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 September 30, 2007

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. (Check one):

Large accelerated filer þ

Accelerated filer ¨

Non-accelerated filer ¨

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 October 26, 2007
Common Stock, $5.00 Par Value	76,576,917

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended September 30, 2007

TABLE OF CONTENTS

Item Number			Page(s)

		PART I - FINANCIAL INFORMATION		3

	1	Condensed Consolidated Financial Statements (Unaudited)		3-6
		Condensed Consolidated Balance Sheets		3
		Condensed Consolidated Statements of Income		4
		Condensed Consolidated Statements of Common Shareholders’ Equity		5
		Condensed Consolidated Statements of Cash Flows		6
		Notes to Condensed Consolidated Financial Statements		7-16
		Note 1 - Accounting Policies and Methods of Application		7-9
		Note 2 - Risk Management		9
		Note 3 - Regulatory Assets and Liabilities		10
		Note 4 - Employee Benefit Plans		10-11
		Note 5 - Common Shareholders’ Equity		11
		Note 6 - Debt		12
		Note 7 - Commitments and Contingencies		13
		Note 8 - Income Taxes		13
		Note 9 - Segment Information		14-16
	2	Management's Discussion and Analysis of Financial Condition and Results of Operations		17-30
		Forward-Looking Statements		17
		Overview		17
		Distribution Operations		17-18
		Retail Energy Operations		18
		Wholesale Services		19
		Energy Investments		19
		Corporate		20
		Executive Summary		20
		Results of Operations		20-26
		Liquidity and Capital Resources		26-29
		Critical Accounting Policies and Estimates		30
		Accounting Developments		30
	3	Quantitative and Qualitative Disclosures About Market Risk		30-33
	4	Controls and Procedures		33

		PART II - OTHER INFORMATION

	1	Legal Proceedings		33
	2	Unregistered Sales of Equity Securities and Use of Proceeds		34
	6	Exhibits		35

		SIGNATURE		36

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PART I - Financial Information Item 1. Financial Statements
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
			As of
In millions, except share data	September 30, 2007		December 31, 2006		September 30, 2006
Current assets
Cash and cash equivalents	$	17	$	20	$	14
Inventories		654		597		627
Energy marketing receivables		365		505		344
Receivables (less allowance for uncollectible accounts of $15 at Sept. 30, 2007, $15 at Dec. 31, 2006 and $16 at Sept. 30, 2006)		141		375		156
Energy marketing and risk management assets		83		159		174
Unrecovered pipeline replacement program costs		27		27		26
Unrecovered environmental remediation costs		24		27		28
Other		117		112		143
Total current assets		1,428		1,822		1,512
Property, plant and equipment
Property, plant and equipment		5,142		4,976		4,943
Less accumulated depreciation		1,610		1,540		1,538
Property, plant and equipment-net		3,532		3,436		3,405
Deferred debits and other assets
Goodwill		420		420		420
Unrecovered pipeline replacement program costs		261		247		258
Unrecovered environmental remediation costs		132		143		151
Other		67		79		89
Total deferred debits and other assets		880		889		918
Total assets	$	5,840	$	6,147	$	5,835
Current liabilities
Short-term debt	$	576	$	539	$	441
Energy marketing trade payables		383		510		373
Payables		131		213		167
Accrued expenses		82		120		76
Accrued pipeline replacement program costs		47		35		35
Customer deposits		39		42		35
Energy marketing and risk management liabilities		19		41		59
Deferred purchased gas adjustment		15		24		16
Accrued environmental remediation costs		11		13		14
Other		72		129		130
Total current liabilities		1,375		1,666		1,346
Accumulated deferred income taxes		527		505		500
Long-term liabilities
Accrued pipeline replacement program costs		204		202		212
Accumulated removal costs		168		162		160
Accrued environmental remediation costs		88		83		88
Accrued pension obligations		83		78		93
Accrued postretirement benefit costs		25		32		41
Other		158		146		143
Total long-term liabilities		726		703		737
Commitments and contingencies (Note 7)
Minority interest		41		42		37
Capitalization
Long-term debt		1,548		1,622		1,634
Common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,623		1,609		1,581
Total capitalization		3,171		3,231		3,215
Total liabilities and capitalization	$	5,840	$	6,147	$	5,835

See Notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

	Three months ended						Nine months ended
	September 30,						September 30,
In millions, except per share amounts	2007			2006			2007			2006
Operating revenues	$	369		$	434		$	1,809		$	1,914
Operating expenses
Cost of gas		159			190			987			1,064
Operation and maintenance		107			111			334			341
Depreciation and amortization		37			33			108			101
Taxes other than income		11			10			31			30
Total operating expenses		314			344			1,460			1,536
Operating income		55			90			349			378
Other income (expense)		-			-			1			(2	)
Interest expense, net		(34	)		(32	)		(92	)		(91	)
Minority interest		-			-			(24	)		(19	)
Earnings before income taxes		21			58			234			266
Income taxes		8			22			89			101
Net income	$	13		$	36		$	145		$	165

Basic earnings per common share	$	0.17		$	0.46		$	1.88		$	2.13
Diluted earnings per common share	$	0.17		$	0.46		$	1.87		$	2.12
Cash dividends paid per common share	$	0.41		$	0.37		$	1.23		$	1.11
Weighted-average number of common shares outstanding
Basic		77.0			77.5			77.4			77.6
Diluted		77.4			77.9			77.8			78.1

See Notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY (UNAUDITED)

						Premium on						Other			Shares
	Common Stock					common			Earnings			comprehensive			Held in
In millions, except per share amount	Shares			Amount		stock			reinvested			loss			Treasury			Total
Balance as of December 31, 2006		77.7		$	390	$	664		$	601		$	(32	)	$	(14	)	$	1,609
Comprehensive income:
Net income		-			-		-			145			-			-			145
Net realized gain from hedging activities (net of taxes of $2)		-			-		-			-			(3	)		-			(3	)
Pension adjustment (net of tax benefit of $-)		-			-		-			-			1			-			1
Total comprehensive income																			143
Dividends on common shares ($1.23 per share)		-			-		-			(96	)		-			4			(92	)
Benefit, dividend reinvestment and share purchase plans		-			-		(1	)		-			-			-			(1	)
Issuance of treasury shares		0.6			-		(6	)		(4	)		-			23			13
Purchase of treasury shares		(1.4	)		-		-			-			-			(57	)		(57	)
Stock-based compensation expense (net of tax benefit of $2)		-			-		8			-			-			-			8
Balance as of September 30, 2007		76.9		$	390	$	665		$	646		$	(34	)	$	(44	)	$	1,623

See Notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

	Nine months ended
	September 30,
In millions	2007			2006
Cash flows from operating activities
Net income	$	145		$	165
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		108			101
Change in risk management assets and liabilities		66			(129	)
Minority interest		24			19
Deferred income taxes		8			115
Changes in certain assets and liabilities
Receivables		374			720
Inventories		(57	)		(84	)
Payables		(209	)		(501	)
Other - net		(73	)	(65		)
Net cash flow provided by operating activities		386			341
Cash flows from investing activities
Property, plant and equipment expenditures		(193	)		(190	)
Other		2			5
Net cash flow used in investing activities		(191	)		(185	)
Cash flows from financing activities
Dividends paid on common shares		(92	)		(84	)
Payment of notes payable to AGL Capital Trust I & II		(75	)		(150	)
Purchase of treasury shares		(57	)		(26	)
Distribution to minority interest		(23	)		(22	)
Payments of medium-term debt		(11	)		-
Issuance of treasury shares		13			8
Net payments and borrowings of short-term debt		49			(81	)
Issuance of senior notes		-			175
Other		(2	)		6
Net cash flow used in financing activities		(198	)		(174	)
Net decrease in cash and cash equivalents		(3	)		(18	)
Cash and cash equivalents at beginning of period		20			32
Cash and cash equivalents at end of period	$	17		$	14
Cash paid during the period for
Interest	$	92		$	77
Income taxes	$	89		$	33

See Notes to Condensed Consolidated Financial Statements (Unaudited).

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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,” or the “company” mean consolidated AGL Resources Inc. and its subsidiaries (AGL Resources).

The year-end condensed balance sheet data was derived from our audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States (U.S.) of America (GAAP). We have prepared the accompanying unaudited condensed consolidated financial statements under the rules of the Securities and Exchange Commission (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 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 our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 7, 2007.

Due to the seasonal nature of our business, our results of operations for the three and nine months ended September 30, 2007 and 2006, and our financial condition as of December 31, 2006, and September 30, 2007 and 2006, 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. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation. Specifically, $39 million at December 31, 2006, and $42 million at September 30, 2006, of net deferred income taxes associated with current assets and liabilities previously presented in accumulated deferred income taxes have been presented in other current liabilities for all balance sheet dates presented herein.

We own a noncontrolling 70% financial interest in SouthStar Energy Services, LLC (SouthStar), and Piedmont Natural Gas Company (Piedmont) owns the remaining 30%. Our 70% interest is noncontrolling because all significant management decisions require approval by both owners. We record the earnings allocated to Piedmont as a minority interest in our consolidated statements of income and we record Piedmont’s portion of SouthStar’s capital as a minority interest in our consolidated balance sheets.

We are the primary beneficiary of SouthStar’s activities and have determined that SouthStar is a variable interest entity as defined by Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities,” as revised in December 2003 (FIN 46R). We determined that SouthStar is a variable interest entity because our equal voting rights with Piedmont are not proportional to our contractual obligation to absorb 75% of any losses or residual returns from SouthStar (except those losses and returns related to customers in Ohio and Florida). The majority of SouthStar’s earnings allocated to us for the three and nine months ended September 30, 2007, were at the 75% contractual rate. Earnings related to customers in Ohio and Florida are allocated 70% to us and 30% to Piedmont. In addition, SouthStar obtains substantially all its transportation capacity for delivery of natural gas through our wholly owned subsidiary, Atlanta Gas Light Company (Atlanta Gas Light).

Inventories

For our distribution operations segment, we record natural gas stored underground at weighted-average cost. For Sequent Energy Management, L.P. (Sequent) and SouthStar, we account for natural gas inventory at the lower of weighted-average cost or market (LOCOM).

Sequent and SouthStar evaluate the average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the weighted-average cost 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 did not record adjustments in the first nine months of 2007 or 2006. Sequent recorded LOCOM adjustments of $1 million and $4 million for the three and nine months ended September 30, 2007. This compares to Sequent’s LOCOM adjustments of $20 million and $33 million for the three and nine months ended September 30, 2006.

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Stock-Based Compensation

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (SFAS) 123(R), “Share Based Payment” (SFAS 123R). On January 30, 2007, we issued grants of approximately 664,000 stock options and 124,000 restricted stock units, which will result in the recognition of approximately $2 million of stock-based compensation expense in 2007. We use the Black-Scholes pricing model to determine the fair value of the options granted. On an annual basis, we evaluate the assumptions and estimates used to calculate our stock-based compensation expense.

There have been no other significant changes to our stock-based compensation, as described in Note 5 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

Comprehensive Income

Our comprehensive income includes net income plus other comprehensive income (OCI), which includes other gains and losses affecting shareholders’ equity that GAAP excludes from net income. Such items consist primarily of gains and losses on certain derivatives designated as cash flow hedges and unfunded pension and postretirement obligations. The following table illustrates our OCI activity.

	Three months ended Sept. 30,
In millions	2007		2006
Cash flow hedges:
Net derivative unrealized gains arising during the period (net of taxes of $1 in 2007 and $3 in 2006)	$	2	$	6
Less reclassification of realized losses included in income (net of taxes of $1 in 2007 and $1 in 2006)		1		1
Pension adjustments (net of taxes of $- in 2007)		-		-
Total	$	3	$	7

	Nine months ended Sept. 30,
In millions	2007			2006
Cash flow hedges:
Net derivative unrealized gains arising during the period (net of taxes of $1 in 2007 and $6 in 2006)	$	2		$	12
Less reclassification of realized gains included in income (net of taxes of $3 in 2007 and $1 in 2006)		(5	)		(2	)
Pension adjustments (net of taxes of $- in 2007)		1			-
Total	$	(2	)	$	10

Earnings per Common Share

We compute basic earnings per common share by dividing our income available to common shareholders by the weighted-average number of common shares outstanding daily. Diluted earnings per common share reflect the potential reduction in earnings per common share that could occur when potential dilutive common shares are added to common shares outstanding.

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

	Three months ended September 30,
In millions	2007		2006
Denominator for basic earnings per share (1)		77.0		77.5
Assumed exercise of restricted stock, restricted stock units and stock options		0.4		0.4
Denominator for diluted earnings per share		77.4		77.9

(1)	Daily weighted-average shares outstanding.

	Nine months ended September 30,
In millions	2007		2006
Denominator for basic earnings per share (1)		77.4		77.6
Assumed exercise of restricted stock, restricted stock units and stock options		0.4		0.5
Denominator for diluted earnings per share		77.8		78.1

(1) Daily weighted-average shares outstanding.

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 literature or in the development of estimates that impact our financial statements. The most significant estimates include our pipeline replacement program (PRP) accruals, environmental liability accruals, allowance for uncollectible accounts and other 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.

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Accounting Developments

SFAS 157 In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 establishes a framework for measuring fair value and requires expanded disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements. However, it eliminates inconsistencies in the guidance provided in previous accounting pronouncements.

SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including financial statements for an interim period within that fiscal year. All valuation adjustments will be recognized as cumulative-effect adjustments to the opening balance of retained earnings for the fiscal year in which SFAS 157 is initially applied. We will adopt SFAS 157 on January 1, 2008, and we are currently evaluating the impact it will have on our consolidated financial condition, results of operations and cash flows.

FSP FIN 39-1 FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” (FIN 39) was issued in March 1992 and provides guidance related to offsetting payable and receivable amounts related to certain contracts, including derivative contracts. It was effective for financial statements issued for periods beginning after December 15, 1993.

FASB Staff Position 39-1 “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1), which was issued in April 2007, amends FIN 39 and addresses whether a company with a master netting arrangement can offset fair value amounts of derivative instruments against a receivable or payable. We enter into derivative contracts, but FSP 39-1 will not have a material effect on our consolidated financial condition.

Note 2 - Risk Management

Our risk management activities are monitored by our Risk Management Committee (RMC). The RMC consists of members of senior management and is charged with reviewing and enforcing our risk management activities and policies. Our risk management policies limit the use of derivative financial instruments and physical hedges within pre-defined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage.

We use the following derivative financial instruments and physical hedges to manage commodity price, interest rate, weather and foreign currency risks:

·	forward contracts

·	futures contracts

·	options contracts

·	financial swaps

·	treasury locks

·	weather derivative contracts

·	storage and transportation capacity transactions

·	foreign currency forward contracts

During the nine months ended September 30, 2007, Sequent entered into foreign currency forward contracts in connection with its 2007 expansion into Canada. Sequent accounts for these contracts in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The contracts are recorded at fair value and marked to market in our condensed consolidated balance sheets, with changes in fair value recorded in earnings in the period of change. The amounts outstanding at September 30, 2007, and earnings associated with these contracts during the nine month period ending September 30, 2007, were not material.

There have been no significant changes to our risk management activities, as described in Note 2 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

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Note 3 - Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our condensed consolidated balance sheets in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). Our regulatory assets and liabilities, and associated liabilities for our unrecovered PRP costs, unrecovered environmental remediation costs (ERC) and the associated assets and liabilities of our Elizabethtown Gas hedging program are summarized in the table below.

In millions	Sept. 30, 2007		Dec. 31, 2006		Sept. 30, 2006
Regulatory assets
Unrecovered PRP costs	$	288	$	274	$	284
Unrecovered ERC		156		170		179
Unrecovered purchased gas adjustment		15		14		8
Unrecovered postretirement benefit costs		12		13		13
Unrecovered seasonal rates		10		11		10
Elizabethtown Gas hedging program		-		16		-
Other		24		20		22
Total regulatory assets		505		518		516
Associated assets
Elizabethtown Gas hedging program		9		-		20
Total regulatory and associated assets	$	514	$	518	$	536
Regulatory liabilities
Accumulated removal costs	$	168	$	162	$	160
Regulatory tax liability		21		22		17
Unamortized investment tax credit		16		18		18
Deferred purchased gas adjustment		15		24		16
Elizabethtown Gas hedging program		9		-		20
Other		16		17		13
Total regulatory liabilities		245		243		244
Associated liabilities
PRP costs (1)		251		237		247
ERC		90		87		93
Elizabethtown Gas hedging program		-		16		-
Total associated liabilities		341		340		340
Total regulatory and associated liabilities	$	586	$	583	$	584

(1)

The $14 million or 6% increase from December 31, 2006, is due to higher material and labor costs,

greater percentage of work in metropolitan Atlanta, which incur a higher cost than pipeline

replacements outside the metropolitan Atlanta area and greater percentage of large diameter pipe

being replaced than were reflected in our previous estimate.

There have been no significant changes to our regulatory assets and liabilities as described in Note 3 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

Note 4 - Employee Benefit Plans

SFAS 158 In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158). We adopted SFAS 158 prospectively on December 31, 2006. SFAS 158 requires that we recognize all obligations related to defined benefit pension and other postretirement benefits. This statement requires that we quantify the plans’ funding status as an asset or a liability on our consolidated balance sheets.

SFAS 158 requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We are also required to recognize as a component of OCI the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit cost as explained in SFAS No. 87, “Employers’ Accounting for Pensions,” or SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”

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

	Three months ended
	September 30,
In millions	2007			2006
Service cost	$	2		$	1
Interest cost		6			5
Expected return on plan assets		(8	)		(7	)
Amortization of prior service cost		(1	)		-
Recognized actuarial loss		2			2
Net cost	$	1		$	1

	Nine months ended
	September 30,
In millions	2007			2006
Service cost	$	6		$	5
Interest cost		18			18
Expected return on plan assets		(24	)		(23	)
Amortization of prior service cost		(2	)		(1	)
Recognized actuarial loss		5			6
Net cost	$	3		$	5

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Our employees do not contribute to these retirement plans. We fund the 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. We calculate the minimum amount of funding using the projected unit credit cost method. The Pension Protection Act (the Act) of 2006 contains new funding requirements for single employer defined benefit pension plans. The Act establishes a 100% funding target for plan years beginning after December 31, 2007. However, a delayed effective date of 2011 may apply if the pension plan meets the following targets: 92% funded in 2008; 94% funded in 2009; and 96% funded in 2010. No contribution is required for our qualified plans in 2007.

Postretirement Benefits The AGL Resources Inc. Postretirement Health Care Plan (AGL Postretirement Plan) covers all eligible AGL Resources employees who were employed as of June 30, 2002, if they reach retirement age while working for us. The state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery. Effective December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law. This act provides 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 is at least actuarially equivalent to Medicare Part D.

Eligibility for benefits under the AGL Postretirement Plan is based on age and years of service. The following are the cost components of the AGL Postretirement Plan for the periods indicated:

	Three months ended
	September 30,
In millions	2007			2006
Service cost	$	-		$	-
Interest cost		1			1
Expected return on plan assets		(1	)		(1	)
Amortization of prior service cost		(1	)		(1	)
Recognized actuarial loss		1			-
Net benefit	$	-		$	(1	)

	Nine months ended
	September 30,
In millions	2007			2006
Service cost	$	-		$	-
Interest cost		4			4
Expected return on plan assets		(3	)		(3	)
Amortization of prior service cost		(3	)		(3	)
Recognized actuarial loss		1			1
Net benefit	$	(1	)	$	(1	)

Employee Savings Plan Benefits

We sponsor the Retirement Savings Plus Plan (RSP Plan), a defined contribution benefit plan that allows eligible participants to make contributions to their accounts up to specified limits. Under the RSP Plan, we made matching contributions to participant accounts of $5 million in the first nine months of each of 2007 and 2006.

Note 5 - Common Shareholders’ Equity

Share Repurchase Program

In February 2006, our Board of Directors authorized a plan to purchase up to 8 million shares of our outstanding common stock over a five-year period. These purchases are intended to offset share issuances under our employee and non-employee director incentive compensation plans and our dividend reinvestment and stock purchase plans. Stock purchases under this program may be made in the open market or in private transactions at times and in amounts that we deem appropriate. There is no guarantee as to the exact number of shares that we will purchase, and we can terminate or limit the program at any time. We will hold the purchased shares as treasury shares. During the nine months ended September 30, 2007, we repurchased 1.4 million shares at a weighted-average price of $39.82 and since inception of the plan we have repurchased a total of 2.5 million shares at a weighted-average price of $38.51.

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Note 6 - Debt

Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies, including state public service commissions, the SEC and the Federal Energy Regulatory Commission (FERC). Our financing consists of short and long-term debt. The following table provides more information on our various debt securities. There have been no significant changes to our debt since December 31, 2006, which was described in Note 7 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

						Outstanding as of:
In millions	Year(s) due		Weighted average interest rate (1)			Sept. 30, 2007			Dec. 31, 2006			Sept. 30, 2006
Short-term debt
Commercial paper	2007			5.7	%	$	549		$	508		$	420
Pivotal Utility Holdings, Inc. line of credit	2007			5.3			13			17			19
Sequent lines of credit	2007			5.1			13			2			1
Capital leases	2007			4.9			1			1			1
Current portion of long-term debt	2007			-			-			11			-
Total short-term debt				5.7	%	$	576		$	539		$	441
Long-term debt - net of current portion
Senior notes		2011-2034		4.5-7.1	%	$	1,150		$	1,150		$	1,150
Gas facility revenue bonds, net of unamortized issuance costs		2022-2032		3.7 - 4.2			199			199			199
Medium-term notes		2012-2027		6.6 - 9.1			196			196			208
Capital leases	2013			4.9			6			6			6
Notes payable to AGL Capital Trust I				-			-			77			77
AGL Capital interest rate swaps	2011			8.8			(3	)		(6	)		(6	)
Total long-term debt				6.0	%	$	1,548		$	1,622		$	1,634

Total debt				5.9	%	$	2,124		$	2,161		$	2,075

(1)	For the nine months ended September 30, 2007.

In June 2007, we refinanced $55 million of our gas facility revenue bonds due June 2032.The original bonds had a fixed interest rate of 5.7% per year and were refinanced with $55 million of adjustable-rate gas facility revenue bonds. The maturity date of these bonds remains June 2032. The bonds were issued at an initial annual interest rate of 3.8% and the interest rate at September 30, 2007, was 4.3%. The bonds have a 35-day auction period where the interest rate will adjust every 35 days.

In June 2007, we extended Sequent’s $25 million line of credit through June 2008. In August 2007, we extended Sequent’s additional $20 million line of credit through August, 2008. These unsecured lines of credit, which bear interest at the federal funds effective rate plus 0.4%, are used solely for the posting of margin deposits for New York Mercantile Exchange (NYMEX) transactions and are unconditionally guaranteed by us.

In June 2007, we provided a redemption notice to AGL Capital Trust I, the holder of our $75 million, 8.17% junior subordinated debentures and classified the balance, together with a $2 million note payable, representing our common securities investment in AGL Capital Trust I, to short-term debt. While these junior subordinated debentures had an original maturity date of June 1, 2037, the terms of the junior subordinated debentures permitted prepayment of the obligation represented by the junior subordinated debentures at any time subsequent to June 1, 2007. These terms however, also require that we pay a premium to AGL Capital Trust I in the event that we redeem these debentures prior to the maturity date. In July 2007, we used the proceeds from the sale of commercial paper to pay AGL Capital Trust I the $75 million principal amount plus a $3 million premium in connection with the early redemption of the junior subordinated debentures, and to pay the $2 million note with respect to our common securities interest in AGL Capital Trust I. The $3 million premium was recorded as interest expense in the three months ending September 30, 2007.

In August 2007, we extended the Pivotal Utility Holdings, Inc. $20 million line of credit through August 2008. This line of credit, which supports Elizabethtown Gas’ hedging program and bears interest at the federal funds effective rate plus 0.4%, is used solely for the posting of deposits and is unconditionally guaranteed by us.

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Note 7 - 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. 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 which were described in Note 8 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

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. The following table illustrates our contingent financial commitments as of September 30, 2007.

	Commitments due before Dec. 31,
In millions	Total		2007		2008 & thereafter
Standby letters of credit and performance and surety bonds	$	22	$	2	$	20

Litigation

We are involved in litigation arising in the normal course of business. The ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

There have been no significant changes in the Jefferson Island Storage & Hub, LLC vs. State of Louisiana litigation, which was described in Note 8 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006. The ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Note 8 - Income Taxes

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109, Accounting for Income Taxes,” which addressed the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. We adopted the provisions of FIN 48 on January 1, 2007. At the date of adoption, and as of September 30, 2007, we did not have a liability for unrecognized tax benefits. Based on current information, we do not anticipate that this will change materially in the next year.

We recognize accrued interest and penalties related to uncertain tax positions in operating expenses in the condensed consolidated statements of income, which is consistent with the recognition of these items in prior reporting periods. As of January 1, 2007, the company did not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

We file a U.S. federal consolidated income tax return and various state income tax returns. We are no longer subject to income tax examinations by the Internal Revenue Service or any state for years before 2002.

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Note 9 - Segment Information

Our four operating segments are as follows:

·	Distribution operations consists primarily of:

o	Atlanta Gas Light Company

o	Chattanooga Gas Company

o	Elizabethtown Gas

o	Elkton Gas

o	Florida City Gas

o	Virginia Natural Gas, Inc.

·	Retail energy operations consists of SouthStar

·	Wholesale services consists primarily of Sequent

·	Energy investments consists primarily of:

o	AGL Networks, LLC

o	Golden Triangle Storage, Inc.

o	Jefferson Island Storage & Hub, LLC

o	Pivotal Propane of Virginia

We treat corporate, our fifth segment, as a non-operating business segment, and it currently includes AGL Services Company, AGL Capital Corporation and the effect of intercompany eliminations.

We evaluate segment performance based primarily on the non-GAAP measure of earnings before interest and taxes (EBIT), which includes the effects of corporate expense allocations. EBIT includes operating income, other income and minority interest. 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 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 we believe is directly relevant to the efficiency of those operations.

You should not consider EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income and net income for the three and nine months ended September 30, 2007 and 2006, are presented in the following tables.

	Three months ended Sept. 30,
In millions	2007		2006
Operating revenues	$	369	$	434
Operating expenses		314		344
Operating income		55		90
Minority interest		-		-
EBIT		55		90
Interest expense		34		32
Earnings before income taxes		21		58
Income taxes		8		22
Net income	$	13	$	36

	Nine months ended Sept. 30,
In millions	2007			2006
Operating revenues	$	1,809		$	1,914
Operating expenses		1,460			1,536
Operating income		349			378
Other income (expense)		1			(2	)
Minority interest		(24	)		(19	)
EBIT		326			357
Interest expense		92			91
Earnings before income taxes		234			266
Income taxes		89			101
Net income	$	145		$	165

Balance sheet information at December 31, 2006, is as follows:


In millions	Identifiable and total assets (1)		Goodwill
Distribution operations	$	4,565	$	406
Retail energy operations		298		-
Wholesale services		849		-
Energy investments		373		14
Corporate and intercompany eliminations (2)		62		-
Consolidated AGL Resources	$	6,147	$	420

(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, property, plant and equipment and reflect the effect of intercompany eliminations.

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Summarized income statement information, identifiable and total assets, goodwill and property, plant and equipment expenditures as of and for the three and nine months ended September 30, 2007 and 2006, by segment are shown in the following tables.

Three months ended September 30, 2007


In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intercompany eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	219	$	128		$	13	$	9	$	-		$	369
Intercompany revenues (1)		37		-			-		-		(37	)		-
Total operating revenues		256		128			13		9		(37	)		369
Operating expenses
Cost of gas		83		112			1		-		(37	)		159
Operation and maintenance		79		16			10		4		(2	)		107
Depreciation and amortization		30		1			1		2		3			37
Taxes other than income taxes		9		1			-		-		1			11
Total operating expenses		201		130			12		6		(35	)		314
Operating income (loss)		55		(2	)		1		3		(2	)		55
Other income (expense)		-		1			-		-		(1	)		-
Minority interest		-		-			-		-		-			-
EBIT	$	55	$	(1	)	$	1	$	3	$	(3	)	$	55

Capital expenditures for property, plant and equipment	$	52	$	2		$	-	$	8	$	6		$	68

Three months ended September 30, 2006
In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intercompany eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	218	$	132		$	74	$	10	$	-		$	434
Intercompany revenues (1)		35		-			-		-		(35	)		-
Total operating revenues		253		132			74		10		(35	)		434
Operating expenses
Cost of gas		86		119			20		-		(35	)		190
Operation and maintenance		82		14			13		5		(3	)		111
Depreciation and amortization		28		1			1		2		1			33
Taxes other than income taxes		7		1			-		-		2			10
Total operating expenses		203		135			34		7		(35	)		344
Operating income (loss)		50		(3	)		40		3		-			90
Other income (expense)		-		1			-		-		(1	)		-
Minority interest		-		-			-		-		-			-
EBIT	$	50	$	(2	)	$	40	$	3	$	(1	)	$	90

Capital expenditures for property, plant and equipment	$	48	$	3		$	1	$	13	$	12		$	77

(1)	Intercompany revenues – Wholesale services records its energy marketing and risk management revenue on a net basis. Wholesale services’ total operating revenues include intercompany revenues of $120 million and $110 million for the three months ended September 30, 2007 and 2006, respectively.

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Nine months ended September 30, 2007

In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments			Corporate and intercompany eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	1,079	$	653		$	50	$	27		$	-		$	1,809
Intercompany revenues (1)		137		-			-		-			(137	)		-
Total operating revenues		1,216		653			50		27			(137	)		1,809
Operating expenses
Cost of gas		612		508			4		-			(137	)		987
Operation and maintenance		250		50			27		14			(7	)		334
Depreciation and amortization		89		4			2		4			9			108
Taxes other than income taxes		25		1			1		1			3			31
Total operating expenses		976		563			34		19			(132	)		1,460
Operating income (loss)		240		90			16		8			(5	)		349
Other income (expense)		2		1			-		(1	)		(1	)		1
Minority interest		-		(24	)		-		-			-			(24	)
EBIT	$	242	$	67		$	16	$	7		$	(6	)	$	326

Identifiable and total assets (2)	$	4,784	$	216		$	699	$	276		$	(135	)	$	5,840
Goodwill	$	406	$	-		$	-	$	14		$	-		$	420
Capital expenditures for property, plant and equipment	$	145	$	3		$	1	$	18		$	26		$	193

Nine months ended September 30, 2006
In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intercompany eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	1,068	$	675		$	141	$	30	$	-		$	1,914
Intercompany revenues (1)		118		-			-		-		(118	)		-
Total operating revenues		1,186		675			141		30		(118	)		1,914
Operating expenses
Cost of gas		594		551			33		4		(118	)		1,064
Operation and maintenance		251		48			33		14		(5	)		341
Depreciation and amortization		86		3			2		4		6			101
Taxes other than income taxes		24		1			-		1		4			30
Total operating expenses		955		603			68		23		(113	)		1,536
Operating income (loss)		231		72			73		7		(5	)		378
Other income (expense)		1		(1	)		-		-		(2	)		(2	)
Minority interest		-		(19	)		-		-		-			(19	)
EBIT	$	232	$	52		$	73	$	7	$	(7	)	$	357

Identifiable and total assets (2)	$	4,568	$	226		$	715	$	374	$	(48	)	$	5,835
Goodwill	$	406	$	-		$	-	$	14	$	-		$	420
Capital expenditures for property, plant and equipment	$	126	$	6		$	2	$	20	$	36		$	190

(1)	Intercompany revenues – Wholesale services records its energy marketing and risk management revenue on a net basis. Wholesale services’ total operating revenues include intercompany revenues of $473 million and $404 million for the nine months ended September 30, 2007 and 2006, respectively.

(2)	Our corporate segment's assists 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 Securities and Exchange Commission (SEC), are forward-looking statements. 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," "indicate," "intend," "may," “outlook,” "plan," "predict," "project,” "seek," "should," "target," "will," "would," or similar expressions. 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 several 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; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; 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 and general economic conditions; uncertainties about environmental issues and the related impact of such issues; the impact of changes in weather 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 that are 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, 2006, among others, could cause our business, results of operations or financial condition in 2007 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 and the sale of natural gas to end-use customers primarily in Georgia through our retail natural gas marketing business. As of September 2007, our six utilities serve 2.2 million end-use customers, making us the largest distributor of natural gas in the southeastern and mid-Atlantic regions of the United States (U.S.) based on customer count. Although our retail natural gas marketing business is not subject to the same regulatory framework as our utilities, it is an integral part of the retail framework for providing gas service to end-use customers in Georgia.

We also engage in natural gas asset management and related logistics activities for our own 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. These businesses allow us to be opportunistic in capturing incremental value at the wholesale level, provide us with deepened business insight about natural gas market dynamics and facilitate our ability, in the case of asset management, to provide transparency to regulators as to how that value can be captured to benefit our utility customers through profit-sharing arrangements. Given the volatile and changing nature of the natural gas resource base in North America and globally, we believe that participation in these related businesses strengthens our company. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services, energy investments and a non-operating corporate segment.

Distribution Operations - Our distribution operations segment is the largest component of our business and includes these natural gas utilities in six states:

·	Atlanta Gas Light Company (Atlanta Gas Light) in Georgia

·	Chattanooga Gas Company (Chattanooga Gas) in Tennessee

·	Elizabethtown Gas in New Jersey

·	Elkton Gas in Maryland

·	Florida City Gas in Florida

·	Virginia Natural Gas, Inc. (Virginia Natural Gas) in Virginia

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Each utility operates subject to regulations of the state regulatory agencies in its service territories with respect to rates charged to our customers, maintenance of accounting records and various other service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. Rates are set at levels that generally should allow us to recover all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return for our shareholders.

With the exception of our Atlanta Gas Light subsidiary, earnings in our distribution operations segment can be affected by customer consumption patterns that are a function of weather conditions and price levels for natural gas. Atlanta Gas Light charges rates to its customers primarily as monthly fixed charges.

Our non-Georgia jurisdictions have various regulatory mechanisms that allow us to recover our costs, but they are not direct offsets to the potential impacts of weather and customer consumption on earnings. In our New Jersey, Virginia and Tennessee utilities, their tariffs contain weather normalization adjustment (WNA) provisions that are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer than normal and decreasing amounts charged when weather is colder than normal. The WNA is most effective in a reasonable temperature range relative to normal weather using historical averages.

We continuously monitor the performance of our utilities to determine whether rates need to be adjusted through the regulatory process. We have long-term fixed rate settlements in our three largest franchises in Georgia, New Jersey and Virginia.

The November 2004 agreement between Elizabethtown Gas and the New Jersey Board of Public Utilities (New Jersey Commission), which approved our acquisition of NUI Corporation, included among other things, a base rate freeze for Elizabethtown Gas for the five-year period from November 2004 to October 2009. Beginning with the measurement period in November 2007, 75% of Elizabethtown Gas’ earnings in excess of an 11% return on equity would be shared with rate payers in the fourth and fifth years of the base rate freeze period. Additionally, if Elizabethtown Gas exceeds a 10% return on equity, it could be required to return a portion of any WNA surcharge to its customers.

In July 2007, the Tennessee Regulatory Authority ordered the second phase of Chattanooga Gas’ rate case, which dealt with various energy conservation proposals, to be closed. There was no change to Chattanooga Gas’ rates or rate design.

In September 2007, the Georgia Public Service Commission approved our request to obtain an undivided interest in pipelines connecting our Georgia service territory to liquefied natural gas facilities at Elba Island, Georgia. We and Southern Natural Gas Company (SNG) have undertaken this pipeline project in an effort to diversify our sources of natural gas. We currently receive the majority of our natural gas supply from a production region in and around the Gulf of Mexico and generally demand for this natural gas is growing faster than supply. This project is contingent upon Federal Energy Regulatory Commission (FERC) approval and therefore we and SNG jointly filed an application with the FERC in October 2007, and anticipate FERC approval in 2008. Construction is expected to begin in 2008 and to be completed in 2009.

Retail Energy Operations - Our retail energy operations segment consists of SouthStar Energy Services LLC, (SouthStar), a joint venture owned 70% by us and 30% by Piedmont Natural Gas Company, Inc. (Piedmont). SouthStar markets natural gas and related services to retail customers on an unregulated basis, principally in Georgia, as well as to commercial and industrial customers in Alabama, Florida, Ohio, Tennessee, North Carolina and South Carolina. SouthStar is the largest marketer of natural gas in Georgia with an approximate 35% market share.

Although our ownership interest in the SouthStar partnership is 70%, the majority of SouthStar's earnings in Georgia are allocated by contract 75% to us and 25% to Piedmont. SouthStar’s earnings related to customers in Ohio and Florida are allocated 70% to us and 30% to Piedmont. We record the earnings allocated to Piedmont as a minority interest in our condensed consolidated statements of income, and we record Piedmont’s portion of SouthStar’s capital as a minority interest in our condensed consolidated balance sheets. The majority of SouthStar’s earnings allocated to us for the three and nine months ended September 30, 2007, were at the 75% contractual rate.

SouthStar’s operations are sensitive to seasonal weather, natural gas prices, and customer growth and consumption patterns similar to those affecting our utility operations. SouthStar’s retail pricing strategies and use of various economic hedging strategies, such as futures, options, swaps, weather derivative instruments and other risk management tools, help to ensure retail customer costs are covered to mitigate the potential effect of these issues on its operations.

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

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

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

In 2006, Sequent entered into an agreement that facilitated the expansion of its operations into the western U.S. and Canada. Sequent continues to work on projects and transactions to extend its operating territory and is entering into agreements with longer tenors, as well as evaluating opportunities to expand its business focus and models.

In October 2007, the Georgia Public Service Commission extended the asset management agreement between Sequent and Atlanta Gas Light to March 2012. Under the terms of the extended agreement, the sharing percentages are unchanged; however the agreement now includes guaranteed minimum annual payments to be made by Sequent of approximately $4 million. The contract year under the extended agreement will be April 1 to March 31 with Sequent making quarterly sharing payments.

For more information on Sequent’s energy marketing and risk management activities, see Item 3, Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk.

Energy Investments - Our energy investments segment includes a number of businesses that are related or complementary to our primary business. The most significant of these businesses is our natural gas storage business, Jefferson Island Storage & Hub, LLC (Jefferson Island), which operates a high-deliverability salt-dome storage asset in the Gulf Coast region of the U.S. and is actively pursuing expansion of the existing facility and the development of new salt-dome storage assets in this region. While our salt-dome storage business also can generate additional revenue during times of peak market demand for natural gas storage services, the majority of its storage services are covered under medium to long-term contracts at a fixed market rate. We also own and operate a small telecommunications business, AGL Networks, LLC (AGL Networks), which constructs and operates conduit and fiber infrastructure within select metropolitan areas.

In December 2006, we announced that our wholly-owned subsidiary, Golden Triangle Storage, Inc. (Golden Triangle Storage), plans to build a natural gas storage facility in the Beaumont, Texas area. The project will initially consist of two underground salt dome storage caverns approximately a half-mile to a mile below ground that will hold about 12 billion cubic feet (Bcf) of working natural gas storage capacity, or a total cavern capacity of 17 Bcf. The facility potentially can be expanded up to a total of five caverns with 28 Bcf of working natural gas storage capacity in the future based on customer interest. Golden Triangle Storage also intends to build an approximately nine-mile natural gas pipeline to connect the storage facility with six interstate and intrastate pipelines.

Our current cost estimate for this facility is between $220 million and $260 million depending upon the facility’s configuration, materials and drilling costs, the amount and cost of pad gas (which includes volumes of non-working natural gas used to maintain the operational integrity of the cavern facility), and financing costs. This estimate could change due to changes in these factors, among others, as we refine our engineering estimates.

In May 2007, Golden Triangle Storage held a non-binding open season for service offerings at the proposed facility, which resulted in indications of market support for the facility. In June 2007, Golden Triangle Storage applied for approval from the FERC. The FERC will serve as the lead agency overseeing the participation of a number of other federal, state and local agencies in reviewing and permitting the facility. We anticipate that the FERC will issue an order by early 2008. Timelines associated with our commencement of commercial operations remain on track with initial construction on the first cavern expected to begin in early 2008.

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Corporate - Our corporate segment includes our nonoperating business units, including AGL Services Company and AGL Capital Corporation (AGL Capital).

We allocate substantially all of our corporate segments operating expenses and interest costs to our operating segments in accordance with state regulations. Our corporate segment also includes intercompany eliminations for transactions between our operating business segments. Our segment results include the impact of these allocations to the various operating segments.

Executive Summary

We continue to focus significant efforts in our distribution operations business on improving our net customer growth trends, despite the industry-wide challenges of rising natural gas prices, competition from alternative fuels and declining natural gas usage per customer. In each of our utility service areas, we continue to implement programs aimed at emphasizing natural gas as the fuel of choice for customers and expanding the use of natural gas through a variety of promotional activities. We are also focused on similar customer growth initiatives at SouthStar as we continue to enter new markets and improve the overall profitability of its customers through a variety of enhancements to existing, and the implementation of new, product offerings and pricing plans.

In 2007 we saw average customer usage patterns return to levels more consistent with historical averages. As the weather grew colder, compared to last year, and moved closer to 10-year average weather patterns, we saw the conservation that occurred a year ago largely reverse itself. Due to these factors, coupled with our targeted marketing and growth programs, we were able to increase our customer count for the nine months ended September 30, 2007, at distribution operations by 1.0% and at retail energy operations by 1.5% as compared to last year. This increase in growth rate is an improvement over our relatively flat customer growth in 2006, when we had slower customer growth coming out of the winter heating season due in part to much higher natural gas prices and warmer weather.

These same weather trends that favorably impacted our distribution operations and retail energy operations segments, along with less volatility in the natural gas markets, as compared to last year, have limited Sequent’s asset optimization and arbitrage opportunities to capture economic value in 2007. An important component of Sequent’s business is its ability to capture operating margin based on seasonal and locational spreads, both of which were significantly reduced in 2007 compared to the prior period.

We utilize outside vendors to assist us with the execution of business processes that are ancillary to our delivery of natural gas and related to the performance of basic business functions. This allows us to control operating costs, increase the efficiency through which these functions are executed and improve our service levels to customers. Most recently, we partnered with third parties in India to provide certain call center operations, as well as certain support functions related to information technology, finance, supply chain and engineering. These efforts are expected to reduce operating expenses associated with these functions, which will largely offset expected increases in costs related to inflation, health care and other costs.

Results of Operations

Revenues We generate nearly all our operating revenues through the sale, distribution and storage of natural gas. We include in our condensed consolidated operating revenues an estimate of revenues from natural gas delivered, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period.

Operating Margin and EBIT We evaluate segment performance using the measures of operating margin and earnings before interest and taxes (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 accounting principles generally accepted in the United States of America (GAAP). EBIT is a non-GAAP measure that includes operating income, other income and expenses and minority interest. 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. Operating margin is also 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.

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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 passed 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 gross profit 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.

For the nine months ended September 30, 2007, we derived approximately 95% of our EBIT from our regulated natural gas distribution business and the sale of natural gas to end-use customers primarily in Georgia through SouthStar. The remaining 5% of our EBIT was principally derived from our wholesale services and energy investments segments.

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 as determined in accordance with GAAP. In addition, our operating margin or EBIT measures may not be comparable to similarly titled measures of other companies.

Seasonality The operating revenues and EBIT of our distribution operations, retail energy operations and wholesale services 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. Occasionally in the summer, Sequent’s operating margins are impacted due to peak usage by power generators in response to summer energy demands. 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.

Seasonality also affects the comparison of certain balance sheet items, such as receivables, inventories and short-term debt across quarters. However, these items are comparable when reviewing our annual results. Accordingly, we have presented the condensed consolidated balance sheet as of September 30, 2006, to provide comparisons of these items to December 31, 2006, and September 30, 2007.

Hedging Changes in commodity prices subject a significant portion of our operations to earnings variability. Our nonutility businesses principally use physical and financial arrangements to economically hedge the risks associated with seasonal fluctuations in market conditions, changing commodity prices and weather. In addition, because these economic hedges may not qualify, or are not designated, for hedge accounting treatment, our reported earnings for the wholesale services and retail energy operations segments include the changes in the fair values of certain derivatives. These values may change significantly from period to period and are reflected as mark-to-market adjustments within our operating margin.

Elizabethtown Gas utilizes certain derivatives in accordance with a directive from the New Jersey Commission to create a hedging program to hedge the impact of market fluctuations in natural gas prices. These derivative products are marked to market value each reporting period. In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in purchased gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset (loss) or liability (gain), as appropriate, in our condensed consolidated balance sheets.

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The following table sets forth a reconciliation of our operating margin and EBIT to our operating income and net income, together with other consolidated financial information for the three and nine months ended September 30, 2007 and 2006.


	Three months ended September 30,							Nine months ended September 30,
In millions, except per share amounts	2007		2006		Change			2007			2006			Change
Operating revenues	$	369	$	434	$	(65	)	$	1,809		$	1,914		$	(105	)
Cost of gas		159		190		(31	)		987			1,064			(77	)
Operating margin (1)		210		244		(34	)		822			850			(28	)
Operating expenses		155		154		1			473			472			1
Operating income		55		90		(35	)		349			378			(29	)
Other income (expense)		-		-		-			1			(2	)		3
Minority interest		-		-		-			(24	)		(19	)		(5	)
EBIT (1)		55		90		(35	)		326			357			(31	)
Interest expense		34		32		2			92			91			1
Earnings before income taxes		21		58		(37	)		234			266			(32	)
Income taxes		8		22		(14	)		89			101			(12	)
Net income	$	13	$	36	$	(23	)	$	145		$	165		$	(20	)
Earnings per common share:
Basic	$	0.17	$	0.46	$	(0.29	)	$	1.88		$	2.13		$	(0.25	)
Diluted	$	0.17	$	0.46	$	(0.29	)	$	1.87		$	2.12		$	(0.25	)
Weighted average number of common shares outstanding:
Basic		77.0		77.5		(0.5	)		77.4			77.6			(0.2	)
Diluted		77.4		77.9		(0.5	)		77.8			78.1			(0.3	)

(1)	These are non-GAAP measurements.

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Selected weather, customer and volume metrics for the three and nine months ended September 30, 2007 and 2006, are presented in the following table.

Weather
Heating degree days (1)							2007 vs.			2007 vs.									2007 vs.			2007 vs.
			Three months				normal			2006					Nine months				normal			2006
			ended September 30,				colder			colder					ended September 30,				colder			colder
	Normal		2007		2006		(warmer)			(warmer)			Normal		2007		2006		(warmer)			(warmer)
Florida		-		-		-		-			-			349		281		357		(19	)%		(21	)%
Georgia		7		-		8		(100	)%		(100	)%		1,595		1,489		1,500		(7	)%		(1	)%
Maryland		37		23		53		(38	)%		(57	)%		3,004		3,063		2,712		2	%		13	%
New Jersey		29		29		38		-			(24	)%		2,992		3,172		2,702		6	%		17	%
Tennessee		8		-		11		(100	)%		(100	)%		1,799		1,753		1,699		(3	)%		3	%
Virginia		6		-		11		(100	)%		(100	)%		2,045		2,090		1,877		2	%		11	%

(1) Obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages.



Customers	Three months ended September 30,									Nine months ended September 30,
	2007			2006			% change			2007			2006			% change
Distribution Operations
Average end-use customers (in thousands)
Atlanta Gas Light		1,539			1,522			1.1	%		1,564			1,552			0.8	%
Chattanooga Gas		60			60			-			61			61			-
Elizabethtown Gas		271			268			1.1	%		272			268			1.5	%
Elkton Gas		6			6			-			6			6			-
Florida City Gas		104			103			1.0	%		104			103			1.0	%
Virginia Natural Gas		265			262			1.1	%		269			264			1.9	%
Total		2,245			2,221			1.1	%		2,276			2,254			1.0	%
Operation and maintenance expenses per customer	$	35		$	37			(5	)%	$	110		$	111			(1	)%
EBIT per customer	$	25		$	22			14	%	$	106		$	103			3	%

Retail Energy Operations
Average customers (in thousands)		535			528			1.3	%		543			535			1.5	%
Market share in Georgia		35	%		35	%		-			35	%		35	%		-



Volumes In billion cubic feet (Bcf)	Three months ended September 30,							Nine months ended September 30,
	2007		2006		% change			2007		2006		% change
Distribution Operations - firm
Firm		20.1		19.7		2	%		148.9		134.3		11	%
Interruptible		25.1		28.0		(10	)%		80.9		87.4		(7	)%
Total		45.2		47.7		(5	)%		229.8		221.7		4	%

Retail Energy Operations
Georgia firm		3.5		3.4		3	%		27.1		24.5		11	%
Ohio and Florida		0.3		-		100	%		3.1		-		100	%

Wholesale Services
Daily physical sales (Bcf / day)		2.3		2.3		-			2.3		2.2		5	%

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Third quarter 2007 compared to third quarter 2006

Segment information Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the three months ended September 30, 2007 and 2006.

In millions	Operating revenues			Operating margin (1)		Operating expenses		EBIT (1)
2007
Distribution operations	$	256		$	173	$	118	$	55
Retail energy operations		128			16		18		(1	)
Wholesale services		13			12		11		1
Energy investments		9			9		6		3
Corporate (2)		(37	)		-		2		(3	)
Consolidated	$	369		$	210	$	155	$	55
2006
Distribution operations	$	253		$	167	$	117	$	50
Retail energy operations		132			13		16		(2	)
Wholesale services		74			54		14		40
Energy investments		10			10		7		3
Corporate (2)		(35	)		-		-		(1	)
Consolidated	$	434		$	244	$	154	$	90

(1) These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in “Results of Operations” herein.

(2) Includes intercompany eliminations.

For the third quarter of 2007, net income decreased by $23 million or 64% and earnings per share decreased by $0.29 per basic and diluted share or 63% compared to last year. The variance between the two quarters was mainly driven by a decreased EBIT contribution of $39 million or 98% from wholesale services due to lower operating margins. This was partially offset by increased EBIT from distribution operations of $5 million or 10% due to increased operating margins.

Operating Margin Our operating margin for the third quarter of 2007 decreased by $34 million or 14% compared to last year. Distribution operations’ operating margin increased $6 million or 4% compared to last year primarily due to customer growth, higher customer usage and new rates at Chattanooga Gas, which became effective January 1, 2007.

Retail energy’s improved operating margin of $3 million or 23% was driven by improved results associated with the management of commodity risk and other asset management activities and improved retail price spreads.

Wholesale services’ operating margin decreased $42 million or 78%. The following table indicates the significant changes in wholesale services’ operating margin for the three months ended September 30, 2007 and 2006.

In millions	2007			2006
Gain on storage hedges	$	12		$	39
(Loss) gain on transportation hedges		(1	)		11
Commercial activity		2			24
Inventory LOCOM, net of hedging recoveries		(1	)		(20	)
Operating margin	$	12		$	54

The decrease of $27 million in gains on the value of storage hedge positions was due to a lower decline in forward New York Mercantile Exchange (NYMEX) prices during the current period compared to the decline experienced in 2006. In addition, the decrease of $12 million in gains on the value of transportation hedges was driven by gains in 2006 resulting from the narrowing of future locational spreads, while in 2007 the opposite impact was experienced. Wholesale services also experienced a $22 million reduction in commercial activity due in part to decreased inventory storage spreads and lower market volatility. These declines were partially offset by a $19 million reduction in required inventory LOCOM adjustments, which is a reflection of reducing wholesale services’ inventory to current market prices.

Energy investments’ margin decreased $1 million or 10% primarily due to lower sales at AGL Networks.

Operating Expenses Our operating expenses for the third quarter of 2007 increased $1 million or 1% as compared to 2006. The following table indicates the significant changes in our operating expenses.

In millions
Operating expenses for third quarter of 2006	$	154
Increased costs at retail energy operations due to growth and improved operations, resulting in higher customer care and compensation costs		2
Increased payroll and other operating costs at wholesale services due to continued growth		3
Decreased incentive compensation costs at wholesale services due to lower operating margins		(6	)
Other, net		2
Operating expenses for third quarter of 2007	$	155

Interest Expense The increase in interest expense of $2 million or 6% for the three months ended September 30, 2007, was primarily due to the increase in short-term interest rates and the $3 million premium paid for early redemption of the $75 million notes payable to AGL Capital Trust I.

	Three months ended September 30,
In millions	2007			2006			Change
Average debt outstanding (1)	$	1,997		$	2,079		$	(82	)
Average rate		6.2	%		5.9	%		0.3	%

(1)	Daily average of all outstanding debt.

Income Taxes The decrease in income tax expense of $14 million or 64% for the third quarter of 2007 compared to the same period in 2006 was primarily due to lower consolidated earnings in the third quarter of 2007.

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Nine months 2007 compared to nine months 2006

Segment information Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables for the nine months ended September 30, 2007 and 2006.

In millions	Operating revenues			Operating margin (1)		Operating expenses		EBIT (1)
2007
Distribution operations	$	1,216		$	604	$	364	$	242
Retail energy operations		653			145		55		67
Wholesale services		50			46		30		16
Energy investments		27			27		19		7
Corporate (2)		(137	)		-		5		(6	)
Consolidated	$	1,809		$	822	$	473	$	326
2006
Distribution operations	$	1,186		$	592	$	361	$	232
Retail energy operations		675			124		52		52
Wholesale services		141			108		35		73
Energy investments		30			26		19		7
Corporate (2)		(118	)		-		5		(7	)
Consolidated	$	1,914		$	850	$	472	$	357

(1) These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in “Results of Operations” herein.

(2) Includes intercompany eliminations.

For the nine months ended September 30, 2007, our net income decreased by $20 million or 12% and our basic earnings per share decreased by $0.25 or 12%, primarily due to decreased EBIT contributions from wholesale services largely due to lower operating margins. This was offset by increased EBIT contributions at distribution operations and retail energy operations due to higher operating margins as compared to last year.

Operating Margin Our operating margin for the nine months ended September 30, 2007, decreased $28 million or 3% compared with the same period in 2006.

Distribution operations’ operating margin increased $12 million or 2% primarily due to customer growth and higher customer usage. These increases in operating margin were due to weather that was closer to 10-year normal weather patterns as compared to 2006 and from overall customer growth of 1.0%.

Retail energy operations’ operating margin increased $21 million or 17% primarily due to a $7 million increase in average customer usage, a $2 million increase in the average number of customers, $3 million from the advancement into the Ohio market, $2 million in higher late payment fees and $3 million from net gains on weather derivatives in the quarter ended March 31, 2007, when weather was 6% warmer than last year. Retail energy operating margins were further positively impacted by higher retail price spreads offset by slightly lower contributions from the optimization of storage and transportation assets and commodity risk management activities.

Energy investments’ operating margin increased $1 million or 4% primarily due to higher revenues at Jefferson Island.

Wholesale services’ operating margin decreased $62 million or 57%. This decrease is due to a $44 million reduction in the amount of hedge gains and a $46 million reduction in commercial activity due in part to milder weather, reduced inventory storage spreads, lower volatility in the marketplace and the deferral of certain planned storage withdrawals. These decreases were partially offset by a $28 million reduction in the required LOCOM adjustments to gas inventories for the nine months ended September 30, 2007, net of $2 million and $3 million in estimated hedging recoveries during 2007 and 2006. These are indicated in the following table:

In millions	2007			2006
Gain on storage hedges	$	15		$	50
Gain on transportation hedges		2			11
Commercial activity		31			77
Inventory LOCOM, net of hedging recoveries		(2	)		(30	)
Operating margin	$	46		$	108

The following graph presents the NYMEX forward natural gas prices as of September 30, 2007, June 30, 2007 and December 31, 2006, for the period of October 2007 through March 2008, and reflects the prices at which wholesale services could buy natural gas at the Henry Hub for delivery in the same time period.

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Wholesale services’ expected natural gas withdrawals from physical salt dome and reservoir storage are presented in the table below along with the expected operating revenue. Wholesale services’ expected operating revenues are net of the impact of regulatory sharing and reflect the amounts that it would expect to realize in future periods based on the inventory withdrawal schedule and forward natural gas prices at September 30, 2007. Wholesale services’ storage inventory is economically hedged with futures contracts, which results in an overall locked-in margin, timing notwithstanding. Wholesale services’ physical salt dome and reservoir volumes are presented in NYMEX equivalent contract units of 10,000 million British thermal units (MMBtu’s).

	Three months ended
	Dec.31, 2007		Mar. 31, 2008		Total
Salt dome		225		109		334
Reservoir		339		798		1,137
Total volumes		564		907		1,471
Expected operating revenues from physical inventory (in millions)	$	5	$	15	$	20

As of September 30, 2007, the weighted-average cost of natural gas in inventory was $6.66 for physical salt dome storage and $6.02 for physical reservoir storage.

Wholesale services’ inventory level and pricing as of September 30, 2007, should result in operating revenues of $5 million in 2007 and $15 million in 2008 if all factors were to remain the same. This expected operating revenue could change as wholesale services adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months. Based upon current projections of year-end storage positions at December 31, 2007, a $1.00 change in the first quarter of 2008 forward NYMEX prices would result in an estimated $7 million impact to wholesale services’ reported operating revenues for the year ending December 31, 2007, after regulatory sharing.

Operating Expenses Our operating expenses for the nine months ended September 30, 2007, were relatively flat compared to 2006. The following table indicates the significant changes in our operating expenses.

In millions
Operating expenses for first nine months of 2006	$	472
Increased costs at retail energy operations due to growth and improved operations, resulting in higher customer care and compensation costs		5
Increased payroll and other operating costs at wholesale services due to continued growth		5
Higher gain on asset sales in 2006 at distribution operations		3
Increased marketing expenses primarily at distribution operations		2
Decreased bad debt expense at retail energy operations		(3	)
Decreased incentive compensation costs at wholesale services due to lower operating margins		(10	)
Other, net		(1	)
Operating expenses for first nine months of 2007	$	473

Interest Expense The increase of $1 million or 1% for the nine months ended September 30, 2007, was due primarily to higher short-term interest rates and a $3 million premium paid for the early redemption of the $75 million notes payable to AGL Capital Trust I, recorded as interest expense in the quarter ending September 30, 2007. This was partially offset by lower average debt, primarily from reduced commercial paper borrowings for most of 2007.

	Nine months ended September 30,
In millions	2007			2006			Change
Average debt outstanding (1)	$	1,899		$	2,002		$	(103	)
Average rate		6.2	%		6.1	%		0.1	%

(1)	Daily average of all outstanding debt.

Based on $836 million of variable-rate debt, which includes $576 million of our variable-rate short-term debt, $100 million of variable-rate senior notes and $160 million of variable-rate gas facility revenue bonds outstanding at September 30, 2007, a 100 basis point change in market interest rates from 5.7% to 6.7% would have resulted in an increase in pretax interest expense of $8 million on an annualized basis.

Income Taxes The decrease in income tax expense of $12 million or 12% for the nine months ended September 30, 2007, compared to the same period in 2006 was due to lower consolidated earnings in 2007.

Liquidity and Capital Resources

To meet our capital and liquidity requirements we rely on operating cash flow; short-term borrowings under our commercial paper program, which is backed by our Credit Facility; borrowings under Sequent’s, SouthStar’s and Pivotal Utility Holdings, Inc. (Pivotal Utility) lines of credit; and borrowings or stock issuances in the long-term capital markets. Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization 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. The availability of borrowings under our Credit Facility is limited and subject to a total debt-to-capital ratio financial covenant of no greater than 70% as specified within the Credit Facility, which we currently meet. We believe these sources will be sufficient for our working capital needs, debt service obligations and scheduled capital expenditures for the foreseeable future.

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We will continue to evaluate the need to increase our available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by the rating agencies and other factors. Additionally, our liquidity and capital resource requirements may change in the future due to a number of other factors, some of which we cannot control. These factors include:

·	the seasonal nature of the natural gas business and our resulting short-term borrowing requirements, which typically peak during colder months

·	increased gas supplies required to meet our customers’ needs during cold weather

·	changes in wholesale prices and customer demand for our products and services

·	regulatory changes and changes in ratemaking policies of regulatory commissions

·	contractual cash obligations and other commercial commitments

·	interest rate changes

·	pension and postretirement funding requirements

·	changes in income tax laws

·	margin requirements resulting from significant increases or decreases in our commodity prices

·	operational risks

·	the impact of natural disasters, including weather

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities. 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. The following table illustrates our expected future contractual obligations as of September 30, 2007.

			Payments due before December 31,
					2008		2010		2012
					&		&		&
In millions	Total		2007		2009		2011		thereafter
Pipeline charges, storage capacity and gas supply (1) (2)	$	1,750	$	143	$	721	$	456	$	430
Long-term debt		1,548		-		1		298		1,249
Interest charges		1,119		23		183		163		750
Short-term debt		576		576		-		-		-
Pipeline Replacement Program (PRP) costs (3)		251		5		113		95		38
Operating leases (4)		159		7		56		39		57
Environmental Remediation Cost (ERC) (3)		99		3		26		59		11
Total	$	5,502	$	757	$	1,100	$	1,110	$	2,535

(1) Charges recoverable through a purchase gas adjustment mechanism or alternatively billed to marketers

selling retail gas in Georgia and certificated by the Georgia Public Service Commission. Also includes demand charges

associated with Sequent.

(2) Amount includes SouthStar gas commodity purchase commitments of 11 Bcf at floating gas prices calculated using forward

natural gas prices as of September 30, 2007, and is valued at $84 million.

(3) Includes charges recoverable through rate rider mechanisms.

(4) We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions.

We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective

minimum lease terms, in accordance with SFAS No. 13, “Accounting for Leases.” However, this accounting treatment does

not affect the future annual operating lease cash obligations as shown herein.

We also have incurred various financial commitments in the normal course of business. 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. The following table illustrates our expected contingent financial commitments as of September 30, 2007.

			Commitments due before Dec. 31, 2008 &
In millions	Total		2007		thereafter
Standby letters of credit, performance/ surety bonds	$	22	$	2	$	20

Cash Flow from Operating Activities In the first nine months of 2007, our net cash flow provided from operating activities was $386 million, an increase of $45 million or 13% from the same period in 2006. This was primarily a result of changes in our energy marketing and risk management assets and liabilities (net) of $195 million, offset by a reduction in deferred income taxes of $107 million.

In 2007, the net fair value of Sequent’s natural gas contracts outstanding decreased by $59 million due to the settlement of $99 million of positions, partially offset by a $40 million increase in the outstanding contracts’ fair value. This compares to a $135 million increase in fair value of outstanding contracts during 2006 offset by only $7 million of settled positions. In 2006, Sequent captured advantageous storage spreads and experienced steady declines in forward natural gas prices, which increased unrealized gains on the instruments used to hedge the storage positions. In 2007, the majority of those storage positions outstanding at the end of the prior periods were settled during the first quarter, also resulting in the payment of deferred income taxes.

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These increases were offset by increased working capital requirements, principally driven by decreased collections of our natural gas receivables of $155 million which was offset by reduced spending of $84 million on our energy marketing receivables and payables (net), decreased spending of $27 million on our natural gas inventories and decreased spending of $17 million on our payables.

Cash Flow from Investing Activities Our investing activities consisted primarily of property, plant and equipment (PP&E) expenditures of $193 million for the nine months ended September 30, 2007 and $190 million for the same period in 2006. The increase of $3 million or 2% in PP&E expenditures was primarily due to an increase in pipeline replacement program expenditures and expenditures for Virginia Natural Gas’ pipeline connecting its northern and southern systems. This was offset by decreased information technology expenditures. In 2006, we received proceeds of approximately $3 million more for the sale of property compared to the same period in 2007.

Cash Flow from Financing Activities Our financing activities are primarily composed of borrowings and payments of short-term debt, payments of medium-term notes, and notes payable to AGL Capital Trust I and II, borrowings of senior notes, distributions to minority interests, cash dividends on our common stock issuances, and purchases and issuances of treasury shares. 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 25% to 45% of total debt), as well as the term and interest rate profile of our debt securities. As of September 30, 2007, our variable-rate debt was 39% of our total debt, compared to 31% as of September 30, 2006. The increased variable-rate debt was due to higher commercial paper borrowings, as well as the early redemption of notes payable to AGL Capital Trust I and medium-term notes both of which were at fixed rates and redeemed through the issuance of commercial paper.

We also work to maintain or improve our credit ratings to manage our existing financing costs effectively and enhance our ability to raise additional capital on favorable terms. Factors we consider important in assessing our credit ratings include our balance sheet 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 table below summarizes our credit ratings as of September 30, 2007, and reflects no change from last year.

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

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’s financial covenant requires 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%. We are currently in compliance with all existing debt provisions and covenants. For more information on our debt, see Note 6 “Debt.”

Short-term Debt Our short-term debt is composed of borrowings under our commercial paper program, lines of credit at Sequent, SouthStar and Pivotal Utility Holdings, Inc. (Pivotal Utility), and the current portion of our capital leases. In June and August 2007, we extended Sequent’s $45 million unsecured lines of credit through June and August 2008. These lines of credit are used solely for the posting of margin deposits for NYMEX transactions and are unconditionally guaranteed by us. In August 2007, we extended Pivotal Utility’s $20 million line of credit through August of 2008. This line of credit supports Elizabethtown Gas’ hedging program and is used solely for the posting of margin deposits. These lines of credit bear interest at the federal funds effective rate plus 0.4% and are unconditionally guaranteed by us.

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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 winter heating season. As of September 30, 2007, our commercial paper borrowings were $129 million or 31% higher than the same time last year, primarily a result of our redemption of the $75 million principal amount of notes payable to AGL Capital Trust I, $31 million for increased common share repurchases and $11 million to redeem our medium-term notes.

As of September 30, 2007 and 2006, we had no outstanding borrowings under the Credit Facility and had unused availability of $1 billion. The availability of borrowings and unused availability under our Credit Facility is limited and subject to conditions specified within the Credit Facility, which we currently meet. These conditions include:

·	the maintenance of a ratio of total debt to total capitalization of no greater than 70%. As of September 30, 2007, our ratio of total debt of 57% to total capitalization was within our targeted and required ranges

·	the continued accuracy of representations and warranties contained in the agreement

Long-term Debt Our long-term debt matures more than one year from the date of issuance and consists of medium-term notes, senior notes, gas facility revenue bonds, and capital leases. In January 2007, we used proceeds from the sale of commercial paper to redeem $11 million of 7% medium-term notes previously scheduled to mature in January 2015.

In June 2007, we refinanced $55 million of our gas facility revenue bonds due June 2032.The original bonds had a fixed interest rate of 5.7% per year and were refinanced with $55 million of adjustable-rate gas facility revenue bonds. The maturity date of these bonds remains June 2032 and there is a 35-day auction period where the interest rate adjusts every 35 days. The interest rate at September 30, 2007, was 4.3%.

In July 2007, we used the proceeds from the sale of commercial paper to pay to AGL Capital Trust I the $75 million principal amount of 8.17% junior subordinated debentures plus a $3 million premium for early redemption of the junior subordinated debentures, and to pay a $2 million note representing our common securities interest in AGL Capital Trust I.

Shelf Registration In August 2007, we filed a new shelf registration with the SEC. The debt securities and related guarantees will be issued by AGL Capital under an indenture dated as of February 20, 2001, as supplemented and modified, as necessary, among AGL Capital, AGL Resources and The Bank of New York Trust Company, N.A., as trustee. The indenture provides for the issuance from time to time of debt securities in an unlimited dollar amount and an unlimited number of series. The debt securities will be guaranteed by AGL Resources. This replaces the previous shelf registration, filed in September 2003, which had $782 million available to be issued.

Share repurchases In February 2006, our Board of Directors authorized a plan to purchase up to 8 million shares of our outstanding common stock over a five-year period. For the nine months ended September 30, 2007, we purchased approximately 1.4 million shares of our common stock at an average cost of $39.82 per share and an aggregate cost of $57 million. This represents a $31 million or 119% increase from last year’s share repurchases. During the same period in 2006, we purchased approximately 0.7 million shares of our common stock at a weighted average cost of $36.19 per share and an aggregate cost of $26 million. We hold the purchased shares as treasury shares.

Capital Structure 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. The components of our capital structure, as of the dates indicated, are summarized in the following table.

In millions	September 30, 2007				December 31, 2006				September 30, 2006
Short-term debt	$	575	15	%	$	527	14	%	$	440	12	%
Current portion of long-term debt		1	-			12	-			1	-
Long-term debt (1)		1,548	42			1,622	43			1,634	45
Total debt		2,124	57			2,161	57			2,075	57
Common shareholders’ equity		1,623	43			1,609	43			1,581	43
Total capitalization	$	3,747	100	%	$	3,770	100	%	$	3,656	100	%

(1) Net of interest rate swaps.

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Critical Accounting Policies and 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 policies used in the preparation of our condensed consolidated financial statements include the following:

·	Pipeline Replacement Program

·	Environmental Remediation Liabilities

·	Derivatives and Hedging Activities

·	Allowance for Uncollectible Accounts and other Contingencies

·	Pension and Other Postretirement Plans

·	Income Taxes

Each of our critical accounting policies and 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 policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006.

Accounting Developments

For information regarding accounting developments, see "Note 1 - Accounting Policies and Methods of Application."

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to risks associated with commodity prices, interest rates, credit and foreign currency exchange rates. Commodity price risk is defined as the potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity. 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 activities and related accounting treatments are described in further detail in Note 2, “Risk Management.“

Commodity Price Risk

We employ a systematic approach to evaluating and managing the risks associated with our contracts related to wholesale marketing and risk management, including Value at Risk (VaR). A 95% confidence interval is used to evaluate our exposures. A 95% confidence interval means there is a 5% probability that the actual change in portfolio value will be greater than the calculated VaR value over the holding period. We currently use a 1-day holding period to evaluate our VaR exposure, and we calculate VaR based on the variance-covariance technique. Additionally, our calculation requires us to make a number of assumptions regarding matters such as prices, volatilities, and positions. 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 are no established industry standards for calculating VaR or for the assumptions underlying such calculations.

Retail Energy Operations SouthStar’s use of derivatives is governed by a risk management policy, created and monitored by its risk management committee, which prohibits the use of derivatives for speculative purposes. A 95% confidence interval is used to evaluate its VaR. SouthStar’s portfolio of positions for the three and nine months ended September 30, 2007 and 2006, 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.

SouthStar generates operating margin from the active management of storage positions through a variety of hedging transactions and derivative instruments aimed at managing exposures arising from changing commodity prices. SouthStar uses these hedging instruments to lock in economic margins (as spreads between wholesale and retail commodity prices widen between periods) and thereby minimize its exposure to declining operating margins.

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

Energy marketing and risk management assets and liabilities The following tables include the fair values and average values of Sequent’s energy marketing and risk management assets and liabilities as of September 30, 2007, December 31, 2006 and September 30, 2006. Sequent bases the average values on monthly averages for the nine months ended September 30, 2007 and 2006.

	Average values at September 30,
In millions	2007		2006
Asset	$	61	$	88
Liability		17		49

	Fair Values at
In millions	Sept. 30, 2007		Dec. 31, 2006		Sept. 30, 2006
Asset	$	67	$	133	$	143
Liability		7		14		28

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The tables below illustrate the change in the net fair value of Sequent’s derivative instruments and energy-trading contracts during the three and nine months ended September 30, 2007 and 2006, and sources of the net fair value of contracts outstanding as of September 30, 2007.

	Three months ended
In millions	2007			2006
Net fair value of contracts outstanding at beginning of period	$	51		$	54
Contracts realized or otherwise settled during period		(17	)		(28	)
Change in net fair value of contracts		26			89
Net fair value of contracts outstanding at end of period	$	60		$	115

	Nine months ended
In millions	2007			2006
Net fair value of contracts outstanding at beginning of period	$	119		$	(13	)
Contracts realized or otherwise settled during period		(99	)		(7	)
Change in net fair value of contracts		40			135
Net fair value of contracts outstanding at end of period	$	60		$	115

The sources of Sequent’s net fair value at September 30, 2007, are as follows:

In millions	Prices actively quoted		Prices provided by other external sources
Maturity less than one year	$	24	$	29
Maturity 1-2 years		1		3
Maturity greater than three years		-		3
Total net fair value	$	25	$	35

The “Prices actively quoted” category represents Sequent’s positions in natural gas, which are valued exclusively using NYMEX futures prices. “Prices provided by other external sources” are transactions that represent the cost to transport the commodity from a NYMEX delivery point to the contract delivery point. Sequent’s basis spreads are primarily based on quotes obtained either directly from brokers or through electronic trading platforms.

Due to the significant net fair value of contracts outstanding at the beginning of the year in 2007 as compared to the prior period, the amount of contracts that were realized or otherwise settled by Sequent during the nine months ended September 30, 2007 increased by $92 million as compared to 2006. Additionally, as a result of the reduction in Sequent’s commercial activities during the nine months ended September 30, 2007, the net fair value of its contracts was $55 million less than last year.

At September 30, 2007, Sequent’s commodity-related derivative financial instruments represented purchases (long) of 638 Bcf and sales (short) of 645 Bcf, with approximately 91% and 94% scheduled to mature in less than two years and the remaining 9% and 6% in three to nine years, respectively. At September 30, 2007, the fair value of these derivatives was reflected in our condensed consolidated balance sheet as an asset of $67 million and a liability of $7 million.

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 commodity positions and the resulting VaR. Sequent continues to maintain a relatively matched book, where its total buy volume is close to sell volume. 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 nine months ended September 30, 2007 and 2006, had the following 1-day holding period VaRs.

	Three months ended September 30,				Nine months ended September 30,
In millions	2007		2006		2007		2006
Period end	$	1.0	$	1.6	$	1.0	$	1.6
Average		1.4		1.3		1.4		1.2
High		2.3		2.5		2.3		2.5
Low		0.9		0.7		0.9		0.7

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. To facilitate the achievement of desired fixed-rate to variable-rate debt ratios, AGL Capital entered into interest rate swaps whereby it agreed to exchange fixed-rate debt to floating-rate debt. The swaps exchanged, at specified intervals, the difference between fixed and variable amounts calculated by reference to agreed-on notional principal amounts. These swaps are designated to hedge the fair values of $100 million of the $300 million Senior Notes due in 2011. In August 2007, we executed a treasury-lock agreement covering a notional amount totaling $125 million to hedge the interest rate risk associated with an anticipated 2007 financing. The 10-year treasury interest rate was locked in at 4.5%.

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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 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 meet the minimum long-term debt rating threshold.

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 September 30, 2007, Sequent’s top 20 counterparties represented approximately 55% of the total counterparty exposure of $260 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures.

As of September 30, 2007, Sequent’s counterparties, or the counterparties’ guarantors, had a weighted-average S&P equivalent credit rating of A-, which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P 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. The following table shows Sequent’s commodity receivable and payable positions as of the dates indicated.

	Sept. 30,		Dec. 31,		Sept. 30,
In millions	2007		2006		2006
Gross receivables
Receivables with netting agreements in place:
Counterparty is investment grade	$	256	$	359	$	264
Counterparty is non-investment grade		13		62		17
Counterparty has no external rating		96		75		51
Receivables without netting agreements in place:
Counterparty is investment grade		-		9		11
Counterparty has no external rating		-		-		1
Amount recorded on balance sheet	$	365	$	505	$	344

Gross payables
Payables with netting agreements in place:
Counterparty is investment grade	$	231	$	297	$	197
Counterparty is non-investment grade		28		52		45
Counterparty has no external rating		124		156		119
Payables without netting agreements in place:
Counterparty is investment grade		-		5		12
Amount recorded on balance sheet	$	383	$	510	$	373

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Sequent has certain trade and credit contracts that have explicit rating trigger events in case of a downgrade in our credit rating. These rating triggers 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. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, Sequent’s ability to continue transacting business with these counterparties would be impaired. If, at September 30, 2007, 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 $13 million.

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, 2006.

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 September 30, 2007, 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 September 30, 2007, 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 controls over financial reporting. There were no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 7 - Commitments and Contingencies” contained in Item 1 of Part I under the caption “Notes to Condensed Consolidated Financial Statements (Unaudited).” With regard to other 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. There have been no significant changes in the litigation which was described in Note 8 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006. We believe the ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

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

The following table sets forth information regarding purchases of our common stock by us and any affiliated purchasers during the three months ended September 30, 2007. 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 will hold the repurchased shares as treasury shares.

Period	Total number of shares purchased (1) (2) (3)		Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (3)		Maximum number of shares that may yet be purchased under the publicly announced plans or programs (3)
July 2007		106,500	$	40.60		106,500		6,393,200
August 2007		492,000	$	37.84		492,000		5,901,200
September 2007		371,608	$	39.53		369,500		5,531,700
Total third quarter		970,108	$	38.79		968,000

(1)	The total number of shares purchased includes an aggregate of 2,108 shares surrendered to us to satisfy tax withholding obligations in connection with the vesting of shares of restricted stock and/or the exercise of stock options.

(2)

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 third quarter of 2007. As of September 30, 2007, we had purchased a total 297,234 of the 600,000 shares authorized for purchase, leaving 302,766 shares authorized for purchase under this program.

(3)

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 authorized for purchase in connection with the Officer Plan as described in note (2) above, over a five-year period.

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Item 6. Exhibits

3.1	Amended and Restated Articles of Incorporation filed November 2, 2005 with the Secretary of State of the state of Georgia (incorporated herein by reference to Exhibit 3.1, AGL Resources Inc.’s Form 8-K dated November 2, 2005).

3.2	Bylaws, as amended on October 29, 2003 (incorporated herein by reference to Exhibit 3.2 of AGL Resources Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003).

4.1	Specimen form of Common Stock certificate.

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.

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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: November 1, 2007	/s/ Andrew W. Evans
	Executive Vice President and Chief Financial Officer