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 June 30, 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 þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” ”accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No þ

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.

Class	Outstanding as of July 19, 2010
Common Stock, $5.00 Par Value	77,930,719

Glossary of Key Terms

Table of Contents

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended June 30, 2010

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

Item
Number

		PART I – FINANCIAL INFORMATION		4 – 41

	1	Condensed Consolidated Financial Statements (Unaudited)		4 – 23
		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 – 23
		Note 1 – Accounting Policies and Methods of Application		9 – 11
		Note 2 – Derivative Financial Instruments		12 – 15
		Note 3 – Employee Benefit Plans		16 – 17
		Note 4 – Variable Interest Entity		17 – 18
		Note 5 – Debt		19
		Note 6 – Commitments and Contingencies		20
		Note 7 – Segment Information		20 – 23
	2	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24 – 37
		Forward-Looking Statements		24
		Overview		24 – 25
		Executive Summary		25 – 28
		Results of Operations		28 – 33
		Liquidity and Capital Resources		33 – 36
		Critical Accounting Estimates		37
	3	Quantitative and Qualitative Disclosures About Market Risk		37 – 40
	4	Controls and Procedures		41

		PART II – OTHER INFORMATION		41 – 42

	1	Legal Proceedings		41
	2	Unregistered Sales of Equity Securities and Use of Proceeds		41
	6	Exhibits		42

		SIGNATURE		43

Glossary of Key Terms

Table of Contents

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.
Hampton Roads	Virginia Natural Gas’ pipeline project, which connects its northern and southern systems
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
Jefferson Island	Jefferson Island Storage & Hub, LLC
LOCOM	Lower of weighted average cost or current market price
Magnolia	Magnolia Enterprise Holdings, Inc.
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
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

Table of Contents

PART 1 – Financial Information

Item 1. Financial Statements

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(UNAUDITED)

			As of
In millions	June 30, 2010		Dec. 31, 2009		June 30, 2009
Current assets
Cash and cash equivalents	$	16	$	26	$	12
Receivables
Energy marketing receivables (Note 1)		520		615		276
Gas, unbilled and other receivables		161		362		209
Less allowance for uncollectible accounts		21		14		19
Total receivables		660		963		466
Inventories, net (Note 1)		560		672		532
Derivative financial instruments – current portion (Note 1 and Note 2)		160		188		177
Unrecovered regulatory infrastructure program costs – current portion (Note 1)		44		43		41
Unrecovered environmental remediation costs – current portion (Note 1)		8		11		14
Other current assets		69		97		74
Total current assets		1,517		2,000		1,316
Long-term assets and other deferred debits
Property, plant and equipment		6,150		5,939		5,685
Less accumulated depreciation		1,849		1,793		1,729
Property, plant and equipment-net		4,301		4,146		3,956
Goodwill		418		418		418
Unrecovered regulatory infrastructure program costs (Note 1)		259		223		174
Unrecovered environmental remediation costs (Note 1)		156		161		146
Derivative financial instruments (Note 1 and Note 2)		49		52		37
Other		78		74		73
Total long-term assets and other deferred debits		5,261		5,074		4,804
Total assets	$	6,778	$	7,074	$	6,120
Current liabilities
Energy marketing trade payable (Note 1)	$	599	$	524	$	317
Short-term debt (Note 5)		394		602		418
Current portion of long-term debt (Note 5)		300		-		-
Accounts payable – trade		171		237		167
Accrued expenses		99		132		107
Accrued regulatory infrastructure program costs – current portion (Note 1)		67		55		50
Derivative financial instruments – current portion (Note 1 and Note 2)		67		52		36
Accrued environmental remediation liabilities – current portion (Note 1 and Note 6)		16		25		19
Other current liabilities		141		145		167
Total current liabilities		1,854		1,772		1,281
Long-term liabilities and other deferred credits
Long-term debt (Note 5)		1,553		1,974		1,675
Accumulated deferred income taxes		729		695		609
Accumulated removal costs (Note 1)		186		183		199
Accrued regulatory infrastructure program costs (Note 1)		175		155		113
Accrued pension obligations (Note 3)		146		159		187
Accrued environmental remediation liabilities (Note 1 and Note 6)		123		119		114
Accrued postretirement benefit costs (Note 3)		34		38		44
Derivative financial instruments (Note 1 and Note 2)		8		10		3
Other long-term liabilities and other deferred credits		143		150		136
Total long-term liabilities and other deferred credits		3,097		3,483		3,080
Total liabilities and other deferred credits		4,951		5,255		4,361
Commitments and contingencies (Note 6)
Equity
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,810		1,780		1,732
Noncontrolling interest (Note 4)		17		39		27
Total equity		1,827		1,819		1,759
Total liabilities and equity	$	6,778	$	7,074	$	6,120
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						Six months ended
	June 30,						June 30,
In millions, except per share amounts	2010			2009			2010			2009
Operating revenues	$	359		$	377		$	1,362		$	1,372
Operating expenses
Cost of gas		141			152			712			741
Operation and maintenance		119			119			244			244
Depreciation and amortization		39			39			79			78
Taxes other than income taxes		12			12			26			24
Total operating expenses		311			322			1,061			1,087
Operating income		48			55			301			285
Other income		-			3			2			5
Interest expense, net		(26	)		(24	)		(54	)		(49	)
Earnings before income taxes		22			34			249			241
Income tax expense		8			13			90			85
Net income		14			21			159			156
Less net income attributable to the noncontrolling interest (Note 4)		-			1			11			17
Net income attributable to AGL Resources Inc.	$	14		$	20		$	148		$	139
Per common share data (Note 1)
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	0.17		$	0.26		$	1.91		$	1.81
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	0.17		$	0.26		$	1.90		$	1.81
Cash dividends declared per common share	$	0.44		$	0.43		$	0.88		$	0.86
Weighted-average number of common shares outstanding (Note 1)
Basic		77.4			76.7			77.3			76.8
Diluted		77.8			76.9			77.7			76.9

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		-		-		-			139			-			-			17			156
Other comprehensive loss		-		-		-			-			(3	)		-			(2	)		(5	)
Dividends on common stock ($0.86 per share)		-		-		-			(66	)		-			(2	)		-			(68	)
Distributions to noncontrolling interest (Note 4)		-		-		-			-			-			-			(20	)		(20	)
Issuance of treasury shares		0.4		-		(6	)		(3	)		-			17			-			8
Stock-based compensation expense (net of tax) (Note 1)		-		-		4			-			-			-			-			4
Balance as of June 30, 2009		77.3	$	390	$	674		$	833		$	(137	)	$	(28	)	$	27		$	1,759

	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		-			-		-			148			-			-			11			159
Other comprehensive loss		-			-		-			-			(11	)		-			-			(11	)
Dividends on common stock ($0.88 per share)		-			-		-			(68	)		-			2			-			(66	)
Purchase of additional 15% ownership interest in SouthStar (Note 4)		-			-		(51	)		-			(1	)		-			(6	)		(58	)
Distributions to noncontrolling interest (Note 4)		-			-		-			-			-			-			(27	)		(27	)
Purchase of treasury shares		(0.1	)		-		-			-			-			(2	)		-			(2	)
Issuance of treasury shares		0.6			-		(8	)		(2	)		-			18			-			8
Stock-based compensation expense (net of tax) (Note 1)		-			-		4			-			-			1			-			5
Balance as of June 30, 2010		78.0		$	390	$	624		$	926		$	(128	)	$	(2	)	$	17		$	1,827

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						Six months ended
	June 30,						June 30,
In millions	2010			2009			2010			2009
Comprehensive income attributable to AGL Resources Inc. (net of tax)
Net income attributable to AGL Resources Inc.	$	14		$	20		$	148		$	139
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		(11	)		(1	)		(17	)		(11	)
Reclassification of derivative financial instruments realized losses included in net income		2			6			6			8
Other comprehensive (loss) income		(9	)		5			(11	)		(3	)
Comprehensive income (Note 1)	$	5		$	25		$	137		$	136

Comprehensive income attributable to noncontrolling interest (net of tax)
Net income attributable to noncontrolling interest	$	-		$	1		$	11		$	17
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		-			(1	)		(1	)		(6	)
Reclassification of derivative financial instruments realized losses included in net income		-			3			1			4
Other comprehensive income (loss)		-			2			-			(2	)
Comprehensive income (Note 1)	$	-		$	3		$	11		$	15

Total comprehensive income, including portion attributable to noncontrolling interest (net of tax)
Net income	$	14		$	21		$	159		$	156
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		(11	)		(2	)		(18	)		(17	)
Reclassification of derivative financial instruments realized losses included in net income		2			9			7			12
Other comprehensive (loss) income		(9	)		7			(11	)		(5	)
Comprehensive income (Note 1)	$	5		$	28		$	148		$	151

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)

	Six months ended
	June 30,
In millions	2010			2009
Cash flows from operating activities
Net income	$	159		$	156
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		79			78
Change in derivative financial instrument assets and liabilities		44			14
Deferred income taxes		36			29
Changes in certain assets and liabilities
Gas, unbilled and other receivables		208			266
Energy marketing receivables and energy marketing trade payables, net (Note 1)		170			51
Inventories		112			131
Deferred natural gas costs (Note 1)		(7	)		46
Gas and trade payables		(66	)		(35	)
Accrued expenses		(33	)		(6	)
Other – net		11			1
Net cash flow provided by operating activities		713			731
Cash flows from investing activities
Payments to acquire property, plant and equipment		(249	)		(207	)
Net cash flow used in investing activities		(249	)		(207	)
Cash flows from financing activities
Net payments and borrowings of short-term debt (Note 5)		(208	)		(448	)
Payments of gas facility revenue bonds (Note 5)		(121	)		-
Dividends paid on common shares		(66	)		(68	)
Purchase of additional 15% ownership interest in SouthStar (Note 4)		(58	)		-
Distribution to noncontrolling interest (Note 4)		(27	)		(20	)
Purchase of treasury shares		(2	)		-
Issuance of treasury shares and other		8			8
Net cash flow used in financing activities		(474	)		(528	)
Net decrease in cash and cash equivalents		(10	)		(4	)
Cash and cash equivalents at beginning of period		26			16
Cash and cash equivalents at end of period	$	16		$	12
Cash paid during the period for
Interest	$	53		$	47
Income taxes	$	35		$	35

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 and six months ended June 30, 2010 and 2009, and our financial condition as of December 31, 2009, and June 30, 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 June 30, 2010, December 31, 2009 and June 30, 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.

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.

Glossary of Key Terms

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	June 30,		Dec. 31,		June 30,
In millions	2010		2009		2009
Regulatory assets
Unrecovered regulatory infrastructure program costs	$	303	$	266	$	215
Unrecovered ERC		164		172		160
Unrecovered postretirement benefit costs		10		10		10
Unrecovered seasonal rates		-		11		-
Other		36		27		28
Total regulatory assets		513		486		413
Associated assets
Derivative financial instruments		23		11		21
Total regulatory and associated assets	$	536	$	497	$	434
Regulatory liabilities
Accumulated removal costs	$	186	$	183	$	199
Deferred natural gas costs		23		30		52
Derivative financial instruments		23		11		21
Regulatory tax liability		16		17		18
Unamortized investment tax credit		12		13		14
Deferred seasonal rates		9		-		9
Other		20		17		17
Total regulatory liabilities		289		271		330
Associated liabilities
Regulatory infrastructure program costs		242		210		163
ERC		128		133		120
Total associated liabilities		370		343		283
Total regulatory and associated liabilities	$	659	$	614	$	613

As of June 30, 2010, there have been no new types of regulatory assets or liabilities as discussed 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, SouthStar and Jefferson Island, we account for natural gas inventory at the lower of WACOG or market price.

SouthStar and Sequent 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 six months ended June 30, 2009; however, no LOCOM adjustments were recorded in the six months ended June 30, 2010. Sequent recorded LOCOM adjustments of $4 million for the six months ended June 30, 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 June 30,
In millions	2010		2009
Denominator for basic earnings per share (1)		77.4		76.7
Assumed exercise of restricted stock, restricted stock units and stock options		0.4		0.2
Denominator for diluted earnings per share		77.8		76.9
(1) Daily weighted-average shares outstanding.

	Six months ended June 30,
In millions	2010		2009
Denominator for basic earnings per share (1)		77.3		76.8
Assumed exercise of restricted stock, restricted stock units and stock options		0.4		0.1
Denominator for diluted earnings per share		77.7		76.9
(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:

	June 30,
In millions	2010		2009
Three months ended		0.8		2.3
Six months ended		0.8		2.2

The decrease of 1.5 million in anti-dilutive shares for the three months and 1.4 million shares for the six months ended June 30, 2010, was primarily a result of a higher average market value of our common shares compared to the same periods during 2009.

Stock-Based Compensation

In the first six months of 2010, we issued grants of approximately 154,000 restricted stock units and 151,000 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. For more information on our derivative financial instruments, see Note 2. For more information on our pension and postretirement obligations, see Note 3.

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 or financial position and became 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 becomes 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.

Subsequent Event

On July 1, 2010, we completed the sale of AGL Networks, our telecommunications business. This sale will not have a material effect on our consolidated results of operations, cash flows or financial position.

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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

Our derivative financial instruments do not contain any material credit-risk-related or other contingent features that could increase the payments for collateral that we post in the normal course of business when our financial instruments are in net liability positions. Additional information on our energy marketing receivables and payables, which does have credit-risk-related or other contingent features, are discussed in 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. The table below summarizes the various ways in which we account for our derivative instruments and the impact on our condensed consolidated financial statements:

	Recognition and Measurement
Accounting Treatment	Statement of Financial Position	Income Statement
Cash flow hedge	Recorded at fair value	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings

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

Interest Rate Swaps

We have $300 million of senior notes set to mature in January 2011. In May 2010, as a result of an anticipated refinancing of these senior notes, we entered into $200 million of forward interest rate swaps, with a treasury rate of 3.94%. We designated the forward interest rate swap as a cash flow hedge against the first 20 future semi-annual interest payments. The fair values of our interest rate swaps were reflected as a short-term liability of $13 million at June 30, 2010. For more information on our senior notes, see Note 5.

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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 June 30, 2010, December 31, 2009 and June 30, 2009. 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 Derivative financial instruments
	June 30, 2010					December 31, 2009					June 30, 2009
In millions	Assets		Liabilities			Assets (1)		Liabilities			Assets		Liabilities
Quoted prices in active markets (Level 1)	$	34	$	(55	)	$	36	$	(37	)	$	34	$	(105	)
Significant other observable inputs (Level 2)		148		(50	)		172		(52	)		140		(18	)
Netting of cash collateral		27		30			30		27			40		84
Total carrying value (2) (3)	$	209	$	(75	)	$	238	$	(62	)	$	214	$	(39	)

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

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

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

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 June 30, 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	June 30, 2010 (1)			Dec. 31, 2009			June 30, 2009
Hedge designation:
Cash flow		5			5			4
Not designated		244			108			124
Total		249			113			128
Hedge position:
Short		(1,571	)		(1,518	)		(995	)
Long		1,820			1,631			1,123
Net long position		249			113			128

(1)	Approximately 93% of these contracts have durations of two years or less and the remaining 7% expire 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 condensed consolidated statements of income.

	For the three months ended June 30,							For the six months ended June 30,
In millions		2010			2009				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		$	(3	)	$	(12	)	$	(10	)	$	(16	)

Not designated as hedges under authoritative guidance related to derivatives and hedging
Natural gas contracts – fair value adjustments recorded in operating revenues (1)			(2	)		16			16			52
Natural gas contracts – net fair value adjustments recorded in cost of gas (2)			(1	)		-			(3	)		(1	)
Total gains on derivative instruments		$	(6	)	$	4		$	3		$	35

(1)	Associated with the fair value of existing derivative instruments at June 30, 2010 and 2009.

(2)	Excludes losses recorded in cost of gas associated with weather derivatives of $20 million for the six months ended June 30, 2010 and $4 million for the six months ended June 30, 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 the fair values of these derivative instruments:

In millions	As of June 30, 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	$	(3	)
Interest rate swaps – expected net loss to be reclassified from OCI into interest expense as the net loss is amortized over next twelve months (1)		(1	)

(1) Remaining $12 million to be amortized over remaining 9 years.

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Derivative Financial Instruments on the Condensed Consolidated Statements of Financial Position

In accordance with regulatory requirements, $7 million and $15 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 and six months ended June 30, 2010, respectively, and $7 million and $20 million during the three and six months ended June 30, 2009, respectively. The following table presents the fair value and statements of financial position classification of our derivative financial instruments.

					As of
In millions	Statement of financial position location (1) (2)	June 30, 2010			Dec. 31, 2009				June 30, 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	$	4		$	6		$	13

Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		(8	)		(5	)		(18	)
Interest rate swap agreement	Derivative financial instruments liabilities – current portion		(13	)		-			-
	Total		(17	)		1			(5	)

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		528			590			417
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		120			118			64

Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		(458	)		(510	)		(392	)
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		(96	)		(78	)		(33	)
	Total		94			120			56
Total derivative financial instruments		$	77		$	121		$	51

(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 cash collateral held on deposit in broker margin accounts of $57 million as of June 30, 2010, $124 million as of June 30, 2009 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 June 30,
In millions	2010			2009
Service cost	$	2		$	2
Interest cost		7			6
Expected return on plan assets		(7	)		(8	)
Amortization of prior service cost		-			-
Recognized actuarial loss		2			3
Net pension benefit cost	$	4		$	3

	Six months ended June 30,
In millions	2010			2009
Service cost	$	5		$	4
Interest cost		14			13
Expected return on plan assets		(15	)		(15	)
Amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		5			5
Net pension benefit cost	$	8		$	6

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, the Patient Protection and Affordable Care Act became law. With this healthcare reform, the cash Retiree Drug 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 June 30,
In millions	2010			2009
Service cost	$	1		$	-
Interest cost		2			2
Expected return on plan assets		(2	)		(1	)
Amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		-			-
Net postretirement benefit cost	$	-		$	-

	Six months ended June 30,
In millions	2010			2009
Service cost	$	1		$	-
Interest cost		3			3
Expected return on plan assets		(3	)		(2	)
Amortization of prior service cost		(2	)		(2	)
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 and established a 100% funding target (over a 7-year amortization period) for plan years beginning after December 31, 2007. If certain conditions are met, the Worker, Retiree and Employer Recovery Act of 2008 (passed in December, 2008) allows us to measure our required contributions based on an increased funding target of 96% for 2010 and will increase to 100% in 2011.

In the first six months of 2010 we contributed $21 million and an additional $5 million in July 2010 for a total of $26 million to our qualified pension plans. Based on the current funding status of the plans, we are required to make a minimum contribution to the plans of approximately $21 million in 2010. We are planning to make additional contributions to our pension plans in 2010 up to $5 million, for a total of up to $31 million to meet our 80% funding target. During the first six months of 2009 we contributed $17 million to our qualified pension plans.

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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 $3 million in the first six months of 2010 and $4 million the same period last year.

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. SouthStar and GNG are involved in litigation arising from the normal course of business. For more information see 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 purchase 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. Our condensed consolidated statements of equity and condensed consolidated statements of cash flows provide additional information regarding the impact the purchase had on our financial statements.

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.

Operations

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, its credit exposure and to certain natural gas suppliers in support of SouthStar’s payment obligations.

·	SouthStar utilizes our commercial paper program for its liquidity and working capital requirements.

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

Back office functions

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

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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 June 30, 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 $105 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 beyond our corporate guarantees we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required.

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

Our cash flows used in our investing activities includes capital expenditures of $1 million for SouthStar during the six months ended June 30, 2010 and 2009. Our cash flow used in our financing activities includes SouthStar’s distributions to the noncontrolling interest, which reflects the cash distribution to Piedmont for its applicable portion of SouthStar’s annual earnings from the prior year. Generally this distribution occurs in the first or second quarter. In the six months ended June 30, 2010 SouthStar distributed $27 million to Piedmont and $20 million during the same period last year. The increase of $7 million in cash distributions that SouthStar made to Piedmont was the result of higher earnings in 2009 compared to 2008.

The following tables provide additional information on SouthStar’s assets and liabilities as of June 30, 2010, December 31, 2009 and June 30, 2009, which are consolidated within our condensed consolidated statement of financial position.

	As of June 30, 2010
In millions	Consolidated		SouthStar (1)		%	(2)
Current assets	$	1,517	$	154	10	%
Long-term assets and other deferred debits		5,261		9	-
Total assets	$	6,778	$	163	2	%
Current liabilities	$	1,854	$	40	2	%
Long-term liabilities and other deferred credits		3,097		-	-
Equity		1,827		123	7
Total liabilities and equity	$	6,778	$	163	2	%

	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 June 30, 2009
In millions	Consolidated		SouthStar (1)		%	(2)
Current assets	$	1,316	$	140	11	%
Long-term assets and other deferred debits		4,804		9	-
Total assets	$	6,120	$	149	2	%
Current liabilities	$	1,281	$	47	4	%
Long-term liabilities and other deferred credits		3,080		-	-
Equity		1,759		102	6
Total liabilities and equity	$	6,120	$	149	2	%

(1)

These amounts reflect information for SouthStar and do not include intercompany eliminations and the balances of a wholly-owned subsidiary with the 85% ownership interest in SouthStar. Accordingly, the amounts will not agree to the identifiable and total assets for our retail energy operations segment reported in Note 7.

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

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Note 5 - Debt

The following table provides maturity dates, interest rates and amounts outstanding for our various debt securities. For additional 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.

			June 30, 2010							June 30, 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	$	-		-	%	$	-
Commercial paper	2010			0.4			393		601		0.9			417
Capital leases		2010-2011		4.9			1		1		4.9			1
Total short-term debt				3.9	% (4)	$	694	$	602		1.0	%	$	418
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		1.8			79		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)				5.4	% (5)	$	1,553	$	1,974		5.5	%	$	1,675

Total debt				5.0	%	$	2,247	$	2,576		4.5	%	$	2,093

(1)	For the six months ended June 30, 2010.

(2)	For the six months ended June 30, 2009.

(3)

Including the $300 million of senior notes due in 2011, our estimated fair value was $2,144 million as of June 30, 2010, $2,060 million as of December 31, 2009 and $1,725 million as of June 30, 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)	Excluding the $300 million of senior notes due in 2011, the weighted average interest rate for the six months ended June 30, 2010 was 0.4%.

(5)	Including the $300 million of senior notes due in 2011, the weighted average interest rate for the six months ended June 30, 2010 was 5.7%.

Gas Facility Revenue Bonds

In June 2010, the letters of credit that provide credit enhancements to $121 million of gas facility revenue bonds expired; therefore, we tendered these bonds with commercial paper borrowings.

Senior Notes

We have $300 million of senior notes, set to mature in January 2011, which are reported as a current portion of long-term debt on our condensed consolidated statements of financial position. As a result of an anticipated refinancing of these senior notes, we entered into $200 million of forward interest rate swaps, at a treasury rate of 3.94%. For more information on our interest rate swaps, see Note 2.

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 54% at June 30, 2010, 57% at December 31, 2009 and 53% at June 30, 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 55% at June 30, 2010, 59% at December 31, 2009 and 54% at June 30, 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 June 30, 2010.

	Commitments due before December 31,
In millions	Total		2010		2011 & thereafter
Standby letters of credit and performance and surety bonds	$	16	$	7	$	9

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 on 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 has been 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. Following are the reconciliations of EBIT to operating income, earnings before income taxes and net income for the three and six months ended June 30, 2010 and 2009.

	Three months ended June 30,
In millions	2010		2009
Operating income	$	48	$	55
Other income		-		3
EBIT		48		58
Interest expense, net		26		24
Earnings before income taxes		22		34
Income taxes		8		13
Net income	$	14	$	21

	Six months ended June 30,
In millions	2010		2009
Operating income	$	301	$	285
Other income		2		5
EBIT		303		290
Interest expense, net		54		49
Earnings before income taxes		249		241
Income taxes		90		85
Net income	$	159	$	156

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 and six months ended June 30, 2010 and 2009, by segment, are shown in the following tables.

Three months ended June 30, 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	$	226	$	117	$	(8	)	$	23		$	1		$	359
Intercompany revenues (1)		34		-		-			-			(34	)		-
Total operating revenues		260		117		(8	)		23			(33	)		359
Operating expenses
Cost of gas		62		99		1			11			(32	)		141
Operation and maintenance		86		17		9			9			(2	)		119
Depreciation and amortization		34		-		1			1			3			39
Taxes other than income taxes		10		-		1			1			-			12
Total operating expenses		192		116		12			22			(31	)		311
Operating income (loss)		68		1		(20	)		1			(2	)		48
Other income (loss)		1		-		-			(1	)		-			-
EBIT	$	69	$	1	$	(20	)	$	-		$	(2	)	$	48
Capital expenditures	$	92	$	-	$	1		$	36		$	6		$	135

Three months ended June 30, 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	$	240	$	125	$	2		$	10	$	-		$	377
Intercompany revenues (1)		35		-		-			-		(35	)		-
Total operating revenues		275		125		2			10		(35	)		377
Operating expenses
Cost of gas		85		102		-			-		(35	)		152
Operation and maintenance		88		16		11			7		(3	)		119
Depreciation and amortization		33		1		1			1		3			39
Taxes other than income taxes		9		1		1			-		1			12
Total operating expenses		215		120		13			8		(34	)		322
Operating income (loss)		60		5		(11	)		2		(1	)		55
Other income		3		-		-			-		-			3
EBIT	$	63	$	5	$	(11	)	$	2	$	(1	)	$	58
Capital expenditures	$	89	$	1	$	-		$	17	$	3		$	110

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Six months ended June 30, 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	$	754	$	510	$	59	$	37		$	2		$	1,362
Intercompany revenues (1)		72		-		-		-			(72	)		-
Total operating revenues		826		510		59		37			(70	)		1,362
Operating expenses
Cost of gas		364		396		9		13			(70	)		712
Operation and maintenance		173		37		24		15			(5	)		244
Depreciation and amortization		68		1		1		3			6			79
Taxes other than income taxes		19		1		2		2			2			26
Total operating expenses		624		435		36		33			(67	)		1,061
Operating income (loss)		202		75		23		4			(3	)		301
Other income (loss)		3		-		-		(1	)		-			2
EBIT	$	205	$	75	$	23	$	3		$	(3	)	$	303

Identifiable and total assets (2)	$	5,217	$	175	$	987	$	530		$	(131	)	$	6,778
Goodwill	$	404	$	-	$	-	$	14		$	-		$	418
Capital expenditures	$	162	$	1	$	1	$	76		$	9		$	249
Six months ended June 30, 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	$	812	$	468	$	70	$	20		$	2		$	1,372
Intercompany revenues (1)		70		-		-		-			(70	)		-
Total operating revenues		882		468		70		20			(68	)		1,372
Operating expenses
Cost of gas		440		361		9		-			(69	)		741
Operation and maintenance		171		36		30		12			(5	)		244
Depreciation and amortization		65		2		2		3			6			78
Taxes other than income taxes		18		1		2		1			2			24
Total operating expenses		694		400		43		16			(66	)		1,087
Operating income (loss)		188		68		27		4			(2	)		285
Other income		5		-		-		-			-			5
EBIT	$	193	$	68	$	27	$	4		$	(2	)	$	290

Identifiable and total assets (2)	$	4,972	$	182	$	686	$	386		$	(106	)	$	6,120
Goodwill	$	404	$	-	$	-	$	14		$	-		$	418
Capital expenditures	$	158	$	1	$	-	$	40		$	8		$	207

(1)

Intercompany revenues – wholesale services records its energy marketing and risk management revenues on a net basis, which includes intercompany revenues of $91 million and $271 million for the three and six months ended June 30, 2010 and $92 million and $257 million for the three and six months ended June 30, 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 June 30, 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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Virginia Natural Gas and Chattanooga Gas both have decoupled rates, which separate the recovery of fixed costs for providing service from the volumes of customer throughput. In traditional rate designs, our utilities’ recovery of a significant portion of their fixed customer service and pipeline infrastructure costs is tied to assumed natural gas volumes used by our customers. We believe that separating the recoverable amount of these costs from the customer throughput volumes, or amounts of natural gas used by our customers, allows us to encourage our customers’ energy conservation and ensures a more stable recovery of our fixed costs.

Our retail energy operations segment, which consists of SouthStar, uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. Our Sequent subsidiary within our wholesale services segment generally has greater opportunity to capture operating margin due to price volatility as a result of extreme weather. Our energy investments segment’s primary activity is our natural gas storage business, which develops, acquires and operates high-deliverability salt-dome storage assets in the Gulf Coast region of the United States. While this business 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. For additional information on our operating segments see Item 1, “Business” of our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 4, 2010.

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 improves customer service and reduces the lag between our investments in infrastructure and the recovery of those investments through various rate mechanisms.

If our rate design proposals are not approved, we will continue to work cooperatively with our regulators, legislators and others to create a framework that is conducive to our business goals and the interests of our customers and shareholders. For additional information on our regulatory strategy see Item 1, “Business” under the caption “Regulatory Planning” of our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 4, 2010.

In 2009, Elizabethtown Gas received approval to increase its annual base rates by $3 million and reduce its overall composite depreciation rate from 3.20% to 2.58%, which equates to an annual reduction in depreciation expenses of approximately $5 million. However, such approval from the New Jersey BPU did not address our proposed decoupling rate design but instead established a separate procedural schedule to consider our proposal. We will continue to work with the New Jersey BPU on the proposed decoupling program and evaluate our proposal relative to feedback and comments received from the New Jersey BPU. Based on the process, we could determine the decoupling proposal no longer meets the needs of our customers and of Elizabethtown Gas, resulting in us delaying our proposal. We expect to reach resolution on our proposed decoupling and energy-efficiency programs at Elizabethtown Gas in 2010. Additionally, effective June 1, 2010, Chattanooga Gas received approval to increase its annual base rates by less than $1 million. Chattanooga Gas also received approval for a one-time $1 million recovery of prior legal expenses.

In 2010, these approved regulatory actions will increase EBIT by approximately $10 million, which is based on the approved new rates for Elizabethtown Gas for all of 2010 and Chattanooga Gas from June 2010 through December 2010. The following provide additional information on our rate cases.

Atlanta Gas Light In May 2010, Atlanta Gas Light filed its rate case request with the Georgia Commission, which would increase the average annual residential natural gas bill by about 3%. The higher revenues requested in the filing would support ongoing operations and are based on the following:

·	reset the company's return on equity ($19 million),

·	fund new customer service initiatives ($13 million),

·	retain a portion of savings from our acquisitions benefiting Atlanta Gas Light customers ($14 million), and

·	restructure depreciation expenses ($8 million).

If approved, these changes totaling $54 million would go into effect in November 2010 and would be reflected in Atlanta Gas Light's base rate charge assessed to customers by the Marketers. We anticipate a decision by the Georgia Commission in November 2010.

Chattanooga Gas In May 2010, the Tennessee Authority approved new base rates for Chattanooga Gas, which went into effect on June 1, 2010. These new rates include energy-efficiency and conservation programs, as well as a mechanism to recover lost revenue resulting from these programs, updated depreciation rates that resulted in decreased depreciation expense of $2 million annually, and the recovery of approximately $1 million in prior legal expenses that was recognized in the second quarter of 2010. The approved rate adjustment includes a reduction in the authorized return on equity from 10.2% to 10.05%. This decoupled rate design is the first such program for a utility in Tennessee.

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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. The following provide updates on some of our larger capital projects.

Atlanta Gas Light 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 Georgia Commission approved the Integrated System Reinforcement Program’s initial three years’ expenditures 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 incorporates our existing pipeline replacement program, which was initiated in 1998 and is scheduled to be completed in December 2013.

In January 2010, the Georgia Commission approved the Integrated Customer Growth Program under STRIDE which authorized Atlanta Gas Light to invest up to an additional $45 million of expenditures to extend Atlanta Gas Light’s pipeline facilities to serve customers without pipeline access and create new economic development opportunities in Georgia. The Integrated Customer Growth Program was approved as a three-year pilot program under STRIDE, and the recovery of the approved surcharge, which was extended until 2025.

The following table provides more information on our expenditures under these programs during the six months ended June 30, 2010.

In millions
Pipeline replacement program	$	32
Integrated System Reinforcement Program		4
Integrated Customer Growth Program		1
Total	$	37

Elizabethtown Gas 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 has been 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 $26 million in the six months ended June 30, 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.

Golden Triangle Storage 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. We have spent approximately $71 million in capital expenditures for this project in the six months ended June 30, 2010.

Jefferson Island In June 2010, Jefferson Island filed a permit application with the Louisiana Department of Natural Resources to expand its natural gas storage facility through the addition of two caverns. We anticipate receiving approval by March 31, 2011. The new caverns are expected to take three to five years to construct and will expand the working gas capacity at Jefferson Island from 7.5 Bcf to approximately 19.5 Bcf.

Customer growth

We continue to see challenging economic conditions in all of the areas we serve, evidenced by high rates of unemployment and a depressed housing market with high inventories and significantly reduced new home construction. As a result, we 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 six months ended June 30, 2010, our distribution operations customer loss rate was less than (0.1)%, compared to (0.3)% for the same period last year. Our customer counts continue to be impacted by both slow growth in the residential housing markets and a slow down in new commercial developments. This trend has been offset slightly by customer attrition mitigation strategies at all of our utilities.

Additionally, we expect these economic conditions will continue to impact our customers’ household incomes during the upcoming winter heating season, driving the increased potential for lower operating revenues due to customer conservation and higher bad debt expense from customers’ inability to pay their natural gas bills. As a result, we continue to work with regulators and state agencies in each of our jurisdictions to educate customers throughout the year about energy costs in advance of the winter heating season, and to ensure that those customers who qualify receive support through various energy assistance programs.

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We continue to mitigate these current economic conditions through our use of a variety of targeted marketing programs to attract new customers and to retain existing ones. These efforts include working to add residential customers, multifamily complexes and commercial customers who use natural gas for purposes other than space heating, as well as evaluating and launching new natural gas related programs, products and services to enhance customer growth, mitigate customer attrition and increase operating revenues. These programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities.

In addition, we partner with numerous third-party entities such as builders, realtors, plumbers, mechanical contractors, architects and engineers to market the benefits of natural gas appliances and to identify potential retention options early in the process for those customers who might consider converting to alternative fuels. We use analytical predictive models to identify and target these customers who might consider switching from natural gas to other sources of energy in order to retain them as a customer.

We have seen a 2% decline in average customer count in Georgia at SouthStar for the six months ended June 30, 2010. This reflects some improvement from last year when SouthStar experienced a 4% decline in average customer count. These declines reflect 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.

The Georgia retail natural gas market is currently comprised of nine Marketers, of which SouthStar has the leading market share. SouthStar’s market share in Georgia during the six months ended June 30, 2010 was 33%, which was consistent with its market share in 2009. This stability in SouthStar’s market share reflects an improvement over last year when it experienced a decline from a 35% market share in 2008. Over the last couple of years, increased competition, volatility in natural gas prices and the heavy promotion of fixed price plans by SouthStar’s competitors has resulted in increased pressure on retail natural gas prices charged to its customers. Accordingly, SouthStar’s residential and commercial customers have been migrating to fixed price plans, which have impacted SouthStar’s customer growth. In addition, SouthStar’s operating margin under these fixed price-plans is lower than variable price plans. SouthStar uses hedges for customers who are on fixed price plans to manage its exposure to commodity price risk. While we have continued to experience customers migrating to fixed price plans, we have seen some stabilization in 2010 of the number of customers on fixed price plans as compared to last year. We expect these trends to continue for the remainder of 2010.

In Ohio, during the second quarter of 2010, SouthStar experienced a decline in customer equivalents as some of the agreements allowing it to supply natural gas to customers in Ohio expired. SouthStar expanded into the Ohio market in 2006, principally through being awarded supply agreements, but has continued its expansion in Ohio through attracting customers using retail choice programs. As the Ohio deregulated market has continued to evolve, we have experienced increased competition with respect to being awarded new supply agreements and being able to attract new retail choice customers. We still believe that Ohio is a growth market for us, but due to the increased competition we will continue to monitor and evaluate other states where natural gas choice programs may offer potential future markets and sources for growth.

Capital market plan

Our capital market plan over the next 6 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.

Over the past two years a number of financial institutions have experienced significant financial distress, resulting in the write-down of assets and the need to raise additional capital. As a result, the cost of credit has increased overall for many companies as financial institutions have required higher returns to be compensated for their own rising costs of capital and additional market risk in an uncertain economy. Due to these significant changes, we expect the terms of any renewed facilities or financing arrangements to be different than those under our existing Credit Facility, which was put into place in 2006 when the overall cost of credit was much lower on a relative basis. Specifically, we expect most lenders to offer credit commitments of a shorter duration than the 5-year term under our existing Credit Facility.

We have not yet determined the ultimate size of our anticipated new Credit Facility relative to our current $1 billion level; however, we expect to refinance at least $1 billion. For additional information on our Credit Facility and our capital market plan see “Liquidity and Capital Resources” under the caption “Cash Flow from Financing Activities” and “Short-term Debt”.

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Energy marketing activities

Sequent’s expected natural gas withdrawals from physical salt dome and reservoir storage are presented in the following table along with the operating revenues expected at the time of withdrawal. 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 June 30, 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
	Salt dome (WACOG $4.22)		Reservoir (WACOG $4.01)		operating revenues (in millions)
2010
Third quarter		-		10	$	5
Fourth quarter		2		8		7
2011
First quarter		1		11		13
Total		3		29	$	25

If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, it expects operating revenues from storage withdrawals of approximately $25 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. 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.

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.

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The following table sets forth a reconciliation of our operating margin to operating income and EBIT to our earnings before income taxes and net income, together with other consolidated financial information for the three and six months ended June 30, 2010 and 2009.

	Three months ended June 30,							Six months ended June 30,
In millions	2010		2009		Change			2010		2009		Change
Operating revenues	$	359	$	377	$	(18	)	$	1,362	$	1,372	$	(10	)
Cost of gas		141		152		(11	)		712		741		(29	)
Operating margin (1)		218		225		(7	)		650		631		19
Operating expenses		170		170		-			349		346		3
Operating income		48		55		(7	)		301		285		16
Other income		-		3		(3	)		2		5		(3	)
EBIT (1)		48		58		(10	)		303		290		13
Interest expense, net		26		24		2			54		49		5
Earnings before income taxes		22		34		(12	)		249		241		8
Income tax expense		8		13		(5	)		90		85		5
Net income		14		21		(7	)		159		156		3
Net income attributable to the noncontrolling interest		-		1		(1	)		11		17		(6	)
Net income attributable to AGL Resources Inc.	$	14	$	20	$	(6	)	$	148	$	139	$	9

(1) These are non-GAAP measurements.

For the second quarter of 2010, net income attributable to AGL Resources Inc. decreased by $6 million or 30% compared to the same period last year. The decrease was primarily the result of lower operating margins at wholesale services and retail energy operations and increased expenses at energy investments. This decrease was partially offset by higher operating margins at distribution operations primarily due to increased revenue from the Hampton Roads Crossing and Magnolia pipeline projects, increased regulatory infrastructure program revenue at Atlanta Gas Light.

For the six months ended June 30, 2010, net income attributable to AGL Resources Inc. increased by $9 million or 6% compared to the same period last year. The increase was primarily the result of higher operating margins at distribution operations and retail energy operations and reduced net income attributable to the noncontrolling interest largely a result of our increased ownership interest in SouthStar.

Interest expense increased by $2 million or 8% for the second quarter of 2010 and $5 million or 10% for the six months ended June 30, 2010 compared to the same periods last year 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 June 30,									Six months ended June 30,
In millions	2010			2009			Change			2010			2009			Change
Average debt outstanding (1)	$	2,099		$	1,996		$	103		$	2,182		$	2,155		$	27
Average rate		5.0	%		4.8	%		0.2	%		4.9	%		4.5	%		0.4	%

(1) Daily average of all outstanding debt.

Our income tax expense decreased by $5 million or 38% for the second quarter of 2010 compared to the second quarter of 2009. This was primarily due to lower consolidated earnings. Our income tax expense increased by $5 million or 6% for the six months ended June 30, 2010 compared to the same period last year. This was primarily due to higher year to date 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 and six months ended June 30, 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 June 30,			2010 vs. normal colder		2010 vs. 2009 colder		Six months ended June 30,			2010 vs. normal colder		2010 vs. 2009 colder
		Normal	2010	2009	(warmer)		(warmer)		Normal	2010	2009	(warmer)		(warmer)
Georgia		140	70	181	(50	)%	(61	)%	1,646	2,022	1,615	23	%	25	%
New Jersey		481	325	473	(32	)%	(31	)%	3,013	2,722	3,100	(10	)%	(12	)%
Virginia		270	192	256	(29	)%	(25	)%	2,103	2,221	2,244	6	%	(1	)%
Florida		15	1	21	(93	)%	(95	)%	397	743	390	87	%	91	%
Tennessee		168	94	200	(44	)%	(53	)%	1,874	2,210	1,864	18	%	19	%
Maryland		491	375	473	(24	)%	(21	)%	3,009	2,852	3,085	(5	)%	(8	)%
Ohio		431	294	433	(32	)%	(32	)%	3,033	3,125	2,985	3	%	5	%
(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 June 30, 2010.

Customers		Three months ended June 30,									Six months ended June 30,
		2010			2009			% change			2010			2009			% change
Distribution Operations
Average end-use customers (in thousands)
Atlanta Gas Light			1,560			1,565			(0.3	)%		1,564			1,571			(0.4	)%
Elizabethtown Gas			274			274			-			275			274			0.4	%
Virginia Natural Gas			275			272			1.1	%		276			274			0.7	%
Florida City Gas			104			103			1.0	%		104			103			1.0	%
Chattanooga Gas			62			62			-			62			62			-
Elkton Gas			6			6			-			6			6			-
Total			2,281			2,282			-			2,287			2,290			(0.1	)%
Operation and maintenance expense per customer		$	38		$	39			(3	)%	$	76		$	75			1	%
EBIT per customer		$	30		$	28			7	%	$	90		$	84			7	%

Retail Energy Operations
Average customers (in thousands)
Georgia			503			510			(1	)%		505			514			(2	)%
Ohio and Florida (1)			71			110			(36	)%		88			104			(15	)%
Total			574			620			(7	)%		593			618			(4	)%
Market share in Georgia			33	%		33	%		-			33	%		33	%		-

(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	Three months ended June 30,							Six months ended June 30,
In billion cubic feet (Bcf)	2010		2009		% change			2010		2009		% change
Distribution Operations
Firm		26		29		(10	)%		148		128		16	%
Interruptible		22		23		(4	)%		49		49		-
Total		48		52		(8	)%		197		177		11	%

Retail Energy Operations
Georgia firm		4		5		(20	)%		28		23		22	%
Ohio and Florida		1		2		(50	)%		7		7		-

Wholesale Services
Daily physical sales (Bcf/day)		3.9		2.6		50	%		4.4		2.8		57	%

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Second quarter 2010 compared to second quarter 2009

Operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the three months ended June 30, 2010 and 2009.

In millions	Operating margin (1)			Operating expenses		EBIT (1)
2010
Distribution operations	$	198		$	130	$	69
Retail energy operations		18			17		1
Wholesale services		(9	)		11		(20	)
Energy investments		12			11		-
Corporate (2)		(1	)		1		(2	)
Consolidated	$	218		$	170	$	48

In millions	Operating margin (1)		Operating expenses		EBIT (1)
2009
Distribution operations	$	190	$	130	$	63
Retail energy operations		23		18		5
Wholesale services		2		13		(11	)
Energy investments		10		8		2
Corporate (2)		-		1		(1	)
Consolidated	$	225	$	170	$	58

(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 10% compared to last year as shown in the following table.

In millions
EBIT for second quarter of 2009				$	63

Operating margin
Increased revenues from the Hampton Roads pipeline project	$	5
Increased regulatory infrastructure program revenue at Atlanta Gas Light		2
Increased revenues from Magnolia pipeline project		1
Increase in operating margin					8

Operating expenses
Increased payroll and incentive compensation expenses	$	(2	)
Increased depreciation expenses		(1	)
Unrecoverable ERC liability recorded in 2009		3
Decreased legal fees		1
Other		(1	)
Net change in operating expenses					-
Other expense					(2	)
EBIT for second quarter of 2010				$	69

Retail energy operations’ EBIT decreased by $4 million or 80% compared to last year as shown in the following table.

In millions
EBIT for second quarter of 2009				$	5

Operating margin
Decreased average customer usage due to warmer weather and lower average usage	$	(3	)
Change in retail pricing plan mix and decrease in average number of customers		(3	)
Increased operating margins in Ohio		1
Decrease in operating margin					(5	)

Operating expenses
Decreased depreciation and other expenses	$	1
Decrease in operating expenses					1
EBIT for second quarter of 2010				$	1

Wholesale services’ EBIT decreased by $9 million or 82% compared to last year as shown in the following table.

In millions
EBIT for second quarter of 2009				$	(11	)

Operating margin
Change in commercial activity	$	10
Change in transportation hedge impact		(17	)
Change in storage hedge impact		(4	)
Net change in operating margin					(11	)

Operating expenses
Decreased incentive compensation costs	$	1
Decreased depreciation expense		1
Decrease in operating expenses					2
EBIT for second quarter of 2010				$	(20	)

The following table indicates the components of wholesale services’ operating margin for the three months ended June 30, 2010 and 2009.

In millions	2010			2009
Commercial activity recognized	$	(1	)	$	(11	)
(Loss) gain on transportation hedges		(6	)		11
(Loss) gain on storage hedges		(2	)		2
Operating margin	$	(9	)	$	2

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

In millions
EBIT for second quarter of 2009				$	2

Operating margin
Increased operating revenues at AGL Networks	$	1
Other		1
Increase in operating margin					2

Operating expenses
Increased incentive and other costs at AGL Networks	$	(3	)
Increase in operating expenses					(3	)
Other expenses					(1	)
EBIT for second quarter of 2010				$	-

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Year-to-date 2010 compared to year-to-date 2009

Operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the six months ended June 30, 2010 and 2009.

In millions	Operating margin (1)		Operating expenses		EBIT (1)
2010
Distribution operations	$	462	$	260	$	205
Retail energy operations		114		39		75
Wholesale services		50		27		23
Energy investments		24		20		3
Corporate (2)		-		3		(3	)
Consolidated	$	650	$	349	$	303

In millions	Operating margin (1)		Operating expenses		EBIT (1)
2009
Distribution operations	$	442	$	254	$	193
Retail energy operations		107		39		68
Wholesale services		61		34		27
Energy investments		20		16		4
Corporate (2)		1		3		(2	)
Consolidated	$	631	$	346	$	290

(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 $12 million or 6% compared to last year as shown in the following table.

In millions
EBIT for six months of 2009				$	193

Operating margin
Increased revenues from the Hampton Roads pipeline project	$	10
Increased revenues from Magnolia pipeline project		3
Increased regulatory infrastructure program revenue at Atlanta Gas Light		3
Increased revenues from higher usage at Florida City Gas due to colder weather		2
Other		2
Increase in operating margin					20

Operating expenses
Increased payroll and incentive compensation expenses	$	(6	)
Increased depreciation expenses		(3	)
Unrecoverable ERC liability recorded in 2009		3
Decreased legal fees		1
Other		(1	)
Increase in operating expenses					(6	)
Other expenses					(2	)
EBIT for six months of 2010				$	205

Retail energy operations’ EBIT increased by $7 million or 10% compared to last year as shown in the following table.

In millions
EBIT for six months of 2009				$	68

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	$	4
Change in LOCOM adjustment		6
Increased operating margins in Ohio and Florida		3
Change in retail pricing plan mix and decrease in average number of customers		(4	)
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		(1	)
Other		(1	)
Increase in operating margin					7

Operating expenses
Increased marketing and direct selling expenses	$	(1	)
Higher bad debt due to increased revenues		(1	)
Decreased customer care, depreciation, outside services and other expenses		2
Net change in operating expenses					-
EBIT for six months of 2010				$	75

Wholesale services’ EBIT decreased by $4 million or 15% compared to last year as shown in the following table.

In millions
EBIT for six months of 2009				$	27

Operating margin
Change in commercial activity	$	21
Decreased gains on transportation hedges		(29	)
Decreased gains on storage hedges		(4	)
Change in LOCOM adjustment, net of estimated current period recoveries		1
Net decrease in operating margin					(11	)

Operating expenses
Decreased incentive compensation costs	$	6
Other		1
Decrease in operating expenses					7
EBIT for six months of 2010				$	23

The following table indicates the components of wholesale services’ operating margin for the six months ended June 30, 2010 and 2009.

In millions	2010			2009
Commercial activity recognized	$	35		$	14
Gain on storage hedges		14			18
Gain on transportation hedges		3			32
Inventory LOCOM, net of estimated current period recoveries		(2	)		(3	)
Operating margin	$	50		$	61

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

In millions
EBIT for six months of 2009				$	4

Operating margin
Increased operating revenues at AGL Networks	$	3
Other		1
Increase in operating margin					4

Operating expenses
Increased incentive and other costs at AGL Networks	$	(3	)
Increase in payroll and benefit costs and property taxes at Golden Triangle Storage		(1	)
Increase in operating expenses					(4	)
Other expenses					(1	)
EBIT for six months 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.

	Six months ended June 30,
In millions	2010			2009
Net cash provided by (used in):
Operating activities	$	713		$	731
Investing activities		(249	)		(207	)
Financing activities		(474	)		(528	)
Net decrease in cash and cash equivalents	$	(10	)	$	(4	)

Cash Flow from Operating Activities In the first six months of 2010, our net cash flow provided from operating activities was $713 million, a decrease of $18 million or 2% from the same period in 2009. This decrease was primarily a result of lower natural gas prices at the beginning of the 2009/2010 heating season compared to the same period last year. These lower prices resulted in approximately $108 million of lower working capital recoveries in 2010 from our inventories, accounts receivable and accounts payable. Additionally, we refunded to our utility customers an additional $53 million for billed commodity costs compared to 2009 as a result of declining natural gas prices.

These increased uses of operating cash flow were mostly offset by decreased working capital used by Sequent of $119 million for its energy marketing activities, resulting from the timing of payments for gas purchases relative to collections of accounts receivable and an increase in Sequent’s daily physical sales.

Cash Flow from Investing Activities Our investing activities consisted of PP&E expenditures of $249 million for the six months ended June 30, 2010 and $207 million for the same period in 2009. The increase of $42 million or 20% in PP&E expenditures was primarily due to a $33 million increase in expenditures for the construction of the Golden Triangle Storage natural gas storage facility, $25 million in expenditures for Elizabethtown Gas’ utility infrastructure enhancements program and $31 million in expenditures for STRIDE and other capital projects in distribution operations. This was offset by reduced expenditures of $52 million for the Hampton Roads project, which was completed last year.

Cash Flow from Financing Activities Our cash used in financing activities was $474 million for the six months ended June 30, 2010 compared to cash used of $528 million for the same period in 2009. The decreased use of cash of $54 million was primarily due to decreased short-term debt payments of $240 million in 2010 compared to the same period in 2009. This was partially offset by our payment of $121 million for a portion of our gas facility revenue bonds, our purchase of an additional 15% ownership interest in SouthStar for $58 million and an increased distribution to the noncontrolling interest of $7 million.

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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 June 30, 2010, our variable-rate debt was 19% of our total debt, compared to 28% as of June 30, 2009. The decrease in our variable-rate debt at June 30, 2010 compared to last year was primarily due to the $300 million in senior notes that we issued in August 2009.

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 June 30, 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 54% at June 30, 2010, 57% at December 31, 2009 and 53% at June 30, 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 and are consistent with the calculations above.

	Jun. 30, 2010			Dec. 31, 2009			Jun. 30, 2009
Short-term debt		17	%		14	%		11	%
Long-term debt		38			45			43
Total debt		55			59			54
Equity		45			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 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 $300 million, our short-term borrowings, as of June 30, 2010, decreased $24 million or 6% 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 use of commercial paper to tender $121 million of gas facility revenue bonds and our purchase of an additional ownership interest in SouthStar for $58 million and increased property, plant and equipment expenditures of $42 million.

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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 complete a new Credit Facility by December 2010, if not sooner. Because of the current conditions in the credit markets, we are anticipating that the costs of a renewed Credit Facility will be higher and that the term could be 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. We have not yet determined the ultimate size of our anticipated new Credit Facility relative to our current $1 billion level; however, we expect to refinance at least $1 billion.

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. As a result of an anticipated refinancing of these senior notes, we entered into $200 million of forward interest rate swaps, at a treasury rate of 3.94%. For more information on our senior notes, see Note 5.

In June 2010, the letters of credit that provide credit enhancements to $121 million of gas facility revenue bonds expired; therefore, we tendered three of our gas facility revenue bonds with principal amounts of $55 million, $46 million and $20 million with commercial paper borrowings. In August 2010, we intend to tender an additional gas facility revenue bond with a principal amount of $39 million. These bonds will be re-issued as variable rate gas facility revenue bonds before the end of 2010 utilizing credit enhancements which are expected to be more cost effective than the letters of credit used previously.

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

Pension Contributions Through July 2010, we have contributed $26 million to our qualified pension plans. We are planning to make additional contributions to our pension plans in 2010 up to $5 million, for a total of up to $31 million to meet our 80% funding target. 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. In the six months ended June 30, 2009, we contributed $17 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 June 30, 2010.

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

Long-term debt	$	1,553	$	-	$	17	$	225	$	1,311
Short-term debt		694		300		394		-		-
Regulatory infrastructure program costs (1)		242		36		154		52		-
Environmental remediation liabilities (1)		139		16		58		36		29
Total	$	2,628	$	352	$	623	$	313	$	1,340

Unrecorded contractual obligations and commitments (2):

Pipeline charges, storage capacity and gas supply (3)	$	2,013	$	280	$	774	$	399	$	560
Interest charges (4)		964		56		176		156		576
Operating leases		110		16		45		16		33
Asset management agreements (5)		25		11		14		-		-
Standby letters of credit, performance / surety bonds		16		7		8		1		-
Total	$	3,128	$	370	$	1,017	$	572	$	1,169

(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 15 Bcf at floating gas prices calculated using forward natural gas prices as of June 30, 2010, and are valued at $70 million.

(4)	Floating rate debt is based on the interest rate as of June 30, 2010, and the maturity of the underlying debt instrument. As of June 30, 2010, we have $40 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.

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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 and six months ended June 30, 2010 and 2009, and provide details of the net fair value of derivative financial instruments outstanding as of June 30, 2010.

	Three months ended June 30,
In millions	2010			2009
Net fair value of derivative financial instruments outstanding at beginning of period	$	(7	)	$	(22	)
Derivative financial instruments realized or otherwise settled during period		4			17
Change in net fair value of derivative financial instruments		1			-
Net fair value of derivative financial instruments outstanding at end of period		(2	)		(5	)
Netting of cash collateral		5			15
Cash collateral and net fair value of derivative financial instruments outstanding at end of period	$	3		$	10

	Six months ended June 30,
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		(3	)		18
Change in net fair value of derivative financial instruments		(2	)		(6	)
Net fair value of derivative financial instruments outstanding at end of period		(2	)		(5	)
Netting of cash collateral		5			15
Cash collateral and net fair value of derivative financial instruments outstanding at end of period	$	3		$	10

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The sources of SouthStar’s net fair value of its natural gas-related derivative financial instruments at June 30, 2010, are as follows:

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

(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 June 30, 2010.

(3)	Excludes cash collateral amounts.

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 six months ended June 30, 2010 and 2009.

	Derivative financial instruments average fair values (1) at June 30,
In millions	2010		2009
Asset	$	3	$	11
Liability		14		28

(1) Excludes cash collateral amounts.

	Derivative financial instruments fair values netted with cash collateral at
In millions	June 30, 2010		Dec. 31, 2009		June 30, 2009
Asset	$	3	$	21	$	10
Liability		-		-		-

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 six months ended June 30, 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 six months ended June 30, 2010 and 2009.

	Derivative financial instruments average values (1) at June 30,
In millions	2010		2009
Asset	$	194	$	176
Liability		39		84

(1)	Excludes cash collateral amounts.

	Derivative financial instruments fair values netted with cash collateral at
In millions	June 30, 2010		Dec. 31, 2009		June 30, 2009
Asset	$	174	$	208	$	183
Liability		37		51		18

Sequent experienced a decrease in the net fair value of its outstanding contracts of $31 million during the six months ended June 30, 2010 and $26 million during the six months ended June 30, 2009, 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 and six months ended June 30, 2010 and 2009, and provide details of the net fair value of contracts outstanding as of June 30, 2010.

	Three months ended June 30,
In millions	2010			2009
Net fair value of derivative financial instruments outstanding at beginning of period	$	84		$	7
Derivative financial instruments realized or otherwise settled during period		6			33
Change in net fair value of derivative financial instruments		(3	)		16
Net fair value of derivative financial instruments outstanding at end of period		87			56
Netting of cash collateral		50			109
Cash collateral and net fair value of derivative financial instruments outstanding at end of period	$	137		$	165

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	Six months ended June 30,
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		(57	)		(78	)
Change in net fair value of derivative financial instruments		26			52
Net fair value of derivative financial instruments outstanding at end of period		87			56
Netting of cash collateral		50			109
Cash collateral and net fair value of derivative financial instruments outstanding at end of period	$	137		$	165

The sources of Sequent’s net fair value of its natural gas-related derivative financial instruments at June 30, 2010, are as follows:

In millions	Prices actively quoted (Level 1) (1)			Significant other observable inputs (Level 2) (2)
Mature through
2010	$	(1	)	$	36
2011 – 2012		(22	)		67
2013 – 2015		(1	)		8
Total derivative financial instruments (3)	$	(24	)	$	111

(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.

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 and six months ended June 30, 2010 and 2009 had the following VaRs.

	Three months ended June 30,				Six months ended June 30,
In millions	2010		2009		2010		2009
Period end	$	1.9	$	2.6	$	1.9	$	2.6
Average		1.3		2.2		1.4		2.1
High		2.4		3.1		3.0		3.3
Low		0.8		1.7		0.7		1.3

Energy Investments We use derivative financial instruments to reduce our exposure to the risk of changes with the price of natural gas that will be purchased in future periods for pad gas and additional volumes of gas used to de-water the cavern (de-water gas) during the construction of storage caverns. Pad gas includes volumes of non-working natural gas used to maintain the operational integrity of the caverns. De-water gas is used to remove water from the cavern in anticipation of commercial service and will be sold after completion of de-watering. We also use derivative financial instruments for asset optimization purposes. As of June 30, 2010, these derivative financial instruments had hedged approximately 4 Bcf of natural gas. The associated fair value of these derivative financial instruments was $7 million, including the netting of cash collateral.

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 $432 million of variable-rate debt, which includes $393 million of our variable-rate short-term debt and $39 million of variable-rate gas facility revenue bonds outstanding at June 30, 2010, a 100 basis point change in average market interest rates from 0.37% to 1.37% would have resulted in an increase in pretax interest expense of $4 million on an annualized basis.

In May 2010, as a result of an anticipated refinancing of $300 million of senior notes, we entered into $200 million of forward interest rate swaps, at a treasury rate of 3.94%. We anticipate issuing the $300 million of senior notes by December 2010, if not sooner. For additional information, see Note 2.

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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 June 30, 2010, Sequent’s top 20 counterparties represented approximately 56% of the total counterparty exposure of $435 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures.

As of June 30, 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 rating at December 31, 2009 and slightly below the credit rating of A at June 30, 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 June 30, 2010 and 2009 and December 31, 2009.

	Gross receivables						Gross payables
	June 30,		Dec. 31,		June 30,		June 30,		Dec. 31,		June 30,
In millions	2010		2009		2009		2010		2009		2009
Netting agreements in place:
Counterparty is investment grade	$	399	$	483	$	207	$	301	$	277	$	170
Counterparty is non-investment grade		11		12		12		29		34		39
Counterparty has no external rating		108		106		50		264		207		104
No netting agreements in place:
Counterparty is investment grade		2		14		5		3		6		4
Counterparty is non-investment grade		-		-		2		2		-		-
Amount recorded on statements of financial position	$	520	$	615	$	276	$	599	$	524	$	317

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 $34 million at June 30, 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.

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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 June 30, 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 June 30, 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 that occurred during the second quarter ended June 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities and litigation incidental to the business. For information regarding pending federal and state regulatory matters, see “Note 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 June 30, 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)
April 2010		4,293	$	39.25		-		4,950,951
May 2010		13,400		35.61		13,400		4,937,551
June 2010		59,500		36.21		59,500		4,878,051
Total second quarter		77,193	$	36.27		72,900

(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 second quarter of 2010. As of June 30, 2010, we had purchased a total of 332,153 of the 600,000 shares authorized for purchase, leaving 267,847 shares available for purchase under this program.

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

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Item 6. Exhibits

3.2	Bylaws, as amended on April 27, 2010.

12	Statement of Computation of Ratio of Earnings to Fixed Charges.

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

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

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

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

101.INS	XBRL Instance Document. (1)

101.SCH	XBRL Taxonomy Extension Schema. (1)

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

101.DEF	XBRL Taxonomy Definition Linkbase. (1)

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

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

(1) Furnished, not filed

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Condensed Consolidated Statements of Financial Position at June 30, 2010, December 31, 2009 and June 30, 2009; (iii) Condensed Consolidated Statements of Income for the three and six months ended June 30, 2010 and 2009; (iv) Condensed Consolidated Statements of Equity for the six months ended June 30, 2010 and 2009; (v) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2010 and 2009; (vi) Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009; and (vii) Notes to Condensed Consolidated Financial Statements.

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

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SIGNATURE

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

AGL RESOURCES INC.

(Registrant)

Date: July 29, 2010 /s/ Andrew W. Evans

Executive Vice President, Chief Financial Officer and Treasurer

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