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, 2011
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from        to
Commission File Number 1-14174
AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)
Georgia	58-2210952
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Ten Peachtree Place NE, Atlanta, Georgia 30309
(Address and zip code of principal executive offices)
404-584-4000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” ”accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No þ
Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.
Class	Outstanding as of October 26, 2011
Common Stock, $5.00 Par Value	78,553,859

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended September 30, 2011

TABLE OF CONTENTS
		Page(s)
Glossary of Key Terms		3
Item
Number
	PART I – FINANCIAL INFORMATION	4 – 43
1	Condensed Consolidated Financial Statements (Unaudited)	4 – 24
	Condensed Consolidated Statements of Financial Position	4
	Condensed Consolidated Statements of Income (Loss)	5
	Condensed Consolidated Statements of Equity	6
	Condensed Consolidated Statements of Comprehensive Income (Loss)	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Condensed Consolidated Financial Statements (Unaudited)	9 – 24
	Note 1 – Organization and Basis of Presentation	9
	Note 2 – Significant Accounting Policies and Methods of Application	9 – 12
	Note 3 – Proposed Merger with Nicor	12
	Note 4 – Fair Value Measurements	13
	Note 5 – Derivative Financial Instruments	13 – 15
	Note 6 – Employee Benefit Plans	16
	Note 7 – Debt	17 – 18
	Note 8 – Non-Wholly-Owned Entity	18 – 19
	Note 9 – Commitments and Contingencies	20 – 21
	Note 10 – Segment Information	21 – 24
2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25 – 43
	Forward-Looking Statements	25
	Overview	25 – 26
	Executive Summary	26 – 29
	Results of Operations	29 – 35
	Liquidity and Capital Resources	35 – 39
	Critical Accounting Estimates	39
	Accounting Developments	39 – 40
3	Quantitative and Qualitative Disclosures About Market Risk	40 – 42
4	Controls and Procedures	42 – 43
	PART II – OTHER INFORMATION	43 – 46
1	Legal Proceedings	43
1A	Risk Factors	43 – 44
2	Unregistered Sales of Equity Securities and Use of Proceeds	45
5	Other Information	45
6	Exhibits	46 – 47
	SIGNATURE	48

2

GLOSSARY OF KEY TERMS

2010 Form 10-K	Our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on February 9, 2011
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Bridge Facility	Credit agreement entered into by AGL Capital Corporation to finance a portion of the proposed merger with Nicor
Chattanooga Gas	Chattanooga Gas Company
Credit Facility	$1.0 billion credit agreement entered into by AGL Capital Corporation
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes financing costs, including interest and debt and income tax expense each of which we evaluate on a consolidated level; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, earnings before income taxes, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP
ERC	Environmental remediation costs associated with our distribution operations segment which are generally recoverable through rate mechanisms
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Golden Triangle Storage	Golden Triangle Storage, Inc.
Hampton Roads	Virginia Natural Gas’ pipeline project which connects its northern and southern pipelines
Heating Degree Days	A measure of the effects of weather on our businesses, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems when weather is colder
Jefferson Island	Jefferson Island Storage & Hub, LLC
LOCOM	Lower of weighted-average cost or current market price
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor	Nicor Inc., an Illinois corporation
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as operating revenues minus cost of gas, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our Condensed Consolidated Statements of Income. Operating margin should not be considered an alternative to, or more meaningful than, operating income as determined in accordance with GAAP
Piedmont	Piedmont Natural Gas Company, Inc.
PP&E	Property, plant and equipment
Regulatory Infrastructure Program	Programs that update or expand our distribution systems and liquefied natural gas facilities to improve system reliability and meet operational flexibility and growth. These programs include the pipeline replacement program and the STRIDE program at Atlanta Gas Light and Elizabethtown Gas’ utility infrastructure enhancements program.
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
SouthStar	SouthStar Energy Services LLC
STRIDE	Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
Term Loan Facility	$300 million credit agreement entered into by AGL Capital Corporation of which $150 million was drawn in January 2011 and subsequently repaid and the agreement terminated on February 14, 2011
VaR	Value at risk is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability
Virginia Natural Gas	Virginia Natural Gas, Inc.
Virginia Commission	Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
WACOG	Weighted-average cost of gas

3

PART 1 – Financial Information

Item 1. Financial Statements

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(UNAUDITED)

			As of
In millions	Sep. 30, 2011		Dec. 31, 2010		Sep. 30, 2010
Current assets
Cash and cash equivalents	$	165	$	24	$	14
Receivables
Energy marketing receivables (Note 2)		512		788		453
Gas, unbilled and other receivables		144		390		126
Less: allowance for uncollectible accounts		17		16		19
Total receivables		639		1,162		560
Inventories, net (Note 2)		635		639		668
Derivative financial instruments – current portion (Note 2, Note 4 and Note 5)		148		182		212
Recoverable Regulatory Infrastructure Program costs – current portion (Note 2)		62		48		43
Recoverable environmental remediation costs – current portion (Note 2 and Note 9)		7		7		7
Other current assets		145		104		124
Total current assets		1,801		2,166		1,628
Long-term assets and other deferred debits
Property, plant and equipment		6,521		6,266		6,139
Less: accumulated depreciation		1,886		1,861		1,846
Property, plant and equipment-net		4,635		4,405		4,293
Goodwill		418		418		418
Recoverable Regulatory Infrastructure Program costs (Note 2)		269		244		244
Recoverable environmental remediation costs (Note 2)		213		164		154
Derivative financial instruments (Note 2, Note 4 and Note 5)		38		46		57
Other		85		77		82
Total long-term assets and other deferred debits		5,658		5,354		5,248
Total assets	$	7,459	$	7,520	$	6,876
Current liabilities
Energy marketing trade payable (Note 2)	$	586	$	744	$	516
Accounts payable – trade		124		178		126
Accrued Regulatory Infrastructure Program costs – current portion (Note 2)		119		62		65
Accrued expenses		87		139		101
Derivative financial instruments – current portion (Note 2, Note 4 and Note 5)		45		44		80
Accrued environmental remediation liabilities – current portion (Note 2 and Note 9)		23		14		21
Current portion of long-term debt (Note 7)		15		300		300
Short-term debt (Note 4 and Note7)		2		733		675
Other current liabilities		139		218		180
Total current liabilities		1,140		2,432		2,064
Long-term liabilities and other deferred credits
Long-term debt (Note 4 and Note 7)		2,687		1,671		1,512
Accumulated deferred income taxes		895		768		727
Accumulated removal costs (Note 2)		254		182		187
Accrued environmental remediation liabilities (Note 2 and Note 9)		166		129		116
Accrued pension obligations (Note 6)		151		186		147
Accrued Regulatory Infrastructure Program costs (Note 2)		138		166		159
Accrued postretirement benefit costs (Note 6)		29		36		32
Derivative financial instruments (Note 2, Note 4 and Note 5)		14		4		10
Other long-term liabilities and other deferred credits		104		110		108
Total long-term liabilities and other deferred credits		4,438		3,252		2,998
Total liabilities and other deferred credits		5,578		5,684		5,062
Commitments and contingencies (Note 9)
Equity
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,864		1,813		1,798
Noncontrolling interest (Note 8)		17		23		16
Total equity		1,881		1,836		1,814
Total liabilities and equity	$	7,459	$	7,520	$	6,876
See Notes to Condensed Consolidated Financial Statements (Unaudited).

4

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)

(UNAUDITED)

	Three months ended						Nine months ended
	September 30,						September 30,
In millions, except per share amounts	2011			2010			2011			2010
Operating revenues	$	295		$	346		$	1,548		$	1,708
Operating expenses
Cost of gas		112			120			701			832
Operation and maintenance		105			114			363			358
Depreciation and amortization		43			40			126			119
Taxes other than income taxes		11			10			36			36
Total operating expenses		271			284			1,226			1,345
Operating income		24			62			322			363
Other income (expense)		1			(1	)		4			1
Interest expense, net		(31	)		(27	)		(92	)		(81	)
(Loss) earnings before income taxes		(6	)		34			234			283
Income tax (benefit) expense		(2	)		13			85			103
Net (loss) income		(4	)		21			149			180
Less net (loss) income attributable to the noncontrolling interest (Note 8)		(1	)		(1	)		10			10
Net (loss) income attributable to AGL Resources Inc.	$	(3	)	$	22		$	139		$	170

Per common share data (Note 2)

Basic (loss) earnings per common share attributable to AGL Resources Inc. common shareholders	$	(0.04	)	$	0.29	$	1.79	$	2.20
Diluted (loss) earnings per common share attributable to AGL Resources Inc. common shareholders	$	(0.04	)	$	0.29	$	1.78	$	2.19
Cash dividends declared per common share	$	0.45		$	0.44	$	1.35	$	1.32

Weighted-average number of common shares outstanding (Note 2)

Basic	78.1	77.5	77.9	77.3
Diluted	78.1	77.9	78.4	77.7

See Notes to Condensed Consolidated Financial Statements (Unaudited).

5

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

	AGL Resources Inc. Shareholders
	Common stock					Premium on common			Earnings			Accumulated other comprehensive			Treasury			Noncontrolling
In millions, except per share amounts	Shares			Amount		stock			reinvested			loss			shares			interest			Total
Balance as of Dec. 31, 2009		77.5		$	390	$	679		$	848		$	(116	)	$	(21	)	$	39		$	1,819
Net income		0.0			0		0			170			0			0			10			180
Other comprehensive loss		0.0			0		0			0			(16	)		0			0			(16	)
Dividends on common stock ($1.32 per share)		0.0			0		0			(102	)		0			3			0			(99	)
Purchase of additional 15% ownership interest in SouthStar		0.0			0		(51	)		0			(1	)		0			(6	)		(58	)
Distributions to noncontrolling interest (Note 8)		0.0			0		0			0			0			0			(27	)		(27	)
Purchase of treasury shares		(0.1	)		0		0			0			0			(5	)		0			(5	)
Issuance of treasury shares		0.6			0		(8	)		(3	)		0			22			0			11
Stock-based compensation expense (net of tax)		0.0			0		8			0			0			1			0			9
Balance as of Sep. 30, 2010		78.0		$	390	$	628		$	913		$	(133	)	$	0		$	16		$	1,814

	AGL Resources Inc. Shareholders
	Common stock				Premium on common		Earnings			Accumulated other comprehensive			Treasury			Noncontrolling
In millions, except per share amounts	Shares		Amount		stock		reinvested			loss			shares			interest			Total
Balance as of Dec. 31, 2010		78.0	$	391	$	631	$	943		$	(150	)	$	(2	)	$	23		$	1,836
Net income		0.0		0		0		139			0			0			10			149
Other comprehensive loss		0.0		0		0		0			(1	)		0			0			(1	)
Dividends on common stock ($1.35 per share)		0.0		0		3		(105	)		0			0			0			(102	)
Distributions to noncontrolling interest (Note 8)		0.0		0		0		0			0			0			(16	)		(16	)
Benefit, dividend reinvestment and stock purchase plans		0.7		3		10		0			0			(2	)		0			11
Purchase of treasury shares		0.0		0		0		0			0			(2	)		0			(2	)
Stock-based compensation expense (net of tax)		0.0		0		6		0			0			0			0			6
Balance as of Sep. 30, 2011		78.7	$	394	$	650	$	977		$	(151	)	$	(6	)	$	17		$	1,881

See Notes to Condensed Consolidated Financial Statements (Unaudited).

6

AGL RESOURCES INC. AND SUBSIDIARIES

 CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

	Three months ended						Nine months ended
	September 30,						September 30,
In millions	2011			2010			2011			2010
Comprehensive income attributable to AGL Resources Inc. (net of tax)
Net (loss) income attributable to AGL Resources Inc.	$	(3	)	$	22		$	139		$	170
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		(1	)		(6	)		(2	)		(23	)
Reclassification of derivative financial instruments realized losses included in net income		1			1			1			7
Other comprehensive loss		0			(5	)		(1	)		(16	)
Comprehensive (loss) income	$	(3	)	$	17		$	138		$	154
Comprehensive income attributable to noncontrolling interest (net of tax)
Net (loss) income attributable to noncontrolling interest	$	(1	)	$	(1	)	$	10		$	10
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		0			0			0			(1	)
Reclassification of derivative financial instruments realized losses included in net income		0			0			0			1
Other comprehensive income		0			0			0			0
Comprehensive (loss) income	$	(1	)	$	(1	)	$	10		$	10
Total comprehensive income, including portion attributable to noncontrolling interest (net of tax)
Net (loss) income	$	(4	)	$	21		$	149		$	180
Cash flow hedges:
Derivative financial instruments unrealized losses arising during the period		(1	)		(6	)		(2	)		(24	)
Reclassification of derivative financial instruments realized losses included in net income		1			1			1			8
Other comprehensive loss		0			(5	)		(1	)		(16	)
Comprehensive (loss) income	$	(4	)	$	16		$	148		$	164

See Notes to Condensed Consolidated Financial Statements (Unaudited).

7

AGL RESOURCES INC. AND SUBSIDIARIES

 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine months ended
	September 30,
In millions	2011			2010
Cash flows from operating activities
Net income	$	149		$	180
Adjustments to reconcile net income to net cash flow provided by operating activities
Change in derivative financial instrument assets and liabilities		53			(1	)
Depreciation and amortization		126			119
Deferred income taxes		105			50
Changes in certain assets and liabilities
Gas, unbilled and other receivables, net of allowance		247			241
Energy marketing receivables and energy marketing trade payables, net (Note 2)		118			154
Inventories		4			4
Deferred natural gas costs		3			(30	)
Accrued expenses		(52	)		(31	)
Gas and trade payables		(54	)		(63	)
Other – net		(139	)		(69	)
Net cash flow provided by operating activities		560			554
Cash flows from investing activities
Payments to acquire property, plant and equipment		(292	)		(370	)
Proceeds from disposition of assets		0			73
Other		0			(4	)
Net cash flow used in investing activities		(292	)		(301	)
Cash flows from financing activities
Issuance of senior notes		1,014			0
Benefit, dividend reinvestment and stock purchase plans		11			11
Purchase of additional 15% ownership interest in SouthStar		0			(58	)
Payment of gas facility revenue bonds		0			(160	)
Purchase of treasury shares		(2	)		(5	)
Distribution to noncontrolling interest (Note 8)		(16	)		(27	)
Dividends paid on common shares		(102	)		(99	)
Payment of senior notes		(300	)		0
Net payments and borrowings of short-term debt		(732	)		73
Net cash flow used in financing activities		(127	)		(265	)
Net increase (decrease) in cash and cash equivalents		141			(12	)
Cash and cash equivalents at beginning of period		24			26
Cash and cash equivalents at end of period	$	165		$	14
Cash paid during the period for
Interest	$	95		$	87
Income taxes	$	10		$	54

See Notes to Condensed Consolidated Financial Statements (Unaudited).

8

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

Note 1 - Organization and Basis of Presentation

General

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

On December 6, 2010, we entered into an Agreement and Plan of Merger (Merger Agreement) with Nicor, which we anticipate completing during the fourth quarter of 2011. See Note 3 for additional discussion of the proposed merger.

The December 31, 2010 Condensed Statement of Financial Position data was derived from our audited financial statements, but does not include all disclosures required by GAAP. We have prepared the accompanying unaudited Condensed Consolidated Financial Statements under the rules and regulations of the SEC. In accordance with such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. Our Condensed Consolidated Financial Statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. You should read these Condensed Consolidated Financial Statements in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our 2010 Form 10-K.

Due to the seasonal nature of our business, our results of operations for the three and nine months ended September 30, 2011 and 2010, and our financial condition as of December 31, 2010, and September 30, 2011 and 2010, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Basis of Presentation

Our Condensed Consolidated Financial Statements include our accounts, the accounts of our majority-owned and controlled subsidiaries and the accounts of our variable interest entity for which we are the primary beneficiary. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts are probable under the affiliates’ rate regulation process. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation. The reclassifications and revisions had no material impact on our prior period balances.

Note 2 – Significant Accounting Policies and Methods of Application

Use of Accounting Estimates

Our accounting policies are described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our 2010 Form 10-K. There were no significant changes to our accounting policies during the nine months ended September 30, 2011.

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

Fair Value Measurements

The carrying values of cash and cash equivalents, receivables, derivative financial assets and liabilities, accounts payable, other current assets and liabilities and accrued interest approximate fair value. There have been no significant changes to our fair value methodologies, as described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our 2010 Form 10-K.

As defined in the authoritative guidance related to fair value measurements and disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observance of those inputs. See Note 4 for additional fair value disclosure.

9

Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements, which enable wholesale services to net receivables and payables by counterparty. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The amounts due from or owed to wholesale services’ counterparties are netted and recorded on our Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing trade payables.

Our wholesale services segment has some trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of September 30, 2011, December 31, 2010 and September 30, 2010, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. However, if such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Inventories

For our distribution operations segment, we record natural gas stored underground at the WACOG. For SouthStar and Sequent we account for natural gas inventory at the lower of WACOG or market price. SouthStar and Sequent evaluate the weighted-average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other-than-temporary. For any declines considered to be other-than-temporary, we record adjustments to reduce the weighted-average cost of the natural gas inventory to market price. Sequent recorded LOCOM adjustments for the periods presented as follows:

	Three months ended September 30,				Nine months ended September 30,
In millions	2011		2010		2011		2010
Sequent	$	9	$	4	$	9	$	8

Regulatory Assets and Liabilities

We account for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose rates are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the period authorized by the regulatory commissions. Further, we are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and believe that we will be able to recover these costs, consistent with our historical recoveries.

As of September 30, 2011, there have been no new types of regulatory assets or liabilities from those discussed in Note 2 to our Consolidated Financial Statements and related notes in Item 8 of our 2010 Form 10-K.

10

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

	Sep. 30,		Dec. 31,		Sep. 30,
In millions	2011		2010		2010
Regulatory assets
Recoverable Regulatory Infrastructure Program costs	$	331	$	292	$	287
Recoverable ERC		220		171		161
Recoverable seasonal rates		9		11		10
Recoverable postretirement benefit costs		9		9		9
Other		44		42		53
Total regulatory assets		613		525		520
Associated assets
Derivative financial instruments		18		20		30
Total regulatory and associated assets	$	631	$	545	$	550

Regulatory liabilities
Accumulated removal costs	$	254	$	182	$	187
Derivative financial instruments		18		20		30
Regulatory tax liability		14		15		16
Unamortized investment tax credit		11		12		12
Deferred natural gas costs		26		23		9
Other		25		24		23
Total regulatory liabilities		348		276		277
Associated liabilities
Regulatory Infrastructure Program costs		257		228		224
ERC		178		132		125
Total associated liabilities		435		360		349
Total regulatory and associated liabilities	$	783	$	636	$	626

The increase in ERC costs is discussed further in Note 9. The increase in Regulatory Infrastructure Program costs primarily relates to updated engineering estimates based on actual path and rights of way for pipeline added to the program in 2010.

Earnings (Loss) per Common Share

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

We derive our potentially dilutive common shares by calculating the number of shares issued under restricted stock or issuable under restricted stock units and stock options. The vesting of shares of the restricted stock and restricted stock units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends upon whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. We did not include approximately 0.6 million shares of potentially dilutive common shares in the calculation of diluted loss per share for the three months ended September 30, 2011, as their effect would be anti-dilutive. The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. common shareholders for the periods presented, if performance units currently earned under our plans ultimately vest and stock options currently exercisable at prices below the average market prices are exercised:

	Three months ended September 30,					Nine months ended September 30,
In millions (except per share amounts)	2011			2010		2011		2010
Net (loss) income attributable to AGL Resources Inc.	$	(3	)	$	22	$	139	$	170
Denominator:
Basic weighted-average number of shares outstanding		78.1			77.5		77.9		77.3
The effect of dilutive securities		0.0			0.4		0.5		0.4
Diluted weighted-average number of shares outstanding		78.1			77.9		78.4		77.7
Basic and diluted (loss) earnings per share
Basic	$	(0.04	)	$	0.29	$	1.79	$	2.20
Diluted	$	(0.04	)	$	0.29	$	1.78	$	2.19

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

	September 30,
In millions	2011 (2)		2010		Change (1)
Three months ended		0.0		0.8		(0.8	)
Nine months ended		0.0		0.8		(0.8	)

(1) The decrease was primarily a result of a higher average market value of our common shares compared to the same period during 2010.

(2) 0.0 values represent amounts less than 0.1 million.

Note 3 – Proposed Merger with Nicor

On December 6, 2010, we entered into a Merger Agreement with Nicor, a copy of which was filed with the SEC on December 7, 2010. In accordance with the Merger Agreement, each share of Nicor common stock outstanding, other than shares to be cancelled and Dissenting Shares, as defined in the Merger Agreement, will be converted into the right to receive consideration of (i) 0.8382 of a share of our common stock and (ii) $21.20 in cash, subject to adjustments in certain circumstances to ensure that the transaction satisfies the “continuity of interest” requirement for a “reorganization” within Section 368(a) of the Internal Revenue Code. The Merger Agreement contains certain termination rights for both Nicor and us, and provides for the payment of fees and expenses upon the termination of the Merger Agreement under certain circumstances. Upon the closing of the proposed merger, it is anticipated that our shareholders will own approximately 67%, and Nicor shareholders will own approximately 33%, of the combined company.

On April 18, 2011, we received antitrust clearance from the Department of Justice and the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvement Act. On April 29, 2011, the SEC declared effective our registration statement on Form S-4 which registered our common stock to be issued to pay the equity portion of the purchase consideration. On June 14, 2011, we and Nicor received shareholder approval of the proposed merger at our respective shareholder meetings. Completion of the proposed merger is conditioned upon, among other things, regulatory approval by the Illinois Commerce Commission.

On January 18, 2011, we filed a joint application with Nicor to the Illinois Commerce Commission for approval of the proposed merger. The application did not request a rate increase, but included a commitment to maintain the number of full-time equivalent employees at Nicor’s natural gas utility for a period of three years. Additionally, we have committed to maintain personnel levels in specific areas of safety oversight of the Nicor Gas system for at least five years following merger completion. The Illinois Commerce Commission has eleven months to act upon the application, with their statutory deadline for action being December 16, 2011. On September 29, 2011, the Administrative Law Judge submitted a proposed order recommending approval of the merger and also recommended imposing the condition that Nicor Gas no longer be permitted to use its call center personnel to solicit its affiliates’ products. On October 13, 2011, briefs were filed to comment on the proposed order.

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

We and Nicor currently anticipate receiving the required authorizations, approvals and consents to complete the proposed merger during the fourth quarter of 2011. However, there can be no assurance as to the timing of these authorizations, approvals and consents or as to our ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to us and Nicor. The Merger Agreement with Nicor contains termination rights for both us and Nicor and provides that, if we terminate the agreement under specified circumstances, we may be required to pay a termination fee of $67 million.

During the three months ended September 30, 2011, we recorded approximately $8 million ($5 million net of tax) of transaction expenses associated with the proposed merger, while we recorded approximately $26 million ($16 million net of tax) of such expenses during the nine months ended September 30, 2011. These costs are expensed as incurred. For additional information concerning the proposed merger please see our Form 8-K filed with the SEC on December 7, 2010 and Form S-4/A filed with the SEC on April 28, 2011.

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Note 4 – Fair Value Measurements

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

	Recurring fair values Derivative financial instruments
	September 30, 2011					December 31, 2010					September 30, 2010
In millions	Assets		Liabilities			Assets (1)		Liabilities			Assets		Liabilities
Quoted prices in active markets (Level 1)	$	26	$	(72	)	$	22	$	(71	)	$	43	$	(91	)
Significant other observable inputs (Level 2)		133		(39	)		153		(29	)		193		(59	)
Netting of cash collateral		27		52			53		52			31		60
Total carrying value (2) (3)	$	186	$	(59	)	$	228	$	(48	)	$	267	$	(90	)

(1)  Less than $1 million premium at September 30, 2011, less than $1 million at December 31, 2010 and $2 million at September 30, 2010 associated with weather derivatives has been excluded as they are based on intrinsic value, not fair value.

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

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

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

Our short-term debt is carried at fair value and our long-term debt is carried at amortized cost. We estimate the fair value of our long-term debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we considered our currently assigned ratings for unsecured debt. The following table presents the carrying value and fair value of our long-term debt as of the following periods.

In millions	September 30, 2011		December 31, 2010		September 30, 2010
Long-term debt carrying amount (1)	$	2,704	$	1,972	$	1,813
Long-term debt fair value (1)	$	3,061	$	2,122	$	2,204

(1)  September 30, 2011 includes $15 million of medium-term notes that are classified in current portion of long-term debt and are due in 2012. December 31, 2010 includes $300 million and September 30, 2010 includes $300 million of senior notes repaid in January 2011.

Note 5 – Derivative Financial Instruments

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

- forward contracts;

- futures contracts;

- options contracts;

- financial swaps;

- treasury locks;

- weather derivative contracts;

- storage and transportation capacity transactions; and

- foreign currency forward contracts.

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

On May 4, 2011, we entered into interest rate swaps with an aggregate notional amount of $250 million to effectively convert a portion of our fixed rate interest obligation on the $300 million 6.4% senior notes due July 15, 2016 to a variable-rate obligation. We pay a floating interest rate equal to the three-month London Inter-bank Offered Rate (LIBOR) plus 3.9%. We designated the interest rate swaps as fair value hedges. The fair values of our interest rate swaps were reflected as a long-term derivative asset of $13 million at September 30, 2011. For more information on our senior notes, see Note 7.

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

Accounting Treatment	Recognition and Measurement
	Statement of Financial Position	Income Statement
Cash flow hedge	Recorded at fair value	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings
Fair value hedge	Recorded at fair value	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	Change in fair value of the derivative instrument is recorded as an adjustment to book value	Effective portion of the gain or loss on the derivative instrument is recognized in earnings
Not designated as hedges	Recorded at fair value	The gain or loss on the derivative instrument is recognized in earnings
	Elizabethtown Gas’ derivative financial instruments are recorded as a regulatory asset or liability until included in natural gas costs	The gain or loss on these derivative instruments is reflected in natural gas costs and is ultimately included in billings to customers
	Change in fair value of the derivative instrument is recorded as an adjustment to book value	Change in fair value of the derivative instrument is recognized in earnings

Quantitative Disclosures Related to Derivative Financial Instruments

As of the periods presented, our derivative financial instruments were comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas.

We had net long natural gas contracts outstanding in the following quantities:

Natural gas contracts

In Bcf	September 30, 2011 (1)			December 31, 2010			September 30, 2010
Hedge designation:
Cash flow		4			4			(1	)
Not designated		161			220			208
Total		165			224			207
Hedge position:
Short		(1,624	)		(1,605	)		(1,664	)
Long		1,789			1,829			1,871
Net long position		165			224			207

(1) Approximately 97% of these contracts have durations of two years or less and the remaining 3% expire in 3 to 6 years.

Derivative Financial Instruments on the Condensed Consolidated Statements of Financial Position

In accordance with regulatory requirements, realized losses on derivative financial instruments used at Elizabethtown Gas in our distribution operations segment were reflected in deferred natural gas costs within our Condensed Consolidated Statements of Financial Position for the periods presented and are contained in the following table.

	Three months ended September 30,				Nine months ended September 30,
In millions	2011		2010		2011		2010
Elizabethtown Gas	$	6	$	10	$	19	$	25

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The following table presents the fair value and statements of financial position classification of our derivative financial instruments:

		As of
In millions	Statement of financial position location(1) (2)	Sep. 30, 2011			Dec. 31, 2010			Sep. 30, 2010
Designated as cash flow and fair value hedges
Asset Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion	$	8		$	3		$	13
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		0			0			4
Interest rate swap agreements	Derivative financial instruments assets – long-term portion		13			0			0
Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		(8	)		(5	)		(15	)
Interest rate swap agreements	Derivative financial instruments liabilities – long-term portion		0			0			(23	)
Total			13			(2	)		(21	)

Not designated as cash flow hedges
Asset Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		486			541			727
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		78			105			139
Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		(447	)		(489	)		(642	)
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		(82	)		(80	)		(117	)
Total			35			77			107
Total derivative financial instruments		$	48		$	75		$	86

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

(2)  As required by the authoritative guidance related to derivatives and hedging, the fair value amounts above are presented on a gross basis. As a result, the amounts above do not include cash collateral held on deposit in broker margin accounts of $79 million as of September 30, 2011, $91 million as of September 30, 2010 and $105 million as of December 31, 2010. Accordingly, the amounts above will differ from the amounts presented on our Condensed Consolidated Statements of Financial Position and the fair value information presented for our derivative financial instruments in the recurring values table of this note.

Derivative Financial Instruments on the Condensed Consolidated Statements of Income

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

	For the three months ended September 30,						For the nine months ended September 30,
In millions	2011			2010			2011			2010
Designated as cash flow and fair value hedges
Natural gas contracts – loss reclassified from OCI into cost of gas for settlement of hedged item (1)	$	(1	)	$	(3	)	$	(2	)	$	(13	)
Interest rate swaps – ineffectiveness recorded as an offset to interest expense		2			0			2			0

Not designated as hedges
Natural gas contracts – fair value adjustments recorded in operating revenues (2)		0		40			12			63
Natural gas contracts – net fair value adjustments recorded in cost of gas (3)		0		(1	)		(2	)		(3	)
Total gains on derivative instruments	$	1	$	36		$	10		$	47

(1)  We expect that $2 million of pre-tax net losses will be reclassified from OCI into cost of gas for the settlement of hedged items over the next twelve months.

(2)  Associated with the fair value of existing derivative instruments at September 30, 2011 and 2010.

(3)  Excludes losses recorded in cost of gas associated with weather derivatives of $4 million for the nine months ended September 30, 2011 and losses of $21 million for the nine months ended September 30, 2010.

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Note 6 - Employee Benefit Plans

Pension Benefits

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

	Three months ended September 30,						Nine months ended September 30,
In millions	2011			2010			2011			2010
Service cost	$	3		$	3		$	10		$	8
Interest cost		7			7			21			21
Expected return on plan assets		(7	)		(7	)		(23	)		(22	)
Amortization of prior service cost		(1	)		(1	)		(2	)		(2	)
Recognized actuarial loss		3			3			10			8
Net pension benefit cost	$	5		$	5		$	16		$	13

Postretirement Benefits

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

	Three months ended September 30,						Nine months ended September 30,
In millions	2011			2010			2011			2010
Service cost	$	1		$	0		$	1		$	1
Interest cost		1			1			4			4
Expected return on plan assets		(1	)		(1	)		(4	)		(4	)
Amortization of prior service cost		(1	)		(1	)		(3	)		(3	)
Recognized actuarial loss		0			1			1			2
Net pension benefit cost	$	0		$	0		$	(1	)	$	0

Contributions

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

The Act contained new funding requirements for single employer defined benefit pension plans and established a 100% funding target (over a 7-year amortization period) for plan years beginning after December 31, 2007. If certain conditions are met, the Worker, Retiree and Employer Recovery Act of 2008 allowed us to measure our required minimum contributions based on a funding target of 100% during 2010 and 2011. In the first nine months of 2011 we contributed $50 million to our qualified pension plans and $26 million during the same period last year.

Employee Savings Plan Benefits

We sponsor the Retirement Savings Plus Plan (RSP), a defined contribution benefit plan that allows eligible participants to make contributions to their accounts up to specified limits. Under the RSP, our matching contributions to participant accounts were $5 million in the first nine months of 2011 and $5 million in the first nine months of 2010.

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Note 7 – Debt

AGL Capital Corporation, our wholly-owned finance subsidiary, provides for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities and other financing arrangements. The following table provides maturity dates, year-to-date weighted-average interest rates and amounts outstanding for our various debt securities and facilities. For additional information on our debt see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our 2010 Form 10-K.

			September 30, 2011								September 30, 2010
In millions (except %)	Year(s) due		Weighted- average interest rate			Outstanding		Outstanding at December 31, 2010			Weighted- average interest rate			Outstanding
Short-term debt
Commercial paper		-		0.4	%	$	0	$	732			0.4	%	$	674
Current portion of long-term debt		2012		8.3			15		300			7.1			300
Current portion of capital leases		2011-2012		4.9			2		1			4.9			1
Total short-term debt and current portion of long-term debt				0.8	%	$	17	$	1,033			3.5	% (1)	$	975
Long-term debt - net of current portion
Senior notes		2013-2041		5.5	%	$	2,275	$	1,275			5.5	%	$	1,275
Gas facility revenue bonds		2022-2033		1.1			200		200			5.3			40
Medium-term notes		2017-2027		7.8			181		196			7.8			196
Interest rate swaps fair value adjustment		2016		4.2			11		0			0.0			0
Capital leases		-		0.0			0		2			4.9			3
Unamortized debt premium (discount), net		-		0.0			20		(2	)		0.0			(2	)
Total long-term debt				5.1	%	$	2,687	$	1,671			5.4	% (2)	$	1,512
Total debt				4.5	%	$	2,704	$	2,704			4.9	%	$	2,487

(1) Excluding the $300 million of senior notes repaid in January 2011, the weighted-average short-term interest rate for the nine months ended September 30, 2010 was 0.4%.

(2) Including the $300 million of senior notes repaid in January 2011, the weighted-average long-term interest rate for the nine months ended September 30, 2010 was 5.6%.

Senior Notes

On March 16, 2011, we completed a public offering of $500 million in 30 year senior notes with an interest rate of 5.9% and a maturity date of March 15, 2041. The net proceeds were used to repay commercial paper, a portion of which we borrowed to repay our $300 million in senior notes that matured on January 14, 2011. The remaining proceeds are expected to be used to pay a portion of the cash consideration and expenses incurred in connection with the proposed merger with Nicor, if completed, or for other general corporate purposes.

On May 4, 2011, we entered into interest rate swaps with an aggregate notional amount of $250 million to effectively convert a portion of our $300 million 6.4% fixed-rate senior notes that mature July 15, 2016 to a variable-rate debt obligation. The interest rates reset quarterly based on three month LIBOR plus 3.9%.

On September 15, 2011, we completed two concurrent public offerings totaling $500 million, comprised of an incremental $200 million of our 5.9% senior notes due on March 15, 2041 and $300 million in new senior notes with an interest rate of 3.5% and a maturity date of September 15, 2021. The net proceeds are expected to be used to pay a portion of the cash consideration and expenses incurred in connection with the proposed merger with Nicor, if completed, or for other general corporate purposes.

On October 27, 2011, we completed an issuance of $275 million in senior notes in the private placement market, comprised of $120 million of Series A senior notes with an interest rate of 1.9% and maturity date of October 27, 2016, and $155 million of Series B senior notes with an interest rate of 3.5% and a maturity date of October 27, 2018. The net proceeds are expected to be used to pay a portion of the cash consideration and expenses incurred in connection with the proposed merger with Nicor, if completed, or for other general corporate purposes.

Following our issuance of these senior notes, and in accordance with the terms of our Bridge Facility, the principal amount of the Bridge Facility has been reduced to $60 million.

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Financial and Non-Financial Covenants

Our Credit Facility includes a financial covenant that requires us to maintain a ratio, on a consolidated basis, of total debt to total capitalization of no more than 70%; however, our goal is to maintain this ratio at a level between 50% and 60%. Our ratio, on a consolidated basis, of total debt to total capitalization as calculated in accordance with our debt covenant includes standby letters of credit, performance/surety bonds and excludes certain pension and other post-retirement benefit adjustments and cash flow hedges that are not yet settled. Adjusting for these items, the following table contains our debt-to-capitalization ratio for the periods presented, which are within our targeted ranges.

	September 30, 2011			December 31, 2010			September 30, 2010
Debt-to-capitalization ratio		57	%		58	%		56	%

The Credit Facility contains certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, restricted payments, asset dispositions, fundamental changes and other matters customarily restricted in such agreements. We are currently in compliance with all existing debt provisions and covenants. Our Bridge Facility contains the same financial covenant and similar non-financial covenants and default provisions; however, most of these are not in effect until we draw under the facility.

Default Provisions

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

- a maximum leverage ratio

- insolvency events and nonpayment of scheduled principal or interest payments

- acceleration of other financial obligations

- change of control provisions

We have no trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other trigger events.

Note 8 – Non-Wholly-Owned Entity

On a quarterly basis we evaluate all of our joint venture interests to determine if they represent a variable interest entity (VIE) as defined by the authoritative accounting guidance on consolidation. We have determined that SouthStar is our only VIE. Additionally, we have concluded that we are the primary beneficiary of the VIE, which requires us to consolidate the assets, liabilities and statements of income of the joint venture. Our methodology for determining that we are the primary beneficiary, and that our involvement allows us to direct SouthStar’s activities that most significantly influence its performance, has not changed during the nine months ended September 30, 2011. See Note 9 to our Consolidated Financial Statements and related notes included in Item 8 of our 2010 Form 10-K. Earnings in 2011 and 2010 were allocated entirely in accordance with the ownership interests.

SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to retail customers primarily in Georgia, and under various other trade names to retail customers in Ohio, Florida and New York and to commercial and industrial customers principally in Alabama, Florida, North Carolina, South Carolina and Tennessee.

During the nine months ended September 30, 2011, there have been no significant changes to the primary risks associated with SouthStar as discussed in our risk factors included in Item 1A of our 2010 Form 10-K. See Note 10 for Summarized Statements of Income, Statements of Financial Position and capital expenditure information related to the retail energy operations segment, which is primarily comprised of SouthStar. The following table illustrates the effect that our 2009 purchase of an additional 15% ownership interest, which became effective in January 2010, had on our equity for the nine months ended September 30, 2010.

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

SouthStar’s financial results are seasonal in nature, with the business depending to a great extent on the winter heating seasons during the first and fourth quarters of each year for the majority of its earnings. SouthStar’s current assets consist primarily of natural gas inventory, derivative financial instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in our commercial paper program. See Note 2 for additional discussions of SouthStar’s inventories. SouthStar’s restricted assets consist of customer deposits and are immaterial as of September 30, 2011 and 2010. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative financial instruments and payables to us from its participation in our commercial paper program.

As of September 30, 2011, SouthStar’s current assets, which approximate fair value, exceeded its current liabilities, long-term assets and other deferred debits and long-term liabilities and other deferred credits by approximately $97 million. SouthStar’s other contractual commitments and obligations, including operating leases and agreements with third party providers, do not contain terms that would trigger material financial obligations in the event such contracts were terminated. As a result, our maximum exposure to a loss at SouthStar is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond the corporate guarantees we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. Additionally, with the exception of our corporate guarantees, we have not entered into any arrangements that could require us to provide financial support to SouthStar.

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

Cash flows used in our financing activities includes SouthStar’s distributions to the noncontrolling interest, which reflects the cash distribution to Piedmont for its ownership interest in SouthStar’s annual earnings from the prior year. Generally this distribution occurs in the first or second quarter. In the nine months ended September 30, 2011 SouthStar distributed $16 million to Piedmont and $27 million during the same period last year. This decrease of $11 million was primarily the result of our increased ownership percentage of SouthStar in 2010.

The following table provides additional information on SouthStar’s assets and liabilities as of the periods presented, which are consolidated within our Condensed Consolidated Statements of Financial Position.

	September 30, 2011						December 31, 2010						September 30, 2010
In millions	Consolidated		SouthStar (1)		% (2)		Consolidated		SouthStar (1)		% (2)		Consolidated		SouthStar (1)		% (2)
Current assets	$	1,801	$	164	9	%	$	2,166	$	239	11	%	$	1,628	$	167	10	%
Long-term assets and other deferred debits		5,658		9	0			5,354		9	0			5,248		10	0
Total assets	$	7,459	$	173	2	%	$	7,520	$	248	3	%	$	6,876	$	177	3	%
Current liabilities	$	1,140	$	57	5	%	$	2,432	$	93	4	%	$	2,064	$	63	3	%
Long-term liabilities and other deferred credits		4,438		0	0			3,252		0	0			2,998		0	0
Total Liabilities		5,578		57	1			5,684		93	2			5,062		63	1
Equity		1,881		116	6			1,836		155	8			1,814		114	6
Total liabilities and equity	$	7,459	$	173	2	%	$	7,520	$	248	3	%	$	6,876	$	177	3	%

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

(2) SouthStars percentage of the amount on our Condensed Consolidated Statements of Financial Position.

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Note 9 - Commitments and Contingencies

Contractual Obligations and Commitments

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Our contractual obligations as of September 30, 2011 are listed in the following table.

			Remainder										2016 &
In millions	Total		of 2011		2012		2013		2014		2015		Thereafter
Recorded contractual obligations:
Long-term debt	$	2,687	$	0	$	0	$	225	$	0	$	200	$	2,262
Regulatory Infrastructure Program costs (1)		257		11		108		138		0		0		0
Environmental remediation liabilities (1)		189		4		27		31		32		18		77
Short-term debt (including current portion of long-term debt)		17		-		17		0		0		0		0
Total	$	3,150	$	15	$	152	$	394	$	32	$	218	$	2,339

Unrecorded contractual obligations and commitments(2) (7):
Pipeline charges, storage capacity and gas supply (3)	$	1,750	$	156	$	455	$	320	$	202	$	123	$	494
Interest charges (4)		2,118		34		133		126		123		113		1,589
Operating leases (5)		188		5		19		20		17		16		111
Asset management agreements (6)		20		3		10		6		1		0		0
Standby letters of credit, performance / surety bonds		15		1		14		0		0		0		0
Total	$	4,091	$	199	$	631	$	472	$	343	$	252	$	2,194

(1)   Includes amounts recoverable through rate rider mechanisms.

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

(3)   Includes amounts recoverable through a natural gas cost recovery mechanism or alternatively billed to Marketers, and includes demand charges associated with Sequent. Also includes SouthStar’s natural gas purchase commitments of 10 Bcf at floating gas prices calculated using forward natural gas prices as of September 30, 2011, and are valued at $40 million.

(4)   Floating rate debt is based on the interest rate as of September 30, 2011, and the maturity of the underlying debt instrument. As of September 30, 2011, we have $35 million of accrued interest on our Condensed Consolidated Statements of Financial Position that will be paid over the next 12 months.

(5)   We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Additionally, minimum payments have not been reduced by minimum sublease rentals of $13 million due in the future under noncancelable subleases.

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

(7)   The Merger Agreement with Nicor contains termination rights for both us and Nicor and provides that, if we terminate the agreement under specified circumstances, we may be required to pay a termination fee of $67 million. In addition, if we terminate the agreement due to a failure to obtain the necessary financing for the transaction, we may also be required to pay Nicor $115 million: however, given that we have issued, or secured, long-term debt financing to pay the cash portion of the purchase consideration, the risk of having to pay this $115 million fee has been greatly reduced.

Litigation

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

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

We have been named as a defendant in several class action lawsuits brought by purported Nicor shareholders challenging Nicor’s proposed merger with us. The complaints allege that we aided and abetted alleged breaches of fiduciary duty by Nicor’s Board of Directors. The shareholder lawsuits seek, among other things, declaratory and injunctive relief, including orders enjoining the defendants from completing the proposed merger and, in certain circumstances, damages. In March 2011, the parties entered into an agreement to resolve all of the shareholder lawsuits, subject to court approval, based on Nicor providing certain supplemental disclosures to our joint proxy statement filed on April 28, 2011. The court has preliminarily approved the agreement, a fairness hearing is set for December 11, 2011 and we expect the court to approve the agreement at this hearing. This lawsuit will have no effect on the closing of the merger. For more information on our proposed merger with Nicor see Note 3.

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Environmental Remediation Costs

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. Except in those instances where a better estimate is known, we have recorded the lower end of the cost estimate range. The following table provides more information on the costs related to remediation of our former operating sites.

In millions	Cost estimate range		Amount recorded		Expected costs over next twelve months
Georgia and Florida	$	39 - $101	$	56	$	7
New Jersey		124 – 175		122		13
North Carolina		11 – 16		11		4
Total	$	174 - $292	$	189	$	24

The increase in our consolidated environmental remediation cost liability of $46 million from December 31, 2010 is primarily a result of increases in estimated excavation and remediation costs at our sites in New Jersey based on updated studies completed during the second quarter of 2011. For more information on our environmental remediation costs, see Note 10 to our Consolidated Financial Statements and related notes as filed in Item 8 of our 2010 Form 10-K.

Note 10 - Segment Information

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

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities. Although the operations of our distribution operations segment are geographically dispersed, the operating subsidiaries within the distribution operations segment are regulated utilities, with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.

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

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

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

Following are the reconciliations of EBIT to operating income, (loss) earnings before income taxes and net (loss) income for the periods presented.

	Three months ended September 30,						Nine months ended September 30,
In millions	2011			2010			2011		2010
Operating income	$	24		$	62		$	322	$	363
Other income		1			(1	)		4		1
EBIT		25			61			326		364
Interest expense, net		31			27			92		81
(Loss) earnings before income taxes		(6	)		34			234		283
Income tax (benefit) expense		(2	)		13			85		103
Net (loss) income	$	(4	)	$	21		$	149	$	180

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

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	5,498		$	404
Retail energy operations		259			0
Wholesale services		1,326			0
Energy investments		479			14
Corporate (2)		(42	)		0
Consolidated	$	7,520		$	418

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

(2)  Our corporate segments assets consist primarily of cash and cash equivalents and property, plant and equipment and reflect the effect of intercompany eliminations.

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Summarized Statements of Income, Statements of Financial Position and capital expenditure information by segment as of and for the periods presented are shown in the following tables.

Three months ended September 30, 2011

In millions	Distribution operations		Retail energy     operations			Wholesale services			Energy investments		Corporate and intercompany eliminations (3)			Consolidated AGL Resources Inc.
Operating revenues from external parties	$	206	$	98		$	(21	)	$	11	$	1		$	295
Intercompany revenues (1)		34		0			0			0		(34	)		0
Total operating revenues		240		98			(21	)		11		(33	)		295
Operating expenses
Cost of gas		47		87			8			2		(32	)		112
Operation and maintenance		78		15			7			5		0			105
Depreciation and amortization		38		1			0			2		2			43
Taxes other than income taxes		9		0			1			0		1			11
Total operating expenses		172		103			16			9		(29	)		271
Operating income (loss)		68		(5	)		(37	)		2		(4	)		24
Other income (expense)		2		0			0			0		(1	)		1
EBIT	$	70	$	(5	)	$	(37	)	$	2	$	(5	)	$	25
Capital expenditures	$	82	$	1		$	0		$	6	$	7		$	96

Three months ended September 30, 2010

In millions	Distribution operations		Retail energy      operations			Wholesale services		Energy investments		Corporate and intercompany eliminations (3)			Consolidated AGL Resources Inc.
Operating revenues from external parties	$	204	$	101		$	32	$	8	$	1		$	346
Intercompany revenues (1)		34		0			0		0		(34	)		0
Total operating revenues		238		101			32		8		(33	)		346
Operating expenses
Cost of gas		55		91			6		2		(34	)		120
Operation and maintenance		85		18			12		3		(4	)		114
Depreciation and amortization		35		1			0		2		2			40
Taxes other than income taxes		8		0			0		0		2			10
Total operating expenses		183		110			18		7		(34	)		284
Operating income (loss)		55		(9	)		14		1		1			62
Other income (expense)		0		0			1		0		(2	)		(1	)
EBIT	$	55	$	(9	)	$	15	$	1	$	(1	)	$	61
Capital expenditures	$	90	$	1		$	0	$	26	$	4		$	121

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Nine months ended September 30, 2011

In millions	Distribution operations		Retail energy     operations		Wholesale services			Energy investments		Corporate and intercompany eliminations (3)			Consolidated AGL Resources Inc.
Operating revenues from external parties	$	948	$	505	$	41		$	51	$	3		$	1,548
Intercompany revenues (1)		113		0		0			0		(113	)		0
Total operating revenues		1,061		505		41			51		(110	)		1,548
Operating expenses
Cost of gas		385		388		12			25		(109	)		701
Operation and maintenance		257		50		35			13		8			363
Depreciation and amortization		109		2		1			7		7			126
Taxes other than income taxes		27		1		2			2		4			36
Total operating expenses		778		441		50			47		(90	)		1,226
Operating income (loss)		283		64		(9	)		4		(20	)		322
Other income		4		0		0			0		0			4
EBIT	$	287	$	64	$	(9	)	$	4	$	(20	)	$	326
Identifiable and total assets (2)	$	5,687	$	182	$	1,004		$	472	$	114		$	7,459
Goodwill	$	404	$	0	$	0		$	14	$	0		$	418
Capital expenditures	$	249	$	2	$	1		$	21	$	19		$	292

Nine months ended September 30, 2010

In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments			Corporate and intercompany eliminations (3)			Consolidated AGL Resources Inc.
Operating revenues from external parties	$	958	$	611	$	91	$	45		$	3		$	1,708
Intercompany revenues (1)		106		0		0		0			(106	)		0
Total operating revenues		1,064		611		91		45			(103	)		1,708
Operating expenses
Cost of gas		419		487		15		15			(104	)		832
Operation and maintenance		258		55		36		18			(9	)		358
Depreciation and amortization		103		2		1		5			8			119
Taxes other than income taxes		27		1		2		2			4			36
Total operating expenses		807		545		54		40			(101	)		1,345
Operating income (loss)		257		66		37		5			(2	)		363
Other income (expense)		3		0		1		(1	)		(2	)		1
EBIT	$	260	$	66	$	38	$	4		$	(4	)	$	364
Identifiable and total assets (2)	$	5,304	$	175	$	1,028	$	460		$	(91	)	$	6,876
Goodwill	$	404	$	0	$	0	$	14		$	0		$	418
Capital expenditures	$	252	$	2	$	1	$	102		$	13		$	370

(1) Intercompany revenues - wholesale services records its energy marketing and risk management revenues on a net basis, which includes intercompany revenues of $118 million and $367 million for the three and nine months ended September 30, 2011 and $79 million and $351 million for the three and nine months ended September 30, 2010.

(2) Identifiable assets are those used in each segments operations.

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

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

The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the notes to the Condensed Consolidated Financial Statements in this quarterly filing, as well as our 2010 Form 10-K.

Forward-Looking Statements

Certain expectations and projections regarding our future performance referenced in this Management’s Discussion and Analysis of Financial Condition and Results of Operations section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC or otherwise release to the public and on our website are forward-looking statements within the meaning of the U.S. federal securities laws and are subject to uncertainties and risks. Senior officers and other employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.

Forward-looking statements involve matters that are not historical facts, and because these statements involve anticipated events or conditions, forward-looking statements often include words such as "anticipate," "assume," “believe,” "can," "could," "estimate," "expect," "forecast," "future," “goaI,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” “proposed,” "seek," "should," "target," "would," or similar expressions. You are cautioned not to place undue reliance on our forward-looking statements. Our expectations are not guarantees and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations are reasonable in view of currently available information, our expectations are subject to future events, risks and uncertainties, and there are numerous factors, many of which are beyond our control, that could cause our actual results to vary significantly from our expectations.

Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation including any changes related to climate change; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, unexpected change in project costs, including the cost of funds to finance these projects; the impact of acquisitions and divestitures; direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including disruptions in the capital markets and lending environment and the current economic uncertainty; general economic conditions; uncertainties about environmental issues and the related impact of such issues; the impact of changes in weather, including climate change, on the temperature-sensitive portions of our business; the impact of natural disasters such as hurricanes on the supply and price of natural gas; acts of war or terrorism; and other factors described in detail in our filings with the SEC.

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

We caution readers that, in addition to the important factors described in Item 1A, Risk Factors, and elsewhere in this report, the factors set forth in Item 1A, “Risk Factors,” of our 2010 Form 10-K, among others, could cause our business, results of operations or financial condition in 2011 and thereafter to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or that are not described in our 2010 Form 10-K or in this report that could cause our actual results to differ significantly from our expectations. Forward-looking statements are only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required under U.S. federal securities law.

Overview

We are an energy services holding company whose principal business is the distribution of natural gas through our regulated natural gas distribution business. As of September 30, 2011, our six utilities served approximately 2.3 million end-use customers. We are also involved in several related and complementary businesses, including retail natural gas marketing to end-use customers in Georgia, Ohio, Florida and New York; natural gas asset management and related logistics activities for each of our utilities as well as for non-affiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability underground natural gas storage assets. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services and energy investments and one nonoperating corporate segment.

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The distribution operations segment is subject to regulation and oversight by agencies in each of the six states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our operating expenses and to earn a reasonable return for our shareholders.

The operating revenues and EBIT of our distribution operations and retail energy operations segments are seasonal. During the Heating Season, natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. Our base operating expenses, excluding cost of gas, interest expense and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, our operating results vary significantly from quarter to quarter as a result of seasonality.

With the exception of Atlanta Gas Light, our largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas and general economic conditions that may impact our customers’ ability to pay for gas consumed. Various mechanisms exist that limit our exposure to weather changes within typical ranges in all of our jurisdictions.

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

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

Changes in commodity prices subject a significant portion of our operations to earnings variability. Our non-utility businesses principally use physical and financial arrangements to reduce the risks associated with both weather-related seasonal fluctuations in market conditions and changing commodity prices. For more information on our derivative financial instruments see Note 5.

Executive Summary

Proposed merger with Nicor

On December 6, 2010, we entered into a Merger Agreement with Nicor, which we expect to complete during the fourth quarter of 2011. We have issued, or secured, long-term debt financing to pay the cash portion of the purchase consideration and we continue to work on securing the necessary approvals, which we anticipate will be obtained.

·   On January 18, 2011, we filed a joint application with Nicor with the Illinois Commerce Commission for approval of the proposed merger. The application did not request a rate increase and included a commitment to maintain 2,070 full-time equivalent employees involved in the operation of Nicor’s gas distribution subsidiary for a period of three years. We have also committed to maintain the personnel numbers in specific areas of safety oversight of the Nicor Gas system for a period of at least five years following the completion of the merger. The Illinois Commerce Commission has eleven months to act on the application with the statutory deadline for action being December 16, 2011.

·   On September 29, 2011, the Administrative Law Judge submitted a proposed order recommending approval of the merger and also recommended imposing the additional condition that Nicor Gas no longer be permitted to use its call center personnel to solicit its affiliates’ products. On October 13, 2011, briefs were filed to comment on the proposed order. Subsequent to the filing of our September 30, 2011 10-Q, the Illinois Commerce Commission has three meetings scheduled prior to the statutory deadline.

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·   On April 18, 2011, the Department of Justice and the Federal Trade Commission granted us early termination of the waiting period under the Hart-Scott-Rodino Act.

·   On April 29, 2011, the SEC declared our registration statement on Form S-4 effective.

·   On May 26, 2011, we received approval from the California Public Utilities Commission to transfer ownership of Central Valley Gas Storage from Nicor to us.

·   On June 14, 2011, we and Nicor held special shareholder meetings where the shareholders of both companies approved the proposed merger and the AGL Resources shareholders approved the issuance of the additional shares of common stock necessary to pay the equity portion of the merger consideration.

·   On August 2, 2011, we announced the four directors designated by Nicor and approved by our board of directors, subject to the approval of AGL Resources, to sit on the board of directors of the combined company, subject to their election to our board of directors upon the close of the merger.

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

Natural gas price volatility and energy marketing activities

Volatility in the natural gas market arises from a number of factors such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices have a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our wholesale services segment to capture value from location and seasonal spreads. During 2008 and 2009, daily Henry Hub spot market prices for natural gas in the United States were extremely volatile. However, during 2010 and 2011, the volatility of natural gas prices has been significantly lower than it had been for several prior years. This is the result of a robust natural gas supply, the weak economy, mild hurricane seasons and ample storage. Our natural gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs.

It is possible that natural gas prices will remain low for an extended period based on current levels of excess supply relative to market demand for natural gas, in part due to abundant sources of new shale natural gas reserves, particularly in the Marcellus Shale producing region where Sequent has natural gas receipt requirements, and the lack of demand growth by commercial and industrial enterprises. However, as economic conditions improve the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets. Consequently, we are working to reposition Sequent’s business model with respect to fixed costs and the types of contracts pursued and executed.

Sequent’s expected natural gas withdrawals from physical salt dome and reservoir storage are presented in the following table along with the operating revenues expected at the time of withdrawal for September 30, 2011 and 2010. Sequent’s expected operating revenues are net of the estimated impact of profit sharing and reflect the amounts that are realizable in future periods based on its expected inventory withdrawal schedule and forward natural gas prices at September 30, 2011 and 2010. A portion of Sequent’s storage inventory is economically hedged with futures contracts, which results in realization of substantially fixed operating revenues, timing notwithstanding.

	Withdrawal schedule
	(in Bcf)				Expected
	Salt dome (WACOG $3.70)		Reservoir (WACOG $3.76)		operating revenues (in millions)
2011
Fourth quarter		3		10	$	3
2012
First quarter		0		12		3
Total at September 30, 2011		3		22	$	6
Total at September 30, 2010		3		22	$	6

If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, it expects operating revenues from storage withdrawals of approximately $6 million during the next twelve months. This will change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate.

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Customer growth initiatives

We use a variety of targeted marketing programs to attract new customers and to retain existing customers. These efforts include working to add residential customers, multifamily complexes and commercial customers who use natural gas for purposes other than space heating, as well as evaluating and launching new natural gas related programs, products and services to enhance customer growth, mitigate customer attrition and increase operating revenues. These programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. On October 10, 2011, Georgia Natural Gas, within our retail energy operations segment, was named the exclusive natural gas partner for the Delta Air Lines Inc. Delta SkyMiles Program in Georgia. This is a long-term partnership and we expect it will help retain current customers as well as attract new customers from other Marketers in Georgia.

Regulatory Strategy

We continue to pursue a regulatory strategy that focuses on creating value for our various stakeholders, by maintaining a reasonable rate of return for our investors and investing in the reliability and safety of our utility infrastructure. For additional information on our regulatory strategy, see caption “Utility Regulation and Rate Design” under Item 1 “Business” of our 2010 Form 10-K.

On February 8, 2011, Virginia Natural Gas filed a rate case proceeding with the Virginia Commission, requesting a net increase in base rates of $25 million. If approved, the revised rate design would reflect the first increase in customer base rates since 1996. The rate adjustment is designed to recover the cost of investments in our pipeline infrastructure over the past ten years, including the Hampton Roads pipeline project, which was completed in January 2010. The rate application seeks a return on equity of 10.95%, and an authorization of equity to total capitalization ratio of 51%.

Interim rates are effective October 1, 2011, subject to refund, until the rate case is finalized. Under the proposed rate design, the typical residential customer’s bill would reflect an increase of $6.27 per month, or approximately 9%.

On October 13, 2011, Virginia Natural Gas filed rebuttal testimony in response to the recommendations of the Virginia Commission staff and the Virginia Attorney General’s office.  Virginia Natural Gas reduced its requested net increase in base rates to $22 million. The reduction is primarily the result to the Virginia Commission staff’s acceptance of Virginia Natural Gas’ proposal to recover certain gas related costs through its purchased gas adjustment mechanism. These costs were previously recovered through base rates. We have been in discussions with the parties to resolve various issues in the rate case. The Virginia Commission has scheduled a formal hearing for November 4, 2011 and a final commission order is expected by the end of 2011 or early 2012.

Capital Projects

We continue to focus on capital discipline and cost control, while moving ahead with projects and initiatives that we expect will have current and future benefits, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. The table below includes the amounts spent for the periods presented and the following discussions provide updates on some of our larger capital projects.

Distribution Operations

	Nine months ended September 30,
In millions	2011		2010
Pipeline replacement program	$	56	$	55
Integrated System Reinforcement Program		54		28
Integrated Customer Growth Program		4		2
Enhanced infrastructure program		19		41
Total	$	133	$	126

Atlanta Gas LightOn October 6, 2009, the Georgia Commission approved Atlanta Gas Light’s STRIDE program. As approved, STRIDE is comprised of the ongoing pipeline replacement program, which was started in 1998 and the new Integrated System Reinforcement Program (i-SRP).

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

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On January 19, 2010, the Georgia Commission also approved the Integrated Customer Growth Program (i-CGP) under STRIDE which authorized Atlanta Gas Light to extend Atlanta Gas Light’s pipeline facilities to serve customers who are currently without pipeline access and create new economic development opportunities in Georgia.

Elizabethtown Gas On April 16, 2009, the New Jersey BPU approved an accelerated enhanced infrastructure program, which was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. A regulatory cost recovery mechanism has been established whereby estimated rates go into effect at the beginning of each year. At the end of the program the regulatory cost recovery mechanism will be trued-up and any remaining costs not previously collected will be included in base rates. On May 16, 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012.

Energy Investments

Golden Triangle Storage Our Golden Triangle Storage project consists of a salt-dome storage facility in the Gulf Coast region of the U.S. designed for 13 Bcf of working natural gas capacity and total cavern capacity of 19 Bcf. The first cavern with 6 Bcf of working capacity was completed and began commercial service in September 2010. Golden Triangle Storage expects the second cavern will now consist of approximately 7 Bcf of working capacity and depending on market conditions, may expand this cavern. The second cavern is expected to be placed into commercial service in 2012. Our remaining estimate to complete the second cavern, based on current prices for labor, materials and pad gas, is approximately $30 million. We spent approximately $8 million in capital expenditures for this project for the nine months ended September 30, 2011.

At September 30, 2011, of the approximate 6 Bcf of working natural gas capacity available for subscription, Golden Triangle Storage had 4 Bcf of capacity subscribed with a third party and 2 Bcf under contract with Sequent. Accordingly, cavern one at Golden Triangle Storage has no remaining capacity available for subscription until March 2013.

Jefferson Island On June 30, 2010, Jefferson Island filed a permit application with the Louisiana Department of Natural Resources to expand its natural gas storage facility through the addition of two caverns. We continue to seek approval to expand our storage facility; however, we cannot predict when this approval will be obtained. The caverns would expand the working gas capacity at Jefferson Island from 7.5 Bcf to approximately 19.5 Bcf.

Asset Management Transactions

On March 30, 2011, the New Jersey BPU authorized the renewal of the asset management agreement between Elizabethtown Gas and Sequent. Expiring in March 2014, the renewed agreement requires Sequent to pay minimum annual fees of $5 million to Elizabethtown Gas and includes overall margin sharing levels of 70% to Elizabethtown Gas and 30% to Sequent. In October 2011, the Virginia Commission authorized the renewal of the asset management agreement between Virginia Natural Gas and Sequent. Expiring in March 2016, the minimum and overall sharing levels of the renewed agreement are consistent with the current agreement.

Results of Operations

We evaluate segment performance using the measures of operating margin and EBIT, which include the effects of corporate expense allocations. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of gas, which excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes and the gain or loss on the sale of our assets. These items are included in our calculation of operating income as reflected in our Condensed Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income, other income and expenses. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated level.

We believe operating margin is a better indicator than operating revenues for the contribution resulting from customer growth in our distribution operations segment since the cost of gas can vary significantly and is generally billed directly to our customers. We also consider operating margin to be a better indicator in our retail energy operations, wholesale services and energy investments segments since it is a direct measure of operating margin before overhead costs. We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

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You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, our operating margin or EBIT measures may not be comparable to similarly titled measures from other companies. The following table sets forth a reconciliation of our operating margin to operating income and EBIT to our earnings before income taxes and net income, together with other consolidated financial information for the periods presented.

	Three months ended September 30,									Nine months ended September 30,
In millions	2011			2010			Change			2011		2010		Change
Operating revenues	$	295		$	346		$	(51	)	$	1,548	$	1,708	$	(160	)
Cost of gas		112			120			(8	)		701		832		(131	)
Operating margin (1)		183			226			(43	)		847		876		(29	)
Operating expenses		159			164			(5	)		525		513		12
Operating income		24			62			(38	)		322		363		(41	)
Other income (expense)		1			(1	)		2			4		1		3
EBIT (1)		25			61			(36	)		326		364		(38	)
Interest expense, net		31			27			4			92		81		11
(Loss) earnings before income taxes		(6	)		34			(40	)		234		283		(49	)
Income tax (benefit) expense		(2	)		13			(15	)		85		103		(18	)
Net (loss) income		(4	)		21			(25	)		149		180		(31	)
Net (loss) income attributable to the noncontrolling interest		(1	)		(1	)		0			10		10		0
Net (loss) income attributable to AGL Resources Inc.	$	(3	)	$	22		$	(25	)	$	139	$	170	$	(31	)

(1) These are non-GAAP measurements.

For the third quarter of 2011, AGL Resources Inc. incurred a net loss of $3 million, versus net income of $22 million in the third quarter of 2010, a decline of $25 million. The decrease was primarily driven by lower operating margin from wholesale services. This decrease was partially offset by an increase in operating margins at distribution operations and energy investments, a decrease in operating expenses at distribution operations and retail energy operations and a decrease in income taxes due to lower earnings before income taxes. Additionally, during the three months ended September 30, 2011, we recorded approximately $8 million ($5 million net of tax) of transaction expenses associated with the proposed merger with Nicor, which are expensed as incurred. Explanations of the earnings variances for each operating segment are contained within the third quarter 2011 compared to third quarter 2010 discussion on the following pages.

For the nine months ended September 30, 2011, net income attributable to AGL Resources Inc. decreased by $31 million or 18% compared to the same period last year. The decrease was primarily the result of reduced operating margins at wholesale services and retail energy operations. This decrease was partially offset by higher operating margins at distribution operations and a decrease in income taxes as a result of lower year-to-date earnings. Additionally, during the nine months ended September 30, 2011, we recorded approximately $26 million ($16 million net of tax) of transaction expenses associated with the proposed merger with Nicor, which are expensed as incurred. The variances for each operating segment are contained within the year-to-date 2011 compared to year-to-date 2010 discussion on the following pages.

Our interest expenses increased by $4 million or 15% for the third quarter of 2011 compared to the third quarter of 2010. The increase resulted from higher average debt outstanding, primarily the result of the additional long-term debt issuance in March 2011, a portion of which is anticipated to be used to fund the proposed Nicor merger. Interest expenses for the nine months ended September 30, 2011 increased by $11 million or 14% due to the same factors that impacted the third quarter.

Our income tax expense decreased by $15 million for the third quarter of 2011 compared to the third quarter of 2010; and $18 million or 17% for the nine months ending September 30, 2011 compared to the same period of 2010. This was primarily due to lower consolidated earnings. Our income tax expense is determined from earnings before income taxes less net income attributable to the noncontrolling interest.

Selected weather, customer and volume metrics, which we consider to be some of the key performance indicators for our operating segments, for the three and nine months ended September 30, 2011 and 2010, are presented in the following tables. We measure the effects of weather on our business through Heating Degree Days. Generally, increased Heating Degree Days result in greater demand for gas on our distribution systems. However, extended and unusually mild weather during the Heating Season can have a significant negative impact on demand for natural gas. Our customer metrics highlight the average number of customers to which we provide services. This number of customers can be impacted by natural gas prices, economic conditions and competition from alternative fuels.

Volume metrics for distribution operations and retail energy operations present the effects of weather and our customers’ demand for natural gas. Wholesale services’ daily physical sales represent the daily average natural gas volumes sold to its customers. Within our energy investments segment, our natural gas storage businesses seek to have a significant percentage of their working natural gas capacity under firm subscription, but also take into account current and expected market conditions. This allows our natural gas storage business to generate additional revenue during times of peak market demand for natural gas storage services, but retain some consistency with their earnings and maximize the value of the investments.

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Weather
Heating degree days (1)
	Nine months ended September 30,						2011 vs. normal colder			2011 vs. 2010 colder
	Normal		2011		2010			(warmer)			(warmer)
Georgia		1,643		1,602		2,022		(2	)%		(21	)%
New Jersey		3,020		2,949		2,725		(2	)%		8	%
Virginia		2,091		2,092		2,221		0	%		(6	)%
Florida		377		244		743		(35	)%		(67	)%
Tennessee		1,869		1,849		2,212		(1	)%		(16	)%
Maryland		3,023		3,026		2,857		0	%		6	%
Ohio		3,070		3,093		3,153		1	%		(2	)%

(1)   Obtained from weather stations relevant to our service areas at the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages from 2002 through September 30, 2011.
Customers	Three months ended September 30,									Nine months ended September 30,
	2011			2010			% change			2011			2010			% change
Distribution Operations
Average end-use customers (in thousands)
Atlanta Gas Light		1,518			1,520			(0.1	)%		1,546			1,549			(0.2	)%
Elizabethtown Gas		275			274			0.4	%		276			274			0.7	%
Virginia Natural Gas		275			272			1.1	%		278			275			1.1	%
Florida City Gas		103			103			0.0	%		103			104			(1.0	)%
Chattanooga Gas		61			60			1.7	%		62			62			0.0	%
Elkton Gas		6			6			0.0	%		6			6			0.0	%
Total		2,238			2,235			0.1	%		2,271			2,270			0.0	%
Retail Energy Operations
Average customers (in thousands)
Georgia		482			487			(1	)%		491			499			(2	)%
Ohio and Florida (2)		94			66			42	%		87			81			7	%
Total		576			553			4	%		578			580			0	%
Market share in Georgia		32.5	%		32.7	%		(0.6	)%		32.4	%		32.9	%		(1.5	)%
(2)   A portion of the Ohio customers represents customer equivalents, which are computed by the actual delivered volumes divided by the expected average customer usage.

Volumes In billion cubic feet (Bcf)	Three months ended September 30,									Nine months ended September 30,
	2011			2010			% change			2011		2010		% change
Distribution Operations
Firm		20			21			(5	)%		147		169		(13	)%
Interruptible		25			22			14	%		78		70		11	%
Total		45			43			5	%		225		239		(6	)%
Retail Energy Operations
Georgia firm		3			3			0	%		25		31		(19	)%
Ohio and Florida		1			1			0	%		6		7		(14	)%
Wholesale Services
Daily physical sales (Bcf/day)		4.9			4.5			9	%		5.1		4.4		16	%
	As of September 30,
		2011			2010		% change
Energy Investments
Working natural gas capacity		13.5			13.5			0	%
% of capacity under subscription (3)		67	%		51	%		31	%

(3)    The percentage of capacity under subscription does not include the 4 Bcf of capacity under contract with Sequent at September 30, 2011, and the 2 Bcf of capacity under contract with Sequent at September 30, 2010.  

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Third quarter 2011 compared to third quarter 2010

Operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the three months ended September 30, 2011 and 2010.

	2011								2010
In millions	Operating margin (1)			Operating expenses		EBIT (1)			Operating margin (1)		Operating expenses		EBIT (1)
Distribution operations	$	193		$	125	$	70		$	183	$	128	$	55
Retail energy operations		11			16		(5	)		10		19		(9	)
Wholesale services		(29	)		8		(37	)		26		12		15
Energy investments		9			7		2			6		5		1
Corporate (2)		(1	)		3		(5	)		1		0		(1	)
Consolidated	$	183		$	159	$	25		$	226	$	164	$	61

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

(2)   The increase in operating expenses of $3 million is primarily due to transaction expenses associated with the proposed merger with Nicor. For more information see Note 3. Additionally, includes intercompany eliminations.

Distribution operations’ EBIT increased by $15 million or 27% compared to last year as shown in the following table.

In millions
EBIT for third quarter of 2010				$	55
Operating margin
Increased revenues from new rates and regulatory infrastructure program revenues at Atlanta Gas Light	$	9
Increased revenues from customer growth, higher usage and enhanced infrastructure program revenues at Elizabethtown Gas		1
Increase in operating margin					10
Operating expenses
Decreased incentive compensation expenses	$	(8	)
Increased depreciation expense		3
Decreased bad debt expenses		(2	)
Increased outside services and other expenses		4
Decrease in operating expenses					(3	)
Increase in other income					2
EBIT for third quarter of 2011				$	70

Retail energy operations’ EBIT increased by $4 million or 45% compared to last year as shown in the following table.

In millions
EBIT for third quarter of 2010				$	(9	)
Operating margin
Increased optimization of storage and transportation assets, partially offset by unfavorable retail pricing plan mix	$	2
Other		(1	)
Increase in operating margin					1
Operating expenses
Decreased legal expense, partially offset by increased marketing expenses	$	(3	)
Decrease in operating expenses					(3	)
EBIT for third quarter of 2011				$	(5	)

Wholesale services’ EBIT decreased by $52 million compared to last year as shown in the following table. The decreases to operating margin are discussed in more detail below the table.

In millions
EBIT for third quarter of 2010				$	15
Operating margin
Change in commercial activity	$	(35	)
Change in transportation hedge movements from the narrowing of transportation basis spreads in 2011 as compared to the widening of transportation basis spreads in 2010		(5	)
Change in storage hedge movements as a result of changing NYMEX natural gas prices		(11	)
Change in LOCOM adjustment		(4	)
Decrease in operating margin					(55	)
Operating expenses
Decreased incentive compensation and other employee related costs	$	(4	)
Decrease in operating expenses					(4	)
Decrease in other income					(1	)
EBIT for third quarter of 2011				$	(37	)

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Change in Commercial activity The reduction in commercial activity reflects significantly lower natural gas price volatility impacting daily and intra-day storage and transportation spreads, as well as losses associated with the forward purchase and sale of natural gas generally held for use under forward transportation contracts. Our wholesale services segment also incurred credit losses of $2 million during the third quarter 2011 ($4 million on a year-to-date basis) associated with a counterparty that filed for bankruptcy during the early part of the third quarter.

Natural gas shale production in the Northeast, specifically from the Marcellus region, is resulting in new pipeline capacity constraints. During the third quarter, our wholesale services segment experienced constraints for natural gas purchased from producers in the Marcellus region, resulting in the sale of shale natural gas at a loss, higher transportation costs and the renegotiation of certain of Sequent’s producer contracts. Total losses related to these constraints during the third quarter of 2011 were approximately $15 million. We expect similar negative impacts to operating margin from these pipeline capacity constraints during the fourth quarter of 2011, but in the range of $4 million to $6 million.

Change on storage and transportation hedges Storage spreads continue to be significantly lower than in 2010 and overall natural gas price volatility remained low during the third quarter of 2011. Gains in the in the third quarter of 2010 were primarily due to significantly larger seasonal storage spreads at the time the hedges were executed and the subsequent downward movement of natural gas prices during the quarter of last year.

The following table indicates the components of wholesale services’ operating margin for the three months ended September 30, 2011 and 2010.

In millions	2011			2010
Gain on transportation hedges	$	0		$	5
Gain on storage hedges		14			25
Commercial activity recognized		(34	)		1
Change in LOCOM adjustment		(9	)		(5	)
Operating margin	$	(29	)	$	26

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

In millions
EBIT for third quarter of 2010				$	1
Operating margin
Increased revenues at Golden Triangle Storage as a result of the start of commercial service in September 2010	$	3
Increase in operating margin					3
Operating expenses
Decreased operating expenses due to sale of AGL Networks, LLC	$	(2	)
Increase in operating and depreciation expenses at Golden Triangle Storage as a result of the start of commercial service in September 2010		2
Increased outside services and other expenses		2
Increase in operating expenses					2
EBIT for third quarter of 2011				$	2

Year-to-date 2011 compared to Year-to-date 2010

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, 2011 and 2010.

	2011								2010
In millions	Operating margin (1)			Operating expenses		EBIT (1)			Operating margin (1)		Operating expenses		EBIT (1)
Distribution operations	$	676		$	393	$	287		$	645	$	388	$	260
Retail energy operations		117			53		64			124		58		66
Wholesale services		29			38		(9	)		76		39		38
Energy investments		26			22		4			30		25		4
Corporate (2)		(1	)		19		(20	)		1		3		(4	)
Consolidated	$	847		$	525	$	326		$	876	$	513	$	364

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

(2)   The increase in operating expenses of $16 million is primarily due to transaction expenses associated with the proposed merger with Nicor. For more information see Note 3. Additionally, includes intercompany eliminations.

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Distribution operations’ EBIT increased by $27 million or 10% compared to last year as shown in the following table.

In millions
EBIT for nine months of 2010				$	260
Operating margin
Increased revenues from new rates and regulatory infrastructure program revenues at Atlanta Gas Light	$	26
Increased revenues from customer growth, higher usage and enhanced infrastructure program revenues at Elizabethtown Gas		6
Decreased revenues from lower usage at Florida City Gas due to warmer weather in the first quarter of 2011		(1	)
Increase in operating margin					31
Operating expenses
Decreased compensation expenses	$	(4	)
Increased pension expense		2
Increased depreciation expense		6
Decreased bad debt expenses		(3	)
Increased outside services and other expenses		4
Increase in operating expenses					5
Increase in other income					1
EBIT for nine months of 2011				$	287

Retail energy operations’ EBIT decreased by $2 million or 3% compared to last year as shown in the following table.

In millions
EBIT for nine months of 2010				$	66
Operating margin
Decreased average customer usage due to warmer weather mainly in the first quarter of 2011	$	(3	)
Decrease related to retail pricing plan mix and optimization of storage and transportation assets		(2	)
Other		(2	)
Decrease in operating margin					(7	)
Operating expenses
Decreased legal expense, partially offset by increased marketing expenses	$	(3	)
Decreased bad debt and other expenses		(2	)
Decrease in operating expenses					(5	)
EBIT for nine months of 2011				$	64

Wholesale services’ EBIT decreased by $47 million or 124% compared to last year as shown in the following table.

In millions
EBIT for nine months of 2010				$	38
Operating margin
Change in storage hedge gains as a result of changing NYMEX natural gas prices	$	(22	)
Change in commercial activity		(17	)
Change in transportation hedge gains due to narrowing of transportation basis spreads		(4	)
Change in LOCOM adjustment		(4	)
Decrease in operating margin					(47	)
Operating expenses
Decreased incentive compensation and other employee related costs	$	(1	)
Decrease in operating expenses					(1	)
Decrease in other income					(1	)
EBIT for nine months of 2011				$	(9	)

The following table indicates the components of wholesale services’ operating margin for the nine months ended September 30, 2011 and 2010.

In millions	2011			2010
Commercial activity recognized	$	20		$	37
Gain on transportation hedges		2			6
Gain on storage hedges		16			38
Inventory LOCOM adjustment, net of estimated current period recoveries		(9	)		(5	)
Operating margin	$	29		$	76

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Energy investments’ EBIT remained flat compared to last year as shown in the following table.

In millions
EBIT for nine months of 2010				$	4
Operating margin
Decreased operating revenues due to sale of AGL Networks, LLC	$	(11	)
Increased revenues at Golden Triangle Storage as a result of the start of commercial service in September 2010		7
Decrease in operating margin					(4	)
Operating expenses
Decreased operating expenses due to sale of AGL Networks, LLC	$	(11	)
Increase in operating and depreciation expenses at Golden Triangle Storage as a result of the start of commercial service in September 2010		6
Increased outside services and other expenses		2
Decrease in operating expenses					(3	)
Decrease in other expense					(1	)
EBIT for nine months of 2011				$	4

Liquidity and Capital Resources

Overview The acquisition of natural gas and pipeline capacity, payment of dividends and working capital requirements are our most significant short-term financing requirements. The need for long-term capital is driven primarily by capital expenditures and maturities of long-term debt. The liquidity required to fund our working capital, capital expenditures and other cash needs is primarily provided by our operating activities. Our short-term cash requirements not met by cash from operations are primarily satisfied with short-term borrowings under our commercial paper program, which is supported by our Credit Facility. Periodically, we raise funds supporting our long-term cash needs from the issuance of long-term debt or equity securities. We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner.

Our capital market strategy has continued to focus on maintaining a strong Consolidated Statement of Financial Position, ensuring ample cash resources and daily liquidity, accessing capital markets at favorable times as necessary, managing critical business risks and maintaining a balanced capital structure through the appropriate combination of equity or long-term debt securities.

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

We believe the amounts available to us under our senior notes, Credit Facility, through the issuance of debt and equity securities, combined with cash provided by operating activities, will continue to allow us to meet our needs for working capital, pension contributions, construction expenditures,anticipated debt redemptions, interest payments on debt obligations, dividend payments, common share repurchases, financing requirements for the proposed Nicor merger and other cash needs through the next several years. Our ability to satisfy our working capital requirements and debt service obligations, or fund planned capital expenditures, will substantially depend upon our future operating performance (which will be affected by prevailing economic conditions), and financial, business and other factors, some of which we are unable to control. These factors include, among others, regulatory changes, the price of natural gas, the demand for natural gas and operational risks.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies, the proposed merger with Nicor and other factors. See Item 1A, “Risk Factors,” of our 2010 Form 10-K, for additional information on items that could impact our liquidity and capital resource requirements.

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 versus 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, 2011, our variable-rate debt was 18% of our total debt, compared to 27% as of September 30, 2010. The decrease in our percentage of variable-rate debt as of September 30, 2011, compared to the same period last year, was primarily due to our securing $1.0 billion in fixed-rate debt during 2011 and that we did not have any commercial paper borrowings as of September 30, 2011. This was partially offset by our $250 million interest rate swaps entered into during May 2011.

Proposed Merger FinancingOn the date of the merger, each outstanding share of Nicor common stock, other than shares to be cancelled and Dissenting Shares, as defined in the Merger Agreement, will be converted into the right to receive consideration of (i) 0.8382 of a share of our common stock and (ii) $21.20 in cash. The value of the consideration to be paid to Nicor shareholders is equal to approximately $2.6 billion based upon the closing price of our common stock on the New York Stock Exchange on October 31, 2011 and the amount of Nicor shares outstanding; however, this amount will fluctuate with changes in the price of our common stock. A 10% change in the market price of our common stock as of October 31, 2011 would increase or decrease the total consideration by approximately $162 million, which would be reflected as an increase in or decrease to the purchase consideration to be paid to the shareholders of Nicor. We anticipate incurring indebtedness in connection with financing the cash portion of the purchase consideration equal to approximately $977 million, and to pay transaction fees and expenses. At the closing of the proposed Nicor merger, we will also assume all of Nicor’s outstanding debt, which was approximately $811 million at September 30, 2011.

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In December 2010, we entered into a 364-day Bridge Facility to provide temporary financing in the event that permanent financing could not be completed prior to closing the proposed merger. The Bridge Facility allowed us to borrow up to $1.05 billion, with proceeds to be used to fund the cash portion of the purchase consideration and to pay related fees and expenses for the proposed merger. Following our 2011 issuances of senior notes, discussed below, we gave notice to the administrative agent to terminate the Bridge Facility.

We have issued or secured long-term debt financing to pay the cash portion of the purchase consideration. This includes approximately $200 million from our $500 million in senior notes that were issued on March 16, 2011, $500 million in senior notes that were issued on September 15, 2011 and $275 million in senior notes that were issued in the private placement market on October 27, 2011.

Credit RatingsOur borrowing costs and ability to obtain adequate and cost effective financing are directly impacted by our credit ratings as well as the availability of financial markets. In addition, credit ratings are important to counterparties when we engage in certain transactions including over-the-counter derivatives. It is our long-term objective to maintain or improve our credit ratings on our debt in order to manage our existing financing costs and enhance our ability to raise additional capital on favorable terms.

Credit ratings and outlooks are opinions subject to ongoing review by the rating agencies and may periodically change. Each rating should be evaluated independently of any other rating. The rating agencies regularly review our performance, prospects and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, including our corporate ratings. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. A credit rating is not a recommendation to buy, sell or hold securities.

Factors we consider important in assessing our credit ratings include our Statements of Financial Position leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any agreements that would require us to issue equity based on credit ratings or other trigger events. The following table summarizes our credit ratings as of September 30, 2011, and reflects no change from December 31, 2010.

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

In December 2010, subsequent to the announcement of our proposed merger with Nicor, S&P placed our long-term debt ratings and our corporate credit ratings on credit watch with negative implications. The primary reason for this change is the increased leverage we will assume to complete the proposed merger and the uncertainties that exist with the proposed merger.

Our credit ratings depend largely on our financial performance, and a downgrade in our current ratings, particularly below investment grade, could adversely affect our borrowing costs and significantly limit our access to the commercial paper market. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources would decrease.

Default provisions As of September 30, 2011, December 31, 2010 and September 30, 2010, we were in compliance with all of our debt provisions and covenants, both financial and non-financial. Additionally, our Bridge Facility contains the same financial covenant and similar non-financial covenants ad default provisions as contained in our Credit Facility: however, most of these are not in effect until we draw under the facility.

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Our ratio, on a consolidated basis, of total debt to total capitalization is typically greater at the beginning of the Heating Season as we make additional short-term borrowings to fund our natural gas purchases and meet our working capital requirements. We intend to maintain our capitalization ratio in a target range of 50% to 60%. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings. For more information on our default provisions see Note 7. The components of our capital structure, as calculated from our Condensed Consolidated Statements of Financial Position, as of the dates indicated, are provided in the following table.

	Sep. 30, 2011			Dec. 31, 2010			Sep. 30, 2010
Short-term debt		0	%		23	%		23	%
Long-term debt		59			37			35
Total debt		59			60			58
Equity		41			40			42
Total capitalization		100	%		100	%		100	%

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the periods presented.

	Nine months ended September 30,
In millions	2011			2010
Net cash provided by (used in):
Operating activities	$	560		$	554
Investing activities		(292	)		(301	)
Financing activities		(127	)		(265	)
Net increase (decrease) in cash and cash equivalents	$	141		$	(12	)

Cash Flow from Operating Activities In the first nine months of 2011, our net cash flow provided from operating activities was $560 million, an increase of $6 million, which is in line with our operating cash flow from the same period in 2010. This increase resulted from a $59 million decrease in cash collateral requirements for our derivative financial instrument activities due to the change in forward NYMEX curve prices in 2011 and a $33 million change in deferred natural gas costs primarily due to decreased natural gas costs at Virginia Natural Gas and Elizabethtown Gas. Offsetting this, we had a $53 million decrease in operating cash flow resulting from loaned gas activities associated with park and loan gas transactions which was due in part to fewer opportunities resulting from a weakening of storage price differentials. Additionally, we had a $36 million increase in cash used by energy marketing receivables and payables (net) as a result of increased purchase volumes at Sequent.

Cash Flow from Investing Activities Our investing activities consisted of PP&E expenditures of $292 million for the nine months ended September 30, 2011, compared to $370 million for the same period in 2010. The decrease of $78 million, or 21%, in PP&E expenditures was primarily due to a $85 million decrease in expenditures for the construction of the Golden Triangle Storage natural gas storage facility due to the completion of base infrastructure spending and completion of the first cavern, offset by an $8 million increase in expenditures at Meadow Branch related to the landfill gas project. This net decrease was partially offset by the proceeds received in the prior year from our 2010 disposition of AGL Networks.

Cash Flow from Financing Activities

Short-term debt Our short-term debt during the first nine months of 2011 was composed of borrowings and payments under our Credit Facility and commercial paper program, the current portion of our capital leases and our senior notes maturing in less than one year.

In millions	Period end balance outstanding (1)		Daily average balance outstanding (2)		Largest balance outstanding (2)
Current portion of long-term debt	$	15	$	21	$	300
Capital leases		2		2		2
Commercial paper		0		282		835
Term loan facility (3)		0		16		150

(1)   As of September 30, 2011.

(2)   For the nine months ended September 30, 2011.

(3)   On February 14, 2011, the Term Loan Facility was repaid through additional commercial paper borrowings at which time the Term Loan Facility expired.

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

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During the nine months ended September 30, of 2011, our short-term debt balances were also impacted by our September 15, 2011 concurrent public offerings of senior notes in the aggregate principal amount of $500 million which was used to completely repay all of our outstanding commercial paper borrowings as of September 30, 2011. We had outstanding commercial paper borrowings of $732 million at December 31, 2010 and $674 million at September 30, 2010.

The timing of natural gas withdrawals is dependent on the weather and natural gas market conditions, both of which impact the price of natural gas. Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected purchases during the upcoming injection season, we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.

The lenders under our Credit Facility and Bridge Facility as of September 30, 2011 are all major financial institutions with approximately $1.6 billion of committed balances and all have investment grade credit ratings. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal. As of September 30, 2011 and 2010, we had no outstanding borrowings on our Credit Facility or Bridge Facility.

Long-term debt On March 16, 2011, we completed a public offering of $500 million of 30 year senior notes with an interest rate of 5.9%. A portion of the net proceeds of this offering was used to pay down the commercial paper borrowings that were used to repay the $300 million of senior notes that matured on January 14, 2011.

On September 15, 2011, we completed two concurrent public offerings of senior notes in the aggregate principal amount of $500 million, comprised of an incremental $200 million of our 5.9% senior notes due 2041 and $300 million in new 3.5% senior notes that are due in 2021.

On October 27, 2011, we completed an issuance of $275 million in senior notes in the private placement market, comprised of $120 million of Series A senior notes due 2016 at an initial interest rate of 1.9% and $155 million of Series B senior notes due 2016 at an interest rate of 3.5%.

Other than as set forth above with respect to $300 million of our March 2011 public offering, the proceeds from these issuances are expected to be used to pay a portion of the cash consideration and expenses incurred in connection with the proposed merger with Nicor, if completed, or for other general corporate purposes.  

Noncontrolling InterestWe recorded a cash distribution for SouthStar’s dividends paid to Piedmont of $16 million for the nine months ended September 30, 2011 and $27 million for the nine months ended September 30, 2010. The primary reason for the reduction in the distribution to Piedmont is due to our increased ownership percentage in SouthStar in 2010, as the current year distribution was paid on 2010 earnings and the 2010 distribution was paid on the 2009 earnings.

Dividends on Common StockOur common stock dividend payments were $102 million for the nine months ended September 30, 2011 and $99 million for the nine months ended September 30, 2010. The increase was generally the result of an annual dividend increase of $0.04 per share last year.

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material effect on liquidity or the availability of requirements for capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. For additional information on our obligations and commitments, see Note 9.

Pension ContributionsIn the first nine months of 2011 we contributed $50 million to our qualified pension plans and an additional $6 million in October 2011 for a total of $56 million during 2011. We do not plan to make any additional contributions during 2011. In the nine months ended September 30, 2010, we contributed $26 million to our pension plans.

During the nine months ended September 30, 2011, we recorded net periodic benefit costs of $15 million related to our defined pension and postretirement benefit plans compared to $13 million during the same period last year. We estimate that during the remainder of 2011, we will record net periodic pension and other postretirement benefit costs in the range of $4 million to $6 million, a $1 million increase compared to 2010. In determining our estimated expenses for 2011, our actuarial consultant assumed an 8.50% expected return on plan assets and a discount rate of 5.40% for the AGL Retirement Plan and 5.20% for the NUI Retirement Plan and for our postretirement plan.

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The following table illustrates our expected future contractual obligation payments such as debt and lease agreements, and commitments and contingencies as of September 30, 2011.

													2016 &
In millions	Total		2011		2012		2013		2014		2015		Thereafter
Recorded contractual obligations:
Long-term debt	$	2,687	$	0	$	0	$	225	$	0	$	200	$	2,262
Regulatory infrastructure program costs (1)		257		11		108		138		0		0		0
Environmental remediation liabilities (1)		189		4		27		31		32		18		77
Short-term debt and current portion of long-term debt		17		2		15		0		0		0		0
Total	$	3,150	$	17	$	150	$	394	$	32	$	218	$	2,339

Unrecorded contractual obligations and commitments(2) (7):
Pipeline charges, storage capacity and gas supply (3)	$	1,750	$	156	$	455	$	320	$	202	$	123	$	494
Interest charges (4)		2,118		34		133		126		123		113		1,589
Operating leases (5)		188		5		19		20		17		16		111
Asset management agreements (6)		20		3		10		6		1		0		0
Standby letters of credit, performance / surety bonds		15		1		14		0		0		0		0
Total	$	4,091	$	199	$	631	$	472	$	343	$	252	$	2,194

(1)   Includes amounts recoverable through rate rider mechanisms. For more on our environmental remediation liabilities, see Note 9.

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

(3)   Includes amounts recoverable through a natural gas cost recovery mechanism or alternatively billed to Marketers, and includes demand charges associated with Sequent. Also includes SouthStar’s natural gas purchase commitments of 10 Bcf at floating gas prices calculated using forward natural gas prices as of September 30, 2011, and are valued at $40 million.

(4)   Floating rate debt is based on the interest rate as of September 30, 2011, and the maturity of the underlying debt instrument. As of September 30, 2011, we have $35 million of accrued interest on our Condensed Consolidated Statements of Financial Position that will be paid over the next 12 months.

(5)   We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with authoritative guidance related to leases. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein. Additionally, minimum payments have not been reduced by minimum sublease rentals of $13 million due in the future under noncancelable subleases.

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

(7)   The Merger Agreement with Nicor contains termination rights for both us and Nicor and provides that, if we terminate the agreement under specified circumstances, we may be required to pay a termination fee of $67 million. In addition, if we terminate the agreement due to a failure to obtain the necessary financing for the transaction, we may also be required to pay Nicor $115 million: however, given that we have issued, or secured, long-term debt financing to pay the cash portion of the purchase consideration, the risk of having to pay this $115 million fee has been greatly reduced.

Critical Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience, where applicable, and various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates on an ongoing basis, and our actual results may differ from these estimates. Our critical accounting estimates used in the preparation of our Condensed Consolidated Financial Statements include the following:

·   Regulatory Infrastructure Program Liabilities

·   Environmental Remediation Liabilities

·   Derivatives and Hedging Activities

·   Contingencies

·   Pension and Other Postretirement Plans

·   Income Taxes

Each of our critical accounting estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. There have been no significant changes to our critical accounting estimates from those disclosed in our Management’s Discussion and Analysis of Financial Condition and Results of Operation as filed on our 2010 Form 10-K.

Accounting Developments

On May 12, 2011, the FASB issued authoritative guidance related to fair value measurements. The guidance expands the qualitative and quantitative disclosures for Level 3 significant unobservable inputs, permits the use of premiums and discounts to value an instrument if it is standard practice and limits best use valuation to non-financial assets and liabilities. This guidance will be effective for us beginning January 1, 2012. We do not expect the guidance to have a material impact on our consolidated financial statements.

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On June 16, 2011, the FASB issued authoritative guidance related to comprehensive income. The guidance eliminates the option to present other comprehensive income in the Statements of Equity, but instead allows companies to elect to present net income and other comprehensive income in one continuous statement (Statements of Comprehensive Income) or in two consecutive statements. This guidance does not change any of the components of net income or other comprehensive income and earnings per share will still be calculated based on net income. This guidance will be effective for us beginning January 1, 2012. This guidance will not have a material impact on our consolidated financial statements.

On September 15, 2011, the FASB issued authoritative guidance related to goodwill impairment testing. The guidance provides us with the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the total events or circumstances, we determine that it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step impairment test is unnecessary. However, if we conclude otherwise, then we are required to perform the first step of the two-step impairment test by calculating the fair value of the reporting unit and comparing the fair value with the carrying amount of the reporting unit. The guidance also gives us the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test and resume performing the qualitative assessment in any subsequent period. This guidance will be effective for our goodwill impairment testing beginning January 1, 2012.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Our Risk Management Committee (RMC) is responsible for establishing the overall risk management policies and monitoring compliance with, and adherence to, the terms within these policies, including approval and authorization levels and delegation of these levels. Our RMC consists of members of senior management who monitor open natural gas price risk positions and other types of risk, corporate exposures, credit exposures and overall results of our risk management activities. It is chaired by our chief risk officer, who is responsible for ensuring that appropriate reporting mechanisms exist for the RMC to perform its monitoring functions. Our risk management activities and related accounting treatment for our derivative financial instruments are described in further detail in Note 5.

The following tables include the fair value and average values of our consolidated derivative financial instruments as of the dates indicated. We base the average values on monthly averages for the nine months ended September 30, 2011 and 2010.

	Derivative financial instruments average values (1) at September 30,
In millions	2011		2010
Asset	$	195	$	233
Liability		46		99

(1)   Excludes cash collateral amounts.

	Derivative financial instruments fair values netted with cash collateral at
In millions	Sep. 30, 2011		Dec. 31, 2010		Sep. 30, 2010
Asset	$	186	$	228	$	269
Liability		59		48		90

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The following tables illustrate the change in the net fair value of our derivative financial instruments during the periods presented, and provide details of the net fair value of contracts outstanding as of the periods presented.

	Three months ended						Nine months ended
	September 30,						September 30,
In millions	2011			2010			2011			2010
Net fair value of derivative financial instruments outstanding at beginning of period	$	46		$	77		$	75		$	121
Derivative financial instruments realized or otherwise settled during the period		(15	)		(26	)		(72	)		(93	)
Change in the net fair value of derivative financial instruments		17			37			45			60
Net fair value of derivative financial instruments outstanding at end of period		48			88			48			88
Netting of cash collateral		79			91			79			91
Cash collateral and net fair value of derivative financial instruments outstanding at end of period	$	127		$	179		$	127		$	179

The sources of net fair value of our derivative financial instruments at September 30, 2011, are as follows:

In millions	Prices actively quoted (Level 1) (1)			Significant other observable inputs (Level 2) (2)
Mature through
2011	$	3		$	11
2012 – 2013		(48	)		70
2014 – 2016		12			0
Total derivative financial instruments (3)	$	(33	)	$	81

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

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

(3)   Excludes cash collateral amounts.

Natural Gas Price Risk

Value at Risk Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the chief risk officer. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally immaterial, permitting us to operate within relatively low VaR limits. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of its open positions. See Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Summary - Natural gas price volatility and energy marketing activities, for additional information about natural gas prices.

Management actively monitors open natural gas positions and the resulting VaR. We continue to maintain a relatively matched book, where our total buy volume is close to sell volume with minimal open natural gas price risk. Based on a 95% confidence interval and employing a 1-day holding period for all positions, our portfolio of positions for the periods presented had the following VaRs.

	Three months ended				Nine months ended
	September 30,				September 30,
In millions	2011		2010		2011		2010
Period end	$	1.9	$	1.1	$	1.9	$	1.1
Average		1.8		1.4		1.5		1.4
High		2.9		2.0		2.9		3.0
Low		0.8		1.1		0.8		0.7

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $410 million of variable-rate debt outstanding at September 30, 2011, a 100 basis point change in average market interest rates would have resulted in an increase in pretax interest expense of $4 million on an annualized basis.

We have $300 million of 6.4% senior notes due in July 2016. In May 2011, we entered into interest rate swaps related to these senior notes to effectively convert a nominal amount of $250 million from fixed rate senior notes to a variable rate obligation. The interest rate resets quarterly based on LIBOR plus 3.9%. This helps us achieve our desired mix of variable to fixed rate debt (i.e. variable debt target of 20% to 45% of total debt). For additional information, see Note 5.

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.

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Additionally, Sequent may require counterparties to pledge additional collateral when deemed necessary. Sequent conducts credit evaluations and obtains appropriate internal approvals for its counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, Sequent requires credit enhancements by way of guaranty, cash deposit or letter of credit for counterparties that do not have investment grade ratings.

Sequent, which provides services to marketers and utility and industrial customers, also has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. As of September 30, 2011, Sequent’s top 20 counterparties represented approximately 55% of the total counterparty exposure of $372 million. Sequent’s counterparties, or the counterparties’ guarantors, had a weighted-average S&P equivalent credit rating of BBB+ at September 30, 2011, December 31, 2010 and September 30, 2010. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P and Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being the equivalent to AAA/Aaa by S&P and Moody’s and 1 being D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios for that counterparty. To arrive at the weighted-average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent.

The following table shows Sequent’s third-party natural gas contracts receivable and payable positions as of the periods presented.

	Gross receivables						Gross payables
	Sep. 30,		Dec. 31,		Sep. 30,		Sep. 30,		Dec. 31,		Sep. 30,
In millions	2011		2010		2010		2011		2010		2010
Netting agreements in place:
Counterparty is investment grade	$	364	$	515	$	335	$	275	$	341	$	231
Counterparty is non-investment grade		8		11		10		22		40		25
Counterparty has no external rating		133		260		99		280		363		259
No netting agreements in place:
Counterparty is investment grade		4		2		8		6		0		1
Counterparty has no external rating		3		0		1		3		0		0
Amount recorded on statements of financial position	$	512	$	788	$	453	$	586	$	744	$	516

Sequent has certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, Sequent would need to post collateral to continue transacting business with some of its counterparties. If such collateral were not posted, Sequent’s ability to continue transacting business with these counterparties would be negatively impacted. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $14 million at September 30, 2011, which would not have a material impact to our condensed consolidated results of operations, cash flows or financial condition.

There have been no other significant changes to our credit risk related to our other segments, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our 2010 Form 10-K.

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, 2011, the end of the period covered by this report. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2011, in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

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(b) Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting that occurred during the third quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

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

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

We have been named as a defendant in several class action lawsuits brought by purported Nicor shareholders challenging Nicor’s proposed merger with us. The complaints allege that we aided and abetted alleged breaches of fiduciary duty by Nicor’s Board of Directors. The shareholder lawsuits seek, among other things, declaratory and injunctive relief, including orders enjoining the defendants from completing the proposed merger and, in certain circumstances, damages. In March 2011, the parties entered into an agreement to resolve all of the shareholder lawsuits, subject to court approval, based on Nicor providing certain supplemental disclosures to our joint proxy statement filed on April 28, 2011. The court has preliminarily approved the agreement, a fairness hearing is set for December 11, 2011 and we expect the court to approve the agreement at this hearing. This lawsuit will have no effect on the closing of the merger.

For more information regarding some of these proceedings, see Note 9 under the caption “Litigation.”

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, "Item 1A. Risk Factors" in our 2010 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in this report and in our 2010 Form 10-K are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. The following risk factors have changed since filing our 2010 Form 10-K.

Risks Related to Our Proposed Merger with Nicor

The merger may be subject to review by the governmental authorities of various other federal, state or local jurisdictions under the antitrust and utility regulation or other applicable laws of those jurisdictions.

We provided a voluntary notice of the merger to the New Jersey BPU and the Maryland Public Service Commission (Maryland Commission), which included a description of the transaction, described the benefits of the transaction and explained why we do not believe that the approval of the New Jersey BPU or Maryland Commission is required to complete the merger. In May 2011, the Maryland Commission issued a letter stating that it had reviewed the notification of proposed merger filed by the Company and after considering the matter, noted the transaction. It is possible that the New Jersey BPU will open proceedings to determine whether they have jurisdiction over the merger. In the event that they are determined to have jurisdiction over the merger transaction, there can be no assurance that the reviewing authorities will approve the merger without restrictions or conditions (which are difficult to predict or quantify) that would have a material adverse effect on the combined company if the merger were completed.

Our indebtedness following the merger will be higher than our existing indebtedness, which could limit our operations and opportunities, make it more difficult for us to pay or refinance our debts and may cause us to issue additional equity in the future, which would increase the dilution of our shareholders or reduce earnings.

In connection with the merger, we will assume Nicor’s outstanding debt. Our total indebtedness as of December 31, 2010 was approximately $2.7 billion. Our pro forma total indebtedness as of December 31, 2010, after giving effect to the merger, would have been approximately $4.7 billion (including approximately $0.3 billion of currently payable long-term debt, approximately $1.2 billion of short-term borrowings and approximately $3.2 billion of long-term debt and other long-term obligations).

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Our debt service obligations with respect to this increased indebtedness could have an adverse impact on our earnings and cash flows (which after the merger would include the earnings and cash flows of Nicor) for as long as the indebtedness is outstanding.

This increased indebtedness could also have important consequences to shareholders. For example, it could:

·   make it more difficult for us to pay or refinance our debts as they become due during adverse economic and industry conditions because any decrease in revenues could cause us to not have sufficient cash flows from operations to make our scheduled debt payments

·   limit our flexibility to pursue other strategic opportunities or react to changes in our business and the industry in which we operate and, consequently, place us at a competitive disadvantage to competitors with less debt

·   require a substantial portion of our cash flows from operations to be used for debt service payments, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions, dividend payments and other general corporate purposes

·   result in a downgrade in the credit rating of our indebtedness, which could limit our ability to borrow additional funds or increase the interest rates applicable to our indebtedness (after the announcement of the merger, Standard & Poor's Ratings Services placed its long-term ratings on AGL Resources on negative watch)

·   reduce the amount of credit available to us to support hedging activities

·   result in higher interest expense in the event of increases in interest rates since some of our borrowings are, and will continue to be, at variable rates.

Based upon current levels of operations, we expect to be able to generate sufficient cash on a consolidated basis to make all of the principal and interest payments when such payments are due under our existing credit agreements, indentures and other instruments governing our outstanding indebtedness, and under the indebtedness of Nicor and its subsidiaries that may remain outstanding after the merger; but there can be no assurance that we will be able to repay or refinance such borrowings and obligations.

We are committed to maintaining and improving our credit ratings. In order to maintain and improve these credit ratings, we may consider it appropriate to reduce the amount of indebtedness outstanding following the merger. This may be accomplished in several ways, including issuing additional shares of common stock or securities convertible into shares of common stock, reducing discretionary uses of cash or a combination of these and other measures. Issuances of additional shares of common stock or securities convertible into shares of common stock would have the effect of diluting the ownership percentage that shareholders will hold in the combined company and might reduce the reported earnings per share. The specific measures that we may ultimately decide to use to maintain or improve our credit ratings and their timing, will depend upon a number of factors, including market conditions and forecasts at the time those decisions are made.

Pending shareholder suits could delay or prevent the closing of the merger or otherwise adversely impact our business and operations.

Several class action lawsuits have been brought by purported Nicor shareholders challenging Nicor’s proposed merger with us. The complaints allege that we aided and abetted alleged breaches of fiduciary duty by Nicor’s Board of Directors. The shareholder actions seek, among other things, declaratory and injunctive relief, including orders enjoining the defendants from completing the proposed merger and, in certain circumstances, damages. No assurances can be given as to the outcome of these lawsuits, including the costs associated withdefending these lawsuits or any other liabilities or costs the parties may incur in connection with the litigation or settlement of these lawsuits. Furthermore, one of the conditions to closing the merger is that there are no injunctions issued by any court preventing the completion of the transactions. No assurance can be given that these lawsuits will not result in such an injunction being issued which could prevent or delay the closing of the merger.

In March 2011, the parties entered into an agreement to resolve all of the shareholder lawsuits, subject to court approval, based on Nicor providing certain supplemental disclosures to our joint proxy statement filed on April 28, 2011. The court has preliminarily approved the agreement, a fairness hearing is set for December 11, 2011 and we expect the court to approve the agreement at this hearing. This lawsuit will have no effect on the closing of the merger. For more information on our proposed merger with Nicor see Note 3.

There have been no other significant changes to our risk factors included in Item 1A of our 2010 Form 10-K.

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

The following table sets forth information about purchases of our common stock by us and any affiliated purchasers during the three months ended September 30, 2011. Stock repurchases may be made in the open market or in private transactions at times and in amounts that we deem appropriate. However, there is no guarantee as to the exact number of additional shares that may be repurchased, and we may terminate or limit the stock repurchase program at any time. We currently anticipate holding the repurchased shares as treasury shares.

Period	Total number of shares purchased (1)		Average price paid per share
July 2011		3,105	$	41.15
August 2011		0		0.00
September 2011		3,333		23.15
Total third quarter		6,438	$	31.83

(1)  

(1)   On March 20, 2001, our Board of Directors approved the purchase of up to 600,000 shares of our common stock in the open market to be used for issuances under the Officer Incentive Plan (Officer Plan). We purchased 6,438 shares for such purposes in the third quarter of 2011. As of September 30, 2011, we had purchased a total of 383,591 of the 600,000 shares authorized for purchase, leaving 216,409 shares available for purchase under this program.

Item 5. Other Information

Private Placement of Senior Notes On August 31, 2011, as previously reported in AGL Resources Inc.’s Current Report on Form 8-K filed on September 7, 2011, AGL Capital Corporation, a wholly-owned subsidiary of AGL Resources Inc., entered into a note purchase agreement with various institutional investors providing for the sale by AGL Capital Corporation to the purchasers of $275 million aggregate principal amount of AGL Capital Corporation’s senior notes, consisting of $120 million of Series A senior notes due 2016 and $155 million of Series B senior notes due 2018.  The senior notes are guaranteed by AGL Resources. The Series A notes bear interest at an initial rate of 1.9% and the Series B notes bear interest at a rate of 3.5%.

On October 27, 2011, AGL Capital Corporation completed the sale of the notes to the purchasers. The Series A and Series B notes mature on the fifth and seventh anniversaries of such closing date, respectively. The notes were sold to the purchasers in a private offering exempt from the registration provisions of the Securities Act of 1933, as amended.

For additional information concerning these issuances please see Current Report on Form 8-K filed with the SEC on September 7, 2011.

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Item 6. Exhibits

Where an exhibit is filed by incorporation by reference to a previously filed registration statement or report, such registration statement or report is identified in parentheses.

4.1	Form of AGL Capital Corporation Series A Senior Notes due 2016 (Exhibit 4.1, AGL Resources Inc. Form 8-K dated September 7, 2011).
4.2	Form of AGL Capital Corporation Series B Senior Notes due 2018 (Exhibit 4.2, AGL Resources Inc. Form 8-K dated September 7, 2011).
10.1	Note Purchase Agreement dated August 31, 2011, by and among AGL Capital Corporation as issuer, AGL Resources Inc. as guarantor and each of the note purchasers signatory thereto (Exhibit 10.1, AGL Resources Inc. Form 8-K dated September 7, 2011).

10.2	First Amendment as of August 11, 2011 to Bridge Term Loan Credit Agreement as of December 21, 2010 by and among AGL Capital Corporation, AGL Resources Inc., Goldman Sachs Bank USA, as administrative agent, and the several lenders named therein.
10.3	Second Amendment as of August 11, 2011 to Credit Agreement as of September 15, 2010, as amended, by and among AGL Capital Corporation, AGL Resources Inc., Wells Fargo Bank, National Association, as administrative agent, and the several lenders named therein.
10.4	Second Amendment dated as of August 11, 2011 to Reimbursement Agreement dated as of October 14, 2010, as amended, by and among Pivotal Utility Holdings, Inc., AGL Resources Inc., JPMorgan Chase Bank, N.A., as administrative agent and lead arranger, and the several other banks and other financial institutions named therein.
10.5	Second Amendment dated as of August 11, 2011 to Reimbursement Agreement dated as of October 14, 2010, as amended, by and among Pivotal Utility Holdings, Inc., AGL Resources Inc., The Bank of Tokyo-Mitsubishi UFJ, Ltd, New York Branch, as administrative agent and lead arranger, and the several other banks and other financial institutions named therein.
10.6	Second Amendment dated as of August 11, 2011 to Reimbursement Agreement dated as of October 14, 2010, as amended, by and among Pivotal Utility Holdings, Inc., AGL Resources Inc., The Bank of Tokyo-Mitsubishi UFJ, Ltd, New York Branch, as administrative agent and lead arranger, and the several other banks and other financial institutions named therein.
10.7	Second Amendment dated as of August 11, 2011 to Reimbursement Agreement dated as of October 14, 2010, as amended, by and among Pivotal Utility Holdings, Inc., AGL Resources Inc., JPMorgan Chase Bank, N.A., as administrative agent and lead arranger, and the several other banks and other financial institutions named therein.

12	Statement of Computation of Ratio of Earnings to Fixed Charges.
31.1	Certification of John W. Somerhalder II pursuant to Rule 13a - 14(a).
31.2	Certification of Andrew W. Evans pursuant to Rule 13a - 14(a).
32.1	Certification of John W. Somerhalder II pursuant to 18 U.S.C. Section 1350.
32.2	Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350.

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101.INS	XBRL Instance Document. (1)
101.SCH	XBRL Taxonomy Extension Schema. (1)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase. (1)
101.DEF	XBRL Taxonomy Definition Linkbase. (1)
101.LAB	XBRL Taxonomy Extension Labels Linkbase. (1)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.(1)

(1)Furnished, not filed.

Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Condensed Consolidated Statements of Financial Position at September 30, 2011, December 31, 2010 and September 30, 2010; (iii) Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010; (iv) Condensed Consolidated Statements of Equity for the nine months ended September 30, 2011 and 2010; (v) Condensed Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2011 and 2010; (vi) Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010; and (vii) Notes to Condensed Consolidated Financial Statements.

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

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SIGNATURE

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

AGL RESOURCES INC.

(Registrant)

Date: November 2, 2011                                                                /s/ Andrew W. Evans

Executive Vice President and Chief Financial Officer

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