trade payables, other than energy marketing	(6)	(61)
Receivables, other than energy marketing	(172)	119
Other - net	58	(39)
Net cash flow provided by operating activities	850	835
Cash flows from investing activities
Expenditures for property, plant and equipment	(148)	(171)
Acquisitions of assets	(122)
Other	14	(4)
Net cash flow used in investing activities	(256)	(175)
Cash flows from financing activities
Net payments and borrowings of short-term debt	(509)	(591)
Dividends paid on common shares	(55)	(42)
Distribution to noncontrolling interest	(17)	(14)
Other	5	(11)
Net cash flow used in financing activities	(576)	(658)
Net increase in cash and cash equivalents	18	2
Cash and cash equivalents at beginning of period	131	69
Cash and cash equivalents at end of period	149	71
Cash paid during the period for
Interest	58	54
Income taxes	26
Non cash financing transaction
Refinancing of gas facility revenue bonds	$ 200

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Note 10 - Segment Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Number of States in which Entity Operates	7
Wholesale Services [Member]
Intercompany Revenues	$ 140	$ 88

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Note 7 - Equity (Tables)

3 Months Ended

Mar. 31, 2013

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

In millions (1)	Cash flow hedges			Retirement benefit plans			Total
Balance as of December 31, 2012	$	(6	)	$	(212	)	$	(218	)
Other comprehensive income, before reclassifications		2			-			2
Amounts reclassified from accumulated other comprehensive income		2			3			5
Net current-period other comprehensive income		4			3			7
Balance as of March 31, 2013	$	(2	)	$	(209	)	$	(211	)

Reclassification Out Of Accumulated Other Comprehensive Income [Table Text Block]

In millions	Amount reclassified from Accumulated Other Comprehensive Loss (1)			Affected line item in the Income Statement
Cash flow hedges
Interest rate contracts	$	(3	)	Interest expense, net
Income tax benefit		1
Total cash flow hedges		(2	)
Retirement benefit plan amortization of
Actuarial losses		(6	)	See (2), below
Prior service credits		1		See (2), below
Total before income tax		(5	)
Income tax benefit		2
Total retirement benefit plans		(3	)
Total reclassification for the period	$	(5	)

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Note 3 - Fair Value Measurements (Detail) - Derivative Assets and Liabilities (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012		Mar. 31, 2012
Netting of Cash Collateral [Member] | Natural Gas Derivatives [Member]
Natural gas derivatives
Derivative Assets	$ 40	[1]	$ 33	[1]	$ 47	[1]
Derivative Liabilities	37		36		162
Fair Value, Inputs, Level 1 [Member] | Natural Gas Derivatives [Member]
Natural gas derivatives
Derivative Assets	14	[1]	8	[1]	7	[1]
Derivative Liabilities	(38)		(45)		(187)
Fair Value, Inputs, Level 2 [Member] | Natural Gas Derivatives [Member]
Natural gas derivatives
Derivative Assets	49	[1]	96	[1]	203	[1]
Derivative Liabilities	(23)		(30)		(68)
Fair Value, Inputs, Level 2 [Member] | Interest Rate Derivatives [Member]
Natural gas derivatives
Derivative Assets	6	[1]	3	[1]	9	[1]
Derivative Liabilities					(10)
Natural Gas Derivatives [Member]
Natural gas derivatives
Derivative Assets	103	[1],[2],[3]	137	[1],[2],[3]	257	[1],[2],[3]
Derivative Liabilities	$ (24)	[2],[3]	$ (39)	[2],[3]	$ (93)	[2],[3]

[1] $2 million of premium at March 31, 2013, $4 million at December 31, 2012 and less than $1 million at March 31, 2012 associated with weather derivatives have been excluded, as they are not material and some are accounted for based on intrinsic value.

[2] There were no material unobservable inputs (Level 3) for any of the periods presented.

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

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Note 10 - Segment Information

3 Months Ended

Mar. 31, 2013

Segment Reporting Disclosure [Text Block]

Note 10 - Segment Information

Our operating segments comprise revenue-generating components of our company for which we produce separate financial information internally that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through five operating segments - distribution operations, retail operations, wholesale services, midstream operations, cargo shipping and one non-operating segment, other.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland. 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, our retail operations segment provides warranty protection solutions to customers and customer move connection services for utilities. Our wholesale services segment includes natural gas asset management and related logistics activities for each of our utilities, except Nicor Gas, as well as for nonaffiliated companies, natural gas storage arbitrage and related activities. Our midstream operations segment includes our non-utility storage and pipeline operations, including the development and operation of high-deliverability natural gas storage assets.

Our cargo shipping segment transports containerized freight 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. Although the majority of its long-lived assets are foreign owned and its revenues are derived from foreign operations, the functional currency is generally the United States dollar. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. Profits and losses are generally allocated to investors’ capital accounts in proportion to their capital contributions. Our investment in Triton is accounted for under the equity method, and our share of earnings is reported within other income in our unaudited Condensed Consolidated Statements of Income.

Our other segment includes intercompany eliminations and aggregated subsidiaries that are not significant enough on a stand-alone basis and that do not meet the criteria in one of our other five operating segments.

We evaluate segment performance using the non-GAAP measure of EBIT that includes operating income, other income and expenses, and equity investment income. Items we do not include in EBIT are income taxes and financing costs, including interest and debt expense, each of which we evaluate on a consolidated basis. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

You should not consider EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income, earnings before income taxes and net income for the three months ended March 31, 2013 and, 2012 are presented below.

In millions	2013		2012
Operating income	$	299	$	262
Other income		5		4
EBIT		304		266
Interest expense		46		47
Earnings before income taxes		258		219
Income taxes		94		80
Net income	$	164	$	139

Information by segment on our Statements of Financial Position as of December 31, 2012, is as follows:

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	11,320		$	1,640
Retail operations		511			122
Wholesale services		1,218			-
Midstream operations		720			14
Cargo shipping		464			61
Other (2)		(92	)		-
Consolidated	$	14,141		$	1,837

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

(2) Our other segment’s assets 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, 2013

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping		Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	1,264	$	302	$	39	$	24	$	87	$	(7	)	$	1,709
Intercompany revenues (1)		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 (3)	$	11,258	$	668	$	1,005	$	714	$	459	$	(164	)	$	13,940
Goodwill	$	1,640	$	168	$	-	$	14	$	61	$	-		$	1,883
Capital expenditures	$	137	$	1	$	-	$	4	$	1	$	5		$	148

Three months ended March 31,2012

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping			Other and intercompany eliminations (4)			Consolidated
Operating revenues from external parties	$	994	$	263	$	64	$	16	$	84		$	(17	)	$	1,404
Intercompany revenues (1)		46		-		-		-		-			(46	)		-
Total operating revenues		1,040		263		64		16		84			(63	)		1,404
Operating expenses
Cost of goods sold		529		166		30		5		50			(61	)		719
Operation and maintenance		173		32		13		5		28			(6	)		245
Depreciation and amortization		88		4		1		2		6			3			104
Taxes other than income taxes		57		1		1		1		2			2			64
Nicor merger expenses (2)		-		-		-		-		-			10			10
Total operating expenses		847		203		45		13		86			(52	)		1,142
Operating income (loss)		193		60		19		3		(2	)		(11	)		262
Other income		1		-		-		-		3			-			4
EBIT	$	194	$	60	$	19	$	3	$	1		$	(11	)	$	266
Identifiable and total assets (3)	$	10,785	$	471	$	917	$	665	$	477		$	(76	)	$	13,239
Goodwill	$	1,586	$	124	$	2	$	16	$	77		$	8		$	1,813
Capital expenditures	$	122	$	2	$	-	$	42	$	-		$	5		$	171

(1) Intercompany revenues - wholesale services records its energy marketing and risk management revenues on a net basis and its total operating revenues include intercompany revenues of $140 million for the three months ended March 31, 2013 and $88 million for the three months ended March 31, 2012.

(2) Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.

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

(4) Our other segment’s assets consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.