Edgar Filing: AGL RESOURCES INC

form_10-q.htm

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, 2011

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 (§232.405 of this chapter) 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 28, 2011
Common Stock, $5.00 Par Value	78,258,498

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended March 31, 2011

TABLE OF CONTENTS
			Page(s)
Glossary of Key Terms				3

Item
Number

		PART I – FINANCIAL INFORMATION		4 – 34

	1	Condensed Consolidated Financial Statements (Unaudited)		4 – 20
		Condensed Consolidated Statements of Financial Position		4
		Condensed Consolidated Statements of Income		5
		Condensed Consolidated Statements of Equity		6
		Condensed Consolidated Statements of Comprehensive Income		7
		Condensed Consolidated Statements of Cash Flows		8
		Notes to Condensed Consolidated Financial Statements (Unaudited)		9 – 20
		Note 1 – Organization and Basis of Presentation		9
		Note 2 – Significant Accounting Policies and Methods of Application		9 – 11
		Note 3 – Proposed Merger with Nicor		11 – 12
		Note 4 – Fair Value Measurements		12 – 13
		Note 5 – Derivative Financial Instruments		13 – 15
		Note 6 – Employee Benefit Plans		15
		Note 7 – Debt		16
		Note 8 – Non-Wholly-Owned Entity		17 – 18
		Note 9 – Commitments and Contingencies		18 – 19
		Note 10 – Segment Information		19 – 20
	2	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21 – 32
		Forward-Looking Statements		21
		Overview		21 – 22
		Executive Summary		22 – 24
		Results of Operations		24 – 27
		Liquidity and Capital Resources		28 – 31
		Critical Accounting Estimates		32
	3	Quantitative and Qualitative Disclosures About Market Risk		32 – 34
	4	Controls and Procedures		34

		PART II – OTHER INFORMATION		34 – 35

	1	Legal Proceedings		34
	2	Unregistered Sales of Equity Securities and Use of Proceeds		35
	6	Exhibits		35

		SIGNATURE		36

Glossary of Key Terms

Table of Contents

GLOSSARY OF KEY TERMS

Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Bridge Facility	Credit agreement entered into by AGL Capital Corporation to finance a portion of the proposed merger with Nicor that was originally $1.05 billion, but per the terms of the agreement was reduced to $852 million in March 2011
Chattanooga Gas	Chattanooga Gas Company
Credit Facility	$1.0 billion credit agreement entered into by AGL Capital Corporation
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes financing costs, including interest and debt and income tax expense each of which we evaluate on a consolidated level; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, earnings before income taxes, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP
ERC	Environmental remediation costs associated with our distribution operations segment which are generally recoverable through rate mechanisms
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
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.
Hampton Roads	Virginia Natural Gas’ pipeline project which connects its northern and southern pipelines
Heating Degree Days	A measure of the effects of weather on our businesses, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems when weather is colder
Jefferson Island	Jefferson Island Storage & Hub, LLC
LOCOM	Lower of weighted-average cost or current market price
Magnolia	Magnolia Enterprise Holdings, Inc.
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 Illinois corporation
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 gas, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our Condensed Consolidated Statements of Income. Operating margin should not be considered an alternative to, or more meaningful than, operating income as determined in accordance with GAAP
Piedmont	Piedmont Natural Gas Company, Inc.
PP&E	Property, plant and equipment
Regulatory Infrastructure Program	Programs that update or expand our distribution systems and liquefied natural gas facilities to improve system reliability and meet operational flexibility and growth. These programs include the pipeline replacement program and the STRIDE program at Atlanta Gas Light and Elizabethtown Gas’ utility infrastructure enhancements program.
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
SouthStar	SouthStar Energy Services LLC
STRIDE	Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
Term Loan Facility	$300 million credit agreement entered into by AGL Capital Corporation of which $150 million was drawn in January 2011 and subsequently repaid and the agreement terminated in February 2011
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
Virginia Natural Gas	Virginia Natural Gas, Inc.
WACOG	Weighted-average cost of gas

Glossary of Key Terms

Table of Contents

PART 1 – Financial Information

Item 1. Financial Statements

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(UNAUDITED)

			As of
In millions	Mar. 31, 2011		Dec. 31, 2010		Mar. 31, 2010
Current assets
Cash and cash equivalents	$	85	$	24	$	19
Receivables
Energy marketing receivables (Note 2)		565		788		563
Gas, unbilled and other receivables		367		390		417
Less: allowance for uncollectible accounts		21		16		21
Total receivables		911		1,162		959
Inventories, net (Note 2)		361		639		370
Derivative financial instruments – current portion (Note 2, Note 4 and Note 5)		124		182		205
Recoverable regulatory infrastructure program costs – current portion (Note 2)		49		48		45
Recoverable environmental remediation costs – current portion (Note 2 and Note 9)		7		7		10
Other current assets		50		104		46
Total current assets		1,587		2,166		1,654
Long-term assets and other deferred debits
Property, plant and equipment		6,348		6,266		6,025
Less: accumulated depreciation		1,830		1,861		1,814
Property, plant and equipment-net		4,518		4,405		4,211
Goodwill		418		418		418
Recoverable regulatory infrastructure program costs (Note 2)		231		244		258
Recoverable environmental remediation costs (Note 2)		162		164		159
Derivative financial instruments (Note 2, Note 4 and Note 5)		29		46		56
Other		81		79		74
Total long-term assets and other deferred debits		5,439		5,356		5,176
Total assets	$	7,026	$	7,522	$	6,830
Current liabilities
Energy marketing trade payable (Note 2)	$	628	$	744	$	620
Accounts payable – trade		161		184		156
Accrued expenses		141		139		137
Accrued regulatory infrastructure program costs – current portion (Note 2)		69		62		75
Short-term debt (Note 4 and Note 7)		26		733		154
Derivative financial instruments – current portion (Note 2, Note 4 and Note 5)		25		44		74
Accrued environmental remediation liabilities – current portion (Note 2 and Note 9)		15		14		31
Current portion of long-term debt		-		300		300
Other current liabilities		248		212		241
Total current liabilities		1,313		2,432		1,788
Long-term liabilities and other deferred credits
Long-term debt (Note 4 and Note 7)		2,173		1,673		1,674
Accumulated deferred income taxes		803		768		711
Accumulated removal costs		250		182		186
Accrued pension obligations (Note 6)		153		186		146
Accrued regulatory infrastructure program costs (Note 2)		143		166		169
Accrued environmental remediation liabilities (Note 2 and Note 9)		126		129		113
Accrued postretirement benefit costs (Note 6)		34		36		36
Derivative financial instruments (Note 2, Note 4 and Note 5)		3		4		8
Other long-term liabilities and other deferred credits		108		110		148
Total long-term liabilities and other deferred credits		3,793		3,254		3,191
Total liabilities and other deferred credits		5,106		5,686		4,979
Commitments and contingencies (Note 9)
Equity
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,903		1,813		1,834
Noncontrolling interest (Note 8)		17		23		17
Total equity		1,920		1,836		1,851
Total liabilities and equity	$	7,026	$	7,522	$	6,830
See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three months ended
	March 31,
In millions, except per share amounts	2011			2010
Operating revenues	$	878		$	1,003
Operating expenses
Cost of gas		455			571
Operation and maintenance		131			125
Depreciation and amortization		41			40
Taxes other than income taxes		13			14
Total operating expenses		640			750
Operating income		238			253
Other income		1			2
Interest expense, net		(29	)		(28	)
Earnings before income taxes		210			227
Income tax expense		76			82
Net income		134			145
Less net income attributable to the noncontrolling interest (Note 8)		10			11
Net income attributable to AGL Resources Inc.	$	124		$	134
Per common share data (Note 2)
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	1.60		$	1.74
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	1.59		$	1.73
Cash dividends declared per common share	$	0.45		$	0.44
Weighted-average number of common shares outstanding (Note 2)
Basic		77.7			77.2
Diluted		78.0			77.6

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

	AGL Resources Inc. Shareholders
In millions, except per share	Common stock				Premium on common				Earnings			Accumulated other comprehensive				Treasury			Noncontrolling
amounts	Shares		Amount			stock			reinvested				loss			shares				interest			Total
Balance as of Dec. 31, 2009		77.5	$	390		$	679		$	848			$	(116	)	$	(21	)		$	39		$	1,819
Net income		-		-			-			134				-			-				11			145
Other comprehensive loss		-		-			-			-				(2	)		-				-			(2	)
Dividends on common stock ($0.44 per share)		-		-			(1	)		(34	)			-			2				-			(33	)
Purchase of additional 15% ownership interest in SouthStar		-		-			(51	)		-				(1	)		-				(6	)		(58	)
Distributions to noncontrolling interest (Note 8)		-		-			-			-				-			-				(27	)		(27	)
Issuance of treasury shares		0.3		-			(9	)		-				-			12				-			3
Stock-based compensation expense (net of tax)		-		-			4			-				-			-				-			4
Balance as of Mar. 31, 2010		77.8	$	390		$	622		$	948			$	(119	)	$	(7	)		$	17		$	1,851

	AGL Resources Inc. Shareholders
In millions, except per share	Common stock				Premium on common			Earnings			Accumulated other comprehensive				Treasury			Noncontrolling
amounts	Shares		Amount			stock		reinvested				loss			shares				interest			Total
Balance as of Dec. 31, 2010		78.0	$	391		$	631	$	943			$	(150	)	$	(2	)		$	23		$	1,836
Net income		-		-			-		124				-			-				10			134
Other comprehensive loss		-		-			-		-				(1	)		-				-			(1	)
Dividends on common stock ($0.45 per share)		-		-			1		(35	)			-			-				-			(34	)
Distributions to noncontrolling interest (Note 8)		-		-			-		-				-			-				(16	)		(16	)
Benefit, dividend reinvestment and stock purchase plans		0.2		1			2		-				-			(2	)			-			1
Purchase of treasury shares		-		-			-		-				-			(2	)			-			(2	)
Stock-based compensation expense (net of tax)		-		-			2		-				-			-				-			2
Balance as of Mar. 31, 2011		78.2	$	392		$	636	$	1,032			$	(151	)	$	(6	)		$	17		$	1,920

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)

	Three months ended
	March 31,
In millions	2011			2010
Comprehensive income attributable to AGL Resources Inc. (net of tax)
Net income attributable to AGL Resources Inc.	$	124		$	134
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		(1	)		(6	)
Reclassification of derivative financial instruments realized losses included in net income		-			4
Other comprehensive loss		(1	)		(2	)
Comprehensive income	$	123		$	132

Comprehensive income attributable to noncontrolling interest (net of tax)
Net income attributable to noncontrolling interest (Note 8)	$	10		$	11
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		-			(1	)
Reclassification of derivative financial instruments realized losses included in net income		-			1
Other comprehensive income		-			-
Comprehensive income	$	10		$	11

Total comprehensive income, including portion attributable to noncontrolling interest (net of tax)
Net income	$	134		$	145
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		(1	)		(7	)
Reclassification of derivative financial instruments realized losses included in net income		-			5
Other comprehensive loss		(1	)		(2	)
Comprehensive income	$	133		$	143

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three months ended
	March 31,
In millions	2011			2010
Cash flows from operating activities
Net income	$	134		$	145
Adjustments to reconcile net income to net cash flow provided by operating activities
Change in derivative financial instrument assets and liabilities		55			(1	)
Depreciation and amortization		41			40
Deferred income taxes		23			14
Changes in certain assets and liabilities
Inventories		278			302
Energy marketing receivables and energy marketing trade payables, net (Note 2)		107			148
Deferred natural gas costs		29			6
Gas, unbilled and other receivables		28			(48	)
Gas and trade payables		(23	)		(40	)
Other – net		46			107
Net cash flow provided by operating activities		718			673
Cash flows from investing activities
Payments to acquire property, plant and equipment		(94	)		(114	)
Other		-			(3	)
Net cash flow used in investing activities		(94	)		(117	)
Cash flows from financing activities
Net payments and borrowings of short-term debt		(707	)		(448	)
Payment of senior notes		(300	)		-
Dividends paid on common shares		(34	)		(33	)
Distribution to noncontrolling interest (Note 8)		(16	)		(27	)
Purchase of treasury shares		(2	)		-
Issuance of senior notes		495			-
Purchase of additional 15% ownership interest in SouthStar		-			(58	)
Benefit, dividend reinvestment and stock purchase plans		1			3
Net cash flow used in financing activities		(563	)		(563	)
Net increase (decrease) in cash and cash equivalents		61			(7	)
Cash and cash equivalents at beginning of period		24			26
Cash and cash equivalents at end of period	$	85		$	19
Cash paid during the period for
Interest	$	36		$	34
Income taxes	$	1		$	1

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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

Note 1 - Organization and Basis of Presentation

General

AGL Resources Inc. is an energy services holding company that conducts substantially all its operations through its subsidiaries. Unless the context requires otherwise, references to “we,” “us,” “our,” “the company,” or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries.

In December 2010, we entered into an Agreement and Plan of Merger (Merger Agreement) with Nicor, which we anticipate completing during the second half of 2011. See Note 3 for additional discussion of the proposed merger.

The December 31, 2010 Condensed 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 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. You should read these Condensed Consolidated Financial Statements in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on February 9, 2011.

Due to the seasonal nature of our business, our results of operations for the three months ended March 31, 2011 and 2010, and our financial condition as of December 31, 2010, and March 31, 2011 and 2010, 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 Condensed Consolidated Financial Statements include our accounts, the accounts of our majority-owned and controlled subsidiaries and the accounts of our variable interest entity for which we are the primary beneficiary. This means that our accounts are combined with our subsidiaries’ accounts. We have eliminated any intercompany profits and transactions in consolidation; however, we have not eliminated intercompany profits when such amounts are probable of recovery 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 our prior period balances.

Note 2 – Significant Accounting Policies and Methods of Application

Use of Accounting Estimates

Our accounting policies are described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010. There were no significant changes to our accounting policies during the three months ended March 31, 2011.

The preparation of our financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience, where applicable, and various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates and assumptions on an ongoing basis and make adjustments in subsequent periods to reflect more current information if we determine that updated assumptions and estimates are warranted. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing financial accounting literature or in the development of estimates that impact our financial statements. The most significant estimates include our regulatory infrastructure program accruals, ERC liability accruals, allowance for uncollectible accounts, contingencies, pension and postretirement obligations, derivative and hedging activities and provision for income taxes. Our actual results could differ from those estimates and such differences could be material.

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 wholesale services 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. The amounts due from or owed to wholesale services’ counterparties are netted and recorded on our 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, 2011, December 31, 2010 and March 31, 2010, 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. However, if such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

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Inventories

For our distribution operations segment, we record natural gas stored underground at the WACOG. For Sequent, SouthStar and Jefferson Island, we account for natural gas inventory at the lower of WACOG or market price.

SouthStar and Sequent 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. SouthStar recorded no LOCOM adjustments in the three months ended March 31, 2011 or March 31, 2010. Sequent recorded LOCOM adjustments of less than $1 million for the three months ended March 31, 2011 and $4 million for the three months ended March 31, 2010.

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 are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future 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 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. Further, we are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and believe that we will be able to recover these costs, consistent with our historical recoveries.

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

	Mar. 31,		Dec. 31,		Mar. 31,
In millions	2011		2010		2010
Regulatory assets
Recoverable regulatory infrastructure program costs	$	280	$	292	$	303
Recoverable ERC		169		171		169
Recoverable seasonal rates		-		11		-
Recoverable postretirement benefit costs		9		9		10
Other		36		42		34
Total regulatory assets		494		525		516
Associated assets
Derivative financial instruments		13		20		32
Total regulatory and associated assets	$	507	$	545	$	548
Regulatory liabilities
Accumulated removal costs	$	250	$	182	$	186
Derivative financial instruments		13		20		32
Regulatory tax liability		15		15		17
Unamortized investment tax credit		11		12		13
Deferred natural gas costs		52		23		41
Deferred seasonal rates		19		-		22
Other		26		24		20
Total regulatory liabilities		386		276		331
Associated liabilities
Regulatory infrastructure program costs		212		228		244
ERC		129		132		132
Total associated liabilities		341		360		376
Total regulatory and associated liabilities	$	727	$	636	$	707

As of March 31, 2011, there have been no 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 Annual Report on Form 10-K for the year ended December 31, 2010.

Earnings per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our net income attributable to AGL Resources Inc. by the daily weighted-average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. common shareholders reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. common shareholders that 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 issued under restricted stock or issuable under restricted stock units and stock options. The vesting of shares of the restricted stock and restricted stock units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends upon 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 our plans ultimately vest and stock options currently exercisable at prices below the average market prices are exercised:

	Three months ended March 31,
In millions	2011		2010
Denominator for basic earnings per share (1)		77.7		77.2
Assumed exercise of restricted stock, restricted stock units and stock options		0.3		0.4
Denominator for diluted earnings per share		78.0		77.6
(1) Daily weighted-average shares outstanding.

The following table contains the weighted-average shares attributable to outstanding stock options that were excluded from the computation of diluted earnings per common share attributable to AGL Resources Inc. because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price:

	March 31,
In millions	2011		2010
Three months ended		0.7		0.8

The decrease of 0.1 million in anti-dilutive shares for the three months ended March 31, 2011, was primarily a result of a higher average market value of our common shares compared to the same period during 2010.

Fair Value Measurements

The carrying values of cash and cash equivalents, receivables, derivative financial assets and liabilities, accounts payable, other current assets and liabilities and accrued interest approximate fair value.

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 pricing 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 and 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 are able to classify fair value balances based on the observance of those inputs. See Note 4 for additional fair value disclosure.

There have been no significant changes to our fair value methodologies, as described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010.

Note 3 – Proposed Merger with Nicor

In December 2010, we entered into a Merger Agreement with Nicor, a copy of which was filed with the SEC on December 7, 2010. In accordance with the Merger Agreement, each share of Nicor common stock outstanding, other than shares to be cancelled and Dissenting Shares, as defined in the Merger Agreement, will be converted into the right to receive consideration of (i) 0.8382 of a share of our common stock and (ii) $21.20 in cash, subject to adjustments in certain circumstances to ensure that the transaction satisfies the “continuity of interest” requirement for a “reorganization” within Section 368(a) of the Internal Revenue Code.

Upon the closing of the proposed merger, it is anticipated that our shareholders will own approximately 67%, and Nicor shareholders will own approximately 33%, of the combined company. The value of the consideration to be received by Nicor shareholders will fluctuate with changes in the price of our common stock and represented a value of $54.92 per share based on the closing price of our common stock on the NYSE on April 25, 2011, the date used to calculate the preliminary purchase price in our Form S-4/A which was filed with the SEC on April 28, 2011. We will also assume all of Nicor’s outstanding debt.

In April 2011, we received antitrust clearance from the Department of Justice and the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvement Act. Additionally, in April, 2011, the SEC declared effective our registration statement on Form S-4 which registered our common stock to be issued in connection with the proposed merger and allowed us to schedule our special meeting of shareholders which will be held in June 2011.

Completion of the proposed merger is conditioned upon, among other things, shareholder approval by both companies and regulatory approval by the Illinois Commerce Commission. The Merger Agreement contains certain termination rights for both Nicor and us, and provides for the payment of fees and expenses upon the termination of the Merger Agreement under certain circumstances.

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In January 2011, we filed a joint application with Nicor to the Illinois Commerce Commission for approval of the proposed merger. The application did not request a rate increase, but included a commitment to maintain the number of full-time equivalent employees at Nicor’s natural gas utility for a period of three years following merger completion. The Illinois Commerce Commission has eleven months to act upon the application; however, we and Nicor have asked for approval of the merger by October 1, 2011.

In April 2011, the Staff of the Illinois Commerce Commission and several intervenors who are participating in the proceeding submitted initial testimony recommending that the Illinois Commerce Commission deny the joint application or that it impose various requirements on the joint applicants as conditions of approval. We and Nicor anticipate submitting joint rebuttal testimony to the Illinois Commerce Commission in May 2011.

The proposed merger may also be subject to review by the governmental authorities of various other federal, state or local jurisdictions under the antitrust and utility regulation or other applicable laws of those jurisdictions. We have provided a voluntary notice of the merger to the New Jersey BPU and the Maryland Public Service Commission (Maryland Commission), which included a description of the transaction, described the benefits of the transaction and explained why we do not believe that the approval of the New Jersey BPU or Maryland Commission is required to complete the merger. It is possible that one or more state commissions will open proceedings to determine whether they have jurisdiction over the merger. In the event that any reviewing authorities are determined to have jurisdiction over the merger transaction, there can be no assurance that the reviewing authorities will permit the applicable statutory waiting periods to expire or that the reviewing authorities will terminate the applicable statutory waiting periods at all, or otherwise approve the merger without restrictions or conditions (which are difficult to predict or quantify) that would have a material adverse effect on the combined company if the merger were completed.

We and Nicor currently anticipate completing the merger in the second half of 2011. Although we and Nicor believe that we will receive the required authorizations, approvals and consents to complete the proposed merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to our ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to us and Nicor.

During the three months ended March 31, 2011, we recorded approximately $5 million ($3 million net of tax) of non-recurring transaction expenses associated with the proposed merger. These costs are expensed as incurred. For additional information concerning the proposed merger please see our Form 8-K filed with the SEC on December 7, 2010.

Note 4 – Fair Value Measurements

The following table summarizes, by level within the fair value hierarchy, our derivative financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2011, December 31, 2010 and March 31, 2010.

	Recurring fair values Derivative financial instruments
	March 31, 2011					December 31, 2010					March 31, 2010
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets		Liabilities
Quoted prices in active markets (Level 1)	$	14	$	(63	)	$	22	$	(71	)	$	44	$	(109	)
Significant other observable inputs (Level 2)		101		(15	)		153		(29	)		185		(46	)
Netting of cash collateral		38		50			53		52			32		73
Total carrying value (2) (3)	$	153	$	(28	)	$	228	$	(48	)	$	261	$	(82	)

(1)	Less than $1 million premium at March 31, 2011 and December 31, 2010 associated with weather derivatives has been excluded as they are based on intrinsic value, not fair 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.

In addition, we have several financial and nonfinancial assets and liabilities subject to fair value measures. These financial assets and liabilities include cash and cash equivalents, accounts receivable, accounts payable and debt. For cash and cash equivalents, accounts receivable and accounts payable we consider carrying value to materially approximate fair value due to their short-term nature. The nonfinancial assets and liabilities include pension and post-retirement benefits, which are presented in Note 3 to our Consolidated Financial Statements and related notes included in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010.

Our debt is recorded at carrying value. 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. In determining the market interest yield curve, we considered our currently assigned ratings for unsecured debt. The following table presents the carrying value and fair value of our debt for the following periods.

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	As of
In millions	March 31, 2011		December 31, 2010		March 31, 2010
Carrying amount	$	2,199	$	2,706	$	2,128
Fair value	$	2,329	$	2,854	$	2,233

Note 5 – Derivative Financial Instruments

Our risk management activities are monitored by our Risk Management Committee, which consists of members of senior management and is charged with reviewing and enforcing our risk management activities and policies. Our use of derivative financial instruments and physical transactions is limited to predefined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following types of derivative financial instruments and physical transactions to manage natural gas price, interest rate, weather and foreign currency risks:

·	forward contracts;

·	futures contracts;

·	options contracts;

·	financial swaps;

·	treasury locks;

·	weather derivative contracts;

·	storage and transportation capacity transactions; and

·	foreign currency forward contracts.

Our derivative financial instruments do not contain any material credit-risk-related or other contingent features that could increase the payments for collateral that we post in the normal course of business when our financial instruments are in net liability positions. Additional information on our energy marketing receivables and payables, which do have credit-risk-related or other contingent features, is discussed in Note 2.

There have been no significant changes to our derivative financial instruments, as described in Note 2 and Note 4 to our Consolidated Financial Statements and related notes included in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010. The table below summarizes the various ways in which we account for our derivative instruments and the impact on our Condensed Consolidated Financial Statements:

	Recognition and Measurement
Accounting Treatment	Statement of Financial Position	Income Statement
Cash flow hedge	Recorded 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 other comprehensive income (loss)	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings

Not designated as hedges	Recorded at fair value	The gain or loss on the derivative instrument is recognized in earnings
	Elizabethtown Gas’ derivative financial instruments are recorded as a regulatory asset or liability until included in natural gas costs	The gain or loss on these derivative instruments is reflected in natural gas costs and is ultimately included in billings to customers
	Change in fair value of the derivative instrument is recorded as an adjustment to book value	Change in fair value of the derivative instrument is recognized in earnings

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Quantitative Disclosures Related to Derivative Financial Instruments

As of March 31, 2011, December 31, 2010 and March 31, 2010, our derivative financial 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:

Natural gas contracts
				As of
In Bcf	March 31, 2011 (1)			December 31, 2010			March 31, 2010
Hedge designation:
Cash flow		3			4			8
Not designated		278			220			268
Total		281			224			276
Hedge position:
Short		(1,617	)		(1,605	)		(1,457	)
Long		1,898			1,829			1,733
Net long position		281			224			276

(1)	Approximately 96% of these contracts have durations of two years or less and the remaining 4% expire in 3 to 6 years.

Derivative Financial Instruments on the Condensed Consolidated Statements of Financial Position

In accordance with regulatory requirements, realized losses on derivative financial instruments used at Elizabethtown Gas in our distribution operations segment were reflected in deferred natural gas costs within our Condensed Consolidated Statements of Financial Position of $8 million during the three months ended March 31, 2011 and $8 million during the three months ended March 31, 2010. The following table presents the fair value and statements of financial position classification of our derivative financial instruments:

		As of
In millions	Statement of financial position location (1) (2)		Mar. 31, 2011		Dec. 31, 2011			Mar. 31, 2010
Designated as cash flow hedges

Asset Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion	$	1		$	3		$	5
Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		(2	)		(5	)		(14	)
Total			(1	)		(2	)		(9	)

Not designated as cash flow hedges

Asset Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		346			541			771
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		77			105			147

Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		(323	)		(489	)		(714	)
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		(62	)		(80	)		(121	)
Total			38			77			83
Total derivative financial instruments		$	37		$	75		$	74

(1)

These amounts are netted within our Condensed Consolidated Statements of Financial Position. Some of our derivative financial instruments have asset positions which are presented as a liability in our Condensed Consolidated Statements of Financial Position, and we have derivative instruments that have liability positions which are presented as an asset in our consolidated statements of financial position.

(2)

As required by the authoritative guidance related to derivatives and hedging, the fair value amounts above are presented on a gross basis. As a result, the amounts above do not include cash collateral held on deposit in broker margin accounts of $88 million as of March 31, 2011 and $105 million as of March 31, 2010 and December 31, 2010. Accordingly, the amounts above will differ from the amounts presented on our Condensed Consolidated Statements of Financial Position and the fair value information presented for our derivative financial instruments in the recurring values table of this note.

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Derivative Financial Instruments on the Condensed Consolidated Statements of Income

The following table presents the impacts of our derivative financial instruments in our Condensed Consolidated Statements of Income:

	For the three months ended March 31,
In millions	2011			2010
Designated as cash flow hedges
Natural gas contracts – loss reclassified from OCI into cost of gas for settlement of hedged item (1)	$	-		$	(7	)

Not designated as hedges
Natural gas contracts – fair value adjustments recorded in operating revenues (2)		11			18
Natural gas contracts – net fair value adjustments recorded in cost of gas (3)		(1	)		(2	)
Total gains on derivative instruments	$	10		$	9

(1)	We expect that $1 million of pre-tax net losses will be reclassified from OCI into cost of gas for the settlement of hedged items over the next twelve months.

(2)	Associated with the fair value of existing derivative instruments at March 31, 2011 and 2010.

(3)	Excludes gains recorded in cost of gas associated with weather derivatives of $3 million for the three months ended March 31, 2011 and losses of $20 million for the three months ended March 31, 2010.

Note 6 - Employee Benefit Plans

Pension Benefits

We sponsor two tax-qualified defined benefit retirement plans for our eligible employees, the AGL Resources Inc. Retirement Plan and the Employees’ Retirement Plan of NUI Corporation. A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant. Following are the combined cost components of our two defined pension plans for the periods indicated:

	Three months ended
	March 31,
In millions	2011			2010
Service cost	$	3		$	3
Interest cost		7			7
Expected return on plan assets		(8	)		(8	)
Amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		4			3
Net pension benefit cost	$	5		$	4

Postretirement Benefits

We sponsor a defined benefit postretirement health care plan for our eligible employees, the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Postretirement Plan). Eligibility for these benefits is based on age and years of service. The AGL Postretirement Plan includes medical coverage for all eligible AGL Resources employees who were employed as of June 30, 2002, if they reach retirement age while working for the Company. Additionally, the AGL Postretirement Plan provides life insurance for all employees if they have a minimum of ten years service at retirement. The state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery.

Following are the cost components of the AGL Postretirement Plan for the periods indicated:

	Three months ended March 31,
In millions	2011			2010
Service cost	$	-		$	-
Interest cost		1			1
Expected return on plan assets		(1	)		(1	)
Amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		1			1
Net postretirement benefit cost	$	-		$	-

Contributions

Our employees do not contribute to these pension and postretirement plans. We fund the qualified pension plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the minimum required amount. As required by The Pension Protection Act (the Act) of 2006, we calculate the minimum amount of funding using the traditional unit credit cost method.

The Act contained new funding requirements for single employer defined benefit pension plans and established a 100% funding target (over a 7-year amortization period) for plan years beginning after December 31, 2007. If certain conditions are met, the Worker, Retiree and Employer Recovery Act of 2008 allowed us to measure our required minimum contributions based on a funding target of 100% during 2010 and 2011. In the first three months of 2011 we contributed $38 million to our qualified pension plans and $17 million during the same period last year.

Employee Savings Plan Benefits

We sponsor the Retirement Savings Plus Plan (RSP), a defined contribution benefit plan that allows eligible participants to make contributions to their accounts up to specified limits. Under the RSP, we made matching contributions to participant accounts of $2 million in the first three months of 2011 and 2010.

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Note 7 – Debt

The following table provides maturity dates, weighted-average interest rates and amounts outstanding for our various debt securities and facilities. For additional information on our debt see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010.

		March 31, 2011							March 31, 2010
In millions	Year(s) due	Weighted- average interest rate			Outstanding		Outstanding at December 31, 2010		Weighted- average interest rate			Outstanding
Short-term debt
Commercial paper	2011		0.4	%	$	25	$	732		0.4	%	$	153
Capital leases	2011-2012		4.9			1		1		4.9			1
Current portion of long-term debt	2011		-			-		300		7.1			300
Total short-term debt and current portion of long-term debt			0.4	%	$	26	$	1,033		3.3	% (1)	$	454
Long-term debt - net of current portion
Senior notes	2013-2041		5.5	%	$	1,775	$	1,275		5.5	%	$	1,275
Gas facility revenue bonds	2022-2033		1.2			200		200		1.2			200
Medium-term notes	2012-2027		7.8			196		196		7.8			196
Capital leases	2013		4.9			2		2		4.9			3
Total long-term debt			5.3	%	$	2,173	$	1,673		5.1	% (2)	$	1,674

Total debt			4.0	%	$	2,199	$	2,706		4.6	%	$	2,128

(1)	Excluding the $300 million of senior notes repaid in January 2011, the weighted-average short-term interest rate for the three months ended March 31, 2010 was 0.4%.

(2)	Including the $300 million of senior notes repaid in January 2011, the weighted-average long-term interest rate for the three months ended March 31, 2010 was 5.4%.

Senior Notes

In March 2011, we completed a public offering of $500 million in senior notes with a 5.875% interest rate. These senior notes mature in 2041. The net proceeds were used to repay commercial paper a portion of which we borrowed to repay our $300 million in senior notes that matured in January 2011. In connection with our issuance of these senior notes, and in accordance with the terms of our Bridge Facility, the principal amount of the Bridge Facility has been reduced from $1.05 billion to $852 million.

Financial and Non-Financial Covenants

In September 2010, we entered into a new $1 billion revolving Credit Facility, which expires in September 2013. The Credit Facility includes a financial covenant that requires us to maintain a ratio, on a consolidated basis, of total debt to total capitalization of no more than 70%; however, our goal is to maintain this ratio at a level between 50% and 60%. Our ratio, on a consolidated basis, of total debt to total capitalization as calculated in accordance with our debt covenant includes standby letters of credit, performance/surety bonds and excludes certain pension and other post-retirement benefit adjustments and cash flow hedges that are not yet settled. Adjusting for these items, our debt-to-capitalization ratio was 51% at March 31, 2011, 58% at December 31, 2010 and 52% at March 31, 2010. These amounts are within our required and targeted ranges.

The Credit Facility contains certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, restricted payments, asset dispositions, fundamental changes and other matters customarily restricted in such agreements. We are currently in compliance with all existing debt provisions and covenants.

Our Bridge Facility contains the same financial covenant and similar non-financial covenants and default provisions; however, most of these are not in effect until we draw under the facility.

Default Provisions

Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. Our most important default provisions 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 trigger 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 trigger events.

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Note 8 – Non-Wholly-Owned Entity

On a quarterly basis we evaluate all of our joint venture interests to determine if they represent a variable interest entity (VIE) as defined by the authoritative accounting guidance on consolidation. We have determined that SouthStar is our only VIE for which we are the primary beneficiary, which requires us to consolidate the assets, liabilities and statements of income of the joint venture. Our methodology for determining that we are the primary beneficiary of the VIE, and our involvement that allows us to direct SouthStar’s activities that most significantly influence its performance, has not changed during the three months ended March 31, 2011. See Note 9 to our Consolidated Financial Statements and related notes included in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010. Earnings in 2011 and 2010 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, and under various other trade names to retail customers in Ohio and Florida and to commercial and industrial customers principally in Alabama, Florida, North Carolina, South Carolina and Tennessee.

During the three months ended March 31, 2011, 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 Annual Report on Form 10-K for the year ended December 31, 2010.

The following table illustrates the effect that our 2009 purchase of an additional 15% ownership interest, which became effective in January 2010, had on our equity for the three months ended March 31, 2010.

In millions		Premium on common stock				Accumulated other comprehensive loss				Total
Purchase of additional 15% ownership interest		$	(51	)		$	(1	)		$	(52	)

See Note 10 for summarized statements of income, statements of financial position and capital expenditure information related to the retail energy operations segment, which is primarily comprised of SouthStar.

SouthStar’s financial results are seasonal in nature, with the business depending to a great extent on the first and fourth quarters of each year for the majority of its earnings. SouthStar’s current assets consist primarily of natural gas inventory, derivative financial instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in our commercial paper program. See Note 2 for additional discussions of SouthStar’s inventories. SouthStar’s restricted assets consist of customer deposits and are immaterial. Such restricted cash makes up less than one-tenth of one percent of our consolidated net assets as of March 31, 2011 and 2010. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative financial instruments and payables to us from its participation in our commercial paper program.

As of March 31, 2011, SouthStar’s current assets, which approximate fair value, exceeded its current liabilities, long-term assets and other deferred debits and long-term liabilities and other deferred credits by approximately $100 million. 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 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 the corporate guarantees 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. Additionally, 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 financial instruments.

Cash flows used in our financing activities includes SouthStar’s distributions to the noncontrolling interest, which reflects the cash distribution to Piedmont for its ownership interest in SouthStar’s annual earnings from the prior year. Generally this distribution occurs in the first or second quarter. In the three months ended March 31, 2011 SouthStar distributed $16 million to Piedmont and $27 million during the same period last year. This decrease of $11 million was primarily the result of our increased ownership percentage of SouthStar in 2010.

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The following tables provide additional information on SouthStar’s assets and liabilities as of March 31, 2011, December 31, 2010 and March 31, 2010, which are consolidated within our Condensed Consolidated Statements of Financial Position.

	As of March 31, 2011
In millions	Consolidated		SouthStar (1)		%	(2)
Current assets	$	1,587	$	170	11	%
Long-term assets and other deferred debits		5,439		9	-
Total assets	$	7,026	$	179	3	%
Current liabilities	$	1,313	$	61	5	%
Long-term liabilities and other deferred credits		3,793		-	-
Equity		1,920		118	6
Total liabilities and equity	$	7,026	$	179	3	%

	As of December 31, 2010
In millions	Consolidated		SouthStar (1)		%	(2)
Current assets	$	2,166	$	239	11	%
Long-term assets and other deferred debits		5,356		9	-
Total assets	$	7,522	$	248	3	%
Current liabilities	$	2,432	$	93	4	%
Long-term liabilities and other deferred credits		3,254		-	-
Equity		1,836		155	8
Total liabilities and equity	$	7,522	$	248	3	%

	As of March 31, 2010
In millions	Consolidated		SouthStar (1)		%	(2)
Current assets	$	1,654	$	212	13	%
Long-term assets and other deferred debits		5,176		9	-
Total assets	$	6,830	$	221	3	%
Current liabilities	$	1,788	$	105	6	%
Long-term liabilities and other deferred credits		3,191		-	-
Equity		1,851		116	6
Total liabilities and equity	$	6,830	$	221	3	%

(1)

These amounts reflect information for SouthStar and do not include intercompany eliminations and the balances of our wholly-owned subsidiary with an 85% ownership interest in SouthStar. Accordingly, the amounts will not agree to the identifiable and total assets for our retail energy operations segment reported in Note 10.

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

Note 9 - Commitments and Contingencies

Contractual Obligations and Commitments

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. There were no significant changes to our contractual obligations described in Note 10 to our Consolidated Financial Statements and related notes as filed in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010.

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. The following table illustrates our contingent financial commitments as of March 31, 2011:

	Commitments due before December 31,
In millions	Total		2011		2012 & thereafter
Standby letters of credit and performance and surety bonds	$	16	$	12	$	4

Litigation

We are involved in litigation arising in the normal course of business. The ultimate resolution of such litigation is not expected to have a material adverse effect on our Condensed Consolidated Statement of Financial Position, Income or Cash Flows.

In February 2008, a class action lawsuit was filed in the Superior Court of Fulton County in the State of Georgia against Georgia Natural Gas alleging that it charged its customers on variable rate plan prices for natural gas that were in excess of the published price, failed to give proper notice regarding the availability of potentially lower price plans and that it changed its methodology for computing variable rates. This lawsuit was dismissed in September 2008. The plaintiffs appealed the dismissal of the lawsuit and, in May 2009, the Georgia Court of Appeals reversed the lower court’s order. In June 2009, Georgia Natural Gas filed a petition for reconsideration with the Georgia Supreme Court. In October 2009, the Georgia Supreme Court agreed to review the Court of Appeals’ decision and held oral arguments in January 2010. In March 2010 the Georgia Supreme Court upheld the Court of Appeals’ decision. The case has been remanded back to the Superior Court of Fulton County for further proceedings. Georgia Natural Gas asserts that no violation of law or Georgia Commission rules has occurred. This case has not had, and is not expected to have, a material impact on our results of operation or financial condition.

We have been named as a defendant in several class action lawsuits brought by purported Nicor shareholders challenging Nicor’s proposed merger with us. The complaints allege that we aided and abetted alleged breaches of fiduciary duty by Nicor’s Board of Directors. The shareholder actions seek, among other things, declaratory and injunctive relief, including orders enjoining the defendants from completing the proposed merger and, in certain circumstances, damages. We believe the claims asserted in each lawsuit to be without merit and intend to vigorously defend against them. For more information on our proposed merger with Nicor see Note 3.

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Environmental Remediation Costs

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 current and former operating sites. For more information on our environmental remediation costs see Note 10 in our Consolidated Financial Statements and related notes in Item 8 of our Form 10-K for the year ended December 31, 2010.

Note 10 - Segment Information

We generate nearly all our operating revenues through the sale, distribution, transportation and storage of natural gas. Our operating segments comprise revenue-generating components of our company for which we produce separate information, internally, that we regularly use to make operating decisions and assess performance. Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. We manage our businesses through four operating segments – distribution operations, retail energy operations, wholesale services and energy investments and a nonoperating corporate segment.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. 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 energy operations segment includes retail natural gas marketing to end-use customers primarily in Georgia. Our wholesale services segment includes natural gas asset management and related logistics activities for each of our utilities as well as for nonaffiliated companies, natural gas storage arbitrage and related activities. Our energy investments segment includes a number of aggregated businesses that are related and complementary to our primary business. The most significant is the development and operation of high-deliverability natural gas storage assets. Our corporate segment includes intercompany eliminations and aggregated subsidiaries that are not significant enough on a stand-alone basis to warrant treatment as an operating segment, and that do not fit into one of our four operating segments.

We evaluate segment performance based primarily on the non-GAAP measure of EBIT, which includes the effects of corporate expense allocations. EBIT includes operating income and other income and expenses. Items 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 level. 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. Following are the reconciliations of EBIT to operating income, earnings before income taxes and net income for the three months ended March 31, 2011 and 2010.

	Three months ended March 31,
In millions	2011		2010
Operating income	$	238	$	253
Other income		1		2
EBIT		239		255
Interest expense, net		29		28
Earnings before income taxes		210		227
Income taxes		76		82
Net income	$	134	$	145

Information by segment on our Statements of Financial Position as of December 31, 2010, is as follows:

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	5,498		$	404
Retail energy operations		259			-
Wholesale services		1,326			-
Energy investments		479			14
Corporate (2)		(40	)		-
Consolidated	$	7,522		$	418

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

(2)	Our corporate segment’s assets consist primarily of cash and cash equivalents and property, plant and equipment 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 three months ended March 31, 2011 and 2010 are shown in the following tables.

2011
In millions	Distribution operations		Retail energy operations		Wholesale services			Energy investments		Corporate (3)			Consolidated
Operating revenues from external parties	$	505	$	290		$	53	$	30	$	-		$	878
Intercompany revenues (1)		38		-			-		-		(38	)		-
Total operating revenues		543		290			53		30		(38	)		878
Operating expenses
Cost of gas		268		201			3		21		(38	)		455
Operation and maintenance		90		20			16		5		-			131
Depreciation and amortization		36		1			-		2		2			41
Taxes other than income taxes		9		-			1		1		2			13
Total operating expenses		403		222			20		29		(34	)		640
Operating income (loss)		140		68			33		1		(4	)		238
Other income		1		-			-		-		-			1
EBIT	$	141	$	68		$	33	$	1	$	(4	)	$	239

Identifiable and total assets (2)	$	5,495	$	222		$	981	$	483	$	(155	)	$	7,026
Goodwill	$	404	$	-		$	-	$	14	$	-		$	418
Capital expenditures	$	80	$	1		$	-	$	7	$	6		$	94

2010
In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate (3)			Consolidated
Operating revenues from external parties	$	528	$	393		$	67	$	14	$	1		$	1,003
Intercompany revenues (1)		38		-			-		-		(38	)		-
Total operating revenues		566		393			67		14		(37	)		1,003
Operating expenses
Cost of gas		302		297			8		2		(38	)		571
Operation and maintenance		87		20			15		6		(3	)		125
Depreciation and amortization		34		1			-		2		3			40
Taxes other than income taxes		9		1			1		1		2			14
Total operating expenses		432		319			24		11		(36	)		750
Operating income (loss)		134		74			43		3		(1	)		253
Other income		2		-			-		-		-			2
EBIT	$	136	$	74		$	43	$	3	$	(1	)	$	255

Identifiable and total assets (2)	$	5,240	$	242		$	981	$	489	$	(122	)	$	6,830
Goodwill	$	404	$	-		$	-	$	14	$	-		$	418
Capital expenditures	$	70	$	1		$	-	$	40	$	3		$	114

(1)	Wholesale services records its energy marketing and risk management revenues on a net basis, which includes intercompany revenues of $147 million for the three months ended March 31, 2011 and $180 million for the three months ended March 31, 2010.

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

(3)	Our corporate segment’s assets consist primarily of cash and cash equivalents, property, plant and equipment 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 the Condensed Consolidated Financial Statements in this quarterly filing, as well as our Annual Report.

Forward-Looking Statements

Certain expectations and projections regarding our future performance referenced in this Management’s Discussion and Analysis of Financial Condition and Results of Operations 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 U.S. 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; the impact of acquisitions and divestitures; direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including recent disruptions in the capital markets and lending environment and the current economic downturn; and general economic conditions; uncertainties about environmental issues and the related impact of such issues; 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; acts of war or terrorism; and other factors described in detail in our filings with the SEC.

In addition, actual results may differ materially due to the expected timing and likelihood of completion of the proposed merger with Nicor, including the timing, receipt and terms and conditions of any required governmental and regulator approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management’s time and attention from our ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.

We caution readers that, in addition to the important factors described elsewhere in this report, the factors set forth in Item 1A, “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2010, among others, could cause our business, results of operations or financial condition in 2011 and thereafter 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 our Form 10-K or 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 U.S. federal securities law.

Overview

We are an energy services holding company whose principal business is the distribution of natural gas through our regulated natural gas distribution business. As of March 31, 2011, our six utilities served approximately 2.3 million end-use customers.

We are also involved in several related and complementary businesses, including retail natural gas marketing to end-use customers in Georgia, Ohio and Florida; natural gas asset management and related logistics activities for each of our utilities as well as for non-affiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability underground natural gas storage assets. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services and energy investments and a non-operating corporate segment.

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The distribution operations segment is subject to regulation and oversight by agencies in each of the six 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 operating expenses and to earn a reasonable return for our shareholders.

The operating revenues and EBIT of our distribution operations and retail energy operations segments are seasonal. During the Heating Season, natural gas usage and operating revenues are generally higher because 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, interest expense and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, our operating results vary significantly from quarter to quarter as a result of seasonality.

With the exception of Atlanta Gas Light, our 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. Various mechanisms exist that limit our exposure to weather changes within typical ranges in all of our jurisdictions.

Virginia Natural Gas and Chattanooga Gas both have decoupled rates, which separate the recovery of fixed costs for providing service from the volumes of customer throughput. In traditional rate designs, our utilities’ recovery of a significant portion of their fixed customer service and pipeline infrastructure costs is tied to assumed natural gas volumes used by our customers. We believe that separating the recoverable amount of these costs from the customer throughput volumes, or amounts of natural gas used by our customers, allows us to encourage our customers’ energy conservation and ensures a more stable recovery of our fixed costs.

Our retail energy operations segment, which consists primarily of SouthStar, uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. Our Sequent subsidiary within our wholesale services segment generally has greater opportunity to capture operating margin due to price volatility as a result of extreme weather. Our energy investments segment’s primary activity is our natural gas storage business, which develops, acquires and operates high-deliverability salt-dome storage assets in the Gulf Coast region of the United States. 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 with third parties at a fixed market rate. For additional information on our operating segments see Item 1, “Business” of our Annual Report on Form 10-K for the year ended December 31, 2010.

Changes in commodity prices subject a significant portion of our operations to earnings variability. 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. For more information on our derivative financial instruments see Note 5.

Executive Summary

Proposed merger with Nicor

In December 2010, we entered into a Merger Agreement with Nicor, which we expect to complete during the second half of 2011. We continue to work on securing the necessary regulatory and shareholder approvals, all of which we anticipate we will obtain, which are discussed below.

In January 2011, we filed a joint application with Nicor with the Illinois Commerce Commission for approval of the proposed merger. The application did not request a rate increase and included a commitment to maintain 2,070 full-time equivalent employees involved in the operation of Nicor’s gas distribution subsidiary for a period of three years following the completion of the merger. The Illinois Commerce Commission has eleven months to act on the application; however, we and Nicor have asked for approval of the merger by October 1, 2011.

·	In January 2011, we filed a joint application with Nicor with the California Public Utilities Commission for approval to transfer ownership of Central Valley Gas Storage from Nicor to us. We currently anticipate receipt of this approval during the first half of 2011.

·	Shareholder approval by both companies. We and Nicor have scheduled our special shareholder meetings for June 14, 2011. The results of the shareholder votes will be announced at these meetings.

In April 2011, the Department of Justice and the Federal Trade Commission granted us early termination of the waiting period under the Hart-Scott-Rodino Act. Additionally, in April 2011, the SEC declared our registration statement on Form S-4 effective.

For additional information relating to the proposed merger please see our Form 8-K filed on December 7, 2010 and Note 3. Further information concerning the proposed merger was included in a joint proxy statement / prospectus contained in our amended registration statement on Form S-4/A that was filed with the SEC on April 28, 2011.

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Regulatory Strategy

We continue to pursue a regulatory strategy that focuses on creating value for our various stakeholders, by maintaining a reasonable rate of return for our investors and investing in the reliability and safety of our energy infrastructure. For additional information on our regulatory strategy, see caption “Utility Regulation and Rate Design” under Item 1 “Business” of our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on February 9, 2011.

In February 2011, Virginia Natural Gas filed a rate case proceeding with the Virginia Commission, requesting a net increase in base rates of $25 million. If approved, the revised rate design would reflect the first increase in customer base rates since 1996. The rate adjustment is designed to recover the cost of investments in our pipeline infrastructure over the past ten years, including the Hampton Roads pipeline project recently completed in January 2010. The rate application seeks a return on equity of 10.95%, and an authorization of equity to total capitalization ratio of 51%. Rates are expected to be effective by August 1, 2011, subject to refund.

Under the proposed rate design, the typical residential customer’s bill would reflect an increase of $6.27 per month, or approximately nine percent. In consideration of current depressed economic conditions, we are proposing a three year phase-in approach that would adjust customer charges by $3.11 per month for the first year, with incremental increases of less than $2.00 per month in the second and third year. The Virginia Commission has scheduled the formal hearing in October 2011 and pre-filed testimonies will be accepted by the Virginia Commission during the period of August 23rd through October 15th, 2011.

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, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. The table below and the following discussions provide updates on some of our larger capital projects.

Distribution Operations

	Three months ended March 31,
In millions	2011		2010
Pipeline replacement program	$	15	$	16
Integrated System Reinforcement Program		26		1
Integrated Customer Growth Program		1		-
Enhanced infrastructure program		-		5
Total	$	42	$	22

Atlanta Gas Light In October 2009, the Georgia Commission approved Atlanta Gas Light’s STRIDE program. As approved, STRIDE is comprised of the ongoing pipeline replacement program, which was started in 1998 and the new Integrated System Reinforcement Program (i-SRP).

The purpose of the i-SRP program under STRIDE is to upgrade Atlanta Gas Light’s distribution system and liquefied natural gas facilities in Georgia, improve its system reliability and operational flexibility and create a platform to meet long-term forecasted growth. Under STRIDE, Atlanta Gas Light is required to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new three-year construction plan every three years for review and approval by the Georgia Commission.

In January 2010, the Georgia Commission also approved the Integrated Customer Growth Program (i-CGP) under STRIDE which authorized Atlanta Gas Light to extend Atlanta Gas Light’s pipeline facilities to serve customers without pipeline access and create new economic development opportunities in Georgia.

Elizabethtown Gas In 2009, the New Jersey BPU approved an accelerated enhanced infrastructure program, which was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. A regulatory cost recovery mechanism has been established whereby estimated rates go into effect at the beginning of each year. At the end of the program the regulatory cost recovery mechanism will be trued-up and any remaining costs not previously collected will be included in base rates. In December 2010, Elizabethtown Gas made a request to the New Jersey BPU to spend an additional $40 million under this program to be spent in 2011 and 2012. The outcome of this request is still pending.

Energy Investments

Golden Triangle Storage Our Golden Triangle Storage project consists of a salt-dome storage facility in the Gulf Coast region of the U.S. designed for 12 Bcf of working natural gas capacity and total cavern capacity of 18 Bcf. The first cavern with 6 Bcf of working capacity was completed and began commercial service in September 2010.The second cavern with an expected 6 Bcf of working capacity is expected to be placed into commercial service in 2012. Golden Triangle Storage currently has 2 BCF under firm subscription, which represents approximately 33% of its current working natural gas capacity. Our estimate to complete both caverns, based on current prices for labor, materials and pad gas, is approximately $325 million. We spent approximately $4 million in capital expenditures for this project for the three months ended March 31, 2011 and $37 million for the same period last year.

Jefferson Island In June 2010, Jefferson Island filed a permit application with the Louisiana Department of Natural Resources to expand its natural gas storage facility through the addition of two caverns. We continue to seek approval to expand our storage facility; however, we cannot predict when this approval will be obtained. The caverns would expand the working gas capacity at Jefferson Island from 7.5 Bcf to approximately 19.5 Bcf.

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Capital Market Activity

In March 2011, we completed a public offering of $500 million in senior notes that mature in 2041 with an interest rate of 5.875%. The net proceeds were used to repay commercial paper, a portion of which we borrowed to repay our $300 million in senior notes that matured in January 2011. We intend to use the remaining net proceeds to pay a portion of the cash consideration and related expenses incurred in connection with the proposed merger with Nicor, if completed, or for other general corporate purposes. In connection with our issuance of these senior notes, and in accordance with the terms of the Bridge Facility, the principal amount of the Bridge Facility has been reduced from $1.05 billion to $852 million. For more information on our senior notes see Note 7.

Energy Marketing Activities

Sequent’s expected natural gas withdrawals from physical salt dome and reservoir storage are presented in the following table along with the operating revenues expected at the time of withdrawal for March 2011 and March 2010. Sequent’s expected operating revenues are net of the estimated impact of profit sharing and reflect the amounts that are realizable in future periods based on its expected inventory withdrawal schedule and forward natural gas prices at March 31, 2011 and 2010. A portion of Sequent’s storage inventory is economically hedged with futures contracts, which results in realization of substantially fixed operating revenues, timing notwithstanding.

	Withdrawal schedule
	(in Bcf)				Expected
	Salt dome (WACOG $3.87)		Reservoir (WACOG $3.36)		operating revenues (in millions)
2011
Second quarter		-		2	$	2
Third quarter		1		3	$	3
Fourth quarter		1		3	$	3
2012
First quarter		-		2	$	3
Total at Mar. 31, 2011		2		10	$	11
Total at Mar. 31, 2010		2		12	$	6

If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, it expects operating revenues from storage withdrawals of approximately $11 million during the next twelve months. This will change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate. In addition, inventory balances are usually near their lowest point at the end of the first quarter just prior to the start of the inventory injection season as inventories are built for the next heating season.

Asset Management Transactions

In March 2011, the New Jersey BPU authorized the renewal of the asset management agreement between Elizabethtown Gas and Sequent. Expiring in March 2014, the renewed agreement requires Sequent to pay minimum annual fees of $5 million to Elizabethtown Gas and includes overall margin sharing levels of 30% to Sequent and 70% to Elizabethtown Gas.

Results of Operations

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 gas, which excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets. These items are included in our calculation of operating income as reflected in our Condensed Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income, 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 level.

We believe operating margin is a better indicator than operating revenues for the contribution resulting from customer growth in our distribution operations segment since the cost of gas can vary significantly and is generally billed directly to our customers. We also consider operating margin to be a better indicator in our retail energy operations, wholesale services and energy investments 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 or EBIT measures may not be comparable to similarly titled measures from other companies.

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The following table sets forth a reconciliation of our operating margin to operating income and EBIT to our earnings before income taxes and net income, together with other consolidated financial information for the three months ended March 31, 2011 and 2010.

	Three months ended March 31,
In millions	2011		2010		Change
Operating revenues	$	878	$	1,003	$	(125	)
Cost of gas		455		571		(116	)
Operating margin (1)		423		432		(9	)
Operating expenses		185		179		6
Operating income		238		253		(15	)
Other income		1		2		(1	)
EBIT (1)		239		255		(16	)
Interest expense, net		29		28		1
Earnings before income taxes		210		227		(17	)
Income tax expense		76		82		(6	)
Net income		134		145		(11	)
Net income attributable to the noncontrolling interest		10		11		(1	)
Net income attributable to AGL Resources Inc.	$	124	$	134	$	(10	)

(1) These are non-GAAP measurements.

For the first quarter of 2011, net income attributable to AGL Resources Inc. decreased by $10 million or 7% compared to the same period last year. The decrease was primarily the result of reduced operating margins at wholesale services, retail energy operations and energy investments, as well as higher operating expenses primarily at distribution operations. This decrease was partially offset by higher operating margins at distribution operations and decreased income taxes as a result of lower earnings. Additionally, during the three months ended March 31, 2011, we recorded approximately $5 million ($3 million net of tax) of non-recurring transaction expenses associated with the proposed merger with Nicor. These costs are expensed as incurred. The variances for each operating segment are contained within the first quarter 2011 compared to first quarter 2010 discussion on the following pages.

Our income tax expense decreased by $6 million or 7% for the first quarter of 2011 compared to the first quarter of 2010. This was primarily due to lower consolidated earnings. Our income tax expense is determined from earnings before income taxes less net income attributable to the noncontrolling interest.

Selected weather, customer and volume metrics, which we consider to be some of the key performance indicators for our operating segments, for the three months ended March 31, 2011 and 2010, are presented in the following tables. 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. However, extended and unusually mild weather during the Heating Season can have a significant negative impact on demand for natural gas. Our customer metrics highlight the average number of customers to which we provide services. This number of customers can be impacted by natural gas prices, economic conditions and competition from alternative fuels.

Volume metrics for distribution operations and retail energy operations present the effects of weather and our customers’ demand for natural gas. Wholesale services’ daily physical sales represent the daily average natural gas volumes sold to its customers. Within our energy investments 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.

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Weather
Heating Degree Days (1)
		Three months ended March 31,						2011 vs. normal colder			2011 vs. 2010 colder
		Normal		2011		2010		(warmer)			(warmer)
Georgia			1,498		1,470		1,952		(2	)%		(25	)%
Virginia			1,829		1,908		2,029		4	%		(6	)%
New Jersey			2,528		2,549		2,397		1	%		6	%
Florida			363		241		719		(34	)%		(66	)%
Tennessee			1,691		1,673		2,116		(1	)%		(21	)%
Maryland			2,521		2,630		2,477		4	%		6	%
Ohio			2,599		2,616		2,831		1	%		(8	)%
(1)	Obtained from weather stations relevant to our service areas at the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages from 2002 through March 31, 2011.

Customers		Three months ended March 31,
		2011			2010			% change
Distribution Operations
Average end-use customers (in thousands)
Atlanta Gas Light			1,569			1,567			0.1	%
Virginia Natural Gas			280			278			0.7	%
Elizabethtown Gas			276			275			0.4	%
Florida City Gas			104			104			-
Chattanooga Gas			63			63			-
Elkton Gas			6			6			-
Total			2,298			2,293			0.2	%

Retail Energy Operations
Average customers (in thousands)
Georgia			498			507			(2	)%
Ohio and Florida (2)			71			106			(33	)%
Total			569			613			(7	)%
Market share in Georgia			32	%		33	%		(3	)%
(2)	A portion of the Ohio customers represents customer equivalents, which are computed by the actual delivered volumes divided by the expected average customer usage.


Volumes In billion cubic feet (Bcf)	Three months ended March 31,
	2011			2010			% change
Distribution Operations
Firm		101			122			(17	)%
Interruptible		27			27			-
Total		128			149			(14	)%

Retail Energy Operations
Georgia firm		18			24			(25	)%
Ohio and Florida		4			6			(33	)%

Wholesale Services
Daily physical sales (Bcf/day)		5.8			4.9			18	%
Energy Investments
Working natural gas capacity		13.5			7.5			80	%
% of capacity under subscription		66	%		93	%		(29	)%

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First quarter 2011 compared to first quarter 2010

Operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the three months ended March 31, 2011 and 2010.

In millions	Operating margin (1)		Operating expenses		EBIT (1)
2011
Distribution operations	$	275	$	135	$	141
Retail energy operations		89		21		68
Wholesale services		50		17		33
Energy investments		9		8		1
Corporate (2)		-		4		(4	)
Consolidated	$	423	$	185	$	239

In millions	Operating margin (1)		Operating expenses		EBIT (1)
2010
Distribution operations	$	264	$	130	$	136
Retail energy operations		96		22		74
Wholesale services		59		16		43
Energy investments		12		9		3
Corporate (2)		1		2		(1	)
Consolidated	$	432	$	179	$	255

(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.

(2)	Includes intercompany eliminations.

Distribution operations’ EBIT increased by $5 million or 4% compared to last year as shown in the following table.

In millions
EBIT for first quarter of 2010				$	136

Operating margin
Increased revenues from new rates and regulatory infrastructure program revenues at Atlanta Gas Light	$	9
Increased revenues from enhanced infrastructure program revenues at Elizabethtown Gas		3
Decreased revenues from lower usage at Florida City Gas due to warmer weather in 2011		(1	)
Increase in operating margin					11

Operating expenses
Increased compensation expenses	$	3
Increased pension expense		1
Increased depreciation expense		2
Decreased bad debt and other expenses		(1	)
Increase in operating expenses					5
Decrease in other income					(1	)
EBIT for first quarter of 2011				$	141

Retail energy operations’ EBIT decreased by $6 million or 8% compared to last year as shown in the following table.

In millions
EBIT for first quarter of 2010				$	74

Operating margin
Decreased average customer usage due to warmer weather	$	(4	)
Decrease related to retail pricing plan mix and optimization of storage and transportation		(2	)
Other		(1	)
Decrease in operating margin					(7	)

Operating expenses
Decreased bad debt expense	$	(1	)
Decrease in operating expenses					(1	)
EBIT for first quarter of 2011				$	68

Wholesale services’ EBIT decreased by $10 million or 23% compared to last year as shown in the following table.

In millions
EBIT for first quarter of 2010				$	43

Operating margin
Change in commercial activity	$	8
Change in LOCOM adjustment		4
Change in transportation hedge gains from the narrowing of transportation basis spreads		(10	)
Change in storage hedge gains as a result of changing NYMEX natural gas prices		(11	)
Decrease in operating margin					(9	)

Operating expenses
Increased incentive compensation costs	$	1
Increase in operating expenses					1
EBIT for first quarter of 2011				$	33

The following table indicates the components of wholesale services’ operating margin for the three months ended March 31, 2011 and 2010.

In millions	2011		2010
Commercial activity recognized	$	49	$	41
Gain on transportation hedges		1		11
Gain on storage hedges		-		11
Inventory LOCOM adjustment		-		(4	)
Operating margin	$	50	$	59

Energy investments’ EBIT decreased by $2 million compared to last year as shown in the following table.

In millions
EBIT for first quarter of 2010				$	3

Operating margin
Decreased operating revenues due to sale of AGL Networks, LLC	$	(6	)
Increased revenues at Golden Triangle Storage as a result of the start of commercial service in September 2010		3
Decrease in operating margin					(3	)

Operating expenses
Decreased operating expenses due to sale of AGL Networks, LLC	$	(3	)
Increase in operating and depreciation expenses at Golden Triangle Storage as a result of the start of commercial service in September 2010		2
Decrease in operating expenses					(1	)
EBIT for first quarter of 2011				$	1

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Liquidity and Capital Resources

Overview The acquisition of natural gas, pipeline capacity, payment of dividends and working capital requirements 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. Additionally, we anticipate incurring indebtedness in connection with financing the consideration for the proposed Nicor merger.

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 by cash from operations are primarily satisfied with short-term borrowings under our commercial paper program, which is supported by our 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.

Our capital market strategy has continued to focus on maintaining a strong Consolidated Statement 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 balance of equity or long-term debt securities.

Our issuance of various securities, including long-term and short-term debt and equity, is subject to customary approval or review by state and federal regulatory bodies including the various public service commissions of the states in which we conduct business, the SEC and the FERC. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow are 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.

We believe the amounts available to us under our senior notes, Credit Facility and Bridge 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, construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments, common share repurchases, financing requirements for the proposed Nicor merger and other cash needs through the next several years. Nevertheless, our ability to satisfy our working capital requirements and 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 natural gas, the demand for natural gas and operational risks.

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, the proposed merger with Nicor and other factors. See Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2010, for additional information on items that could impact our liquidity and capital resource requirements.

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the three months ended March 31, 2011 and 2010.

	Three months ended March 31,
In millions	2011			2010
Net cash provided by (used in):
Operating activities	$	718		$	673
Investing activities		(94	)		(117	)
Financing activities		(563	)		(563	)
Net increase (decrease) in cash and cash equivalents	$	61		$	(7	)

Cash Flow from Operating Activities In the first three months of 2011, our net cash flow provided from operating activities was $718 million, an increase of $45 million or 7% from the same period in 2010. This increase was primarily a result of the recovery of $76 million in working capital in 2011 as a result of colder weather in December 2010 as compared to last year. We also had an increase in cash of $23 million from deferred natural gas costs as a result of fluctuations in natural gas prices as well as an increase in cash of $17 million in trade payables primarily due to the timing differences of wire transfer payments and receipts. These increases were offset by an increase in working capital requirements for Sequent’s energy marketing activities of $41 million during the current year, which was primarily driven by the effects of the timing of payments for gas purchases relative to collections of accounts receivable. Additionally, we had a $24 million decrease in cash from inventories, which was mainly driven by reduced storage volumes at Sequent and Golden Triangle Storage, partially offset by higher storage volumes at SouthStar.

Cash Flow from Investing Activities Our investing activities consisted of PP&E expenditures of $94 million for the three months ended March 31, 2011 compared to $117 million for the same period in 2010. The decrease of $23 million or 20% in PP&E expenditures was primarily due to a $33 million decrease in expenditures for the construction of the Golden Triangle Storage natural gas storage facility, a $7 million decrease in expenditures for system preservation and upgrades to automate meter readings and a $5 million reduction in expenditures for AGL Networks projects. This was offset by increased expenditures of $25 million for STRIDE and other capital projects in distribution operations.

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Cash Flow from Financing Activities Our cash used in financing activities was $563 million for the three months ended March 31, 2011, which is in line with the cash used in financing activities for the same period in 2010. Our cash increased by $500 million due to our senior note offering in March 2011. Our prior year purchase of an additional 15% ownership interest in SouthStar resulted in an increase in cash of $58 million compared to the same period in 2010. Offsetting these amounts was our $300 million payment for our senior notes that matured in January 2011. Additionally, net payments on short-term debt increased by $259 million when compared to the same period in 2010 as we paid down our commercial paper borrowings with the remaining proceeds from our senior note offering and cash on hand.

Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of equity and debt securities. This strategy includes active management of the percentage of total debt relative to total capitalization, appropriate mix of debt with fixed to floating interest rates (our variable-rate debt target is 20% to 45% of total debt), as well as the term and interest rate profile of our debt securities. As of March 31, 2011, our variable-rate debt was 8% of our total debt, compared to 15% as of March 31, 2010. The decrease in our variable-rate debt at March 31, 2011 compared to the same period last year was primarily due to an increase of $200 million in fixed-rate debt resulting from our $500 million senior note offering, which was offset by the January 2011 maturity of $300 million in senior notes. Additionally, our commercial paper borrowings decreased $128 million as a portion of the proceeds from the senior note offering in March 2011 and cash on hand was used to pay down our commercial paper borrowings.

Credit Ratings Our borrowing costs and ability to obtain adequate and cost effective financing are directly impacted by our credit ratings as well as the availability of financial markets. In addition, credit ratings are important to counterparties when we engage in certain transactions including over-the-counter derivatives. It is our long-term objective to maintain or improve our credit ratings on our debt 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. Each rating should be evaluated independently of any other rating. The rating agencies regularly review our performance, prospects and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, including our corporate ratings.

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.

Factors we consider important in assessing our credit ratings include our Statements of Financial Position leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger 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, 2011, and reflects no change from December 31, 2010.

	S&P	Moody’s	Fitch
Corporate rating	A-		A-
Commercial paper	A-2	P-2	F2
Senior unsecured	BBB+	Baa1	A-
Ratings outlook	Negative	Stable	Stable

Subsequent to the announcement of our proposed merger with Nicor, S&P placed our long-term debt ratings and our corporate credit ratings on credit watch with negative implications. The primary reason for this change is the increased leverage we will assume to complete the proposed merger and the uncertainties that exist with the proposed merger.

Our credit ratings depend largely on our financial performance, and a downgrade in our current ratings, particularly below investment grade, could adversely affect our borrowing costs and significantly 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 would decrease.

Default provisions As of March 31, 2011, December 31, 2010 and March 31, 2010, we were in compliance with all of our existing debt provisions and covenants, both financial and non-financial. Additionally, our Bridge Facility contains the same financial covenant and similar non-financial covenants and default provisions as contained in our Credit Facility; however, most of these are not in effect until we draw under the facility.

Our ratio, on a consolidated basis, of total debt to total capitalization 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 capitalization ratio 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 7. The components of our capital structure, as calculated from our Condensed Consolidated Statements of Financial Position, as of the dates indicated, are provided in the following table.

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	Mar. 31, 2011		Dec. 31, 2010		Mar. 31, 2010
Short-term debt	1	%	23	%	11	%
Long-term debt	53		37		42
Total debt	54		60		53
Equity	46		40		47
Total capitalization	100	%	100	%	100	%

Short-term debt Our short-term debt during the quarter was composed of borrowings and payments under our Credit Facility and commercial paper program, Term Loan Facility, the current portion of our capital leases and our senior notes maturing in less than one year.

	Period end balance outstanding		Daily average balance outstanding		Largest balance outstanding
In millions		(1)		(2)		(2)
Commercial paper	$	25	$	623	$	835
Capital leases		1		1		1
Current portion of long-term debt		-		47		300
Term loan facility		-		50		150

(1)	As of March 31, 2011.

(2)	For the three months ended March 31, 2011.

The largest amounts borrowed on our commercial paper borrowings are important when assessing the intra-period fluctuation of our short-term borrowings and any potential liquidity risk. Our short-term debt financing generally increases between June and December as we purchase natural gas in advance of the Heating Season. The variation of when we pay our suppliers for natural gas purchases and when we recover our costs from our customers through their monthly bills can significantly affect our short-term cash requirements. Our short-term debt balances are typically reduced during the Heating Season because a significant portion of our current assets, primarily natural gas inventories, are converted into cash.

During the first quarter of 2011, our short-term debt balances were also impacted by our $300 million senior notes, which were current at December 31, 2010 and matured in January 2011. These senior notes were initially repaid with a $150 million funding under our Term Loan Facility and borrowings under our commercial paper program.

In February 2011, the Term Loan Facility was repaid through additional commercial paper borrowings at which time the Term Loan Facility expired. In March 2011, we completed a new $500 million senior note offering, using a portion of the proceeds to reduce outstanding commercial paper to $25 million at March 31, 2011, as compared to $732 million at December 31, 2010 and $153 million at March 31, 2010.

The timing of natural gas withdrawals is dependent on the weather and natural gas market conditions, both of which impact the price of natural gas. Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected purchases during the upcoming injection season, a $1 increase per Mcf in natural gas prices could result in an additional $60 to $70 million of working capital requirements during the peak of the Heating Season based upon our current injection plan. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position.

The lenders under our Credit Facility and Bridge Facility are all major financial institutions with approximately $2.1 billion of committed balances and all have investment grade credit ratings as of March 31, 2011. 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. As of March 31, 2011 and 2010, we had no outstanding borrowings on our Credit Facility or Bridge Facility.

Long-term debt Our long-term debt matures more than one year from the date of our Statements of Financial Position and consists of medium-term notes, senior notes, gas facility revenue bonds and capital leases.

In March 2011, we completed a public offering of $500 million senior notes that mature in 2041 with an interest rate of 5.875%. A portion of the net proceeds of this offering was used to pay down the commercial paper borrowings that were used to repay the $300 million of senior notes that matured in January 2011. The remaining proceeds are expected to be used to pay a portion of the cash consideration and expenses incurred in connection with the proposed merger with Nicor, if completed, or for other general corporate purposes. In connection with our issuance of these senior notes, and in accordance with the terms of the Bridge Facility, the principal amount of the Bridge Facility has been reduced from $1.05 billion to $852 million. For more information on our senior notes see Note 7.

Noncontrolling Interest In We recorded cash distribution for SouthStar’s dividends paid to Piedmont of $16 million for the three months ended March 31, 2011 and $27 million for the three months ended March 31, 2010.

Dividends on Common Stock Our common stock dividend payments were $34 million for the three months ended March 31, 2011 and $33 million for the three months ended March 31, 2010. The increase was generally the result of annual dividend increases of $0.04 per share for each of the last two years. For information about restrictions on our ability to pay dividends on our common stock, see Note 2.

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Contractual Obligations and Commitments 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 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.

Pension Contributions In the first three months of 2011 we contributed $38 million to our qualified pension plans and an additional $6 million in April 2011 for a total of $44 million during 2011. We plan to make additional contributions up to $12 million, for a total of up to $56 million during 2011. Based on the funding status of the plans as of December 31, 2010, we were required to make a minimum contribution to the plans of $30 million in 2011. In the three months ended March 31, 2010, we contributed $17 million to our pension plans and through April 2010, we contributed $21 million.

During the three months ended March 31, 2011, we recorded net periodic benefit costs of $5 million related to our defined pension and postretirement benefit plans compared to $4 million during the same period last year. We estimate that during the remainder of 2011, we will record net periodic pension and other postretirement benefit costs in the range of $14 million to $16 million, a $2 million increase compared to 2010. In determining our estimated expenses for 2011, our actuarial consultant assumed an 8.50% expected return on plan assets and a discount rate of 5.40% for the AGL Retirement Plan and 5.20% for the NUI Retirement Plan and for our postretirement plan.

The following table illustrates our expected future contractual obligation payments such as debt and lease agreements, and commitments and contingencies as of March 31, 2011.

					2012 &		2014 &		2016 &
In millions	Total		2011		2013		2015		thereafter
Recorded contractual obligations:

Long-term debt	$	2,173	$	-	$	242	$	200	$	1,731
Regulatory infrastructure program costs (1)		212		47		165		-		-
Environmental remediation liabilities (1)		141		11		63		53		14
Short-term debt		26		26		-		-		-
Total	$	2,552	$	84	$	470	$	253	$	1,745

Unrecorded contractual obligations and commitments (2) (7):

Pipeline charges, storage capacity and gas supply (3)	$	1,909	$	446	$	704	$	290	$	469
Interest charges (4)		1,740		88		224		201		1,227
Operating leases (5)		111		20		40		20		31
Asset management agreements (6)		26		10		14		2		-
Standby letters of credit, performance / surety bonds		16		12		4		-		-
Total	$	3,802	$	576	$	986	$	513	$	1,727

(1)	Includes charges recoverable through rate rider mechanisms.

(2)	In accordance with GAAP, these items are not reflected in our Condensed Consolidated Statements of Financial Position.

(3)

Charges recoverable through a natural gas cost recovery mechanism or alternatively billed to Marketers, and includes demand charges associated with Sequent. Also includes SouthStar’s natural gas purchase commitments of 23 Bcf at floating gas prices calculated using forward natural gas prices as of March 31, 2011, and are valued at $97 million.

(4)	Floating rate debt is based on the interest rate as of March 31, 2011, and the maturity of the underlying debt instrument. As of March 31, 2011, we have $30 million of accrued interest on our Condensed Consolidated Statements of Financial Position that will be paid over the next 12 months.

(5)

We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Additionally, minimum payments have not been reduced by minimum sublease rentals of $15 million due in the future under noncancelable subleases.

(6)	Represent fixed-fee minimum payments for Sequent’s asset management agreements.

(7)

The Merger Agreement with Nicor contains termination rights for both us and Nicor and provides that, if we terminate the agreement under specified circumstances, we may be required to pay a termination fee of $67 million. In addition, if we terminate the agreement due to a failure to obtain the necessary financing for the transaction, we may also be required to pay Nicor $115 million.

Glossary of Key Terms

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Critical 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 of contingent assets and liabilities. We based our estimates on historical experience, where applicable, and various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates on an ongoing basis, and our actual results may differ from these estimates. Our critical accounting estimates used in the preparation of our Condensed Consolidated Financial Statements include the following:

·	Regulatory Infrastructure Program Liabilities

·	Environmental Remediation Liabilities

·	Derivatives and Hedging Activities

·	Contingencies

·	Pension and Other Postretirement Plans

·	Income Taxes

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 Operation as filed on Form 10-K with the SEC on February 9, 2011.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to risks associated with natural gas prices, interest rates and credit. 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 Risk Management Committee (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 financial instruments are described in further detail in Note 5.

Natural Gas Price Risk

The following tables include the fair value and average values of our consolidated derivative financial instruments as of the dates indicated. We base the average values on monthly averages for the three months ended March 31, 2011 and 2010.

	Derivative financial instruments average values (1) at March 31,
In millions	2011		2010
Asset	$	210	$	209
Liability		47		7

(1)	Excludes cash collateral amounts.

	Derivative financial instruments fair values netted with cash collateral at
In millions	Mar. 31, 2011		Dec. 31, 2010		Mar. 31, 2010
Asset	$	153	$	228	$	261
Liability		28		48		82

The following tables illustrate the change in the net fair value of our derivative financial instruments during the three months ended March 31, 2011 and 2010, and provide details of the net fair value of contracts outstanding as of March 31, 2011 and 2010.

	Three months ended March 31,
In millions	2011			2010
Net fair value of derivative financial instruments outstanding at beginning of period	$	75		$	121
Derivative financial instruments realized or otherwise settled during period		(55	)		(64	)
Change in net fair value of derivative financial instruments		17			16
Net fair value of derivative financial instruments outstanding at end of period		37			73
Netting of cash collateral		88			105
Cash collateral and net fair value of derivative financial instruments outstanding at end of period	$	125		$	178

The sources of net fair value of our natural gas-related derivative financial instruments at March 31, 2011, are as follows:

In millions	Prices actively quoted (Level 1) (1)			Significant other observable inputs (Level 2) (2)
Mature through
2011	$	(32	)	$	43
2012 – 2013		(17	)		41
2014 – 2016		-			2
Total derivative financial instruments (3)	$	(49	)	$	86

(1)	Valued using NYMEX futures prices and other quoted sources.

(2)	Values primarily related to 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.

Glossary of Key Terms

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Value at Risk Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the chief risk officer. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally 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 its open positions.

Management actively monitors open natural gas positions and the resulting VaR. We continue to maintain a relatively matched book, where our total buy volume is close to 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 of positions for the three months ended March 31, 2011 and 2010 had the following VaRs.

	Three months ended March 31,
In millions	2011		2010
Period end	$	1.8	$	0.7
Average		1.4		1.4
High		1.8		3.0
Low		0.9		0.7

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 $185 million of variable-rate debt outstanding at March 31, 2011, a 100 basis point change in average market interest rates from 0.26% to 1.26% would have resulted in an increase in pretax interest expense of $2 million on an annualized basis.

Credit Risk

Wholesale Services Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. Sequent also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Sequent is engaged in more than one outstanding derivative transaction with the same counterparty and it has 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 Sequent’s credit risk. Sequent also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Sequent to net certain assets and liabilities by counterparty. Sequent also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions.

Additionally, Sequent may require counterparties to pledge additional collateral when deemed necessary. Sequent conducts credit evaluations and obtains appropriate internal approvals for its 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, Sequent requires credit enhancements by way of guaranty, cash deposit or letter of credit for counterparties that do not have investment grade ratings.

Sequent, which provides services to marketers and utility and industrial customers, also has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. As of March 31, 2011, Sequent’s top 20 counterparties represented approximately 56% of the total counterparty exposure of $395 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures. Sequent’s counterparties, or the counterparties’ guarantors, had a weighted-average S&P equivalent credit rating of BBB+ at March 31, 2011 and December 31, 2010 and A- at March 31, 2010. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P and Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being the 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 for 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. There were no credit defaults with Sequent’s counterparties in the quarter ended March 31, 2011.

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The following table shows Sequent’s third-party natural gas contracts receivable and payable positions as of March 31, 2011 and 2010 and December 31, 2010.

	Gross receivables						Gross payables
	Mar. 31,		Dec. 31,		Mar. 31,		Mar. 31,		Dec. 31,		Mar. 31,
In millions	2011		2010		2010		2011		2010		2010
Netting agreements in place:
Counterparty is investment grade	$	337	$	515	$	449	$	255	$	341	$	328
Counterparty is non-investment grade		8		11		3		37		40		19
Counterparty has no external rating		208		260		101		317		363		265
No netting agreements in place:
Counterparty is investment grade		9		2		10		14		-		8
Counterparty has no external rating		2		-		-		2		-		-
Amount recorded on statements of financial position	$	564	$	788	$	563	$	625	$	744	$	620

Sequent has 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, Sequent would need to post collateral to continue transacting business with some of its counterparties. If such collateral were not posted, Sequent’s ability to continue transacting business with these counterparties would be negatively impacted. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $28 million at March 31, 2011, which would not have a material impact to our condensed 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 Annual Report on Form 10-K for the year ended December 31, 2010.

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 in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of March 31, 2011, 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, 2011, 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, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 and litigation incidental to the business. For information regarding pending federal and state regulatory matters see “Note 9 - Commitments and Contingencies” contained in Item 1 of Part I under the caption “Notes to Condensed Consolidated Financial Statements (Unaudited).”

With regard to legal proceedings, we are a party, as both plaintiff and defendant, to a number of other suits, claims and counterclaims on an ongoing basis. Management believes that the outcome of all such other litigation in which it is involved has not had and will not have a material adverse effect on our Consolidated Financial Statements.

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

The following table sets forth information about purchases of our common stock by us and any affiliated purchasers during the three months ended March 31, 2011. Stock repurchases may be made in the open market or in private transactions at times and in amounts that we deem appropriate. However, there is no guarantee as to the exact number of additional shares that may be repurchased, and we may terminate or limit the stock repurchase program at any time. We currently anticipate holding the repurchased shares as treasury shares.

Period	Total number of shares purchased (1) (2)		Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (2)		Maximum number of shares that may yet be purchased under the publicly announced plans or programs (2)
January 2011		54,450	$	36.22		54,450		4,707,051
February 2011		10,800		36.38		10,800		4,696,251
March 2011		30,000		21.91		-		4,696,251
Total first quarter		95,250	$	31.73		65,250

(1)

On March 20, 2001, our Board of Directors approved the purchase of up to 600,000 shares of our common stock in the open market to be used for issuances under the Officer Incentive Plan (Officer Plan). We purchased 30,000 shares for such purposes in the first quarter of 2011. As of March 31, 2011, we had purchased a total of 377,153 of the 600,000 shares authorized for purchase, leaving 222,847 shares available for purchase under this program.

(2)

On February 3, 2006, we announced that our Board of Directors had authorized a plan to repurchase up to a total of 8 million shares of our common stock, excluding the shares remaining available for purchase in connection with the Officer Plan as described in note (1) above, over a five-year period. This plan expired January 31, 2011 and 10,800 shares that were purchased in January 2011 settled in February 2011.

Item 6. Exhibits

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. (1)

101.SCH	XBRL Taxonomy Extension Schema. (1)

101.CAL	XBRL Taxonomy Extension Calculation Linkbase. (1)

101.DEF	XBRL Taxonomy Definition Linkbase. (1)

101.LAB	XBRL Taxonomy Extension Labels Linkbase. (1)

101.PRE	XBRL Taxonomy Extension Presentation Linkbase.(1)

(1) Furnished, not filed

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Condensed Consolidated Statements of Financial Position at March 31, 2011, December 31, 2010 and March 31, 2010; (iii) Condensed Consolidated Statements of Income for the three months ended March 31, 2011 and 2010; (iv) Condensed Consolidated Statements of Equity for the three months ended March 31, 2011 and 2010; (v) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2011 and 2010; (vi) Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010; and (vii) Notes to Condensed Consolidated Financial Statements.

Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability. We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

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SIGNATURE

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

AGL RESOURCES INC.

(Registrant)

Date: May 3, 2011 /s/ Andrew W. Evans

Executive Vice President and Chief Financial Officer

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