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, 2010

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 ¨ 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 20, 2010
Common Stock, $5.00 Par Value	77,849,493

Glossary of Key Terms

Table of Contents

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended March 31, 2010

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

Item
Number

		PART I – FINANCIAL INFORMATION		4 – 35

	1	Condensed Consolidated Financial Statements (Unaudited)		4 – 21
		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 (Loss)		7
		Condensed Consolidated Statements of Cash Flows		8
		Notes to Condensed Consolidated Financial Statements (Unaudited)		9 – 21
		Note 1 – Accounting Policies and Methods of Application		9 – 11
		Note 2 – Derivative Financial Instruments		11 – 14
		Note 3 – Employee Benefit Plans		15
		Note 4 – Variable Interest Entity		16 – 17
		Note 5 – Debt		18
		Note 6 – Commitments and Contingencies		19
		Note 7 – Segment Information		19 – 21
	2	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22 – 32
		Forward-Looking Statements		22
		Overview		22 – 23
		Executive Summary		23
		Distribution Operations		23 – 24
		Retail Energy Operations		24
		Wholesale Services		25
		Energy Investments		25 – 26
		Results of Operations		26 – 29
		Liquidity and Capital Resources		29 – 31
		Critical Accounting Estimates		32
	3	Quantitative and Qualitative Disclosures About Market Risk		32 – 35
	4	Controls and Procedures		35

		PART II – OTHER INFORMATION		36

	1	Legal Proceedings		36
	2	Unregistered Sales of Equity Securities and Use of Proceeds		36
	6	Exhibits		36

		SIGNATURE		37

Glossary of Key Terms

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GLOSSARY OF KEY TERMS

AGL Capital	AGL Capital Corporation
AGL Networks	AGL Networks, LLC
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Chattanooga Gas	Chattanooga Gas Company
Credit Facility	$1.0 billion credit agreement of AGL Capital
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 rates 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
GNG	Georgia Natural Gas, the name under which SouthStar does business in Georgia
Golden Triangle Storage	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of the effects of weather on our businesses, calculated when the average daily actual temperatures are less than a baseline temperature of 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
LOCOM	Lower of weighted average cost or current market price
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
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
OTC	Over-the-counter
Piedmont	Piedmont Natural Gas
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 STRIDE 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
Tennessee Authority	Tennessee Regulatory Authority, the state regulatory agency for Chattanooga Gas
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 goods

Glossary of Key Terms

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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, 2010		Dec. 31, 2009		Mar. 31, 2009
Current assets
Cash and cash equivalents	$	19	$	26	$	21
Receivables
Energy marketing receivables (Note 1)		563		615		326
Gas, unbilled and other receivables		417		362		458
Less allowance for uncollectible accounts		21		14		20
Total receivables		959		963		764
Inventories, net (Note 1)		370		672		348
Derivative financial instruments – current portion (Note 1 and Note 2)		205		188		202
Unrecovered regulatory infrastructure program costs – current portion (Note 1)		45		43		42
Unrecovered environmental remediation costs – current portion (Note 1)		10		11		16
Other current assets		41		97		38
Total current assets		1,649		2,000		1,431
Long-term assets and other deferred debits
Property, plant and equipment		6,025		5,939		5,592
Less accumulated depreciation		1,814		1,793		1,706
Property, plant and equipment-net		4,211		4,146		3,886
Goodwill		418		418		418
Unrecovered regulatory infrastructure program costs (Note 1)		258		223		177
Unrecovered environmental remediation costs (Note 1)		159		161		121
Derivative financial instruments (Note 1 and Note 2)		56		52		48
Other		74		74		76
Total long-term assets and other deferred debits		5,176		5,074		4,726
Total assets	$	6,825	$	7,074	$	6,157
Current liabilities
Energy marketing trade payable (Note 1)	$	620	$	524	$	342
Current portion of long-term debt (Note 5)		301		1		1
Accounts payable – trade		219		237		193
Short-term debt (Note 5)		153		601		402
Accrued expenses		137		132		151
Accrued regulatory infrastructure program costs – current portion (Note 1)		75		55		43
Derivative financial instruments – current portion (Note 1 and Note 2)		74		52		43
Customer deposits		52		41		58
Accrued environmental remediation liabilities – current portion (Note 1 and Note 6)		31		25		20
Other current liabilities		121		104		95
Total current liabilities		1,783		1,772		1,348
Long-term liabilities and other deferred credits
Long-term debt (Note 5)		1,674		1,974		1,675
Accumulated deferred income taxes		711		695		586
Accumulated removal costs (Note 1)		186		183		194
Accrued regulatory infrastructure program costs (Note 1)		169		155		126
Accrued pension obligations (Note 3)		146		159		188
Accrued environmental remediation liabilities (Note 1 and Note 6)		113		119		85
Accrued postretirement benefit costs (Note 3)		36		38		45
Derivative financial instruments (Note 1 and Note 2)		8		10		8
Other long-term liabilities and other deferred credits		148		150		139
Total long-term liabilities and other deferred credits		3,191		3,483		3,046
Total liabilities and other deferred credits		4,974		5,255		4,394
Commitments and contingencies (Note 6)
Equity
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,834		1,780		1,734
Noncontrolling interest (Note 4)		17		39		29
Total equity		1,851		1,819		1,763
Total liabilities and equity	$	6,825	$	7,074	$	6,157
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	2010			2009
Operating revenues	$	1,003		$	995
Operating expenses
Cost of gas		571			589
Operation and maintenance		125			125
Depreciation and amortization		40			39
Taxes other than income taxes		14			12
Total operating expenses		750			765
Operating income		253			230
Other income		2			2
Interest expense, net		(28	)		(25	)
Earnings before income taxes		227			207
Income tax expense		82			72
Net income		145			135
Less net income attributable to the noncontrolling interest (Note 4)		11			16
Net income attributable to AGL Resources Inc.	$	134		$	119
Per common share data (Note 1)
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	1.74		$	1.55
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	1.73		$	1.55
Cash dividends declared per common share	$	0.44		$	0.43
Weighted-average number of common shares outstanding (Note 1)
Basic		77.2			76.7
Diluted		77.6			76.8

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
	Common stock				Premium on common			Earnings			Accumulated other comprehensive			Treasury			Noncontrolling
In millions, except per share amounts	Shares		Amount		stock			reinvested			loss			shares			interest			Total
Balance as of Dec. 31, 2008		76.9	$	390	$	676		$	763		$	(134	)	$	(43	)	$	32		$	1,684
Net income		-		-		-			119			-			-			16			135
Other comprehensive loss		-		-		-			-			(7	)		-			(4	)		(11	)
Dividends on common stock ($0.43 per share)		-		-		-			(33	)		-			1			-			(32	)
Distributions to noncontrolling interest		-		-		-			-			-			-			(15	)		(15	)
Issuance of treasury shares		0.3		-		(6	)		(2	)		-			9			-			1
Stock-based compensation expense (net of tax) (Note 1)		-		-		1			-			-			-			-			1
Balance as of March 31, 2009		77.2	$	390	$	671		$	847		$	(141	)	$	(33	)	$	29		$	1,763

	AGL Resources Inc. Shareholders
	Common stock				Premium on common			Earnings			Accumulated other comprehensive			Treasury			Noncontrolling
In millions, except per share 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		-		-		-			-			-			-			(27	)		(27	)
Issuance of treasury shares		0.3		-		(9	)		-			-			12			-			3
Stock-based compensation expense (net of tax) (Note 1)		-		-		4			-			-			-			-			4
Balance as of March 31, 2010		77.8	$	390	$	622		$	948		$	(119	)	$	(7	)	$	17		$	1,851

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 (LOSS)

(UNAUDITED)

	Three months ended
	March 31,
In millions	2010			2009
Comprehensive income attributable to AGL Resources Inc. (net of tax)
Net income attributable to AGL Resources Inc.	$	134		$	119
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		(6	)		(9	)
Reclassification of derivative financial instruments realized losses included in net income		4			2
Other comprehensive loss		(2	)		(7	)
Comprehensive income (Note 1)	$	132		$	112

Comprehensive income attributable to noncontrolling interest (net of tax)
Net income attributable to noncontrolling interest	$	11		$	16
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		(1	)		(5	)
Reclassification of derivative financial instruments realized losses included in net income		1			1
Other comprehensive loss		-			(4	)
Comprehensive income (Note 1)	$	11		$	12

Total comprehensive income (net of tax)
Net income	$	145		$	135
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		(7	)		(14	)
Reclassification of derivative financial instruments realized losses included in net income		5			3
Other comprehensive loss		(2	)		(11	)
Comprehensive income (Note 1)	$	143		$	124

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	2010			2009
Cash flows from operating activities
Net income	$	145		$	135
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		40			39
Deferred income taxes		14			(10	)
Change in derivative financial instrument assets and liabilities		(1	)		(10	)
Changes in certain assets and liabilities
Inventories		302			315
Energy marketing receivables and energy marketing trade payables, net		148			26
Accrued expenses		5			38
Gas and trade payables		(18	)		(9	)
Gas, unbilled and other receivables		(48	)		18
Other – net		83			69
Net cash flow provided by operating activities		670			611
Cash flows from investing activities
Payments to acquire property, plant and equipment		(114	)		(97	)
Net cash flow used in investing activities		(114	)		(97	)
Cash flows from financing activities
Net payments and borrowings of short-term debt		(448	)		(463	)
Purchase of additional 15% ownership interest in SouthStar		(58	)		-
Dividends paid on common shares		(33	)		(32	)
Distribution to noncontrolling interest		(27	)		(15	)
Issuance of treasury shares and other		3			1
Net cash flow used in financing activities		(563	)		(509	)
Net (decrease) increase in cash and cash equivalents		(7	)		5
Cash and cash equivalents at beginning of period		26			16
Cash and cash equivalents at end of period	$	19		$	21
Cash paid during the period for
Interest	$	34		$	29
Income taxes	$	1		$	16

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 - Accounting Policies and Methods of Application

General

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

The year-end 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 of the SEC. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. However, the 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, 2009, filed with the SEC on February 4, 2010.

Due to the seasonal nature of our business, our results of operations for the three months ended March 31, 2010 and 2009, and our financial condition as of December 31, 2009, and March 31, 2010 and 2009, 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 variable interest entities 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.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, and we evaluate our estimates on an ongoing basis. Each of our estimates involves 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 our 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, 2010, December 31, 2009 and March 31, 2009, the collateral that wholesale services would have been required to post 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 impaired.

Glossary of Key Terms

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Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our condensed consolidated statements of financial position in accordance with authoritative guidance related to regulated operations. Our regulatory assets and liabilities, and associated liabilities for our unrecovered regulatory infrastructure program costs, unrecovered ERC and the derivative financial instrument assets and liabilities for Elizabethtown Gas’ hedging program, are summarized in the following table.

	Mar. 31,		Dec. 31,		Mar. 31,
In millions	2010		2009		2009
Regulatory assets
Unrecovered regulatory infrastructure program costs	$	303	$	266	$	219
Unrecovered ERC		169		172		137
Unrecovered postretirement benefit costs		10		10		11
Unrecovered seasonal rates		-		11		-
Other		29		27		28
Total regulatory assets		511		486		395
Associated assets
Derivative financial instruments		32		11		29
Total regulatory and associated assets	$	543	$	497	$	424
Regulatory liabilities
Accumulated removal costs	$	186	$	183	$	194
Deferred natural gas costs		36		30		33
Derivative financial instruments		32		11		29
Regulatory tax liability		17		17		18
Unamortized investment tax credit		13		13		14
Deferred seasonal rates		22		-		22
Other		20		17		19
Total regulatory liabilities		326		271		329
Associated liabilities
Regulatory infrastructure program costs		244		210		169
ERC		132		133		95
Total associated liabilities		376		343		264
Total regulatory and associated liabilities	$	702	$	614	$	593

There have been no significant changes to our regulatory assets and liabilities as described in Note 1 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, 2009, filed with the SEC on February 4, 2010. For more information on our derivative financial instruments, see Note 2.

Inventories

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

Sequent and SouthStar evaluate the 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 LOCOM adjustments of $6 million in the three months ended March 31, 2009; however, no LOCOM adjustments were recorded in the three months ended March 31, 2010. Sequent recorded LOCOM adjustments of $4 million for the three months ended March 31, 2010 and $8 million for the same period in 2009.

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.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The future issuance of shares underlying 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 the plan ultimately vest and stock options currently exercisable at prices below the average market prices are exercised.

	Three months ended March 31,
In millions	2010		2009
Denominator for basic earnings per share (1)		77.2		76.7
Assumed exercise of restricted stock, restricted stock units and stock options		0.4		0.1
Denominator for diluted earnings per share		77.6		76.8
(1) Daily weighted-average shares outstanding.

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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	2010		2009
Three months ended		0.8		2.2

The decrease of 1.4 million in anti-dilutive shares for the three months ended March 31, 2010, was primarily a result of a higher average market value of our common shares compared to the same period of 2009.

Stock-Based Compensation

In the first three months of 2010, we issued grants of approximately 154,000 restricted stock units and 150,000 of performance share units, which will result in the recognition of approximately $3 million in annual stock-based compensation expense in 2010. No material share awards have been granted to employees whose compensation is subject to capitalization. On an annual basis, we evaluate the assumptions and estimates used to calculate our stock-based compensation expense.

There have been no significant changes to our stock-based compensation, as described in 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, 2009, filed with the SEC on February 4, 2010.

Comprehensive Income

Our comprehensive income or loss includes net income and net income attributable to AGL Resources Inc. plus OCI, which includes other gains and losses affecting equity that GAAP excludes from net income and net income attributable to AGL Resources Inc. Such items consist primarily of unrealized gains and losses on certain derivatives designated as cash flow hedges and unfunded or overfunded pension and postretirement obligation adjustments.

Fair Value Measurements

The carrying values of cash and cash equivalents, receivables, derivative financial assets and liabilities, accounts payable, pension and postretirement plan assets and liabilities, other current assets and liabilities and accrued interest approximate fair value. As defined in 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 2 and Note 5 for additional fair value disclosures.

In January 2010, we adopted amended fair value measurement guidance, which primarily clarifies the disclosure requirements for fair value measurements and requires that we disclose any transfers between Levels 1, 2 or 3. This guidance had no financial impact to our condensed consolidated results of operations, cash flows and financial position and is effective for interim and annual reporting periods beginning after December 15, 2009. The reporting of Level 3 purchases, sales, issuances and settlements on a gross basis are effective for interim and annual reporting periods beginning after December 15, 2010.

There have been no significant changes to our fair value methodologies, as described in Note 1 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, 2009, filed with the SEC on February 4, 2010.

Note 2 – Derivative Financial Instruments

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, automobile fuel price 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

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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. For information on our energy marketing receivables and payables, which do have credit-risk-related or other contingent features, refer to Note 1.

There have been no significant changes to our derivative financial instruments, 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, 2009, filed with the SEC on February 4, 2010.

Derivative Financial Instruments – Fair Value Hierarchy

The following table sets forth, 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, 2010. As required by the authoritative guidance, derivative financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Recurring fair values Natural gas derivative financial instruments
	March 31, 2010					December 31, 2009					March 31, 2009
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Quoted prices in active markets (Level 1)	$	44	$	(109	)	$	36	$	(37	)	$	39	$	(198	)
Significant other observable inputs (Level 2)		185		(46	)		172		(52	)		163		(19	)
Netting of cash collateral		32		73			30		27			48		166
Total carrying value (2) (3)	$	261	$	(82	)	$	238	$	(62	)	$	250	$	(51	)

(1)	$2 million premium at December 31, 2009 associated with weather derivatives has been excluded as they are based on intrinsic value, not fair value.

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

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

The determination of the fair values above incorporates various factors required under the guidance. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities.

Quantitative Disclosures Related to Derivative Financial Instruments

As of March 31, 2010 and 2009, 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	Mar. 31, 2010 (1)			Dec. 31, 2009			Mar. 31, 2009
Hedge designation:
Cash flow		8			5			9
Not designated		268			108			223
Total		276			113			232
Hedge position:
Short		(1,457	)		(1,518	)		(896	)
Long		1,733			1,631			1,128
Net long position		276			113			232

(1)	Approximately 94% of these contracts have durations of two years or less and the remaining 6% in 3 to 6 years.

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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 consolidated statements of income.


	For the three months ended March 31,
In millions	2010			2009

Designated as cash flow hedges under authoritative guidance related to derivatives and hedging
Natural gas contracts – loss reclassified from OCI into cost of gas for settlement of hedged item	$	(7	)	$	(4	)

Not designated as hedges under authoritative guidance related to derivatives and hedging
Natural gas contracts – fair value adjustments recorded in operating revenues (1)		18			20
Natural gas contracts – net fair value adjustments recorded in cost of gas (2)		(2	)		(1	)
Total gains on derivative instruments	$	9		$	15

(1)	Associated with the fair value of existing derivative instruments at March 31, 2010 and 2009.

(2)	Excludes losses recorded in cost of gas associated with weather derivatives of $20 million for the three months ended March 31, 2010 and $4 million for the three months ended March 31, 2009.

The following amounts (pre-tax) represent the expected recognition over the next 12 months in our consolidated statements of income of the deferred losses recorded in OCI associated with retail energy operations’ derivative instruments, based upon the fair values of these financial instruments:

	As of March 31,
In millions	2010
Designated as hedges under authoritative guidance related to derivatives and hedging
Natural gas contracts – expected net loss reclassified from OCI into cost of gas for settlement of hedged item over next twelve months	$	(9	)

Derivative Financial Instruments on the Condensed Consolidated Statements of Financial Position

In accordance with regulatory requirements, $8 million of 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 during the three months ended March 31, 2010 and $13 million during the three months ended March 31, 2009. The following table presents the fair value and statements of financial position classification of our derivative financial instruments.

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		As of
In millions	Statement of financial position location (1) (2)	Mar. 31, 2010			Dec. 31, 2009			Mar. 31, 2009
Designated as cash flow hedges under authoritative guidance related to derivatives and hedging

Asset Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion	$	5		$	6		$	12

Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		(14	)		(5	)		(32	)
	Total		(9	)		1			(20	)

Not designated as cash flow hedges under authoritative guidance related to derivatives and hedging

Asset Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		771			590			546
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		147			118			91

Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		(714	)		(510	)		(563	)
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		(121	)		(78	)		(69	)
	Total		83			120			5
Total derivative financial instruments		$	74		$	121		$	(15	)

(1)

These amounts are netted within our consolidated statements of financial position. Some of our derivative financial instruments have asset positions which are presented as a liability in our 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 $105 million and $214 million of cash collateral held on deposit in broker margin accounts as of March 31, 2010 and 2009, respectively and $57 million as of December 31, 2009. Accordingly, the amounts above will differ from the amounts presented on our 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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Note 3 - Employee Benefit Plans

Pension Benefits

We sponsor two tax-qualified defined benefit retirement plans for our eligible employees, the AGL Resources Inc. Retirement Plan (AGL Retirement Plan) and the Employees’ Retirement Plan of NUI Corporation (NUI Retirement Plan). 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	2010			2009
Service cost	$	3		$	2
Interest cost		7			7
Expected return on plan assets		(8	)		(7	)
Amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		3			2
Net pension benefit cost	$	4		$	3

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 us. Additionally, the AGL Postretirement Plan provides life insurance for all employees if they have ten years of service at retirement. The state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 provided for a prescription drug benefit under Medicare (Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that was at least actuarially equivalent to Medicare Part D. This cash subsidy, known as the Retiree Drug Subsidy, was tax-free and companies were allowed to deduct the benefits paid to retirees. In March 2010, President Obama signed into law HR2590, the Patient Protection and Affordable Care Act, and the U.S. Congress passed HR4872, Reconciliation Act of 2010, which amends HR2590. With this healthcare reform, the cash subsidy is no longer tax-free. Accounting guidance requires that companies record the tax impacts of this healthcare reform on the date of enactment. However, we did not receive the Retiree Drug Subsidy and therefore did not recognize any additional expense.

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

	Three months ended March 31,
In millions	2010			2009
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 the retirement 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. The Act 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 (passed December, 2008) allowed us to measure our 2008 and 2009 minimum required contributions based on a funding target at 92% and 94%, respectively. In 2010, this will increase to 96% and for 2011 it will increase to 100%. In the first three months of 2010 we contributed $17 million and an additional $4 million in April 2010 for a total of $21 million to our qualified pension plans. Based on the current funding status of the plans, we were required to make a minimum contribution to the plans of approximately $21 million in 2010. However, we are planning to make additional contributions to our pension plans in 2010 up to $10 million, for a total of up to $31 million. During the first three months of 2009 we contributed $14 million to our qualified pension plans.

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 2010 and $2 million the same period last year.

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Note 4 – Variable Interest Entity

SouthStar, a joint venture owned by us and Piedmont, markets natural gas and related services under the trade name GNG 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, North Carolina, South Carolina and Tennessee.

The primary risks associated with SouthStar are discussed in our risk factors included in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 4, 2010. SouthStar utilizes derivative financial instruments to manage natural gas price and weather risks. See Note 2 for additional disclosures of these instruments. GNG is currently involved in litigation which is discussed further in Note 6.

In July 2009, we entered into an amended joint venture agreement with Piedmont pursuant to which we purchased an additional 15% ownership interest in SouthStar for $58 million, effective January 1, 2010, thus increasing our ownership interest to 85%. This was accounted for as an acquisition of equity interests. Piedmont retained the remaining 15% share. We have no further option rights to Piedmont’s remaining 15% ownership interest and all significant management decisions continue to require approval by both owners.

Piedmont’s interest in SouthStar is reflected as a separate component of equity on our condensed consolidated statement of financial position. The following table provides the effects the purchase had on our equity.

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

Earnings in 2010 are allocated entirely in accordance with the ownership interests. Earnings in 2009 were allocated 75% to us and 25% to Piedmont except for earnings related to customers in Ohio and Florida, which were allocated 70% to us and 30% to Piedmont. Earnings allocated to Piedmont are presented separately in our condensed consolidated statements of income as net income attributable to the noncontrolling interest.

We have determined that SouthStar is a variable interest entity (VIE) and we are the primary beneficiary of SouthStar’s activities as defined by the authoritative guidance related to consolidations, which requires us to consolidate the VIE. We have determined that SouthStar is a VIE because our equal voting rights with Piedmont are not proportional to our economic obligation to absorb 85% of any losses or residual returns from SouthStar.

On January 1, 2010 we adopted authoritative accounting guidance that required us to reassess the determination that we are the primary beneficiary of the VIE based on whether we have the power to direct matters that most significantly impact the activities of the VIE, and have the obligation to absorb losses or the right to receive benefits of the VIE. The adoption of this guidance had no effect on our condensed consolidated results of operations, cash flows or financial position because we concluded that SouthStar’s accounts should continue to be consolidated with the accounts of AGL Resources Inc. and its majority-owned and controlled subsidiaries.

Following are the significant factors considered in determining that we have the power to direct SouthStar’s activities that most significantly impact its performance.

Operation of the business

Our wholly-owned subsidiary, Atlanta Gas Light, provides the following services in accordance with Georgia Commission authorization that affect SouthStar’s operations.

·	Provides meter reading services for SouthStar’s customers in Georgia.

·	Maintains and expands the natural gas infrastructure in Georgia.

Markets the benefits of natural gas, performs outreach to residential and commercial developers, offers natural gas appliance rebates and billboard and print advertising, all of which support SouthStar’s efforts to maintain and expand its residential, commercial and industrial customers in its largest market, Georgia.

·	Assigns storage and transportation capacity used in delivering natural gas to SouthStar's customers.

Liquidity and capital resources

·	We provide guarantees for SouthStar’s activities with its counterparties and for its credit exposure.

·	SouthStar utilizes our commercial paper program for its liquidity and working capital requirements. This provides SouthStar with the benefit of borrowing at lower interest rates as it would not be able to receive these rates on a stand alone basis.

·	We support SouthStar’s daily cash management activities and assist with ensuring SouthStar has adequate liquidity and working capital resources.

·	We provide guarantees to certain natural gas suppliers in support of SouthStar's payment obligations.

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Back office functions

·	Pursuant to a services agreement we provide services to SouthStar with respect to accounting, information technology, credit and internal controls.

See Note 7 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 1 for additional discussions of SouthStar’s inventories. The nature of restrictions on SouthStar’s assets are immaterial. 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, 2010, SouthStar’s current assets, which approximate fair value, exceeded its current liabilities, long-term assets and other deferred debits, long-term liabilities and other deferred credits by approximately $98 million. Further, 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. We have provided no financial or other support that was not previously contractually required.

The following tables provide additional information on SouthStar’s assets and liabilities as of March 31, 2010, December 31, 2009 and March 31, 2009, which are consolidated within our condensed consolidated statement of financial position.

	As of March 31, 2010

In millions	Consolidated		SouthStar (1)		% (2)
Current assets	$	1,649	$	212	13	%
Long-term assets and other deferred debits		5,176		9	-
Total assets	$	6,825	$	221	3	%
Current liabilities	$	1,783	$	105	6	%
Long-term liabilities and other deferred credits		3,191		-	-
Equity		1,851		116	6
Total liabilities and equity	$	6,825	$	221	3	%

	As of December 31, 2009

In millions	Consolidated		SouthStar (1)		% (2)
Current assets	$	2,000	$	238	12	%
Long-term assets and other deferred debits		5,074		9	-
Total assets	$	7,074	$	247	3	%
Current liabilities	$	1,772	$	96	5	%
Long-term liabilities and other deferred credits		3,483		-	-
Equity		1,819		151	8
Total liabilities and equity	$	7,074	$	247	3	%

	As of March 31, 2009

In millions	Consolidated		SouthStar (1)		% (2)
Current assets	$	1,431	$	208	15	%
Long-term assets and other deferred debits		4,726		11	-
Total assets	$	6,157	$	219	4	%
Current liabilities	$	1,348	$	112	8	%
Long-term liabilities and other deferred credits		3,046		-	-
Equity		1,763		107	6
Total liabilities and equity	$	6,157	$	219	4	%

(1)	These amounts reflect information for SouthStar and do not include intercompany eliminations and the balances of our wholly-owned subsidiary with the 85% ownership interest in SouthStar and therefore the amounts will not agree to the identifiable and total assets reported in Note 7.

(2)	SouthStar’s percentage of the amount on our condensed consolidated statement of financial position.

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Note 5 - Debt

Our issuance of various securities, including long-term and short-term debt, is subject to customary approval, authorization or review by state and federal regulatory bodies, including state public service commissions, the SEC and the FERC pursuant to the Energy Policy Act of 2005. The following table provides more information on our various debt securities. For more information on our debt, see Note 6 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, 2009, filed with the SEC on February 4, 2010.

			March 31, 2010							March 31, 2009
In millions	Year(s) due		Weighted average interest rate (1)			Outstanding		Outstanding at December 31, 2009		Weighted average interest rate (2)			Outstanding
Short-term debt
Senior notes (3)	2011			7.1	%	$	300	$	-		-	%	$	-
Capital leases	2010-2011			4.9			1		1		4.9			1
Total current portion of long-term debt				7.1			301		1		4.9			1
Commercial paper		2010		0.4			153		601		1.2			335
SouthStar line of credit		-		-			-		-		1.1			45
Sequent lines of credit		-		-			-		-		0.9			22
Total excluding current portion of long-term debt				0.4			153		601		1.2			402
Total short-term debt				3.3	%	$	454	$	602		1.1	%	$	403
Long-term debt - net of current portion
Senior notes	2013-2034			5.5	%	$	1,275	$	1,575		5.9	%	$	1,275
Gas facility revenue bonds	2022-2033			1.2			200		200		1.3			200
Medium-term notes	2012-2027			7.8			196		196		7.8			196
Capital leases		2013		4.9			3		3		4.9			4
Total long-term debt (3)				5.1	% (4)	$	1,674	$	1,974		5.5	%	$	1,675

Total debt				4.6	%	$	2,128	$	2,576		4.3	%	$	2,078

(1)	For the three months ended March 31, 2010.

(2)	For the three months ended March 31, 2009.

(3)

Our estimated fair value was $2,080 million as of March 31, 2010, $2,060 million as of December 31, 2009 and $1,633 million as of March 31, 2009. We estimate the fair value 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 of BBB+ by S&P, Baa1 by Moody’s and A- by Fitch.

(4)	Including the $300 million of senior notes due in 2011, the weighted average interest rate for the three months ended March 31, 2010 was 5.5%.

Default Events

Our Credit Facility financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%. Our ratio of total debt to total capitalization calculation contained in our debt covenant includes standby letters of credit, surety bonds and the exclusion of other comprehensive income pension adjustments. Adjusting for these items, our debt-to-equity calculation, as defined by our Credit Facility, was 52% at March 31, 2010, 57% at December 31, 2009 and 53% at March 31, 2009. These amounts are within our required and targeted ranges. Our debt-to-equity calculation, as calculated from our condensed consolidated statements of financial position, was 53% at March 31, 2010, 59% at December 31, 2009 and 54% at March 31, 2009.

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 events include:

·	a maximum leverage ratio

·	insolvency events and nonpayment of scheduled principal or interest payments

·	acceleration of other financial obligations

·	change of control provisions

We have no 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. We are currently in compliance with all existing debt provisions and covenants.

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Note 6 - 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 7 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, 2009, filed with the SEC on February 4, 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, 2010.

	Commitments due before December 31,
In millions	Total		2010		2011 & thereafter
Standby letters of credit and performance and surety bonds	$	16	$	10	$	6

Litigation

We are involved in litigation arising in the normal course of business. The ultimate resolution of such litigation, including the discussion below is not expected to have a material adverse effect on our condensed consolidated financial position, results of operations 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 GNG alleging that it charged its customers of variable rate plans 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, GNG 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 will be remanded back to the Superior Court of Fulton County for further proceedings. GNG asserts that no violation of law or Georgia Commission rules has occurred.

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 7 in our consolidated financial statements and related notes in Item 8 of our Form 10-K for the year ended December 31, 2009, filed with the SEC on February 4, 2010.

Note 7 - 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.

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We evaluate segment performance based primarily on the non-GAAP measure of EBIT, which includes the effects of corporate expense allocations. EBIT is a non-GAAP measure that 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. The reconciliations of EBIT to operating income, earnings before income taxes and net income for the three months ended March 31, 2009 and 2008 are presented below.

	Three months ended March 31,
In millions	2010			2009
Operating income	$	253		$	230
Other income		2			2
EBIT		255			232
Interest expense, net		(28	)		(25	)
Earnings before income taxes		227			207
Income taxes		82			72
Net income	$	145		$	135

Information by segment on our statement of financial position at December 31, 2009, is as follows:

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	5,230		$	404
Retail energy operations		261			-
Wholesale services		1,168			-
Energy investments		454			14
Corporate and intercompany eliminations (2)		(39	)		-
Consolidated AGL Resources Inc.	$	7,074		$	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 income statement, statements of financial position and capital expenditure information as of and for the three months ended March 31, 2010 and 2009, by segment, are shown in the following tables.

Three months ended March 31, 2010

In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments		Corporate and intercompany eliminations (3)			Consolidated AGL Resources Inc.
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)	$	5,235	$	242	$	981	$	489	$	(122	)	$	6,825
Goodwill	$	404	$	-	$	-	$	14	$	-		$	418
Capital expenditures	$	70	$	1	$	-	$	40	$	3		$	114

Three months ended March 31, 2009


In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments		Corporate and intercompany eliminations (3)			Consolidated AGL Resources Inc.
Operating revenues from external parties	$	572	$	343	$	68	$	10	$	2		$	995
Intercompany revenues (1)		35		-		-		-		(35	)		-
Total operating revenues		607		343		68		10		(33	)		995
Operating expenses
Cost of gas		355		259		9		-		(34	)		589
Operation and maintenance		83		20		19		5		(2	)		125
Depreciation and amortization		32		1		1		2		3			39
Taxes other than income taxes		9		-		1		1		1			12
Total operating expenses		479		280		30		8		(32	)		765
Operating income (loss)		128		63		38		2		(1	)		230
Other income		2		-		-		-		-			2
EBIT	$	130	$	63	$	38	$	2	$	(1	)	$	232

Identifiable and total assets (2)	$	5,095	$	261	$	653	$	373	$	(225	)	$	6,157
Goodwill	$	404	$	-	$	-	$	14	$	-		$	418
Capital expenditures	$	69	$	-	$	-	$	23	$	5		$	97

(1)	Intercompany revenues – wholesale services records its energy marketing and risk management revenues on a net basis, which includes intercompany revenues of $180 million for the three months ended March 31, 2010 and $165 million for the three months ended March 31, 2009.

(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

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. 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,” "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 results to differ 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.

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, 2009, among others, could cause our business, results of operations or financial condition in 2010 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 results to differ significantly from our expectations.

Forward-looking statements are only as of the date they are made. We do not update these statements to reflect subsequent circumstances or events.

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, 2010, our six utilities serve 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, energy investments and a non-operating corporate segment.

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 fixed and variable costs such as depreciation, interest, maintenance and overhead costs, 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 than in periods of warmer 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.

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Our retail energy operations segment, which consists 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 is temperature insensitive, but 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 also can 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.

Changes in commodity prices subject a significant portion of our operations to earnings variability. Our nonutility 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 2.

Executive Summary

Regulatory strategy We continue to actively pursue a regulatory strategy that reduces the lag between our investments in infrastructure and the recovery of those investments through various rate mechanisms. Our regulatory planning includes rate design proposals that should provide stabilized revenues by separating the recovery of fixed costs for providing service from the volumes of customer throughput. Our rate cases also include proposals for energy-efficiency programs that should help customers lower the amount of gas used and conserve energy.

Capital projects We continue to focus aggressively on capital discipline and cost control, while moving ahead with projects and initiatives that we expect will have current and future benefits and provide an appropriate return on invested capital. In addition, our Golden Triangle Storage project in Beaumont, Texas is on schedule and we expect the first cavern to be in operation in the second half of 2010.

Customer growth We continue to see challenging economic conditions in all of the areas we serve and, as a result, have experienced slight customer losses in our distribution operations and retail energy operations segments, a trend we expect to continue through the remainder of 2010.

For the three months ended March 31, 2010, our distribution operations customer loss rate was (0.3)%, compared to (0.1)% for the same period last year. Our customer counts continue to be impacted by both slow growth in the residential housing markets and a recent slow down in new commercial developments. This trend has been offset slightly by colder than normal weather as customers have tended to stay connected to our systems and the favorable impact of the customer attrition mitigation strategies at all of our utilities.

We have seen a 2% decline in average customer count in Georgia at SouthStar for the three months ended March 31, 2010, as compared to the same period last year. This decline reflects some of the same economic conditions that have affected our utility businesses, as well as a more competitive retail market for natural gas in Georgia.

Capital market plan Our capital market plan over the next 9 to 15 months includes maintaining our total debt to total capitalization targets between 50% and 60%, the renewal of our $1 billion Credit Facility, the renewal of the letter of credit agreements which provide credit support for our variable-rate gas facility revenue bonds and refinancing of $300 million in 7.125% senior notes set to mature in January 2011.

We cannot predict whether renewing our Credit Facility or refinancing the senior notes would result in favorable terms or interest rates. Additionally, due to the significant changes in the credit markets, we expect that the costs of a renewed credit facility would increase and the duration would be less than the 5-year term under our existing Credit Facility. We have not yet determined whether we will seek to increase or decrease the size of the Credit Facility from its current $1 billion level.

Distribution Operations

Regulatory Planning

Atlanta Gas Light In July 2009, Atlanta Gas Light filed a request with the Georgia Commission to postpone its scheduled filing of a rate case in November 2009. This request was approved by the Georgia Commission which agreed to postpone the filing until April 1, 2010, but no later than June 1, 2010. We plan to file the rate case prior to June 1, 2010.

Elizabethtown Gas In December 2009, the New Jersey BPU approved an agreement with Elizabethtown Gas regarding its March 2009 base rate filing and the energy conservation programs. Under the terms of the agreement, Elizabethtown Gas received an increase in base rates which equates to approximately $3 million on an annual basis. Additionally, Elizabethtown Gas reduced its overall composite depreciation rate from 3.20% to 2.58%, which equates to an annual reduction in depreciation expenses of approximately $5 million. The agreement included a two-year freeze on base rates except as may be adjusted in the second phase of our rate case, in which the New Jersey BPU will consider, among other things, our request for the Efficiency Usage and Adjustment mechanism, which separates recovery of fixed costs for providing service from the volumes of customer usage. Elizabethtown Gas expects to reach resolution on the remaining items during 2010.

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Chattanooga Gas In November 2009, Chattanooga Gas filed a rate case with the Tennessee Authority. We are currently requesting an annual increase of approximately $2 million in base rates. The rate case proposal includes energy-efficiency and conservation programs, as well as a mechanism to recover lost revenue resulting from these programs. We expect a decision by the Tennessee Authority in the second quarter of 2010.

Capital Projects

The Georgia Commission has approved Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement (STRIDE) program. As approved, STRIDE is comprised of the on going pipeline replacement program and the new Integrated System Reinforcement Program. The program’s initial three years’ expenditures are estimated at approximately $176 million. The purpose of this program 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 would be required to file an updated ten-year forecast of infrastructure requirements along with a new three-year construction plan every three years for review and approval by the Georgia Commission. STRIDE is a new umbrella program that merges our existing pipeline replacement program, which was initiated in 1998 and is scheduled to end in December 2013.

In January 2010, the Georgia Commission approved a third program under STRIDE which authorized Atlanta Gas Light to invest up to an additional $45 million of expenditures under the STRIDE program to extend Atlanta Gas Light’s pipeline facilities to serve customers without pipeline access and create new economic development. This program was approved as a three-year pilot program under STRIDE, and the recovery of the approved surcharge was extended until 2025. Atlanta Gas Light spent approximately $16 million for the STRIDE program in the three months ended March 31, 2010, and expects that approximately $105 million in capital expenditures for the STRIDE program will be incurred for the remainder of 2010.

The New Jersey BPU has approved an accelerated enhanced infrastructure program for Elizabethtown Gas which began in 2009 and is scheduled to be completed in 2011. This program 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 will be established with estimated rates put 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. Elizabethtown Gas spent approximately $5 million in the three months ended March 31, 2010 and expects that approximately $45 million in capital expenditures for this program will be incurred for the remainder of 2010. For more information on our regulatory infrastructure programs, see Note 1 in our consolidated financial statements and related notes as filed in Item 8 of our Form 10-K for the year ended December 31, 2009, filed with the SEC on February 4, 2010.

Retail Energy Operations

Our retail energy operations segment consists of SouthStar, a joint venture owned by us and Piedmont. In July 2009, we entered into an amended joint venture agreement with Piedmont pursuant to which we purchased an additional 15% ownership interest for $58 million, effective January 1, 2010, thus increasing our interest to 85%. Piedmont retained the remaining 15% share. Earnings are allocated entirely in accordance with the ownership interests. We have no further option rights to Piedmont’s remaining 15% ownership interest and all significant management decisions continue to require approval by both owners. Prior to January 1, 2010, we owned a 70% interest in SouthStar and Piedmont owned 30%, and SouthStar’s earnings for customers in Georgia were allocated 75% to us and 25% to Piedmont, while its earnings for customers in Ohio and Florida were allocated 70% to us and 30% to Piedmont.

SouthStar markets natural gas and related services to retail customers on an unregulated basis, principally in Georgia, as well as Ohio and Florida. In addition, SouthStar markets gas to larger commercial and industrial customers in Alabama, Florida, Ohio, Tennessee, North Carolina and South Carolina. SouthStar is the largest marketer of natural gas in Georgia with an approximate 33% market share based on customer count.

We record the earnings allocated to Piedmont as a noncontrolling interest in our condensed consolidated statements of income, and we record Piedmont’s portion of SouthStar’s capital as a noncontrolling interest in our condensed consolidated statements of financial position.

Over the last couple of years, SouthStar’s residential and commercial customers have been migrating to fixed price plans in response to volatility in natural gas prices and increased competition from other Marketers in Georgia. SouthStar’s operating margin under these fixed price-plans is lower than variable price plans. Generally, we use hedges for customers who are on fixed price plans to manage our exposure to commodity price risk. We have seen some stabilization in the number of residential customers on fixed price plans as compared to last year. In 2010, we have seen more commercial customers migrating to fixed price plans, resulting in continued downward pressure on operating margin. We expect this trend to continue for the remainder of 2010.

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Wholesale Services

Our wholesale services segment consists primarily of Sequent, our subsidiary involved in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing. Sequent seeks asset optimization opportunities, which focus on capturing the value from idle or underutilized assets, typically by participating in transactions to take advantage of pricing differences between varying markets and time horizons within the natural gas supply, storage and transportation markets to generate earnings. These activities are generally referred to as arbitrage opportunities.

Sequent’s profitability is driven by volatility in the natural gas marketplace. Volatility arises from a number of factors such as weather fluctuations or the change in supply of, or demand for, natural gas in different regions of the United States. Sequent seeks to capture value from the price disparity across geographic locations and various time horizons (location and seasonal spreads). In doing so, Sequent also seeks to mitigate the risks associated with this volatility and protect its margin through a variety of risk management and economic hedging activities.

Sequent provides its customers with natural gas from the major producing regions and market hubs in the United States and Canada. Sequent acquires transportation and storage capacity to meet its delivery requirements and customer obligations in the marketplace. Sequent’s customers benefit from its logistics expertise and ability to deliver natural gas at prices that are advantageous relative to other alternatives available to its customers.

Storage inventory outlook 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. Sequent’s expected operating revenues are net of the estimated impact of regulatory profit sharing and reflect the amounts that are realizable in future periods based on its inventory withdrawal schedule and forward natural gas prices at March 31, 2010. A portion of Sequent’s storage inventory is economically hedged with futures contracts, which results in realization of a substantially fixed margin, timing notwithstanding.

	Withdrawal schedule (in Bcf)				Expected operating
	Salt dome (WACOG $4.38)		Reservoir (WACOG $3.79)			revenues (in millions)
2010
Second quarter		-		3		$	-
Third quarter		-		4			1
Fourth quarter		1		3			1
2011
First quarter		1		2			4
Total		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 $6 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 traditionally near their lowest point at the end of the first quarter just prior to the beginning of the inventory injection season when inventories are built for the next heating season. For more information on Sequent’s energy marketing and risk management activities, see Item 3, Quantitative and Qualitative Disclosures About Market Risk - Natural Gas Price Risk.

Energy Investments

Our energy investments segment includes a number of businesses that are related or complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops, acquires and operates high-deliverability salt-dome and other storage assets in the Gulf Coast region of the United States. While this business also can generate additional revenue during times of peak market demand for natural gas storage services, the majority of its storage services are covered under a portfolio of short, medium and long-term contracts at a fixed market rate.

Our Golden Triangle Storage project will consist of a new salt-dome storage facility in the Gulf Coast region of the U.S. with 12 Bcf of working natural gas capacity and total cavern capacity of 18 Bcf. The facility potentially can be expanded to a total of five caverns with 38 Bcf of working natural gas storage capacity in the future. It is also expected that Golden Triangle Storage will build an approximately nine-mile dual 24” natural gas pipeline to connect the storage facility with three interstate and three intrastate pipelines. We expect the first cavern with 6 Bcf of working capacity to be in service in the third quarter of 2010 and the second cavern with 6 Bcf of working capacity to be in service in mid 2012. There have been no material changes to our cost estimate to construct the facility of approximately $314 million.

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We also own and operate a telecommunications business, AGL Networks, which constructs and operates conduit and fiber infrastructure within select metropolitan areas in the United States. The sale of this business, which we expect to complete in June 2010, will not have a material effect on our consolidated results of operations, cash flows or financial position.

Results of Operations

Operating margin and EBIT We evaluate segment performance using the measures of operating margin and EBIT, which include the effects of corporate expense allocations. Our operating margin and EBIT are not measures that are considered to be calculated in accordance with GAAP. 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.

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, 2010 and 2009.

	Three months ended March 31,
In millions	2010		2009		Change
Operating revenues	$	1,003	$	995	$	8
Cost of gas		571		589		(18	)
Operating margin (1)		432		406		26
Operating expenses		179		176		3
Operating income		253		230		23
Other income		2		2		-
EBIT (1)		255		232		23
Interest expense, net		28		25		3
Earnings before income taxes		227		207		20
Income tax expense		82		72		10
Net income		145		135		10
Net income attributable to the noncontrolling interest		11		16		(5	)
Net income attributable to AGL Resources Inc.	$	134	$	119	$	15

(1) These are non-GAAP measurements.

For the first quarter of 2010, net income attributable to AGL Resources Inc. increased by $15 million or 13% compared to the same period last year. The increase was primarily the result of higher operating margins at distribution operations, retail energy operations and energy investments and reduced net income attributable to the noncontrolling interest as a result of our increased ownership interest in SouthStar. This increase was partially offset by higher operating expenses primarily due to increased payroll and incentive compensation and depreciation expenses at distribution operations, offset by decreased incentive and other expenses at wholesale services.

Interest expense increased by $3 million or 12% for the first quarter of 2010 compared to the first quarter of 2009 due to slightly higher average debt outstanding, largely resulting from the issuance of $300 million in senior notes in August 2009. More information about our average debt and rates are indicated in the following table.

	Three months ended March 31,
In millions		2010			2009			Change
Average debt outstanding		$	2,366		$	2,333		$	33
Average rate (1)			4.6	%		4.3	%		0.3	%

(1) Daily weighted average of all outstanding debt.

Our income tax expense increased by $10 million or 14% for the first quarter of 2010 compared to the first quarter of 2009. This was primarily due to higher consolidated earnings. Our income tax expense is determined from earnings before income taxes less net income attributable to the noncontrolling interest.

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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, 2010 and 2009, 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.

Weather
Heating degree days (1)
	Three months ended March 31,						2010 vs. normal colder			2010 vs. 2009 colder
	Normal		2010		2009		(warmer)			(warmer)
Georgia		1,506		1,952		1,434		30	%		36	%
New Jersey		2,532		2,397		2,627		(5	)%		(9	)%
Virginia		1,833		2,029		1,988		11	%		2	%
Florida		379		719		369		90	%		95	%
Tennessee		1,706		2,116		1,664		24	%		27	%
Maryland		2,518		2,477		2,612		(2	)%		(5	)%
Ohio		2,602		2,831		2,552		9	%		11	%
(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 2001 through 2010.

Customers	Three months ended March 31,
	2010			2009			% change
Distribution Operations
Average end-use customers (in thousands)
Atlanta Gas Light		1,567			1,577			(0.6	)%
Elizabethtown Gas		275			275			-
Virginia Natural Gas		278			276			0.7	%
Florida City Gas		104			103			1.0	%
Chattanooga Gas		63			63			-
Elkton Gas		6			6			-
Total		2,293			2,300			(0.3	)%
Operation and maintenance expense per customer	$	38		$	36			6	%
EBIT per customer	$	59		$	57			4	%

Retail Energy Operations
Average customers (in thousands)
Georgia		507			518			(2	)%
Ohio and Florida (1)		106			98			8	%
Total		613			616			(0.5	)%
Market share in Georgia		33	%		34	%		(3	)%

(1) 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,
	2010		2009		% change
Distribution Operations
Firm		122		99		23	%
Interruptible		27		26		4	%
Total		149		125		19	%

Retail Energy Operations
Georgia firm		24		18		33	%
Ohio and Florida		6		5		20	%

Wholesale Services
Daily physical sales (Bcf/day)		4.9		3.1		58	%

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Three months ended March 31, 2010 compared to three months ended March 31, 2009

Segment information 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, 2010 and 2009.

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

In millions	Operating margin (1)		Operating expenses		EBIT (1)
2009
Distribution operations	$	252	$	124	$	130
Retail energy operations		84		21		63
Wholesale services		59		21		38
Energy investments		10		8		2
Corporate (2)		1		2		(1	)
Consolidated	$	406	$	176	$	232

(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 $6 million or 5% compared to last year as shown in the following table.

In millions
EBIT for first quarter of 2009				$	130

Operating margin
Increased revenues from the Hampton Roads pipeline project	$	5
Increased revenues from higher usage at Florida City Gas due to colder weather		2
Increased revenues from Magnolia pipeline project		2
Increased regulatory infrastructure program revenue at Atlanta Gas Light		1
Other		2
Increase in operating margin					12

Operating expenses
Increased payroll and incentive expenses	$	(4	)
Increased depreciation expenses		(2	)
Increase in operating expenses					(6	)
EBIT for first quarter of 2010				$	136

Retail energy operations’ EBIT increased by $11 million or 17% compared to last year as shown in the following table.

In millions
EBIT for first quarter of 2009				$	63

Operating margin
Increased average customer usage due to colder weather net of losses on weather derivatives further offset by changes in consumption mix between residential and commercial customers	$	8
Change in LOCOM adjustment		6
Increased operating margins in Ohio and Florida		2
Decreased contribution from the management and optimization of storage and transportation assets driven in part by increasing NYMEX prices offset by higher retail price spreads		(2	)
Change in retail pricing plan mix and decrease in average number of customers		(1	)
Other		(1	)
Increase in operating margin					12

Operating expenses
Increased marketing and direct selling expenses	$	(1	)
Higher bad debt due to increased revenues		(1	)
Decreased customer care, outside services and other expenses		1
Increase in operating expenses					(1	)
EBIT for first quarter of 2010				$	74

Wholesale services’ EBIT increased by $5 million or 13% compared to last year as shown in the following table.

In millions
EBIT for first quarter of 2009				$	38

Operating margin
Increased gains on storage hedges	$	3
Change in commercial activity		6
Decreased gains on transportation hedges		(13	)
Change in LOCOM adjustment		4
Net change in operating margin					-

Operating expenses
Decreased incentive compensation costs	$	4
Other		1
Decrease in operating expenses					5
EBIT for first quarter of 2010				$	43

The following table indicates the components of wholesale services’ operating margin for the three months ended March 31, 2010 and 2009.

In millions	2010			2009
Commercial activity recognized	$	41		$	35
Gain on transportation hedges		11			24
Gain on storage hedges		11			8
Inventory LOCOM		(4	)		(8	)
Operating margin	$	59		$	59

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Energy investments’ EBIT increased by $1 million compared to last year as shown in the following table.

In millions
EBIT for first quarter of 2009				$	2

Operating margin
Increased operating revenues at AGL Networks	$	2
Increase in operating margin					2

Operating expenses
Increase in payroll and benefit costs and property taxes at Golden Triangle Storage	$	(1	)
Increase in operating expenses					(1	)
EBIT for first quarter of 2010				$	3

Liquidity and Capital Resources

Our primary sources of liquidity are cash provided by operating activities, short-term borrowings under our commercial paper program (which is supported by our Credit Facility) and borrowings under subsidiary lines of credit. 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 needed; managing critical business risks; and maintaining a balanced capital structure through the appropriate issuance of equity or long-term debt securities.

Our issuance of various securities, including long-term and short-term debt, is subject to customary approval, authorization or review by state and federal regulatory bodies including state public service commissions, the SEC and the FERC. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation.

We believe the amounts available to us under our Credit Facility and the issuance of debt and equity securities, together 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 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 are beyond our control.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies and other factors. See Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2009, for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities.

	Three months ended March 31,
In millions	2010			2009
Net cash provided by (used in):
Operating activities	$	670		$	611
Investing activities		(114	)		(97	)
Financing activities		(563	)		(509	)
Net (decrease) increase in cash and cash equivalents	$	(7	)	$	5

Cash Flow from Operating Activities In the first three months of 2010, our net cash flow provided from operating activities was $670 million, an increase of $59 million or 10% from the same period in 2009. This increase was primarily a result of a decrease in deployment of working capital for Sequent’s energy marketing activities of $122 million, primarily driven by the effects of an increase in Sequent’s daily physical sales and the timing of payments for gas purchases relative to collections of accounts receivable. This was partially offset by a $66 million decrease in cash from the collection of our natural gas receivables, as our utilities in Georgia, Florida and Tennessee, along with SouthStar, experienced a much colder winter in the first quarter of 2010 compared to the prior year.

Cash Flow from Investing Activities Our investing activities consisted of PP&E expenditures of $114 million for the three months ended March 31, 2010 and $97 million for the same period in 2009. The increase of $17 million or 18% in PP&E expenditures was primarily due to a $17 million increase at energy investments primarily due to costs associated with Golden Triangle Storage’s natural gas storage facility.

Cash Flow from Financing Activities Our cash used in financing activities was $563 million for the three months ended March 31, 2010 compared to cash used of $509 million for the same period in 2009. The increased use of cash of $54 million was primarily due to our purchase of an additional 15% ownership interest in SouthStar for $58 million and an increased distribution to the noncontrolling interest of $12 million. This was partially offset by $15 million of net decreased short-term debt payments of $448 million in 2010 compared to net payments of $463 million for the same period in 2009.

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, 2010, our variable-rate debt was 15% of our total debt, compared to 27% as of March 31, 2009.

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We strive to maintain or improve our credit ratings on our debt to manage our existing financing costs and enhance our ability to raise additional capital on favorable terms. 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, 2010, and reflects no change from December 31, 2009.

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

Our credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. We cannot ensure 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. If the rating agencies downgrade our ratings, particularly below investment grade, it may significantly limit our access to the commercial paper market and our borrowing costs would increase. 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 events 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 events include maintaining covenants with respect to a maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, and acceleration of other financial obligations and change of control provisions.

Our Credit Facility has financial covenants that require us to maintain a ratio of total debt to total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. Our ratio of total debt to total capitalization calculation contained in our debt covenant includes standby letters of credit, surety bonds and the exclusion of other comprehensive income pension adjustments. Our debt-to-total-equity calculation, as defined by our Credit Facility was 52% at March 31, 2010, 57% at December 31, 2009 and 53% at March 31, 2009. These amounts are within our required and targeted ranges. 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.

	Mar. 31, 2010			Dec. 31, 2009			Mar. 31, 2009
Short-term debt		11	%		14	%		10	%
Long-term debt		42			45			44
Total debt		53			59			54
Equity		47			41			46
Total capitalization		100	%		100	%		100	%

We currently comply with all existing debt provisions and covenants. We believe that accomplishing our capitalization objectives and maintaining sufficient cash flow are necessary to maintain our investment-grade credit ratings and to allow us access to capital at reasonable costs.

Short-term debt Our short-term debt is composed of borrowings and payments under our Credit Facility and commercial paper program, lines of credit and the current portion of our capital leases. Our short-term debt financing generally increases between June and December because our payments for natural gas and pipeline capacity are generally made to suppliers prior to the collection of accounts receivable from our customers. We typically reduce short-term debt balances in the spring because a significant portion of our current assets are converted into cash at the end of the heating season.

Excluding the current portion of our long-term debt of $301 million, our short-term borrowings, as of March 31, 2010, decreased $249 million or 62% compared to the same period last year. This was primarily a result of paying down short-term debt with a portion of the proceeds received from the issuance of $300 million of senior notes in August 2009, and reduced working capital requirements as a result of lower natural gas prices. This was offset by our purchase of an additional ownership interest in SouthStar for $58 million and increased property, plant and equipment expenditures of $17 million.

Our commercial paper borrowings are supported by our $1 billion Credit Facility which expires in August 2011. We have the option to request an increase in the aggregate principal amount available for borrowing under the $1 billion Credit Facility to $1.25 billion on not more than three occasions during each calendar year. We expect to begin the process of renewing our Credit Facility during 2010. Because of the current conditions in the credit markets, we are anticipating that the costs of a renewed Credit Facility will be significantly higher and that the term could be significantly shorter than the 5-year term of the current facility. These market conditions could also result in the need for us to increase the number of financial institution participants to provide a similar amount of financial commitments as our existing Credit Facility. As part of our renewal process we will consider whether the facility should increase or decrease from its current capacity of $1 billion.

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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. However, we have $300 million of senior notes set to mature in January 2011, which are now reported as current portion of long-term debt on our consolidated statements of financial position. We expect to refinance the $300 million of senior notes in 2010.

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.

Through April 2010, we have contributed $21 million to our qualified pension plans. Based on the current funding status of the plans, we were required to make a minimum contribution to the plans of approximately $21 million in 2010. However, we are planning to make additional contributions to our pension plans in 2010 up to $10 million, for a total of up to $31 million. In the three months ended March 2009, we contributed $14 million to our pension plans.

The following table illustrates our expected future contractual obligation payments such as debt and lease agreements, and commitments and contingencies as of March 31, 2010.

					2011 &		2013 &		2015 &
In millions	Total		2010		2012		2014		thereafter
Recorded contractual obligations:

Long-term debt	$	1,674	$	-	$	17	$	225	$	1,432
Short-term debt		454		154		300		-		-
Regulatory infrastructure program costs (1)		244		53		159		32		-
Environmental remediation liabilities (1)		144		24		59		42		19
Total	$	2,516	$	231	$	535	$	299	$	1,451

Unrecorded contractual obligations and commitments (2):

Pipeline charges, storage capacity and gas supply (3)	$	2,089	$	405	$	755	$	381	$	548
Interest charges (4)		989		82		176		156		575
Operating leases		109		22		39		15		33
Asset management agreements (5)		31		17		14		-		-
Standby letters of credit, performance / surety bonds		16		10		6		-		-
Pension contributions (6)		4		4		-		-		-
Total	$	3,238	$	540	$	990	$	552	$	1,156

(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 gas natural gas purchase commitments of 22 Bcf at floating gas prices calculated using forward natural gas prices as of March 31, 2010, and are valued at $94 million.

(4)	Floating rate debt is based on the interest rate as of March 31, 2010, and the maturity of the underlying debt instrument. As of March 31, 2010, we have $33 million of accrued interest on our condensed consolidated statements of financial position that will be paid over the next 12 months.

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

(6)	We made a $4 million contribution in April 2010.

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Critical Accounting Estimates

The preparation of our financial statements 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 base our estimates on historical experience 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 4, 2010.

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 2.

Natural Gas Price Risk

Retail Energy Operations SouthStar’s use of derivative instruments is governed by a risk management policy, approved and monitored by its Finance and Risk Management Committee, which prohibits the use of derivatives for speculative purposes.

SouthStar routinely utilizes various types of derivative financial instruments to mitigate certain natural gas price and weather risk inherent in the natural gas industry. This includes the active management of storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. SouthStar uses these hedging instruments to lock in economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize its exposure to declining operating margins.

The following tables illustrate the change in the net fair value of the derivative financial instruments during the three months ended March 31, 2010 and 2009, and provide details of the net fair value of derivative financial instruments outstanding as of March 31, 2010.

	Three months ended Mar. 31,
In millions	2010			2009
Net fair value of derivative financial instruments outstanding at beginning of period	$	3		$	(17	)
Derivative financial instruments realized or otherwise settled during period		(4	)		9
Change in net fair value of derivative financial instruments		(6	)		(14	)
Net fair value of derivative financial instruments outstanding at end of period		(7	)		(22	)
Netting of cash collateral		17			27
Cash collateral and net fair value of derivative financial instruments outstanding at end of period	$	10		$	5

The sources of SouthStar’s net fair value of its natural gas-related derivative financial instruments at March 31, 2010, are as follows:

In millions		Prices actively quoted (Level 1) (1)				Significant other observable inputs (Level 2) (2)
Mature through 2010 (3)		$	(7	)		$	-

(1)	Valued using NYMEX futures prices.

(2)	Values primarily related to basis transactions that represent the commodity from NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers and were immaterial as of March 31, 2010.

(3)	Excludes cash collateral amounts.

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SouthStar routinely utilizes various types of financial and other instruments to mitigate certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts and swap agreements. The following tables include the fair values and average values of SouthStar’s derivative instruments as of the dates indicated. SouthStar bases the average values on monthly averages for the three months ended March 31, 2010 and 2009.

	Derivative financial instruments average fair values (1) at March 31,
In millions		2010		2009
Asset		$	3	$	11
Liability			14		35

(1) Excludes cash collateral amounts.

	Derivative financial instruments fair values netted with cash collateral at
In millions	Mar. 31, 2010		Dec. 31, 2009		Mar. 31, 2009
Asset	$	10	$	21	$	10
Liability		-		-		5

Value at Risk A 95% confidence interval is used to evaluate VaR exposure. A 95% confidence interval means that over the holding period, an actual loss in portfolio value is not expected to exceed the calculated VaR more than 5% of the time. We calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price distribution, price volatility, confidence interval and holding period. Our VaR may not be comparable to a similarly titled measure of another company because, although VaR is a common metric in the energy industry, there is no established industry standard for calculating VaR or for the assumptions underlying such calculations. SouthStar’s portfolio of positions for the three months ended March 31, 2010 and 2009 had quarterly average 1-day holding period VaRs of less than $100,000 and its high, low and period end 1-day holding period VaR were immaterial.

Wholesale Services Sequent routinely utilizes various types of derivative financial instruments to mitigate certain natural gas price risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts and financial swap agreements.

The following tables include the fair values and average values of Sequent’s derivative financial instruments as of the dates indicated. Sequent bases the average values on monthly averages for the three months ended March 31, 2010 and 2009.

	Derivative financial instruments average values (1) at March 31,
In millions	2010		2009
Asset	$	199	$	187
Liability		38		82

(1)	Excludes cash collateral amounts.

	Derivative financial instruments fair values netted with cash collateral at
In millions	Mar. 31, 2010		Dec. 31, 2009		Mar. 31, 2009
Asset	$	218	$	208	$	211
Liability		46		51		17

Sequent experienced $34 million and $75 million decreases in the net fair value of its outstanding contracts during the first three months of 2010 and 2009, respectively, due to changes in the fair value of derivative financial instruments utilized in its energy marketing and risk management activities and contract settlements.

The following tables illustrate the change in the net fair value of Sequent’s derivative financial instruments during the three months ended March 31, 2010 and 2009, and provide details of the net fair value of contracts outstanding as of March 31, 2010.

	Three months ended March 31,
In millions	2010			2009
Net fair value of derivative financial instruments outstanding at beginning of period	$	118		$	82
Derivative financial instruments realized or otherwise settled during period		(52	)		(95	)
Change in net fair value of derivative financial instruments		18			20
Net fair value of derivative financial instruments outstanding at end of period		84			7
Netting of cash collateral		88			187
Cash collateral and net fair value of derivative financial instruments outstanding at end of period	$	172		$	194

The sources of Sequent’s net fair value of its natural gas-related derivative financial instruments at March 31, 2010, are as follows:

In millions		Prices actively quoted (Level 1) (1)			Significant other observable inputs (Level 2) (2)
Mature through
2010		$	(33	)	$	65
	2011 – 2012		(22	)		67
	2013 – 2015		-			7
Total derivative financial instruments (3)		$	(55	)	$	139

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

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

(3)	Excludes cash collateral amounts.

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Value at Risk Sequent’s 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 Sequent generally manages physical gas assets and economically protects its positions by hedging in the futures markets, its open exposure is generally immaterial, permitting Sequent to operate within relatively low VaR limits. Sequent employs daily risk testing, using both VaR and stress testing, to evaluate the risks of its open positions.

Sequent’s management actively monitors open natural gas positions and the resulting VaR. Sequent continues to maintain a relatively matched book, where its 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, Sequent’s portfolio of positions for the three months ended March 31, 2010 and 2009 had the following VaRs.

	Three months ended March 31,
In millions	2010		2009
Period end	$	0.7	$	2.1
Average		1.4		1.9
High		3.0		3.3
Low		0.7		1.3

Energy Investments In 2009, Golden Triangle Storage began using derivative financial instruments to reduce its exposure during the construction of the storage caverns to the risk of changes with the price of natural gas that will be purchased in future periods for pad gas, which includes volumes of non-working natural gas used to maintain the operational integrity of the caverns. As of April 5, 2010, Golden Triangle Storage had hedged the price of the required pad gas for the first storage cavern or 3 Bcf and the associated fair value of the derivative financial instruments was immaterial.

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 $313 million of variable-rate debt, which includes $153 million of our variable-rate short-term debt and $160 million of variable-rate gas facility revenue bonds outstanding at March 31, 2010, a 100 basis point change in average market interest rates from 0.32% to 1.32% would have resulted in an increase in pretax interest expense of $3 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, 2010, Sequent’s top 20 counterparties represented approximately 65% of the total counterparty exposure of $473 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures.

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As of March 31, 2010, Sequent’s counterparties, or the counterparties’ guarantors, had a weighted-average S&P equivalent credit rating of A-, which is consistent with the credit ratings at March 31, 2009 and December 31, 2009. 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. The following table shows Sequent’s third-party natural gas contracts receivable and payable positions as of March 31, 2010 and 2009 and December 31, 2009.

	Gross receivables						Gross payables
	Mar. 31,		Dec. 31,		Mar. 31,		Mar. 31,		Dec. 31,		Mar. 31,
In millions	2010		2009		2009		2010		2009		2009
Netting agreements in place:
Counterparty is investment grade	$	449	$	483	$	237	$	328	$	277	$	168
Counterparty is non-investment grade		3		12		8		19		34		19
Counterparty has no external rating		101		106		76		265		207		153
No netting agreements in place:
Counterparty is investment grade		10		14		5		8		6		2
Amount recorded on statements of financial position	$	563	$	615	$	326	$	620	$	524	$	342

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 impaired. 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 $44 million at March 31, 2010, 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, 2009.

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, 2010, 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, 2010, 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 during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities and litigation incidental to the business. For information regarding pending federal and state regulatory matters, see “Note 6 - 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 will not have a material adverse effect on our consolidated financial statements.

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, 2010. 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 2010		-	$	-		-		4,950,951
February 2010		-		-		-		4,950,951
March 2010		-		-		-		4,950,951
Total first quarter		-	$	-		-

(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 no shares for such purposes in the first quarter of 2010. As of March 31, 2010, we had purchased a total of 327,860 of the 600,000 shares authorized for purchase, leaving 272,140 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.

Item 6. Exhibits

10	Continuity Agreement, entered into as of December 1, 2009, by and between AGL Resources Inc., on behalf of itself and AGL Services Company (its wholly owned subsidiary) and Paul R. Shlanta.

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.

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SIGNATURE

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

AGL RESOURCES INC.

(Registrant)

Date: April 27, 2010 /s/ Andrew W. Evans

Executive Vice President, Chief Financial Officer and Treasurer

Glossary of Key Terms

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