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, 2008

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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” ”accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

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

Class	Outstanding as of October 22, 2008
Common Stock, $5.00 Par Value	76,780,439

Glossary of Terms

Table of Contents

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended September 30, 2008

TABLE OF CONTENTS
		Page(s)
Glossary of Key Terms & Referenced Accounting Standards		3

Item
Number
	PART 1 – FINANCIAL INFORMATION	4-38

1	Condensed Consolidated Financial Statements (Unaudited)	4-7
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Income	5
	Condensed Consolidated Statements of Common Shareholders’ Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8-19
	Note 1 - Accounting Policies and Methods of Application	8-11
	Note 2 - Financial Instruments and Risk Management	11-13
	Note 3 - Employee Benefit Plans	13-14
	Note 4 - Common Shareholders’ Equity	14
	Note 5 - Debt	15
	Note 6 - Commitments and Contingencies	16-17
	Note 7 - Segment Information	17-19
2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20-38
	Forward-Looking Statements	20
	Overview	20
	Executive Summary	20-22
	Distribution Operations	22
	Retail Energy Operations	23
	Wholesale Services	23-24
	Energy Investments	24
	Corporate	25
	Results of Operations	25-30
	Liquidity and Capital Resources	30-33
	Critical Accounting Policies and Estimates	34
	Accounting Developments	34
3	Quantitative and Qualitative Disclosures About Market Risk	34-38
4	Controls and Procedures	38

	PART II – OTHER INFORMATION	39-40

1	Legal Proceedings	39
2	Unregistered Sales of Equity Securities and Use of Proceeds	39
6	Exhibits	39

	SIGNATURE	40

Glossary of Terms

Table of Contents

GLOSSARY OF KEY TERMS

AFUDC	Allowance for funds used during construction, which has been authorized by applicable state regulatory agencies to record the cost of debt and equity funds as part of the cost of construction projects
AGL Capital	AGL Capital Corporation
AGL Networks	AGL Networks, LLC
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Chattanooga Gas	Chattanooga Gas Company
Credit Facility	Credit agreements supporting our commercial paper program
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income, other income, minority interest in SouthStar’s earnings and gain on sales of assets and excludes interest and income tax expense; as an indictor of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, operating income or net income as determined in accordance with GAAP
EITF	Emerging Issues Task Force
ERC	Environmental remediation costs associated with our distribution operations segment which are recoverable through rates mechanisms
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation Number
Fitch	Fitch Ratings
Florida Commission	Florida Public Service Commission
FSP	FASB Staff Position
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission
GNG	Georgia Natural Gas, the name under which SouthStar does business in Georgia
Golden Triangle Storage	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of the effects of weather on our businesses, calculated when the average daily actual temperatures are less than a baseline temperature of 65 degrees Fahrenheit.
Heating Season	The period from November to March when natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems when weather is colder
Jefferson Island	Jefferson Island Storage & Hub, LLC
LOCOM	Lower of weighted average cost or current market price
Maryland Commission	Maryland Public Service Commission
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
MMBtu	NYMEX equivalent contract units of 10,000 million British thermal units
Moody’s	Moody’s Investors Service
New Jersey Commission	New Jersey Board of Public Utilities
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as revenues minus cost of gas, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our statements of consolidated income. Operating margin should not be considered an alternative to, or more meaningful than operating income or net income as determined tin accordance with GAAP
OTC	Over-the-counter
Piedmont	Piedmont Natural Gas
Pivotal Utility	Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PGA	Purchased gas adjustment
PP&E	Property, plant and equipment
PRP	Pipeline replacement program for Atlanta Gas Light
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
SFAS	Statement of Financial Accounting Standards
SouthStar	SouthStar Energy Services LLC
VaR	Value at risk is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability
Virginia Natural Gas	Virginia Natural Gas, Inc.
Virginia Commission	Virginia State Corporation Commission
WACOG	Weighted average cost of gas
WNA	Weather normalization adjustment

REFERENCED ACCOUNTING STANDARDS

FSP FIN 39-1	FASB Staff Position 39-1 “Amendment of FIN 39”
FIN 46 & FIN 46R	FIN 46, “Consolidation of Variable Interest Entities”
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of SFAS Statement No. 109”
FSP EITF 03-6-1	FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”
FSP EITF 06-3	FSP EITF 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation)”
FSP FAS 133-1	FSP No. FAS 133-1, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133”
FSP FAS 157-3	FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”
SFAS 71	SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141	SFAS No. 141, “Business Combinations”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements”
SFAS 161	SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of SFAS 133”

Glossary of Terms

Table of Contents

PART 1 – 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, 2008		December 31, 2007		September 30, 2007
Current assets
Cash and cash equivalents	$	11	$	19	$	14
Energy marketing receivables		535		598		363
Inventories		811		551		654
Receivables (less allowance for uncollectible accounts of $17 at Sept. 30, 2008, $14 at Dec. 31, 2007 and $15 at Sept. 30, 2007)		189		391		143
Energy marketing and risk management assets		172		69		90
Unrecovered PRP costs – current portion		40		31		27
Unrecovered ERC – current portion		20		23		24
Other current assets		162		115		100
Total current assets		1,940		1,797		1,415
Property, plant and equipment
Property, plant and equipment		5,377		5,177		5,142
Less accumulated depreciation		1,651		1,611		1,610
Property, plant and equipment-net		3,726		3,566		3,532
Deferred debits and other assets
Goodwill		418		420		420
Unrecovered PRP costs		202		254		261
Unrecovered ERC		124		135		132
Other		94		86		71
Total deferred debits and other assets		838		895		884
Total assets	$	6,504	$	6,258	$	5,831
Current liabilities
Short-term debt	$	769	$	580	$	576
Energy marketing trade payables		568		578		383
Accounts payable - trade		181		172		131
Accrued expenses		83		87		82
Accrued PRP costs – current portion		43		55		47
Customer deposits		39		35		39
Energy marketing and risk management liabilities – current portion		34		16		9
Deferred purchased gas adjustment		14		28		15
Accrued environmental remediation liabilities – current portion		16		10		11
Other current liabilities		75		73		73
Total current liabilities		1,822		1,634		1,366
Accumulated deferred income taxes		625		566		527
Long-term liabilities and other deferred credits (excluding long-term debt)
Accumulated removal costs		176		169		168
Accrued PRP costs		152		190		204
Accrued environmental remediation liabilities		89		97		88
Accrued pension obligations		43		43		83
Accrued postretirement benefit costs		19		24		25
Other long-term liabilities and other deferred credits		150		152		158
Total long-term liabilities and other deferred credits (excluding long-term debt)		629		675		726
Commitments and contingencies (Note 6)
Minority interest		29		47		41
Capitalization
Long-term debt		1,675		1,675		1,548
Common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,724		1,661		1,623
Total capitalization		3,399		3,336		3,171
Total liabilities and capitalization	$	6,504	$	6,258	$	5,831
See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Terms

Table of Contents

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		2008			2007		2008				2007
Operating revenues	$	539		$	369		$	1,995		$	1,809
Operating expenses
Cost of gas		261			159			1,193			987
Operation and maintenance		104			107			337			334
Depreciation and amortization		38			37			112			108
Taxes other than income taxes		10			11			33			31
Total operating expenses		413			314			1,675			1,460
Operating income		126			55			320			349
Other income		2			-			6			1
Minority interest		5			-			(12	)		(24	)
Interest expense, net		(29	)		(34	)		(85	)		(92	)
Earnings before income taxes		104			21			229			234
Income tax expense		39			8			86			89
Net income	$	65		$	13		$	143		$	145
Per common share data
Basic earnings per common share	$	0.85		$	0.17		$	1.87		$	1.88
Diluted earnings per common share	$	0.85		$	0.17		$	1.87		$	1.87
Cash dividends declared per common share	$	0.42		$	0.41		$	1.26		$	1.23
Weighted-average number of common shares outstanding
Basic		76.4			77.0			76.2			77.4
Diluted		76.6			77.4			76.5			77.8

See notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Terms

Table of Contents

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY

(UNAUDITED)

											Other			Shares held
	Common stock				Premium on			Earnings			comprehensive			in treasury
In millions, except per share amount	Shares		Amount		common stock			reinvested			loss			and trust			Total
Balance as of December 31, 2007		76.4	$	390	$	667		$	680		$	(13	)	$	(63	)	$	1,661
Comprehensive income:
Net income		-		-		-			143			-			-			143
Net realized gains from hedging activities (net of tax of $-)		-		-		-			-			(1	)		-			(1	)
Total comprehensive income																		142
Dividends on common stock ($1.26 per share)		-		-		-			(96	)		-			3			(93	)
Issuance of treasury shares		0.4		-		(1	)		(4	)		-			12			7
Stock-based compensation expense (net of tax of $1)		-		-		7			-			-			-			7
Balance as of September 30, 2008		76.8	$	390	$	673		$	723		$	(14	)	$	(48	)	$	1,724

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Terms

Table of Contents

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Nine months ended
	September 30,
In millions	2008			2007
Cash flows from operating activities
Net income	$	143		$	145
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		112			108
Change in energy marketing and risk management assets and liabilities		(86	)		27
Minority interest		12			24
Deferred income taxes		66			8
Changes in certain assets and liabilities
Gas, unbilled and other receivables		202			232
Energy marketing receivables and energy marketing trade payables, net		53			15
Inventories		(260	)		(57	)
Gas and trade payables		9			(82	)
Other – net		(79	)		(34	)
Net cash flow provided by operating activities		172			386
Cash flows from investing activities
Property, plant and equipment expenditures		(254	)		(193	)
Other		-			2
Net cash flow used in investing activities		(254	)		(191	)
Cash flows from financing activities
Net payments and borrowings of short-term debt		189			49
Issuance of variable rate gas facility revenue bonds		161			-
Payments of long-term debt		(161	)		(86	)
Dividends paid on common shares		(93	)		(92	)
Distribution to minority interest		(30	)		(23	)
Issuance of treasury shares		7			13
Purchase of treasury shares		-			(57	)
Other		1			(2	)
Net cash flow provided by (used in) financing activities		74			(198	)
Net decrease in cash and cash equivalents		(8	)		(3	)
Cash and cash equivalents at beginning of period		19			17
Cash and cash equivalents at end of period	$	11		$	14
Cash paid during the period for
Interest	$	88		$	92
Income taxes	$	27		$	89

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Terms

Table of Contents

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 GAAP. We have prepared the accompanying unaudited condensed consolidated financial statements under the rules of the SEC. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. However, the condensed consolidated financial statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. For a glossary of key terms and referenced accounting standards, see page 3. 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, 2007, filed with the SEC on February 7, 2008.

Due to the seasonal nature of our business, our results of operations for the three and nine months ended September 30, 2008 and 2007, and our financial condition as of December 31, 2007, and September 30, 2008 and 2007, 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.

We currently own a noncontrolling 70% financial interest in SouthStar and 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 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.

We are the primary beneficiary of SouthStar’s activities and have determined that SouthStar is a variable interest entity as defined by FIN 46, which was 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. Earnings related to SouthStar’s 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.

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 PRP accruals, environmental liability accruals, allowance for uncollectible accounts and other contingencies, pension and postretirement obligations, derivative and hedging activities, unbilled revenues and provision for income taxes. Our actual results could differ from our estimates, and such differences could be material.

Inventories

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

Sequent and SouthStar evaluate the average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, we record adjustments to reduce the weighted average cost of the natural gas inventory to market price. SouthStar recorded LOCOM adjustments of $18 million in the three and nine months ended September 30, 2008 and did not record LOCOM adjustments in 2007. Sequent recorded LOCOM adjustments of $34 million in the three and nine months ended September 30, 2008 and $1 million and $4 million for the three and nine months ended September 30, 2007, respectively.

Glossary of Terms

Table of Contents

Stock-Based Compensation

In the first nine months of 2008, we issued grants of approximately 258,000 stock options and 207,000 restricted stock units, which will result in the recognition of approximately $2 million of stock-based compensation expense in 2008. No material share awards have been granted to employees whose compensation is subject to capitalization. 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 significant changes to our stock-based compensation, as described in Note 4 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.

Comprehensive Income

Our comprehensive income includes net income plus 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 or over funded pension and postretirement obligations. The following table illustrates our OCI activity.

	Three months ended September 30,
In millions	2008			2007
Cash flow hedges:
Net derivative unrealized gains (losses) arising during the period (net of taxes of $- in 2008 and $1 in 2007)	$	(1	)	$	2
Less reclassification of realized losses included in income (net of taxes of $- in 2008 and $1 in 2007)		1			1
Total	$	-		$	3

	Nine months ended September 30,
In millions	2008			2007
Cash flow hedges:
Net derivative unrealized gains arising during the period (net of taxes of $2 in 2008 and $1 in 2007)	$	3		$	2
Less reclassification of realized gains included in income (net of taxes of $3 in 2008 and $3 in 2007)		(4	)		(5	)
Pension adjustments (net of taxes of $- in 2007)		-			1
Total	$	(1	)	$	(2	)

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 potentially dilutive common shares are added to common shares outstanding.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The future issuance of shares underlying the restricted stock and restricted 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	2008		2007
Denominator for basic earnings per share (1)		76.4		77.0
Assumed exercise of restricted stock, restricted stock units and stock options		0.2		0.4
Denominator for diluted earnings per share		76.6		77.4
(1) Daily weighted-average shares outstanding.
	Nine months ended September 30,
In millions	2008		2007
Denominator for basic earnings per share (1)		76.2		77.4
Assumed exercise of restricted stock, restricted stock units and stock options		0.3		0.4
Denominator for diluted earnings per share		76.5		77.8
(1) Daily weighted-average shares outstanding.

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

	September 30,
In millions	2008		2007 (1)
Three months ended		2.1		0.1
Nine months ended		1.6		0.0

(1)	0.0 values represent amounts less than 0.1 million.

The increase in the number of shares that were excluded from the computation is the result of a significant decline in the market value of our common shares at September 30, 2008 as compared to September 30, 2007.

Glossary of Terms

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Income Taxes

We adopted FIN 48 on January 1, 2007, and as of September 30, 2008, December 31, 2007 or September 30, 2007, we did not have a liability for unrecognized tax benefits.

We do not collect income taxes from our customers on behalf of governmental authorities. We do collect and remit state and local taxes and record these amounts within our condensed consolidated balance sheets. Therefore, EITF No. 06-3 does not apply to us.

There have been no significant changes to our income taxes as 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, 2007.

Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our condensed consolidated balance sheets in accordance with SFAS 71. Our regulatory assets and liabilities, and associated liabilities for our unrecovered PRP costs, unrecovered ERC and the associated assets and liabilities for our Elizabethtown Gas hedging program, are summarized in the following table.

	Sept. 30		Dec. 31		Sept. 30
In millions	2008		2007		2007
Regulatory assets
Unrecovered PRP costs	$	242	$	285	$	288
Unrecovered ERC		144		158		156
Unrecovered postretirement benefit costs		11		12		12
Unrecovered seasonal rates		10		11		10
Unrecovered PGA		33		23		15
Other		31		24		24
Total regulatory assets		471		513		505
Associated assets
Elizabethtown Gas hedging program		15		4		9
Total regulatory and associated assets	$	486	$	517	$	514
Regulatory liabilities
Accumulated removal costs	$	176	$	169	$	168
Elizabethtown Gas hedging program		15		4		9
Unamortized investment tax credit		15		16		16
Deferred PGA		14		28		15
Regulatory tax liability		19		20		21
Other		21		19		18
Total regulatory liabilities		260		256		247
Associated liabilities
PRP costs		195		245		251
ERC		95		96		90
Total associated liabilities		290		341		341
Total regulatory and associated liabilities	$	550	$	597	$	588

There have been no significant changes to our regulatory assets and liabilities as described in Note 1 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.

Accounting Developments

Previously discussed

SFAS 160 In December 2007, the FASB issued SFAS 160, which is effective for fiscal years beginning after December 15, 2008. SFAS 160 will require us to present our minority interest, to be referred to as a noncontrolling interest, separately within the capitalization section of our consolidated balance sheets. We will adopt SFAS 160 on January 1, 2009.

SFAS 161 In March 2008, the FASB issued SFAS 161, which is effective for fiscal years beginning after November 15, 2008. SFAS 161 amends the disclosure requirements of SFAS 133 to provide an enhanced understanding of how and why derivative instruments are used, how they are accounted for and their effect on an entity’s financial condition, performance and cash flows. We will adopt SFAS 161 on January 1, 2009 which will require additional disclosures, but will not have a financial impact to our consolidated results of operations, cash flows or financial condition.

FSP EITF 03-6-1 The FASB issued this FSP in June 2008 and it is effective for fiscal years beginning after December 15, 2008. This FSP classifies unvested share-based payment grants containing nonforfeitable rights to dividends as participating securities that will be included in the computation of earnings per share. As of September 30, 2008, we had approximately 149,000 restricted shares with nonforfeitable dividend rights. We will adopt FSP EITF 03-6-1 on January 1, 2009.

Recently issued

FSP FAS 133-1 The FASB issued this FSP in September 2008 and it is effective for fiscal years beginning after November 15, 2008. This FSP requires more detailed disclosures about credit derivatives, including the potential adverse effects of changes in credit risk on the financial position, financial performance and cash flows of the sellers of the instruments. This FSP will have no financial impact to our consolidated results of operations, cash flows or financial condition. We will adopt FSP FAS 133-1 on January 1, 2009.

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FSP FAS 157-3 The FASB issued this FSP in October 2008 and it is effective upon issuance including prior periods for which financial statements have not been issued. This FSP clarifies the application of SFAS 157 in an inactive market, including; how internal assumptions should be considered when measuring fair value, how observable market information in a market that is not active should be considered and how the use of market quotes should be used when assessing observable and unobservable data. We adopted this FSP as of September 30, 2008, which had no financial impact to our consolidated results of operations, cash flows or financial condition.

Note 2 – Financial Instruments and Risk Management

Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting Arrangements

We maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts.

On January 1, 2008, we adopted FIN 39-1, which required that we offset cash collateral held in these broker accounts on our condensed consolidated balance sheets with the associated fair value of the instruments in the accounts. Prior to the adoption of FIN 39-1, we presented such cash collateral on a gross basis within other current assets and liabilities on our condensed consolidated balance sheets. Our cash collateral amounts are provided in the following table.

				As of
In millions	Sept. 30, 2008			Dec. 31, 2007			Sept. 30, 2007
Right to reclaim cash collateral	$	53		$	3		$	18
Obligations to return cash collateral		(1	)		(10	)		-
Total cash collateral	$	52		$	(7	)	$	18

Fair value measurements

In September 2006, the FASB issued SFAS 157, which 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. The carrying value of cash and cash equivalents, receivables, accounts payable, other current liabilities, derivative assets, derivative liabilities and accrued interest approximate fair value. The following table shows the carrying amounts and fair values of our long-term debt including any current portions included in our condensed consolidated balance sheets.

In millions	Carrying amount		Estimated fair value
As of September 30, 2008	$	1,675	$	1,671
As of December 31, 2007		1,675		1,710
As of September 30, 2007		1,548		1,556

SFAS 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In December 2007, the FASB provided a one-year deferral of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value on a recurring basis, at least annually. We adopted SFAS 157 on January 1, 2008, for our financial assets and liabilities, which primarily consist of derivatives we record in accordance with SFAS 133. The adoption of SFAS 157 primarily impacts our disclosures and did not have a material impact on our condensed consolidated results of operations, cash flows and financial condition. We will adopt SFAS 157 for our nonfinancial assets and liabilities on January 1, 2009, and are currently evaluating the impact to our condensed consolidated results of operations, cash flows and financial condition.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observance of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1

Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of financial instruments with exchange-traded derivatives.

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Level 2

Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options.

Level 3

Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. We do not have any material assets or liabilities classified as level 3.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Recurring fair value measurements as of September 30, 2008

In millions	Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Netting of cash collateral			Total carrying value
Assets: (1)
Derivatives at wholesale services	$	27	$	87	$	-	$	26		$	140
Derivatives at distribution operations		-		15		-		-			15
Derivatives at retail energy operations (3)		32		-		-		-			32
Total assets	$	59	$	102	$	-	$	26		$	187
Liabilities: (2)
Derivatives at wholesale services	$	11	$	20	$	-	$	(7	)	$	24
Derivatives at distribution operations		-		15		-		1			16
Derivatives at retail energy operations		20		1		-		(20	)		1
Total liabilities	$	31	$	36	$	-	$	(26	)	$	41

(1) Includes $172 million of current assets and $16 million of long-term assets reflected within our condensed consolidated balance sheet.

(2) Includes $34 million of current liabilities and $7 million of long-term liabilities reflected within our condensed consolidated balance sheet.

(3) $1 million premium associated with weather derivatives has been excluded as they are based on intrinsic value, not fair value.

The determination of the fair values above incorporates various factors required under SFAS 157. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities.

Derivatives at distribution operations relate to Elizabethtown Gas and are utilized in accordance with a directive from the New Jersey Commission to create a program to hedge the impact of market fluctuations in natural gas prices. These derivative products are accounted for at fair 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 or liability, as appropriate, in our condensed consolidated balance sheets.

Sequent’s and SouthStar’s derivatives include exchange-traded and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within level 1. Some exchange-traded derivatives are valued using broker or dealer quotation services, or market transactions in either the listed or OTC markets, which are classified within level 2.

At the beginning of 2008, we had a notional principal amount of $100 million of interest rate swap agreements associated with our senior notes. In March 2008, we terminated these interest rate swap agreements. We received a payment of $2 million, which included accrued interest and the fair value of the interest rate swap agreements at the termination date. The payment was recorded as deferred income and classified as a liability in our condensed consolidated balance sheets. The amount will be amortized through January 2011, the remaining life of the associated senior notes. The following table sets forth a reconciliation of the termination of our interest rate swaps, classified as level 3 in the fair value hierarchy.

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In millions	Nine months ended September 30, 2008
Balance as of January 1, 2008	$	(2	)
Realized and unrealized gains		-
Settlements		2
Transfers in or out of level 3		-
Balance as of September 30, 2008	$	-
Change in unrealized gains (losses) relating to instruments held as of September 30, 2008	$	-

Transfers in or out of level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the methodology inputs became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

Risk Management

Our risk management activities are monitored by our Risk Management Committee (RMC) which consists of members of senior management and our Finance and Risk Management Committee (FRMC) which consists of members from our Board of Directors. Both the RMC and FRMC are charged with reviewing and enforcing our risk management activities. Our risk management policies limit the use of derivative financial instruments and physical transactions within predefined 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 transactions 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

Note 3 - Employee Benefit Plans

Pension Benefits

We sponsor two tax-qualified defined benefit retirement plans for our eligible employees, the AGL Resources Inc. Retirement Plan and the Employees’ Retirement Plan of NUI Corporation. A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant. 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	2008			2007
Service cost	$	2		$	2
Interest cost		7			6
Expected return on plan assets		(9	)		(8	)
Amortization of prior service cost		-			(1	)
Recognized actuarial loss		-			2
Net pension cost	$	-		$	1

	Nine months ended September 30,
In millions	2008			2007
Service cost	$	6		$	6
Interest cost		20			18
Expected return on plan assets		(25	)		(24	)
Amortization of prior service cost		(1	)		(2	)
Recognized actuarial loss		2			5
Net pension cost	$	2		$	3

Our employees do not contribute to the 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 2008.

Postretirement Benefits The AGL Resources Inc. Postretirement Health Care Plan (AGL Postretirement Plan) covers all eligible AGL Resources employees who were employed as of September 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.

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

	Three months ended September 30,						Nine months ended September 30,
In millions	2008			2007			2008			2007
Service cost	$	-		$	-		$	1		$	-
Interest cost		1			1			4			4
Expected return on plan assets		(1	)		(1	)		(4	)		(3	)
Amortization of prior service cost		(1	)		(1	)		(3	)		(3	)
Recognized actuarial loss		-			1			-			1
Net postretirement benefit cost	$	(1	)	$	-		$	(2	)	$	(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 $5 million in matching contributions to participant accounts in the first nine months of 2008 and $5 million in the same period last year.

Note 4 - Common Shareholders’ Equity

Share Repurchase Program

In March 2001, our Board of Directors approved the purchase of up to 600,000 shares of our common stock to be used for issuances under the Officer Incentive Plan. In the first nine months of 2008, we purchased 10,333 shares under this plan. As of September 30, 2008, we had purchased a total 307,567 shares, leaving 292,433 shares available for purchase.

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. We did not purchase shares under this program during the first nine months of 2008. As of September 30, 2008, we had repurchased 3,049,049 shares at a weighted average price of $38.58.

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Note 5 - 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 FERC as granted by the Energy Policy Act of 2005. The following table provides more information on our various debt securities.

						Weighted			Outstanding as of
In millions	Year(s) due (1)		Interest rate (1)			average interest rate(2)			Sept. 30, 2008		Dec. 31, 2007			Sept.30, 2007
Short-term debt
Credit Facility	2008			3.5	%		3.5	%	$	485	$	-		$	-
Commercial paper	2008			4.6			3.5			198		566			549
SouthStar line of credit	2008			3.5			3.5			55		-			-
Sequent lines of credit	2008			2.8			2.7			20		1			13
Pivotal Utility line of credit	2008			1.6			2.9			10		12			13
Capital leases	2008			4.9			4.9			1		1			1
Total short-term debt				3.7	%		3.4	%	$	769	$	580		$	576
Long-term debt - net of current portion
Senior notes		2011-2034		4.5-7.1	%		5.9	%	$	1,275	$	1,275		$	1,150
Gas facility revenue bonds		2022-2033		4.2-8.1			3.5			200		200			200
Medium-term notes		2012-2027		6.6-9.1			7.8			196		196			196
Capital leases	2013			4.9			4.9			4		6			5
Interest rate swaps		-		-			-			-		(2	)		(3	)
Total long-term debt				6.0	%		5.8	%	$	1,675	$	1,675		$	1,548

Total debt				5.3	%		5.4	%	$	2,444	$	2,255		$	2,124

(1)	As of September 30, 2008

(2)	For the nine months ended September 30, 2008

Credit Facility

Gas Facility Revenue Bonds

In 2008, a portion of our gas facility revenue bonds failed to draw enough potential buyers due to the dislocation or disruption in the auction markets as a result of the downgrades to the bond insurers that provide credit protections for these instruments which reduced investor demand and liquidity for these types of investments. In March and April 2008, we tendered these bonds with a cumulative principal amount of $161 million through commercial paper borrowings.

In June and September 2008, we completed a Letter of Credit Agreement for these bonds which provided additional credit support which increased investor demand for the bonds. As a result, these bonds with a cumulative principal amount of $161 million were successfully auctioned and issued as variable rate gas facility bonds and reduced our commercial paper borrowings. The bonds with principal amounts of $55 million, $47 million and $39 million now have interest rates that reset daily and the bond with a principal amount of $20 million has an interest rate that resets weekly. There was no change to the maturity dates on these bonds.

SouthStar Credit Facility

SouthStar’s five-year $75 million unsecured credit facility expires in November 2011. SouthStar will use this line of credit for working capital and its general corporate needs. We do not guarantee or provide any other form of security for the repayment of this credit facility.

Sequent Lines of Credit

In June 2008, we extended one of Sequent’s lines of credit in the amount of $25 million to June 2009. This line of credit bears interest at the federal funds effective rate plus 0.75%. In September 2008, Sequent obtained a second line of credit for $20 million that bears interest at the LIBOR Rate plus 1.0% to September 2009. This line of credit replaced the line of credit that expired in August 2008. Both lines of credit are used for the posting of margin deposits for NYMEX transactions and are unconditionally guaranteed by us.

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Note 6 - Commitments and Contingencies

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. There were no significant changes to our contractual obligations described in Note 7 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our contingent financial commitments as of September 30, 2008.

	Commitments due before Dec. 31,
In millions	Total		2008		2009 & thereafter
Standby letters of credit and performance and surety bonds	$	48	$	8	$	40

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.

In March 2008, Jefferson Island served discovery requests on the State of Louisiana and sought a trial date in its pending lawsuit over its natural gas storage expansion project at Lake Peigneur. Jefferson Island also asserted additional claims against the State seeking to obtain a declaratory ruling that Jefferson Island’s surface lease, under which it operates its existing two storage caverns, authorizes the creation of the two new expansion caverns separate and apart from the mineral lease challenged by the State. Jefferson Island originally filed the suit against the State in the 19th Judicial District Court in Baton Rouge in September 2006.

In addition, in June 2008, the State of Louisiana passed legislation restricting water usage from the Chicot aquifer, which is a main source of fresh water required for the expansion of our Jefferson Island capacity. We contend that this legislation is unconstitutional and have sought to amend the pending litigation to seek a declaration that the legislation is invalid and cannot be enforced. Even if we are not successful on those grounds, we believe the legislation does not materially impact the feasibility of the expansion project.

Additional information in the Jefferson Island Storage & Hub, LLC vs. State of Louisiana litigation is 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, 2007. The ultimate resolution of such litigation cannot be determined, but it is not expected to have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

In February 2008, the consumer affairs staff of the Georgia Commission alleged that GNG charged its customers on variable rate plans prices for natural gas that were in excess of the published price, that it failed to give proper notice regarding the availability of potentially lower price plans and that it changed its methodology for computing variable rates. GNG asserted that it fully complied with all applicable rules and regulations, that it properly charged its customers on variable rate plans the rates on file with the Georgia Commission, and that, consistent with its terms and conditions of service, it routinely switched customers who requested to move to another price plan for which they qualified. In order to resolve this matter GNG agreed to pay $2.5 million in the form of credits to customers, or as directed by the Georgia Commission, which was recorded in our condensed consolidated statements of income for the nine months ended September 30, 2008.

In February 2008, a class action lawsuit was filed in the Superior Court of Fulton County in the State of Georgia against GNG containing similar allegations to those asserted by the Georgia Commission staff and seeking damages on behalf of a class of GNG customers. This lawsuit was dismissed in September 2008.

In March 2008, a second class action suit was filed against GNG in the State Court of Fulton County in the State of Georgia, regarding monthly service charges. This lawsuit alleges that GNG arbitrarily assigned customer service charges rather than basing each customer service charge on a specific credit score. GNG asserts that no violation of law or Georgia Commission rules has occurred, that this lawsuit is without merit and has filed motions to dismiss this class action suit on various grounds. The ultimate resolution of this lawsuit cannot be determined, but is not expected to have a material adverse effect on our condensed consolidated results of operations, cash flows or financial condition.

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Review of Compliance with FERC Regulations

We recently conducted an internal review of our compliance with FERC interstate natural gas pipeline capacity release rules and regulations. Independent of our internal review, we also received data requests from FERC’s Office of Enforcement relating specifically to compliance with FERC’s capacity release posting and bidding requirements. We have responded to FERC’s data requests and are fully cooperating with FERC in its investigation. As a result of this process, we have identified certain instances of possible non-compliance. We are committed to full regulatory compliance and we have met with the FERC Enforcement staff to discuss with them these instances of possible non-compliance. At this time we are unable to predict the outcome of the FERC investigation.

Note 7 - Segment Information

We are an energy services holding company whose principal business is the distribution of natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. We generate nearly all our operating revenues through the sale, distribution, transportation and storage of natural gas. We are involved in several related and complementary businesses, including retail natural gas marketing to end-use customers primarily in Georgia; natural gas asset management and related logistics activities for each of our utilities as well as for nonaffiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability natural gas storage assets. We manage these businesses through four operating segments – distribution operations, retail energy operations, wholesale services and energy investments and a nonoperating corporate segment which includes intercompany eliminations.

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

You should not consider EBIT an alternative to, or a more meaningful indicator of our operating performance than, operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The following table contains the reconciliations of EBIT to operating income, earnings before income taxes and net income for the three and nine months ended September 30, 2008 and 2007.

	Three months ended September 30,
In millions	2008			2007
Operating revenues	$	539		$	369
Operating expenses		413			314
Operating income		126			55
Minority interest		5			-
Other income		2			-
EBIT		133			55
Interest expense, net		(29	)		(34	)
Earnings before income taxes		104			21
Income tax expense		39			8
Net income	$	65		$	13

	Nine months ended September 30,
In millions	2008			2007
Operating revenues	$	1,995		$	1,809
Operating expenses		1,675			1,460
Operating income		320			349
Minority interest		(12	)		(24	)
Other income		6			1
EBIT		314			326
Interest expense, net		(85	)		(92	)
Earnings before income taxes		229			234
Income taxes		86			89
Net income	$	143		$	145

Balance sheet information at December 31, 2007, is as follows:

In millions		Identifiable and total assets (1)			Goodwill
Distribution operations	$	4,847		$	406
Retail energy operations		282			-
Wholesale services		890			-
Energy investments		287			14
Corporate and intercompany eliminations (2)		(48	)		-
Consolidated AGL Resources	$	6,258		$	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 and 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, 2008 and 2007, by segment are shown in the following tables.

Three months ended September 30, 2008

In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intercompany eliminations (3)			Consolidated AGL Resources
Operating revenues from external parties	$	237	$	149		$	138	$	13	$	2		$	539
Intercompany revenues (1)		35		-			-		-		(35	)		-
Total operating revenues		272		149			138		13		(33	)		539
Operating expenses
Cost of gas		101		154			37		3		(34	)		261
Operation and maintenance		72		15			13		6		(2	)		104
Depreciation and amortization		32		1			1		1		3			38
Taxes other than income taxes		9		-			1		-		-			10
Total operating expenses		214		170			52		10		(33	)		413
Operating income (loss)		58		(21	)		86		3		-			126
Other income		1		-			-		-		1			2
Minority interest		-		5			-		-		-			5
EBIT	$	59	$	(16	)	$	86	$	3	$	1		$	133

Capital expenditures for property, plant and equipment	$	62	$	-		$	-	$	23	$	3		$	88

Three months ended September 30, 2007

In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intercompany eliminations (3)			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

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Nine months ended September 30, 2008

In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intercompany eliminations (3)			Consolidated AGL Resources
Operating revenues from external parties	$	1,146	$	701		$	104	$	43	$	1		$	1,995
Intercompany revenues (1)		147		-			-		-		(147	)		-
Total operating revenues		1,293		701			104		43		(146	)		1,995
Operating expenses
Cost of gas		694		600			41		4		(146	)		1,193
Operation and maintenance		241		50			35		16		(5	)		337
Depreciation and amortization		94		3			4		4		7			112
Taxes other than income taxes		27		1			2		1		2			33
Total operating expenses		1,056		654			82		25		(142	)		1,675
Operating income (loss)		237		47			22		18		(4	)		320
Other income		2		-			-		-		4			6
Minority interest		-		(12	)		-		-		-			(12	)
EBIT	$	239	$	35		$	22	$	18	$	-		$	314

Identifiable and total assets (2)	$	4,992	$	271		$	1,007	$	326	$	(92	)	$	6,504
Goodwill	$	404	$	-		$	-	$	14	$	-		$	418
Capital expenditures for property, plant and equipment	$	196	$	7		$	-	$	44	$	7		$	254

Nine months ended September 30, 2007

In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments			Corporate and intercompany eliminations (3)			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)	$	4,780	$	211		$	699	$	276		$	(135	)	$	5,831
Goodwill	$	406	$	-		$	-	$	14		$	-		$	420
Capital expenditures for property, plant and equipment	$	145	$	3		$	1	$	18		$	26		$	193

(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 $289 million and $120 million for the three months ended September 30, 2008 and 2007, respectively; and $806 million and $473 million for the nine months ended September 30, 2008 and 2007, respectively.

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

(3)	Our corporate segment’s assets consist primarily of cash and cash equivalents, property, plant and equipment and reflect the effect of intercompany eliminations.

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

FORWARD-LOOKING STATEMENTS

Certain expectations and projections regarding our future performance referenced in this Management’s

Discussion and Analysis of Financial Condition and

Results of Operations section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC 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," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "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 on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, unexpected change in project costs, including the cost of funds to finance these projects; the impact of acquisitions and divestitures; direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions 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 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, 2007, among others, could cause our business, results of operations or financial condition in 2008 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. For the nine months ended September 2008, our six utilities serve 2.3 million average end-use customers, making us the largest distributor of natural gas in the southeastern and mid-Atlantic regions of the United States 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 framework for providing natural 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.

Executive Summary

Customer growth - We continue to see challenging economic conditions in all the areas we serve and, as a result, have experienced lower than expected customer growth throughout 2008, a trend we expect to continue through 2009.

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For the nine months ended September 30, 2008, our consolidated utility customer growth rate was 0.1%, compared to 1.0% for the comparable period last year. We had anticipated customer growth in 2008 of about 0.5%. The reduction in customer count is primarily a result of much slower growth in the residential housing markets throughout our service territories. This trend has been offset slightly by growth in the commercial customer segment in certain areas, primarily as a result of conversions to natural gas from other fuel sources.

We continue to use a variety of targeted marketing programs to attract new customers and to retain existing ones. These programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities.

We have seen a 3% decline in average customer count at SouthStar for the nine months ended September 30, 2008, as compared to the same period in 2007. This decline reflects some of the same economic conditions that have affected our utility businesses as well as a more competitive market for natural gas in Georgia. As a result of recent disruptions in the credit markets, one of the smaller Marketers in Georgia filed for bankruptcy in October 2008, after being unable to obtain ongoing funding for working capital needs. Another Marketer assumed responsibility for the bankrupt Marketer’s 30,000 customers, under an agreement approved by the Georgia Commission. Our financial exposure to this Marketer is immaterial.

Natural gas prices - Increased energy and transportation prices are expected to impact a significantly larger portion of consumer household incomes as we move into the 2008/2009 winter heating season. Although natural gas prices dropped during the third quarter of 2008, industry projections are that customers’ heating costs in the U.S. could increase as much as 30% over last year. As a result, we may incur additional bad debt expense during the winter season as well as lower operating margins due to increased customer conservation in an environment of high natural gas prices. While we expect these factors could adversely impact our results of operations, we expect regulatory and operational mechanisms in place in most of our jurisdictions will help mitigate our exposure to these factors.

These risks of increased bad debt expense and decreased operating margins from conservation are minimized at our largest utility, Atlanta Gas Light, as a result of its straight-fixed variable rate structure. In addition, customers in Georgia buy their natural gas from certificated marketers rather than from Atlanta Gas Light. Our credit exposure at Atlanta Gas Light is primarily related to the provision of services to the certificated marketers, but that exposure is mitigated, as we obtain security support in an amount equal to a minimum of two times a marketer’s highest month’s estimated bill. At our other utilities, while customer conservation could adversely impact our operating margins, we will utilize measures to collect delinquent accounts and continue to be rigorous in monitoring and mitigating the impact of these expenses. We do, however, expect that our bad debt expense for the upcoming winter heating season will be higher than the prior year.

We are working with regulators and state agencies in each of our jurisdictions to educate customers about these issues in advance of the winter heating season, in particular to ensure that those qualified for the Low Income Home Energy Assistance Program funds and other similar programs will receive that assistance.

SouthStar may also be affected by the conservation and bad debt trends, but its overall exposure is partially mitigated by the high credit quality of SouthStar’s customer base, disciplined collection practices and the unregulated pricing structure in Georgia.

The rising commodity prices during the first six month of 2008, along with reduced opportunities related to the management of storage and transportation assets throughout the first nine months of 2008 further negatively impacted SouthStar’s operating margin by $15 million. More favorable market conditions and decreasing natural gas prices in the first six months of 2007 as compared to rising prices during the same time frame in 2008 enabled SouthStar to recognize higher operating margins for year-to-date September 30, 2007 as compared to 2008. SouthStar’s reported results were also negatively impacted during the current year quarter by the significant decrease in natural gas prices during the three months ended September 30, 2008 as SouthStar was required to record an $18 million LOCOM adjustment to reduce its natural gas inventory to market.

Due to the rising commodity price environment and the widening of transportation basis spreads during the first six months of 2008, Sequent recorded $70 million in losses on the financial instruments it uses to hedge its storage and transportation positions. The natural gas market remained volatile with significant decreases in prices and narrowing of basis spreads during the quarter ended September 30, 2008. Consequently Sequent recognized gains on hedging instruments of $117 million for the quarter and $47 million for the first nine months of 2008. This is a $106 million and $30 million net increase compared to last year’s third quarter and year-to-date periods, respectively. In addition to the increase in hedge gains Sequent’s commercial activity improved by $16 million and $19 million for the quarter ended and year-to-date periods ended September 30, 2008, respectively due to more favorable business opportunities presented by the greater volatility in the marketplace than in 2007. This improvement was due in part to increased hurricane activity, although the market did not react as strongly as it did after hurricanes Rita and Katrina in 2005 as there was less damage to the natural gas infrastructure and increased onshore production.

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In addition, the decrease in forward prices caused Sequent to be subject to a LOCOM adjustment on its natural gas inventory. The increase in the impact of the adjustment, net of estimated hedging recoveries, was $33 million and $32 million for the quarter and year-to-date periods, respectively. These changes resulted in Sequent reporting operating margin that was $89 million and $17 million higher for the current quarter and year-to-date periods ended September 30, 2008, respectively, as compared to last year.

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 in Georgia

·	Chattanooga Gas in Tennessee

·	Elizabethtown Gas in New Jersey

·	Elkton Gas in Maryland

·	Florida City Gas in Florida

·	Virginia Natural Gas in Virginia

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.

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.

With the exception of Atlanta Gas Light and Elkton Gas, 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. In May 2008, new rates became effective for Elkton Gas which included mechanisms that returned operating margin per customer to levels approved by the Maryland Commission in its most recent rate decision.

Our other 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 respective tariffs contain WNA or similar 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.

Upcoming rate cases Beginning in 2009 through 2010, we will file rate cases in four of our six jurisdictions. These rate case filings are required due to settlements we reached with the applicable state authority in previous rate case or acquisition proceedings. The expected filing dates and dates for which current rates are effective are outlined in the chart below:

Company	Expected filing date	Current rates effective until
Elizabethtown Gas	Q1 2009	Q4 2009 - Q1 2010
Atlanta Gas Light	Q4 2009	Q2 2010
Virginia Natural Gas	Q1 2010	Q3 2011
Chattanooga Gas	Q2 2010	Q1 2011

Virginia Natural Gas In July 2008, Virginia Natural Gas filed a Conservation and Ratemaking Efficiency Plan (Conservation Plan) with the Virginia Commission. The plan was filed pursuant to a Virginia law that allows natural gas utilities to implement conservation programs and alternative rate designs which would allow the utility to recover the cost of providing safe and reliable service based on normal customer usage. On Octoer 29, 2008, Virginia Natural Gas filed with the Virginia Commission a motion for approval of a proposed stipulation. If the proposed stipulation is approved by the Virginia Commission, Virginia Natural Gas will invest approximately $7 million over three years in new conservation programs. Virginia Natural Gas will also implement an accompanying decoupled rate design mechanism that will mitigate the impact of conservation and declining usage and provide the utility with an opportunity to recover its fixed costs. Hearings on the Conservation Plan and proposed stipulation were held in October 2008, and the Virginia Commission is expected to issue a ruling by the end of 2008.

Magnolia Enterprise Holdings, Inc. (Magnolia) In September 2007, we received approval from the Georgia Commission for Atlanta Gas Light’s capacity supply plan in Georgia. A key part of that agreement was the ability to diversify our supply sources by gaining more access to the Elba Island liquefied natural gas (LNG) facility. As a result, Southern Natural Gas (SNG) and our affiliate, Magnolia filed a joint application with the FERC to obtain an undivided interest in pipelines connecting our Georgia service territory to the Elba Island LNG facility and for approval of the project. Under the proposed transaction, Magnolia would purchase the undivided interest and lease the interest to SNG. Atlanta Gas Light would then subscribe to the associated capacity from SNG. The project is expected to be completed in 2010.

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Retail Energy Operations - Our retail energy operations segment consists of SouthStar, a joint venture owned 70% by us and 30% by 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, based on customer count.

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, 2008, were at the 75% contractual rate.

Beginning in October 2008, SouthStar was awarded the right to supply a total of approximately 15 Bcf of natural gas to customers of Vectren Energy Delivery of Ohio (VEDO) through March 2010. As part of this agreement, SouthStar will manage the supply, transportation and storage of natural gas on behalf of VEDO.

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.

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

Sequent’s profitability is driven by volatility in the natural gas marketplace. Volatility arises from a number of factors such as weather fluctuations or the change in supply of, or demand for, natural gas in different regions of the 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 in the U.S. and Canada. Sequent acquires transportation and storage capacity to meet its delivery requirements and customer obligations in the marketplace. Sequent’s

customers benefit from its logistics expertise and ability to deliver natural gas at prices that are advantageous relative to other alternatives available to its customers.

During the third quarter of 2008, Sequent negotiated an agreement for 40,000 dekatherms per day of transportation capacity for a period of 25 years beginning in August 2009. Upon execution of this agreement in 2009, we will include approximately $89 million of future demand payments associated with this capacity within our unrecorded contractual obligations and commitment disclosures. Sequent will identify opportunities to lock-in economic value associated with this capacity through the use of financial hedges. The hedging of the capacity may increase our exposure to hedge gains and losses as well as potentially impact VaR. There was no significant impact to hedge gains or losses or VaR during the period.

Asset management transactions The following table provides updated information on Sequent’s asset management agreements with its affiliated utilities, including amended or extended agreements in 2008 with Florida City Gas, Chattanooga Gas and Elizabethtown Gas.

		% of shared
	Expiration date	profits or annual fee
Virginia Natural Gas	Mar 2009	(A)
Chattanooga Gas	Mar 2011		50% (B)
Elizabethtown Gas	Mar 2011	(A) (B)
Atlanta Gas Light	Mar 2012	up to 60%		(B)
Florida City Gas	Mar 2013		50%

(A)	Shared on a tiered structure.

(B)	Includes aggregate annual minimum payments of $12 million for Chattanooga Gas, Elizabethtown Gas and Atlanta Gas Light.

Storage inventory outlook The following graph presents the NYMEX forward natural gas prices as of September 30, 2008, June 30, 2008 and December 31, 2007, for the period of October 2008 through September 2009, and reflects the prices at which Sequent could buy natural gas at the Henry Hub for delivery in the same time period.

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Sequent’s expected natural gas withdrawals from physical salt dome and reservoir storage are presented in the following table along with the operating revenues expected at the time of withdrawal. Sequent’s expected operating revenues are net of the estimated impact of regulatory sharing and reflect the amounts that are realizable in future periods based on the inventory withdrawal schedule and forward natural gas prices at September 30, 2008. Sequent’s storage inventory is economically hedged with futures contracts, which results in an overall locked-in margin, timing notwithstanding.

	Withdrawal schedule (in Bcf)
	Salt dome (WACOG $6.82)		Reservoir (WACOG $6.84)		Expected operating revenues (in millions)
2008
Fourth quarter		2		9	$	7
2009
First quarter		-		5		5
Total		2		14	$	12

If Sequent’s optimization efforts are executed as planned, it expects operating revenues from storage withdrawals of approximately $7 million during the three months ending December 31, 2008 and $5 million in 2009. This could change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate. Based upon Sequent’s current projection of year-end storage positions at December 31, 2008, a $1.00 increase in the first quarter 2009 forward NYMEX prices could result in a $4 million reduction to Sequent’s reported operating revenues for the year ending December 31, 2008, after regulatory sharing. A $1.00 decrease in forward NYMEX prices would result in a $4 million positive impact to Sequent’s reported operating revenues; however additional LOCOM adjustments could potentially offset a portion of the positive impact. This amount does not include operating expenses that will be incurred to realize this amount. 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, which operates a high-deliverability salt-dome storage asset in the Gulf Coast region of the U.S. 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 are actively pursuing litigation against the State of Louisiana to obtain a court order or settlement confirming Jefferson Island’s right to expand its existing facility. Jefferson Island’s litigation with the State of Louisiana is described in further detail in Note 6, “Commitments and Contingencies.” In June 2008, the State of Louisiana passed legislation restricting water usage from the Chicot aquifer, which is a main source of fresh water required for the expansion of the Jefferson Island capacity. We contend that this legislation is unconstitutional and have sought to amend the pending litigation to seek a declaration that it is invalid and cannot be enforced. Even if we are not successful on those grounds, we believe the legislation does not materially impact the feasibility of the expansion project.

Through Golden Triangle Storage, we are constructing a new salt-dome storage facility in the Gulf Coast region of the U.S. In May 2008, Golden Triangle Storage started construction on the first cavern. Hurricanes Gustav and Ike caused some damage and minor delays in September 2008, but our timelines associated with commencement of commercial operations remain on schedule. We previously estimated based on then current prices for labor, materials and pad gas that costs to construct the facility would be approximately $265 million. However, prices for labor, materials and pad gas have risen significantly in the ensuing months, increasing the estimated construction cost by approximately 10% to 20%. The actual project costs depend upon the facility’s configuration, materials, drilling costs, financing costs and 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. The costs for the vast majority of these items have not been fixed and are subject to continued variability during the period of construction. Further, since we are not able to predict whether these costs of construction will continue to increase, moderate or decrease from current levels, we believe that there could be continued volatility in the construction cost estimates.

We also own and operate a telecommunications business, AGL Networks, which constructs and operates conduit and fiber infrastructure within select metropolitan areas.

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

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

Results of Operations

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

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.

You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than net income as determined in accordance with GAAP. In addition, our operating margin or EBIT measures may not be comparable to similarly titled measures from other companies.

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 sheets as of September 30, 2007, to provide comparisons of these items to December 31, 2007, and September 30, 2008.

Hedging Changes in commodity prices subject a significant portion of our operations to earnings variability. Our nonutility businesses principally use physical and financial arrangements economically to 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 accounted for at fair 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 or liability, 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, earnings before income taxes and net income, together with other consolidated financial information for the three and nine months ended September 30, 2008 and 2007.

	Three months ended September 30,							Nine months ended September 30,
In millions, except per share data	2008		2007		Change				2008			2007			Change
Operating revenues	$	539	$	369	$	170			$	1,995		$	1,809		$	186
Cost of gas		261		159		102				1,193			987			206
Operating margin (1)		278		210		68				802			822			(20	)
Operating expenses		152		155		(3	)			482			473			9
Operating income		126		55		71				320			349			(29	)
Other income		2		-		2				6			1			5
Minority interest		5		-		5				(12	)		(24	)		12
EBIT (1)		133		55		78				314			326			(12	)
Interest expense, net		29		34		(5	)			85			92			(7	)
Earnings before income taxes		104		21		83				229			234			(5	)
Income tax expense		39		8		31				86			89			(3	)
Net income	$	65	$	13	$	52			$	143		$	145		$	(2	)

Earnings per common share
Basic	$	0.85	$	0.17	$	0.68			$	1.87		$	1.88		$	(0.01	)
Diluted	$	0.85	$	0.17	$	0.68			$	1.87		$	1.87		$	-
Weighted-average number of common shares outstanding
Basic		76.4		77.0		(0.6	)			76.2			77.4			(1.2	)
Diluted		76.6		77.4		(0.8	)			76.5			77.8			(1.3	)

(1)	These are non-GAAP measurements.

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Selected weather, customer and volume metrics, which we consider to be some of the key performance indicators for our operating segments, for the three and nine months ended September 30, 2008 and 2007, are presented in the following tables. We measure the effects of weather on our business through heating degree days. Generally, increased heating degree days result in greater demand for gas on our distribution systems. However, extended and unusually mild weather during the heating season can have a significant negative impact on demand for natural gas. Our marketing and customer retention initiatives are measured by our customer metrics which can be impacted by natural gas prices, economic conditions and competition from alternative fuels. Volume metrics for distribution operations and retail energy operations present the effects of weather and our customer’s demand for natural gas. Wholesale services’ daily physical sales represent the daily average natural gas volumes sold to its customers.

Weather
Heating degree days (1)
	Nine months ended September 30,						2008 vs. normal colder			2008 vs. 2007 colder
	Normal		2008		2007		(warmer)			(warmer)
Florida		336		215		281		(36	)%		(23	)%
Georgia		1,587		1,654		1,489		4	%		11	%
Maryland		3,032		2,828		3,063		(7	)%		(8	)%
New Jersey		3,031		2,918		3,172		(4	)%		(8	)%
Tennessee		1,807		1,888		1,753		4	%		8	%
Virginia		2,052		1,880		2,090		(8	)%		(10	)%

(1) Obtained from weather stations relevant to our service areas at the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages from October 1999 through September 2008.

	Three months ended									Nine months ended
Customers	September 30,									September 30,
		2008			2007		% Change				2008			2007		% Change
Distribution Operations
Average end-use customers (in thousands)
Atlanta Gas Light		1,536			1,539			(0.2	)%		1,564			1,564			-
Chattanooga Gas		60			60			-			61			61			-
Elizabethtown Gas		272			271			0.4	%		273			272			0.4	%
Elkton Gas		6			6			-			6			6			-
Florida City Gas		103			104			(1.0	)%		104			104			-
Virginia Natural Gas		268			265			1.1.	%		271			269			0.7	%
Total		2,245			2,245			-			2,279			2,276			0.1	%
Operation and maintenance per customer	$	32		$	35			(9	)%	$	106		$	110			(4	)%
EBIT per customer	$	26		$	24			8	%	$	105		$	106			(1	)%

Retail Energy Operations
Average customers in Georgia (in thousands)		518			535			(3	)%		529			543			(3	)%
Market share in Georgia		34	%		35	%		(1	)%		35	%		35	%		-

Volumes	Three months ended September 30,							Nine months ended September 30,
In billion cubic feet (Bcf)	2008		2007		% change			2008		2007		% change
Distribution Operations
Firm		20.0		20.1		(1	)%		146.8		148.9		(1	)%
Interruptible		24.1		25.1		(4	)%		78.1		80.9		(3	)%
Total		44.1		45.2		(2	)%		224.9		229.8		(2	)%

Retail Energy Operations
Georgia firm		3.5		3.5		-			27.0		27.1		-
Ohio and Florida		0.3		0.3		-			3.3		3.1		6	%

Wholesale Services
Daily physical sales (Bcf/day)		2.6		2.3		13	%		2.5		2.3		9	%

Glossary of Terms

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Third quarter 2008 compared to third quarter 2007

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, 2008 and 2007.

In millions	Operating revenues			Operating margin (1)			Operating expenses		EBIT(1)
2008
Distribution operations	$	272		$	171		$	113	$	59
Retail energy operations		149			(5	)		16		(16	)
Wholesale services		138			101			15		86
Energy investments		13			10			7		3
Corporate (2)		(33	)		1			1		1
Consolidated	$	539		$	278		$	152	$	133

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

(1)	These are non-GAAP measures. A reconciliation of operating margin and EBIT to our operating income, (loss) earnings before income taxes and net income is located in “Results of Operations” herein.

(2)	Includes intercompany eliminations.

For the third quarter of 2008, net income increased by $52 million and earnings per share increased by $0.68 per basic and diluted share compared to same period last year. The variance between the two quarters was primarily the result of the effects of changes in forward natural gas prices on the operating margins at retail energy operations and wholesale services as discussed in more detail below.

Operating margin Our operating margin for the third quarter of 2008 increased by $68 million or 32% compared to the same period last year. This increase was primarily due to increased operating margins at wholesale services and energy investments partially offset by decreased operating margins at distribution operations and retail energy operations.

Distribution operations’ operating margin decreased by $2 million or 1% compared to last year. The following table indicates the significant changes in distribution operations’ operating margin for the three months ended September 30, 2008 compared to 2007.

In millions
Operating margin for third quarter of 2007	$	173
Reduced customer growth and usage		(3	)
Higher PRP revenues at Atlanta Gas Light		2
Other		(1	)
Operating margin for third quarter of 2008	$	171

Retail energy operations’ operating margin decreased by $21 million or 131%. The following table indicates the significant changes in retail energy operations’ operating margin for the three months ended September 30, 2008 compared to 2007.

In millions
Operating margin for third quarter of 2007	$	16
Inventory LOCOM		(18	)
Decrease in average number of customers and other		(2	)
Lower operating margins in Ohio		(1	)
Operating margin for third quarter of 2008	$	(5	)

Wholesale services’ operating margin increased $89 million compared to the third quarter of 2007 primarily due to gains on the instruments used to hedge its storage and transportation positions as a result of a significant decrease in forward NYMEX natural gas prices and the narrowing of transportation basis spreads in the current period compared to moderate price declines experienced in 2007. These gains were partially offset by a larger required LOCOM adjustment in the current period. The following table indicates the significant changes in wholesale services’ operating margin for the three months ended September 30, 2008 and 2007.

In millions	2008			2007
Gain on storage hedges	$	105		$	12
Commercial activity		18			2
Gain (loss) on transportation hedges		12			(1	)
Inventory LOCOM, net of hedging recoveries		(34	)		(1	)
Operating margin	$	101		$	12

For more information on Sequent’s expected operating revenues from its storage inventory in the remainder of 2008 and in 2009 and discussion of the increased commercial activity as compared to last year, see the description of wholesale services’ business in this section beginning on page 21.

Operating Expenses Our operating expenses for the third quarter of 2008 decreased $3 million or 2% as compared to the third quarter of 2007. The following table indicates the significant changes in our operating expenses.

In millions
Operating expenses for third quarter of 2007	$	155
Increased bad debt expenses at distribution operations due to higher natural gas prices		3
Decreased pension expenses at distribution operations, primarily due to updated actuarial expense estimates		(4	)
Decreased incentive compensation program expenses at distribution operations		(3	)
Increased incentive compensation costs at wholesale services due to increased earnings		3
Decreased operating costs at retail energy operations due to slightly lower outside services and marketing costs		(2	)
Operating expenses for third quarter of 2008	$	152

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Interest Expense Interest expense decreased by $5 million or 15% for the three months ended September 30, 2008, primarily due to the decrease in short-term interest rates partially offset by higher average debt outstanding as indicated in the following table.

	Three months ended September 30,
In millions	2008			2007			Change
Average debt outstanding (1)	$	2,225		$	1,997		$	228
Average rate		5.2	%		6.2	%		(1.0	)%

(1) Daily average of all outstanding debt.

Nine months 2008 compared to nine months 2007

Segment information Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the nine months ended September 30, 2008 and 2007.

In millions	Operating revenues			Operating margin (1)		Operating expenses		EBIT(1)
2008
Distribution operations	$	1,293		$	599	$	362	$	239
Retail energy operations		701			101		54		35
Wholesale services		104			63		41		22
Energy investments		43			39		21		18
Corporate (2)		(146	)		-		4		-
Consolidated	$	1,995		$	802	$	482	$	314

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

(1) These are non-GAAP measures. A reconciliation of operating margin and EBIT to our operating income, earnings before income taxes and net income is located in “Results of Operations” herein.

(2) Includes intercompany eliminations.

For the nine months ended September 30, 2008, net income decreased by $2 million and basic earnings per share was down $0.01 compared to the same period last year. This variance was primarily the result of changes in forward natural gas prices on the operating margins at retail energy operations and wholesale services and reduced natural gas usage at distribution operations and retail energy operations as discussed in more detail below.

Operating margin Our operating margin for the nine months ended September 30, 2008, decreased by $20 million or 2% compared to the same period last year. This decrease was primarily due to decreased operating margins at retail energy operations and distribution operations partially offset by increased operating margins at wholesale services and energy investments.

Distribution operations’ operating margin decreased by $5 million or 1% compared to the same period last year. The following table indicates the significant changes in distribution operations’ operating margin for the nine months ended September 30, 2008 compared to 2007.

In millions
Operating margin for the first nine months of 2007	$	604
Customer growth and lower natural gas usage		(4	)
Revision in estimated unbilled natural gas volumes at Elizabethtown Gas		(3	)
Lower natural gas storage carrying costs at Atlanta Gas Light		(2	)
Higher PRP revenues at Atlanta Gas Light		4
Operating margin for the first nine months of 2008	$	599

Retail energy operations’ operating margin decreased by $44 million or 30%. The following table indicates the significant changes in retail energy operations’ operating margin for the nine months ended September 30, 2008 compared to 2007.

In millions
Operating margin for the first nine months of 2007	$	145
Lower contributions from the management of storage and transportation assets largely due to rising commodity prices in 2008		(15	)
Inventory LOCOM adjustment		(18	)
Retail pricing settlement with Georgia Commission		(3	)
Colder weather		5
Lower number of customers and usage		(3	)
Ohio and Florida margins		(2	)
Loss on weather derivatives		(7	)
Other		(1	)
Operating margin for the first nine months of 2008	$	101

Wholesale services’ operating margin increased $17 million or 37% compared to the first nine months of 2007 primarily due to stronger commercial activity and gains on the instruments used to hedge its storage positions resulting from falling natural gas prices. These gains were partially offset by a $34 million LOCOM adjustment in the current period as compared to a $2 million LOCOM adjustment (net of hedging recoveries) last year. The following table indicates the significant changes in wholesale services’ operating margin for the nine months ended September 30, 2008 and 2007.

In millions	2008			2007
Commercial activity	$	50		$	31
Gain on storage hedges		46			15
Gain on transportation hedges		1			2
Inventory LOCOM, net of hedging recoveries		(34	)		(2	)
Operating margin	$	63		$	46

The increase of $30 million in gains associated with storage and transportation hedge positions was primarily due to larger decreases in forward NYMEX prices during the current period compared to those experienced in 2007. For more information on Sequent’s expected operating revenues from its storage inventory in the remainder of 2008 and in 2009 and discussion of the increased commercial activity as compared to last year, see the description of wholesale services’ business in this section beginning on page 21.

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Energy investments’ operating margin increased $12 million or 44% primarily due to higher operating margins at AGL Networks of $10 million due to a network expansion project and $2 million at Jefferson Island as a result of increased interruptible operating margins.

Operating Expenses Our operating expenses for the nine months ended September 30, 2008, increased $9 million or 2% as compared to the same period of 2007. The following table indicates the significant changes in our operating expenses.

In millions
Operating expenses for the first nine months of 2007	$	473
Increased operating costs at wholesale services due to continued commercial expansion and incentive compensation costs associated with earnings		11
Increased depreciation expenses at distribution operations due to PP&E placed into service		5
Increased bad debt expenses primarily at Elizabethtown Gas and Virginia Natural Gas in distribution operations due to higher natural gas prices and decline in the economy		5
Increased bad debt expenses at retail energy operations due to higher natural gas prices		2
Increased operating costs due to AGL Networks expansion project		2
Decreased operating costs at retail energy operations due to lower compensation, marketing, outside services and other costs		(3	)
Decreased operating costs at distribution operations due to lower costs related to benefits and incentives, marketing, customer service and outside services offset by higher fuel costs and property taxes		(8	)
Decreased pension expenses at distribution operations primarily due to updated actuarial expense estimate		(4	)
Lower corporate costs		(1	)
Operating expenses for the first nine months of 2008	$	482

Interest Expense The decrease in interest expense of $7 million or 8% for the nine months ended September 30, 2008, was primarily due to the decrease in short-term interest rates partially offset by higher average debt outstanding as indicated in the following table.

	Nine months ended September 30,
In millions	2008			2007			Change
Average debt outstanding (1)	$	2,046		$	1,899		$	147
Average rate		5.5	%		6.2	%		(0.7	)%

(1) Daily average of all outstanding debt.

Liquidity and Capital Resources

Our primary sources of liquidity are cash provided by operating activities, short term borrowings under our commercial paper program (which is supported by our Credit Facilities) and borrowings under lines of credit. Additionally from time to time, we raise funds from the public debt and equity capital markets through our existing shelf registration statement to fund our liquidity and capital resource needs. We believe these sources will continue to allow us to meet our needs for working capital, construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments, common share repurchases and other cash needs.

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 and the SEC. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies and other factors. See Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2007, for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities.

	Nine months ended Sept. 30,
In millions	2008			2007
Net cash provided by (used in):
Operating activities	$	172		$	386
Investing activities		(254	)		(191	)
Financing activities		74			(198	)
Net decrease in cash and cash equivalents	$	(8	)	$	(3	)

Cash Flow from Operating Activities In the first nine months of 2008, our net cash flow provided from operating activities was $172 million, a decrease of $214 million or 55% from the same period in 2007. This was primarily a result of increased working capital requirements, principally driven by rising natural gas prices during the first half of 2008. In addition, as a result of the increase in natural gas prices, our margin requirements for our energy marketing and risk management activities were higher than in the prior year which included approximately $114 million of cash received upon settlement of derivative positions versus $58 million in the current period.

Cash Flow from Investing Activities Our investing activities consisted of PP&E expenditures of $254 million for the nine months ended September 30, 2008 and $193 million for the same period in 2007. The increase of $61 million or 32% in PP&E expenditures was primarily due to a $51 million increase at distribution operations, which included higher spending for the pipeline replacement program and expenditures for Virginia Natural Gas’ Hampton Roads pipeline project connecting its northern and southern systems.

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Additionally, our retail energy operations’ PP&E expenditures increased $4 million as a result of its purchase of information technology assets in support of its transition to a new customer care and call center vendor. Our energy investments’ PP&E expenditures increased $26 million primarily from increased expenditures at Golden Triangle Storage as we began construction on our planned natural gas storage facility and from increased telecommunication expenditures at AGL Networks on its Phoenix network expansion. These PP&E expenditure increases were partially offset by decreased expenditures at our corporate segment of $19 million primarily due to decreased spending primarily on information technology.

Cash Flow from Financing Activities Our financing activities are primarily composed of borrowings and payments of short-term debt, payments of medium-term notes, 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 20% to 45% of total debt), as well as the term and interest rate profile of our debt securities. As of September 30, 2008, our variable-rate debt was 38% of our total debt, compared to 39% as of September 30, 2007.

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 following table summarizes our credit ratings as of September 30, 2008, and reflects no change from December 31, 2007.

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

A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s is Baa3 and Fitch is BBB-. 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%. Our ratio of total debt to total capitalization calculation contained in our debt covenant includes minority interest, standby letters of credit, surety bonds and the exclusion of other comprehensive income pension adjustments. If these items were included, our debt-to-equity calculation would increase by 1-2%. Our debt and equity capitalization ratios, as of the dates indicated, are summarized in the following table.

	Sept. 30, 2008			Dec. 31, 2007			Sept. 30, 2007
Short-term debt		19	%		15	%		15	%
Long-term debt		40			43			42
Total debt		59			58			57
Common shareholders’ equity		41			42			43
Total capitalization		100	%		100	%		100	%

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. We currently comply with all existing debt provisions and covenants. For more information on our debt, see Note 5 “Debt.”

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Short-term debt Our short-term debt is composed of borrowings under our commercial paper program, Credit Facilities, lines of credit at Sequent, SouthStar and Pivotal Utility, and the current portion of our capital leases. In June 2008, we extended one of Sequent’s lines of credit to June 2009. In September 2008, Sequent obtained a second line of credit for $20 million that bears interest at the LIBOR Rate plus 1.0% to September 2009. This line of credit replaced the line of credit that expired in August 2008. Both lines of credit are used for the posting of margin deposits for NYMEX transactions and are unconditionally guaranteed by us.

In September 2008, we completed a $140 million Credit Facility that expires in September 2009, which will provide additional liquidity for working capital and capital expenditure needs. This $140 million Credit Facility allows for the option to request an increase in the borrowing capacity to $150 million and supplements our existing $1.0 billion Credit Facility which expires in August 2011. More information on our short-term debt as of September 30, 2008, which we consider one of our primary sources of liquidity, is presented in the following table:

In millions	Capacity		Outstanding
Credit Facilities (1)	$	1,140	$	683
SouthStar line of credit		75		55
Sequent lines of credit		45		20
Pivotal Utility line of credit		20		10
Total	$	1,280	$	768

(1)	Supported by our $1.0 billion and $140 million Credit Facilities, and includes $198 million of commercial paper borrowings.

Our short-term debt financing generally increases between June and December because our payments for natural gas and pipeline capacity are generally made to suppliers prior to the collection of accounts receivable from our customers. We typically reduce short-term debt balances in the spring because a significant portion of our current assets are converted into cash at the end of the heating season. As of September 30, 2008, our outstanding short-term borrowings increased by $193 million or 34% as compared to the same time last year, primarily a result of increased working capital requirements, primarily for the higher cost of natural gas inventories and increased PP&E expenditures of $61 million.

As of September 30, 2008 we had $485 million outstanding under our $1.0 billion Credit Facility. In the third quarter 2008 due to disruption in the credit markets, we were unable to issue commercial paper at acceptable interest rates and relied upon our Credit Facility for our liquidity and capital resource needs. We expect to repay the amounts outstanding under our Credit Facility with commercial paper borrowings. As of September 30, 2007 and December 31, 2007, we had no outstanding borrowings under the Credit Facility. Our exposure to financial institutions that experienced difficulty during the disruption in the credit markets was limited.

The availability of borrowings and unused availability under our Credit Facilities is limited and subject to conditions specified within the Credit Facilities, which we currently meet. These conditions include:

·	the maintenance of 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%. As of September 30, 2008, our ratio of total debt of 59% 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 balance sheet date and consists of medium-term notes, senior notes, gas facility revenue bonds, and capital leases.

In 2008, a portion of our gas facility revenue bonds failed to draw enough potential buyers due to the dislocation or disruption in the auction markets as a result of the downgrades to the bond insurers which reduced investor demand and liquidity for these types of investments. Three of these bonds with principal amounts of $55 million, $47 million and $20 million had interest rates that were adjusted every 35-days, and one of the bonds with a principal amount of $39 million had an interest rate which was reset daily. In March and April 2008, we tendered these bonds with a cumulative principal amount of $161 million through commercial paper borrowings.

In June and September 2008, we completed Letter of Credit Agreements for these bonds which provided credit support and enhanced investor demand. As a result, these bonds were successfully issued as variable rate gas facility revenue bonds and reduced our commercial paper borrowings. The bonds with principal amounts of $55 million, $47 million and $39 million now have interest rates that reset daily and the bond with a principal amount of $20 million has an interest rate that resets weekly. There was no change to the maturity dates on these bonds. Currently, these bonds have potential buyers; however, should these bonds fail to draw buyers, we would be required to either draw on the Letter of Credit Agreements or tender these bonds with commercial paper. For more information on the maturity of the gas facility revenue bonds see Note 6 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.

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, 2008, we did not purchase any shares of our common stock under this plan. During the same period in 2007, we purchased approximately 1.4 million shares of our common stock at a weighted average cost of $39.82 per share and an aggregate cost of $57 million. We hold the purchased shares as treasury shares.

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Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities. 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. 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.

In recent months, declines in the investment markets have negatively impacted our pension plan assets. In order to comply with the funding requirements from the Pension Protection Act of 2006, we anticipate that we will be required to make a contribution to our pension plan in 2009. The decline in investment values could also result in a charge to other comprehensive income for the increased difference between investment values and the pension liabilities at our next measurement date of December 31, 2008, as well as an increase in the amount of pension expense we would recognize in 2009 and beyond. We are currently unable to determine these amounts since actual asset performance through the end of the year and the discount rate at year-end can significantly impact the determination of these amounts. The following tables illustrate our expected future contractual obligations and commitments as of September 30, 2008.

					2009 &		2011 &		2013 &
In millions	Total		2008		2010		2012		thereafter
Recorded contractual obligations:
Long-term debt	$	1,675	$	1	$	3	$	315	$	1,356
Short-term debt		769		769		-		-		-
PRP costs (1)		195		7		102		63		23
Environmental remediation liabilities (1)		105		3		34		39		29
Total	$	2,744	$	780	$	139	$	417	$	1,408

(1)	Includes charges recoverable through rate rider mechanisms.

					2009 &		2011 &		2013 &
In millions	Total		2008		2010		2012		thereafter
Unrecorded contractual obligations and commitments (1):
Pipeline charges, storage capacity and gas supply (2)	$	1,751	$	164	$	736	$	402	$	449
Interest charges (3)		1,135		26		204		161		744
Operating leases		136		7		50		34		45
Standby letters of credit, performance / surety bonds		48		8		40		-		-
Asset management agreements (4)		43		3		24		16		-
Total	$	3,113	$	208	$	1,054	$	613	$	1,238

(1)	In accordance with generally accepted accounting principles, these items are not reflected in our condensed consolidated balance sheet.

(2)

Charges recoverable through a PGA mechanism or alternatively billed to Marketers. Also includes SouthStar’s gas commodity purchase commitments of 11.6 Bcf at floating gas prices calculated using forward natural gas prices as of September 30, 2008, and valued at $90 million. Additionally, includes amounts associated with a subsidiary of NUI which entered into two long-term agreements for the firm transportation and storage of natural gas during 2003 with annual aggregate demand charges of approximately $5 million. As a result of our acquisition of NUI and in accordance with SFAS 141, we valued the contracts at fair value and established a long-term liability of $38 million for the excess liability. This excess liability is being amortized to our condensed consolidated statements of income over the remaining lives of the contracts of $2 million annually through November 2023 and $1 million annually from November 2023 to November 2028.

(3)	Floating rate debt is based on the interest rate as of September 30, 2008, and the maturity of the underlying debt instrument. As of September 30, 2008, we have $32 million of accrued interest on our condensed consolidated balance sheet.

(4)	Represent fixed-fee or guaranteed minimum payments for Sequent’s asset management agreements between its affiliated utilities.

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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, 2007.

Accounting Developments

Previously discussed

FSP EITF 03-6-1 The FASB issued this FSP in June 2008 and is effective for fiscal years beginning after December 15, 2008. This FSP classifies unvested share-based payment grants containing nonforfeitable rights to dividends as participating securities that will be included in the computation of earnings per share. As of September 30, 2008, we had approximately 149,000 restricted shares with nonforfeitable dividend rights, which potentially could be included in our basic earnings per share calculation. We will adopt FSP EITF 03-6-1 on January 1, 2009.

Recently issued

Item 3. Quantitative and Qualitative Disclosures

About Market Risk

We are exposed to risks associated with commodity prices, interest rates and credit. Commodity price risk is defined as the potential loss that we may incur as a result of changes in the fair value of natural gas. Interest rate risk results from our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business. Credit risk results from the extension of credit throughout all aspects of our business but is particularly concentrated at Atlanta Gas Light in distribution operations and in wholesale services.

Commodity Price Risk

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

Energy marketing and risk management assets and liabilities SouthStar routinely utilizes various types of financial and other instruments to mitigate certain commodity price and weather risk inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts and financial swap agreements.

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We have designated a portion of SouthStar’s derivative transactions as cash flow hedges in accordance with SFAS 133. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period as the underlying hedged item occurs and is recorded in earnings. We record any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not offset and are greater than the losses or gains on the hedged item, in cost of gas in our condensed consolidated statement of income in the period in which the ineffectiveness occurs. SouthStar currently has minimal hedge ineffectiveness. We have not designated the remainder of SouthStar’s derivative instruments as hedges under SFAS 133 and, accordingly we record changes in their fair value in earnings in the period of change.

SouthStar experienced an increase of $2 million in the net fair value of derivative instruments utilized in its energy marketing and risk management activities in the first nine months of 2008 compared to $6 million decrease for the same period last year. The following tables illustrate the change in the net fair value of the derivative instruments and energy-trading contracts during the three and nine months ended September 30, 2008 and 2007, and provide details of the net fair value of contracts outstanding as of September 30, 2008.

	Three months ended Sept. 30,
In millions		2008			2007
Net fair value of contracts outstanding at beginning of period		$	8		$	3
Contracts realized or otherwise settled during period			6			6
Change in net fair value of contracts			(2	)		2
Net fair value of contracts outstanding at end of period			12			11
Netting of cash collateral			20			10
Cash collateral and net fair value of contracts outstanding at end of period		$	32		$	21

	Nine months ended Sept. 30,
In millions	2008			2007
Net fair value of contracts outstanding at beginning of period	$	10		$	17
Contracts realized or otherwise settled during period		(10	)		(15	)
Change in net fair value of contracts		12			9
Net fair value of contracts outstanding at end of period		12			11
Netting of cash collateral		20			10
Cash collateral and net fair value of contracts outstanding at end of period	$	32		$	21

The sources of SouthStar’s net fair value at September 30, 2008, are as follows:

In millions	Prices actively quoted (1)		Prices provided by other external sources
Mature through 2008	$	8	$	(1	)
Mature through 2009		4		-
Mature through 2010		1		-

(1)	Valued using NYMEX futures prices.

The following tables include the cash collateral fair values and average values of SouthStar’s energy marketing and risk management assets and liabilities as of September 30, 2008, December 31, 2007 and September 30, 2007. SouthStar bases the average values on monthly averages for the nine months ended September 30, 2008 and 2007.

	Average values at Sept. 30,
In millions	2008		2007
Asset (1)	$	13	$	10
Liability (1)		5		4

(1) Average values represent only the derivative instruments and excludes netting of cash collateral amounts.

	Cash collateral and fair values at
In millions	Sept. 30, 2008		Dec. 31, 2007		Sept. 30, 2007
Asset	$	33	$	13	$	21
Liability		1		-		-

Value at Risk A 95% confidence interval is used to evaluate VaR exposure. A 95% confidence interval means that over the holding period, an actual loss in portfolio value is not expected to exceed the calculated VaR more than 5% of the time. We calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price distribution, price volatility, confidence interval and holding period. Our VaR may not be comparable to a similarly titled measure of another company because, although VaR is a common metric in the energy industry, there is no established industry standard for calculating VaR or for the assumptions underlying such calculations. SouthStar’s portfolio of positions for the three months ended September 30, 2008 and 2007, had quarterly average 1-day holding period VaRs of less than $100,000 and its high, low and period end 1-day holding period VaR were immaterial.

Wholesale Services Sequent routinely utilizes various types of 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 OTC energy contracts, such as forward contracts, futures contracts, options contracts and financial swap agreements.

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Energy marketing and risk management assets and liabilities The following tables include the cash collateral, fair values and average values of Sequent’s energy marketing and risk management assets and liabilities as of September 30, 2008, December 31, 2007 and September 30, 2007. Sequent bases the average values on monthly averages for the nine months ended September 30, 2008 and 2007.

	Average values at Sept. 30,
In millions	2008		2007
Asset (1)	$	72	$	61
Liability (1)		48		17

(1) Average values represent only the derivative instruments and excludes netting of cash collateral amounts.

	Cash collateral and fair values at
In millions	Sept. 30, 2008		Dec. 31, 2007		Sept. 30, 2007
Asset	$	140	$	61	$	68
Liability		24		13		7

At September 30, 2008, Sequent’s commodity-related derivative financial instruments represented purchases (long) of 708 Bcf and sales (short) of 697 Bcf, with approximately 90% and 94% scheduled to mature in less than two years and the remaining 10% and 6% in three to nine years, respectively.

Sequent experienced a change in the net fair value of its outstanding contracts of $26 million during the first nine months of 2008 compared to a $59 million decrease during the same period last year due to changes in the fair value of derivative instruments utilized in its energy marketing and risk management activities and contract settlements.

The following tables illustrate the change in the net fair value of Sequent’s derivative instruments and energy trading contracts during the three and nine months ended September 30, 2008 and 2007, and provide details of the net fair value of contracts outstanding as of September 30, 2008.

	Three months ended Sept. 30,
In millions	2008			2007
Net fair value of contracts outstanding at beginning of period	$	(96	)	$	51
Contracts realized or otherwise settled during period		60			(17	)
Change in net fair value of contracts		119			26
Net fair value of contracts outstanding at end of period		83			60
Netting of cash collateral		33			1
Cash collateral and net fair value of contracts outstanding at end of period	$	116		$	61

	Nine months ended Sept. 30,
In millions	2008			2007
Net fair value of contracts outstanding at beginning of period	$	57		$	119
Contracts realized or otherwise settled during period		(48	)		(99	)
Change in net fair value of contracts		74			40
Net fair value of contracts outstanding at end of period		83			60
Netting of cash collateral		33			1
Cash collateral and net fair value of contracts outstanding at end of period	$	116		$	61

The sources of Sequent’s net fair value at September 30, 2008, are as follows:

In millions	Prices actively quoted (1)			Prices provided by other external sources (2)
Mature through 2008	$	27		$	56
Mature 2009 – 2010		(11	)		9
Mature 2011 – 2013		-			2
Total net fair value	$	16		$	67

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

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

Due to the $62 million lower net fair value of contracts outstanding at the beginning of the year in 2008 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, 2008 decreased by $51 million as compared to 2007. Additionally, as a result of decreases in forward natural gas prices during the nine months ended September 30, 2008, compared to the prior year’s more modest price declines, the change in fair value was an increase of $34 million. These changes resulted in the net fair value of its contracts being $23 million more than last year.

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.

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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 with minimal open commodity risk. Based on a 95% confidence interval and employing a 1-day holding period for all positions, Sequent’s portfolio of positions for the three and nine months ended September 30, 2008 and 2007 had the following VaRs.

	Three months ended September 30,					Nine months ended September 30,
In millions		2008		2007		2008		2007
Period end	$	1.9	$	1.0	$	1.9	$	1.0
Average		1.8		1.4		1.7		1.4
High		2.4		2.3		2.9		2.3
Low		1.0		0.9		0.8		0.9

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $929 million of variable-rate debt, which includes $768 million of our variable-rate short-term debt and $161 million of variable-rate gas facility revenue bonds outstanding at September 30, 2008, a 100 basis point change in market interest rates from 4.06% to 5.06% would have resulted in an increase in pretax interest expense of $9 million on an annualized basis.

At the beginning of 2008, we had a notional principal amount of $100 million of interest rate swap agreements associated with our senior notes. In March 2008, we terminated these interest rate swap agreements. We received a payment of $2 million, which included accrued interest and the fair value of the interest rate swap agreements at the termination date which was recorded as a liability in our condensed consolidated balance sheets and will be amortized through January 2011, which is the remaining life of the associated senior notes.

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, 2008, Sequent’s top 20 counterparties represented approximately 60% of the total counterparty exposure of $425 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures.

As of September 30, 2008, Sequent’s counterparties, or the counterparties’ guarantors, had a weighted-average S&P equivalent credit rating of A-, which is consistent with the rating at December 31, 2007 and September 30, 2007. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P and Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being the equivalent to AAA/Aaa by S&P and Moody’s and 1 being D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios for that counterparty. To arrive at the weighted average credit rating, each counterparty’s assigned internal ratio is multiplied by the counterparty’s credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. There were no credit defaults with Sequent’s counterparties as a result of the disruption in the credit markets.

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The following table shows Sequent’s third-party commodity receivable and payable positions as of September 30, 2008 and 2007 and December 31, 2007.

	Gross receivables						Gross payables
	September 30,		December 31,		September 30,		September 30,		December 31,		September 30,
In millions	2008		2007		2007		2008		2007		2007
Netting agreements in place:
Counterparty is investment grade	$	446	$	437	$	256	$	338	$	356	$	231
Counterparty is non-investment grade		10		24		13		16		18		28
Counterparty has no external rating		76		134		94		212		204		124
No netting agreements in place:
Counterparty is investment grade		3		3		-		2		-		-
Amount recorded on balance sheet	$	535	$	598	$	363	$	568	$	578	$	383

Sequent has certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, Sequent would need to post collateral to continue transacting business with some of its counterparties. 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, 2008, 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 $15 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, 2007.

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, 2008, 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, 2008, in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities and litigation incidental to the business. For information regarding pending federal and state regulatory matters, see “Note 6 - Commitments and Contingencies” contained in Item 1 of Part I under the caption “Notes to Condensed Consolidated Financial Statements (Unaudited).” With regard to 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 7 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007. 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.

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, 2008. 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 2008		-	$	-		-		4,950,951
August 2008		89		32.92		-		4,950,951
September 2008		2,108		32.87		-		4,950,951
Total third quarter		2,197	$	32.87		-

(1)	The total number of shares purchased includes an aggregate of 2,197 shares surrendered to us to satisfy tax withholding obligation in connection with the vesting of shares of restricted stock and 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 did not purchase any shares for such purposes in the third quarter of 2008. As of September 30, 2008, we had purchased a total 307,567 of the 600,000 shares authorized for purchase, leaving 292,433 shares available 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 available for purchase in connection with the Officer Plan as described in note (2) above, over a five-year period.

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 (Exhibit 3.1, AGL Resources Inc. Form 8-K dated November 2, 2005).

3.2	Bylaws, as amended on October 31, 2007 (Exhibit 3.2, AGL Resources Inc. Form 8-K dated October 31, 2007).

4.1	Specimen form of Common Stock certificate (Exhibit 4.1, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 1999).

10.1

Letter of Credit and Security Agreement dated as of September 4, 2008 by and among Pivotal Utility Holdings, Inc. as borrower, AGL Resources Inc. as Guarantor, Bank of America, N.A. as Administrative Agent, The Bank of Tokyo-Mitsubishi UFJ, LTD. as Syndication Agent and Bank of America, N.A. as Issuing Bank.

10.2

Credit Agreement as of September 30, 2008 by and among AGL Resources Inc., AGL Capital Corporation, Wachovia Bank, N.A. as Administrative Agent, Wachovia Capital Markets, LLC as sole lead arranger and sole lead bookrunner. SunTrust Bank, NA, The Bank of Tokyo-Mitsubishi UFJ, LTD., Calyon New York Brand and The Royal Bank of Scotland PLC. as Co-Documentation Agents (Exhibit 10.1, AGL Resources Inc. Form 8-K dated September 30, 2008).

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: October 30, 2008 /s/ Andrew W. Evans

Executive Vice President and Chief Financial Officer

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