AGL RESOURCES INC Form 10-Q Quarterly Report Filed 2012-11-01

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, 2012

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 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.

2011 Form 10-K	Our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 22, 2012
AGL Capital	AGL Capital Corporation
AGL Credit Facility	$1.3 billion credit agreement entered into by AGL Capital to support the AGL Capital commercial paper program
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Central Valley	Central Valley Gas Storage, LLC
Chattanooga Gas	Chattanooga Gas Company
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes financing costs, including interest on 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
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.
Heating Degree Days	A measure of the effects of weather on our businesses, calculated as the extent to which the average daily temperature is less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher because weather is colder
Horizon Pipeline	Horizon Pipeline Company, LLC
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson Island	Jefferson Island Storage & Hub, LLC
LIFO	Last-in, first-out, an accounting method used to value inventory
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 acquisition completed in December 2011 and former holding company of Nicor Gas
Nicor Advanced Energy	Prairie Point Energy, LLC, doing business as Nicor Advanced Energy
Nicor Gas	Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Gas Credit Facility	$700 million credit facility entered into by Nicor Gas to support its commercial paper program
Nicor Services	Nicor Energy Services Company
Nicor Solutions	Nicor Solutions, LLC
NUI	NUI 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 goods sold and revenue tax expense, that excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes, Nicor merger expenses, and gains or losses on the sale of our assets, if any; these items are included in our calculation of operating income as reflected in our Consolidated Statements of Income. Operating margin should not be considered an alternative to, or more meaningful than, operating income as determined in accordance with GAAP
OTC	Over-the-counter
PBR	Performance-based rate, a regulatory plan that ended in 2003, which provided economic incentives based on natural gas cost performance
Piedmont	Piedmont Natural Gas Company, Inc.
PP&E	Property, plant and equipment
S&P	Standard & Poor’s Ratings Services
Sawgrass Storage	Sawgrass Storage, LLC
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
Seven Seas	Seven Seas Insurance Company, Inc.
SNG	Substitute natural gas, a synthetic form of gas manufactured from coal
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 to repay the $300 million senior notes due in 2011
TEU	Twenty-foot equivalent unit, a measure of volume in containerized shipping equal to one 20-foot-long container
Triton	Triton Container Investments LLC
Tropical Shipping	A wholly owned business and a carrier of containerized freight in the Bahamas and the Caribbean region
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

	As of
In millions	September 30, 2012			December 31, 2011			September 30, 2011
Current assets
Cash and cash equivalents	$	91		$	69		$	165
Short-term investments		60			53			0
Receivables
Energy marketing receivables		397			607			512
Gas, unbilled and other receivables		305			692			144
Less allowance for uncollectible accounts		31			15			17
Total receivables		671			1,284			639
Inventories		778			750			635
Regulatory assets		158			131			99
Derivative instruments		144			226			132
Other current assets		233			233			131
Total current assets		2,135			2,746			1,801
Long-term assets and other deferred debits
Property, plant and equipment		10,281			9,779			6,521
Less accumulated depreciation		2,069			1,879			1,886
Property, plant and equipment, net		8,212			7,900			4,635
Goodwill		1,817			1,813			418
Regulatory assets		1,086			1,079			532
Derivative instruments		15			62			36
Other long-term assets and other deferred debits		330			313			37
Total long-term assets and other deferred debits		11,460			11,167			5,658
Total assets	$	13,595		$	13,913		$	7,459
Current liabilities
Short-term debt	$	1,048		$	1,321		$	0
Energy marketing trade payables		444			590			586
Accounts payable - trade		292			294			124
Current portion of long-term debt and capital leases		226			17			17
Customer deposits and credit balances		159			152			39
Accrued regulatory infrastructure program costs		122			131			119
Accrued expenses		119			162			87
Regulatory liabilities		117			112			34
Accrued environmental remediation liabilities		61			37			23
Derivative instruments		37			99			45
Other current liabilities		139			169			66
Total current liabilities		2,764			3,084			1,140
Long-term liabilities and other deferred credits
Long-term debt		3,330			3,561			2,687
Accumulated deferred income taxes		1,555			1,445			895
Regulatory liabilities		1,465			1,405			296
Accrued environmental remediation liabilities		365			290			166
Accrued other retirement benefit costs		296			320			29
Accrued pension obligations		213			238			151
Accrued regulatory infrastructure program costs		123			145			138
Derivative instruments		5			11			14
Other long-term liabilities and other deferred credits		81			75			62
Total long-term liabilities and other deferred credits		7,433			7,490			4,438
Total liabilities and other deferred credits		10,197			10,574			5,578
Commitments, guarantees and contingencies (see Note 9)
Equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 117,743,809 shares at September 30, 2012, 117,044,803 shares at December 31, 2011 and 78,539,528 shares at September 30, 2011		590			586			394
Additional paid in capital		2,012			1,989			650
Retained earnings		990			967			977
Accumulated other comprehensive loss		(203	)		(217	)		(151	)
Treasury shares		(8	)		(7	)		(6	)
Total common shareholders’ equity		3,381			3,318			1,864
Noncontrolling interest		17			21			17
Total equity		3,398			3,339			1,881
Total liabilities and equity	$	13,595		$	13,913		$	7,459
See Notes to Condensed Consolidated Financial Statements (Unaudited).

	Three months ended						Nine months ended
	September 30,						September 30,
In millions, except per share amounts	2012			2011			2012			2011
Operating revenues (includes revenue taxes of $8 and $63 for the three and nine months in 2012)	$	614		$	295		$	2,704		$	1,548
Operating expenses
Cost of goods sold		215			112			1,174			701
Operation and maintenance		212			103			675			351
Depreciation and amortization		104			43			310			126
Taxes other than income taxes		27			11			123			36
Nicor merger expenses		2			2			15			12
Total operating expenses		560			271			2,297			1,226
Operating income		54			24			407			322
Other income		6			1			19			4
Interest expense, net		(45	)		(31	)		(137	)		(92	)
Earnings (loss) before income taxes		15			(6	)		289			234
Income tax expense (benefit)		6			(2	)		106			85
Net income (loss)		9			(4	)		183			149
Less net income (loss) attributable to the noncontrolling interest		0			(1	)		10			10
Net income (loss) attributable to AGL Resources Inc.	$	9		$	(3	)	$	173		$	139
Per common share data
Basic earnings (loss) per common share attributable to AGL Resources Inc. common shareholders	$	0.08		$	(0.04	)	$	1.48		$	1.79
Diluted earnings (loss) per common share attributable to AGL Resources Inc. common shareholders	$	0.08		$	(0.04	)	$	1.48		$	1.78
Cash dividends declared per common share	$	0.46		$	0.45		$	1.28		$	1.35
Weighted-average number of common shares outstanding
Basic		117.1			78.1			116.9			77.9
Diluted		117.5			78.1			117.3			78.4

	Nine months ended
	September 30,
In millions	2012			2011
Cash flows from operating activities
Net income	$	183		$	149
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		310			126
Deferred income taxes		89			105
Change in derivative instrument assets and liabilities		61			51
Changes in certain assets and liabilities
Receivables, other than energy marketing		403			247
Energy marketing receivables and trade payables, net		64			118
Prepaid taxes		13			(31	)
Trade payables, other than energy marketing		14			(54	)
Inventories		(28	)		4
Accrued expenses		(43	)		(52	)
Other - net		(42	)		(103	)
Net cash flow provided by operating activities		1,024			560
Cash flows from investing activities
Expenditures for property, plant and equipment		(569	)		(292	)
Net cash flow used in investing activities		(569	)		(292	)
Cash flows from financing activities
Net payments and borrowings of short-term debt		(273	)		(732	)
Dividends paid on common shares		(150	)		(105	)
Payment of medium-term notes		(15	)		0
Distribution to noncontrolling interest		(14	)		(16	)
Proceeds from termination of interest rate swap		17			0
Payment of senior notes		0			(300	)
Payments of term loan facility		0			(150	)
Proceeds from term loan facility		0			150
Issuance of senior notes		0			1,014
Other		2			12
Net cash flow used in financing activities		(433	)		(127	)
Net increase in cash and cash equivalents		22			141
Cash and cash equivalents at beginning of period		69			24
Cash and cash equivalents at end of period	$	91		$	165
Cash paid during the period for
Interest	$	142		$	95
Income taxes	$	4		$	10

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. Our estimates are based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Our estimates may involve complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. The most significant estimates relate to our pipeline replacement program accruals, environmental liability accruals, uncollectible accounts and other allowances for contingent losses, goodwill and intangible assets, retirement plan benefit obligations, derivative and hedging activities and provisions for income taxes. We evaluate our estimates on an ongoing basis and our actual results could differ from our estimates.

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, 2012, December 31, 2011 and September 30, 2011, 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.

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 in the current period are capitalized as regulatory assets when it is probable that such costs or expenditures will be recovered in future rates. 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. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover these costs consistent with our historical recoveries. In the event that the authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income, and be classified as an extraordinary item.

In millions	September 30, 2012 (1)		December 31, 2011 (2)		September 30, 2011
Regulatory assets
Recoverable regulatory infrastructure program costs	$	46	$	48	$	62
Recoverable ERC		33		7		7
Recoverable pension and other retirement benefit costs		27		29		0
Other		52		47		30
Total regulatory assets - current		158		131		99
Regulatory assets
Recoverable ERC		421		351		213
Recoverable regulatory infrastructure program costs		286		305		269
Recoverable pension and other retirement benefit costs		228		263		10
Long-term debt fair value adjustment		92		99		0
Other		59		61		40
Total regulatory assets - noncurrent		1,086		1,079		532
Total regulatory assets	$	1,244	$	1,210	$	631
Regulatory liabilities
Accrued natural gas costs	$	62	$	53	$	26
Bad debt rider		30		30		0
Accumulated removal costs		14		14		0
Other		11		15		8
Total regulatory liabilities - current		117		112		34
Regulatory liabilities
Accumulated removal costs		1,381		1,321		254
Unamortized investment tax credit		30		32		11
Regulatory income tax liability		23		27		14
Bad debt rider		16		14		0
Other		15		11		17
Total regulatory liabilities - noncurrent		1,465		1,405		296
Total regulatory liabilities	$	1,582	$	1,517	$	330

Wholesale Services We purchase natural gas for storage when the current market price we pay to buy and transport natural gas plus the cost to store the natural gas is less than the market price we can receive in the future, resulting in a positive net operating margin. We use NYMEX futures contracts and OTC derivatives to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is sold. We also enter into transactions to secure transportation capacity between two delivery points in order to serve our customers and various markets. We use NYMEX futures and OTC derivatives to capture the price differential or spread between the locations served by the capacity in order to substantially lock in the operating margin we will ultimately realize when we physically flow natural gas between the two delivery points. These contracts generally meet the definition of derivatives under the authoritative guidance related to derivatives and hedging and are carried at fair value in our unaudited Condensed Consolidated Statements of Financial Position, with changes in fair value recorded in our unaudited Condensed Consolidated Statements of Income in the period of change. These futures contracts are not designated as hedges as may be permitted under the accounting guidance.

We concluded that net book value is a reasonable estimate of fair value for Nicor’s tangible and intangible assets and liabilities that are explicitly subject to cost-of-service ratemaking. The company determined the fair value of Nicor’s long-term debt using the income approach, and used a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. As a result, our purchase price allocation included an adjustment of $99 million to step-up the basis of Nicor’s long-term debt to fair value as of the merger date. A corresponding regulatory asset was recorded in connection with the fair value adjustment of the debt. While the regulatory asset related to debt is not included in rate base, the costs are recovered over the term of the debt through the authorized rate of return component of base rates. The following table summarizes our purchase price allocation for Nicor Gas’ regulatory assets and liabilities:

	Recognition and Measurement
Accounting Treatment	Statement of Financial Position	Income Statement
Cash flow hedge	Derivative carried 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 OCI (loss)	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated OCI (loss) and into earnings when the hedged transaction affects earnings
Fair value hedge	Derivative carried at fair value Changes in fair value of the hedged item are recorded as adjustments to the carrying amount of the hedged item	Gains or losses on the derivative instrument and the hedged item are recognized in earnings. As a result, to the extent the hedge is effective, the gains or losses will offset and there is no impact on earnings. Any hedge ineffectiveness will impact earnings.
Not designated as hedges	Derivative carried at fair value	Realized and unrealized gains or losses on the derivative instrument are recognized in earnings
	Distribution operations’ gains and losses on derivative instruments are deferred as regulatory assets or liabilities until included in cost of goods sold	The gain or loss on these derivative instruments is reflected in natural gas costs and is ultimately included in billings to customers

Glossary of Key Terms

Table of Contents

Derivative Instruments Impacts on the Unaudited Condensed Consolidated Statements of Financial Position

The following table presents the fair value and unaudited Condensed Consolidated Statements of Financial Position classification of our derivative instruments as of the periods presented:

In millions	Unaudited Condensed Consolidated Statements of Financial Position Location (1) (2)	Sept. 30, 2012			Dec. 31, 2011			Sept. 30, 2011
Designated as cash flow and fair value hedges
Asset Instruments
Current natural gas contracts	Derivative instruments assets and liabilities - current portion	$	4		$	9		$	8
Interest rate swap agreements	Derivative instruments assets - long-term portion		0			13			13
Liability Instruments
Current natural gas contracts	Derivative instruments assets and liabilities - current portion		(3	)		(12	)		(8	)
Interest rate swap agreements	Derivative instruments liabilities - long-term portion		0			(13	)		0
Total			1			(3	)		13

Not designated as cash flow hedges
Asset Instruments
Current natural gas contracts	Derivative instruments assets and liabilities - current portion		427			706			470
Noncurrent natural gas contracts	Derivative instruments assets and liabilities		54			133			76

Liability Instruments
Current natural gas contracts	Derivative instruments assets and liabilities - current portion		(408	)		(689	)		(447	)
Noncurrent natural gas contracts	Derivative instruments assets and liabilities		(50	)		(116	)		(82	)
Total			23			34			17
Total derivative instruments		$	24		$	31		$	30

(1)	These amounts are netted within our unaudited Condensed Consolidated Statements of Financial Position for amounts which we have netting arrangements with the counterparties.

(2)

As required by the authoritative guidance related to derivatives and hedging, the fair value amounts are presented on a gross basis. As a result, the amounts do not include cash collateral held on deposit in broker margin accounts of $93 million as of September 30, 2012, $147 million as of December 31, 2011 and $79 million as of September 30, 2011. Accordingly, these amounts will differ from the amounts presented on our unaudited Condensed Consolidated Statements of Financial Position and the fair value information presented for our derivative instruments in the recurring fair values table of Note 4.

Derivative Instruments Impacts on the Unaudited Condensed Consolidated Statements of Income

The following table presents the gain (loss) on derivative instruments in our unaudited Condensed Consolidated Statements of Income for the periods presented:

	For the three months ended September 30,						For the nine months ended September 30,
In millions	2012			2011			2012			2011

Designated as cash flow hedges
Natural gas contracts - net loss reclassified from OCI into cost of goods sold for settlement of hedged item	$	(6	)	$	(1	)	$	(2	)	$	(2	)
Natural gas contracts - net gain reclassified from OCI into operation and maintenance for settlement of hedged item		(2	)		0			(1	)		0
Interest rate swaps - gain recognized in OCI and ineffectiveness recorded as an offset to interest expense		2			2			(1	)		2

Not designated as hedges
Natural gas contracts - net (loss) gain fair value adjustments recorded in operating revenues (1)		(17	)		0			(40	)		12
Natural gas contracts - net loss fair value adjustments recorded in cost of goods sold (2)		1			0			(2	)		(2	)
Total gain (loss) on derivative instruments	$	(22	)	$	1		$	(46	)	$	10

(1)	Associated with the fair value of existing derivative instruments at September 30, 2012 and 2011.

(2)	Excludes gains recorded in cost of goods sold associated with weather derivatives of $14 million for the nine months ended September 30, 2012 and $4 million for the nine months ended September 30, 2011.

		September 30, 2012							September 30, 2011
Dollars in millions	Year(s) due	Weighted average interest rate (1)			Outstanding		Outstanding at December 31, 2011		Weighted average interest rate (1)			Outstanding
Short-term debt
Commercial paper- AGL Capital (2)	2012		0.5	%	$	875	$	869		0.4	%	$	0
Commercial paper- Nicor Gas (2)	2012		0.5			173		452		n/a			n/a
Total short-term debt			0.5	%	$	1,048	$	1,321		0.4	%	$	0
Current portion of long-term debt and capital leases
Current portion of long-term debt	2013		4.6	%	$	225	$	15		8.3	%	$	15
Current portion of capital leases	2012-2013		4.9			1		2		4.9			2
Total current portion of long-term debt and capital leases			4.6	%	$	226	$	17		8.0	%	$	17
Long-term debt - excluding current portion

Senior notes	2015-2041		5.1	%	$	2,325	$	2,550		5.5	%	$	2,275
First mortgage bonds	2016-2038		5.6			500		500		n/a			n/a
Gas facility revenue bonds	2022-2033		1.1			200		200		1.1			200
Medium-term notes	2017-2027		7.8			181		181		7.8			181
Total principal long-term debt			5.0	%	$	3,206	$	3,431		5.3	%	$	2,656
Fair value adjustment of long-term debt (3)	2016-2038		n/a		$	106	$	112		n/a		$	11
Unamortized debt premium, net	n/a		n/a			18		18		n/a			20
Total non-principal long-term debt			n/a		$	124	$	130		n/a		$	31
Total long-term debt					$	3,330	$	3,561				$	2,687

Total debt					$	4,604	$	4,899				$	2,704

Cash flows used in our investing activities include capital expenditures for SouthStar of $2 million for the nine months ended September 30, 2012 and 2011. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year. Generally, this distribution occurs in the first or second quarter of each fiscal year. For the nine months ended September 30, 2012, SouthStar distributed $14 million to Piedmont and $16 million during the same period last year. The decrease of $2 million was primarily the result of decreased earnings year-over-year. The following table provides additional information for the dates presented, which are consolidated within our unaudited Condensed Consolidated Statements of Financial Position:

	September 30, 2012						December 31, 2011						September 30, 2011
In millions	Consolidated		SouthStar (1)		% (2)		Consolidated		SouthStar (1)		% (2)		Consolidated		SouthStar (1)		% (2)
Current assets	$	2,135	$	152	7	%	$	2,746	$	210	8	%	$	1,801	$	164	9	%
Long-term assets and other deferred debits		11,460		10	0			11,167		9	0			5,658		9	0
Total assets	$	13,595	$	162	1	%	$	13,913	$	219	2	%	$	7,459	$	173	2	%
Current liabilities	$	2,764	$	42	2	%	$	3,084	$	77	2	%	$	1,140	$	57	5	%
Long-term liabilities and other deferred credits		7,433		0	0			7,490		0	0			4,438		0	0
Total Liabilities		10,197		42	0			10,574		77	1			5,578		57	1
Equity		3,398		120	4			3,339		142	4			1,881		116	6
Total liabilities and equity	$	13,595	$	162	1	%	$	13,913	$	219	2	%	$	7,459	$	173	2	%

(1)	These amounts reflect information for SouthStar and do not include intercompany eliminations or the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.

(2)	SouthStar’s percentage of the amount on our unaudited Condensed Consolidated Statements of Financial Position.

The following table provides additional information on SouthStar’s revenues and expenses for the periods presented, which are consolidated within our unaudited Condensed Consolidated Statements of Income:

In November 2011, we filed a lawsuit against the IPA and the developer of this second proposed plant contending that the draft contract approved by the IPA does not conform to certain requirements of the enabling legislation. The lawsuit is pending in circuit court in DuPage County, Illinois. In accordance with the enabling legislation, the draft contract approved by the IPA for the second proposed plant was submitted to the Illinois Commission for further approvals by that regulatory body. The Illinois Commission issued an order on January 10, 2012 approving a final form of the contract for the second plant. The final form of contract approved by the Illinois Commission modified the draft contract submitted by the IPA in various respects. Both we and the developer of the plant filed applications for a rehearing with the Illinois Commission seeking changes to the final form of the contract. The Illinois Commission agreed to grant a rehearing. On July 11, 2012, the Illinois Commission issued its order on rehearing in which it modified its earlier order to change certain of the terms of the approved form of SNG purchase contract. The Illinois state court denied our appeal of the Illinois Commission’s order, but that does not impact the pending DuPage County lawsuit challenging the IPA’s earlier order approving the draft form of contract. We have appealed the Illinois Commission’s decision to Illinois state court. In May 2012, the Illinois legislature passed a bill that directed the Illinois Commission to approve a final form of contract that differed in certain respects from the form the Illinois Commission approved in its July 11, 2012 order and that purported to address issues raised in our pending lawsuit against the IPA. This bill was vetoed by the Governor of Illinois on August 10, 2012. As a result of pending litigation challenging aspects of the IPA and Illinois Commission decisions regarding the contract terms, we have not yet signed a contract with the developer to purchase SNG from the second proposed plant.

PBR Proceeding Nicor Gas’ PBR plan for natural gas costs went into effect in 2000 and was terminated effective January 1, 2003. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. The PBR plan is currently under review by the Illinois Commission as there are allegations that Nicor Gas acted improperly in connection with the PBR plan. On June 27, 2002, the Citizens Utility Board (CUB) filed a motion to reopen the record in the Illinois Commission’s proceedings to review the PBR plan. As a result of the motion to reopen, Nicor Gas entered into a stipulation with the staff of the Illinois Commission and CUB providing for additional discovery. The Illinois Attorney General’s Office (IAGO) has also intervened in this matter. In addition, the IAGO issued Civil Investigation Demands (CIDs) to CUB and the Illinois Commission staff. The CIDs ordered that CUB and the Illinois Commission staff produce all documents relating to any claims that Nicor Gas may have presented, or caused to be presented, regarding false information related to its PBR plan. The staff of the Illinois Commission, IAGO and CUB submitted direct testimony to the Illinois Commission in April 2009 and rebuttal testimony in October 2011. In rebuttal testimony, the staff of the Illinois Commission, IAGO and CUB requested refunds of $85 million, $255 million and $305 million, respectively. We have committed to cooperate fully in the reviews of the PBR plan.

In February 2012, we committed to a stipulated resolution of issues with the staff of the Illinois Commission, which includes crediting Nicor Gas customers $64 million, which is not recoverable from our customers. This liability is reflected in our unaudited Condensed Consolidated Statements of Financial Position at September 30, 2012 and December 31, 2011. The stipulated resolution does not constitute an admission of fault, and it is not final and is subject to review and approval by the Illinois Commission. CUB and IAGO are not parties to the stipulated resolution and continue to pursue their claims in this proceeding. Evidentiary hearings before the Administrative Law Judge were held during the first quarter of 2012 and post-trial legal briefs from the parties were submitted during the second quarter of 2012. Following the submission of legal briefs, the Administrative Law Judge will issue a proposed decision. There is no date scheduled for the issuance of that proposed decision.

Our cargo shipping segment transports containerized freight between Florida, the eastern coast of Canada, the Bahamas and the Caribbean region. Our cargo shipping segment also includes amounts related to cargo insurance coverage sold to our customers and other third parties. Our cargo shipping segment’s vessels are under foreign registry, and its containers are considered instruments of international trade. Although the majority of its long-lived assets are foreign owned and its revenues are derived from foreign operations, the functional currency is generally the United States dollar. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. Profits and losses are generally allocated to investors’ capital accounts in proportion to their capital contributions. Our investment in Triton is accounted for under the equity method, and our share of earnings is reported within “Other Income” on our unaudited Condensed Consolidated Statements of Income.

In millions	Distribution operations		Retail operations		Wholesale services			Midstream operations		Cargo shipping			Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	1,848	$	517	$	59		$	56	$	247		$	(23	)	$	2,704
Intercompany revenues (1)		124		0		0			0		0			(124	)		0
Total operating revenues		1,972		517		59			56		247			(147	)		2,704
Operating expenses
Cost of goods sold		767		342		34			24		152			(145	)		1,174
Operation and maintenance		473		83		35			13		83			(12	)		675
Depreciation and amortization		262		10		1			10		17			10			310
Nicor merger expenses		0		0		0			0		0			15			15
Taxes other than income taxes		103		3		3			4		4			6			123
Total operating expenses		1,605		438		73			51		256			(126	)		2,297
Operating income (loss)		367		79		(14	)		5		(9	)		(21	)		407
Other income		7		0		1			1		8			2			19
EBIT	$	374	$	79	$	(13	)	$	6	$	(1	)	$	(19	)	$	426

Identifiable and total assets (2)	$	11,062	$	472	$	970		$	712	$	482		$	(103	)	$	13,595
Goodwill	$	1,591	$	122	$	0		$	14	$	90		$	0		$	1,817
Capital expenditures	$	457	$	7	$	1		$	77	$	2		$	25		$	569

Forward-looking statements involve matters that are not historical facts, and because these statements involve anticipated events or conditions, forward-looking statements often include words such as "anticipate," "assume," "believe,” "can," "could," "estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” “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 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; limits on pipeline capacity; the impact of acquisitions and divestitures; our ability to integrate successfully operations that we have or may acquire or develop in the future, including those of Nicor, and realize cost savings and any other synergies related to any such integration, or the risk that any such integration could be more difficult, time-consuming or costly than expected; uncertainty of our expected financial performance following the completion of the Nicor merger; disruption from the Nicor merger making it more difficult to maintain relationships with customers, employees or suppliers; direct or indirect effects on our business, financial condition or liquidity resulting from any change in our credit ratings resulting from the merger with Nicor or otherwise or any change in 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 economic downturn; general economic conditions; uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans; 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; the outcome of litigation; and other factors discussed elsewhere herein and in our filings with the SEC.

Overview

We are an energy services holding company whose principal business is the distribution of natural gas in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland - through our seven natural gas distribution utilities. At September 30, 2012, our seven utilities serve approximately 4.5 million end-use customers.

We have other energy-related businesses, including our retail operations segment, which serves more than one million retail customers and markets natural gas and related home services to end-use customers primarily in Georgia, Illinois, Indiana, Ohio, Florida and New York. Our wholesale services segment provides natural gas storage arbitrage and related activities, natural gas asset management and related logistics activities for each of our utilities, except for Nicor Gas, as well as for non-affiliated companies. Our midstream operations segment engages in the operation of non-utility storage and pipeline facilities, including the development and operation of high-deliverability natural gas storage assets and provides natural gas storage arbitrage and related activities. In addition to these energy-related businesses, we also have a cargo shipping segment that transports containerized freight, owns and leases cargo containers and provides cargo insurance.

Our midstream operations segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops, acquires and operates high-deliverability underground natural gas storage assets primarily in the Gulf Coast region of the United States and in northern California. While this business can generate additional revenue during times of peak market demand for natural gas storage services, the majority of our natural gas storage facilities are covered under a portfolio of short, medium and long-term contracts at a fixed market rate. Golden Triangle Storage’s Cavern 1 began full commercial operations during the first quarter of 2011 and Cavern 2 began full commercial operations in the third quarter of 2012. Cavern 1 is expected to go through a process to assess the cavern’s working gas capacity and to slightly increase the size of the facility. The process is expected to begin in early 2013 and continue through the third quarter of 2013. Cavern 2 will cover the obligations of Cavern 1 during this process. Central Valley, located in northern California, began commercial operations and providing services to firm customers during the second quarter 2012.

Natural gas price volatility Natural gas market volatility 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 has 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. Since 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 to much warmer than normal weather and ample natural gas storage. Our strategies to acquire natural gas and secure transportation capacity are designed to secure sufficient supplies of natural gas and the rights to physically flow natural gas between delivery points in order to meet the needs of our utility customers and to hedge gas prices and location spreads 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 optimize within our wholesale and midstream businesses in a sustained low volatility market, but with lower actual results as compared to historical periods with higher volatility. It is possible that natural gas prices will remain low for an extended period based on current levels of supply relative to market demand for natural gas, in part due to abundant sources of shale natural gas reserves and the lack of demand 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 continuing to reposition our wholesales services business model through the management of operating costs, an increase in our fee-based services and continuing the optimization of our transportation and storage portfolio.

Hedges Our third quarter 2012 earnings were negatively impacted by pre-tax hedge losses of $16 million in our wholesale services segment. These losses are temporary and will be recovered in future periods. Based on current expectations, we anticipate that these losses largely will be recovered in the fourth quarter of 2012 and the first quarter of 2013. 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. These economic hedges may not qualify, or are not designated for, hedge accounting treatment. As a result, our reported earnings for the wholesale services, retail operations and midstream operations segments reflect changes in the fair values of certain derivatives. These values may change significantly from period to period and are reflected as gains or losses within our operating revenues or our OCI for those derivative instruments that qualify and are designated as accounting hedges.

Sequent’s storage balances and expected operating revenues are higher than last year reflecting the effects of the historically warmer weather in 2012 as compared to 2011 and a year-over-year improvement in seasonal price differentials. If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, we expect operating revenues from storage withdrawals of approximately $28 million in 2012 and $37 million in 2013. 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.

Based on Sequent’s current projection of year-end storage positions at December 31, 2012 of 33 Bcf, a $1.00 increase in the 2013 forward NYMEX prices could result in a $31 million reduction to Sequent’s reported operating revenues for the year ending December 31, 2012, after regulatory sharing but would increase the expected operating revenues to be realized in 2013 by a corresponding amount. A $1.00 decrease in forward NYMEX prices would result in a $31 million positive impact to Sequent’s reported operating revenues; however, additional LOCOM adjustments could potentially offset a portion of the positive impact. Excluding any additional LOCOM adjustments, the $1.00 decrease in forward NYMEX prices would result in a corresponding decrease in the expected operating revenues to be realized in 2013. This does not include operating expenses and storage demand fees that will be incurred to realize these amounts.

The expected operating revenues to be generated from the physical withdrawal of natural gas from storage also do not reflect the earnings impact related to the movement in our hedges to lock in the forward location spread for the delivery of natural gas between two transportation delivery points. For the nine months ended September 30, 2012, we have recorded $15 million in gains associated with the hedging of our transportation portfolio or $13 million higher as compared to the nine months ended September 30, 2011. These hedge gains primarily relate to forward transportation positions for the fourth quarter of 2012 through 2013, effectively accelerating operating revenues into the current period from those future periods during which we expect to physically flow natural gas between the hedged transportation delivery points. Consequently, the value that we realize from our transportation portfolio for the balance of the year will be lower since a significant portion of the previously expected revenues were recognized through the recording of the associated transportation hedge gains.

Atlanta Gas Light Our STRIDE program is comprised of the ongoing pipeline replacement program, the Integrated System Reinforcement Program (i-SRP), and Integrated Customer Growth Program (i-CGP). The purpose of the i-SRP program under STRIDE is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Our i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission. The deadline for filing our next STRIDE construction plan was extended by the Georgia Commission to August 2013 to allow additional time to complete the installation of the initial i-SRP construction program.

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 goods sold and revenue tax expense can vary significantly and are generally billed directly to our customers. We also consider operating margin to be a better indicator in our retail operations, wholesale services, midstream operations and cargo shipping segments since it is a direct measure of operating margin before overhead costs.

We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations. You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, our operating margin and EBIT measures may not be comparable to similarly titled measures of other companies. The following table reconciles operating revenue and operating margin to operating income and EBIT to 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	2012			2011			Change			2012			2011			Change
Operating revenues	$	614		$	295		$	319		$	2,704		$	1,548		$	1,156
Cost of goods sold		(215	)		(112	)		(103	)		(1,174	)		(701	)		(473	)
Revenue tax expense (1)		(8	)		0			(8	)		(62	)		0			(62	)
Operating margin		391			183			208			1,468			847			621
Revenue tax expense (1)		8			0			8			62			0			62
Operating expenses (2)		(343	)		(157	)		(186	)		(1,108	)		(513	)		(595	)
Nicor merger expenses (3)		(2	)		(2	)		0			(15	)		(12	)		(3	)
Operating income		54			24			30			407			322			85
Other income		6			1			5			19			4			15
EBIT		60			25			35			426			326			100
Interest expense, net (3)		(45	)		(31	)		(14	)		(137	)		(92	)		(45	)
Earnings (loss) before income taxes		15			(6	)		21			289			234			55
Income tax (expense) benefit		(6	)		2			(8	)		(106	)		(85	)		(21	)
Net income (loss)		9			(4	)		13			183			149			34
Net income (loss) attributable to the noncontrolling interest		0			1			(1	)		(10	)		(10	)		0
Net income (loss) attributable to AGL Resources Inc.	$	9		$	(3	)	$	12		$	173		$	139		$	34

Our cargo shipping segment’s primary activity is transporting containerized freight in the Bahamas and the Caribbean, a region that has historically been characterized by modest market growth and intense competition. Such shipments consist primarily of southbound cargo such as building materials, food and other necessities for developers, distributors and residents in the region, as well as tourist-related shipments intended for use in hotels and resorts, and on cruise ships. The balance of the cargo consists primarily of interisland shipments of consumer staples and northbound shipments of apparel, rum and agricultural products. Other related services such as inland transportation and cargo insurance are also provided within the cargo shipping segment. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. For more information about our investment in Triton, see Note 10 to our Consolidated Financial Statements under Item 8 included in our 2011 Form 10-K. Cargo shipping reported $(1) million of EBIT for the third quarter of 2012.

Pension and other retirement plan obligations In the first nine months of 2012, we contributed $32 million to our qualified pension plans and an additional $8 million in October 2012 for a total of $40 million during 2012. In the nine months ended September 30, 2011, we contributed $50 million to these qualified pension plans and an additional $6 million in October 2011 for a total of $56 million in 2011. Based on the current funding status of these plans, we are not required to make any further contributions to the plans for the remainder of 2012. In July 2012, the Pension Protection Act of 2006 was changed to provide near-term funding relief to certain pension plans and to increase Pension Benefit Guaranty Corporation premiums. As a result, recent actuarial estimates indicate that our minimum contributions to our pension plans for 2013 may decrease from approximately $50 million to approximately $25 million. However, we may contribute additional amounts to the plans above the required funding levels.

In November 2011, we filed a lawsuit against the IPA and the developer of this second proposed plant contending that the draft contract approved by the IPA does not conform to certain requirements of the enabling legislation. The lawsuit is pending in circuit court in DuPage County, Illinois. In accordance with the enabling legislation, the draft contract approved by the IPA for the second proposed plant was submitted to the Illinois Commission for further approvals by that regulatory body. The Illinois Commission issued an order on January 10, 2012 approving a final form of the contract for the second plant. The final form of contract approved by the Illinois Commission modified the draft contract submitted by the IPA in various respects. Both we and the developer of the plant filed applications for a rehearing with the Illinois Commission seeking changes to the final form of the contract. The Illinois Commission agreed to grant a rehearing. On July 11, 2012, the Illinois Commission issued its order on rehearing in which it modified its earlier order to change certain of the terms of the approved form of SNG purchase contract. The Illinois state court denied our appeal of the Illinois Commission’s order, but that does not impact the pending DuPage County lawsuit challenging the IPA’s earlier order approving the draft form of contract. In May 2012, the Illinois legislature passed a bill that directed the Illinois Commission to approve a final form of contract that differed in certain respects from the form the Illinois Commission approved in its July 11, 2012 order and that purported to address issues raised in our pending lawsuit against the IPA. This bill was vetoed by the Governor of Illinois on August 10, 2012. As a result of pending litigation challenging aspects of the IPA and Illinois Commission decisions regarding the contract terms, we have not yet signed a contract with the developer to purchase SNG from the second proposed plant.

On July 27, 2012, the FASB issued authoritative guidance related to the testing of indefinite-lived intangible assets for impairment. 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 indefinite-lived asset is impaired. If, after assessing the total events or circumstances, we determine that it is not more-likely-than-not that the indefinite-lived asset is impaired, then we are not required to take further action. However, if we conclude otherwise, then we are required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount. The guidance also gives us the option to bypass the qualitative assessment for any period and proceed directly to performing the quantitative impairment test and resume performing the qualitative assessment in any subsequent period. This guidance will be effective for us beginning January 1, 2013 and will not have a material impact on our consolidated financial statements.

As of September 30, 2012, our counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of A-, which is an improvement from the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being 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 of 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 our third-party natural gas contracts receivable and payable positions:

(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 under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of September 30, 2012, 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, 2012, 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.

3	Bylaws as amended on August 6, 2012 (Exhibit 3.01, AGL Resources, Inc. Form 8-K filed August 6, 2012).

4	Supplemental Indenture, dated October 26, 2012, of Northern Illinois Gas Company to BNY Mellon Trust Company, N.A., Trustee, under the Indenture dated as of January 1, 1954 (Exhibit 4, Northern Illinois Gas Company Form 10-Q for the fiscal quarter ended September 30, 2012).
12	Statement of Computation of Ratio of Earnings to Fixed Charges.
31.1	Certification of John W. Somerhalder II pursuant to Rule 13a - 14(a).

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

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

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

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase.
101.DEF		XBRL Taxonomy Definition Linkbase.

101.LAB		XBRL Taxonomy Extension Labels Linkbase.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

	Nine months ended			Fiscal			Fiscal			Fiscal			Fiscal			Fiscal
Dollars in millions	September 30, 2012			2011			2010			2009			2008			2007
Earnings before income taxes	$	289		$	311		$	390		$	384		$	369		$	368
Add:
Fixed charges (see “B” below)		152			145			123			115			127			134
Amortization of capitalized interest		-			1			-			-			-			-
Distributed income of equity investees		10			-			-			-			-			-
Less:
Interest capitalized		(1	)		(1	)		(5	)		(3	)		(2	)		-
Noncontrolling interest in pre-tax income of subsidiaries that have not incurred fixed charges		(10	)		(14	)		(16	)		(27	)		(20	)		(30	)
Adjusted Earnings (A)	$	440		$	442		$	492		$	469		$	474		$	472

Fixed charges
Interest on long-term debt	$	132		$	101		$	109		$	98		$	96		$	97
Other interest, including amortized premiums, discounts and capitalized expenses related to indebtedness liability		10			37			7			10			24			30
Estimated interest components of rentals		10			7			7			7			7			7
Total fixed charges (B)	$	152		$	145		$	123		$	115		$	127		$	134

Ratio of earnings to fixed charges (A)/(B)		2.89			3.05			4.00			4.08			3.73			3.52

1.	I have reviewed this quarterly report on Form 10-Q of AGL Resources Inc.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

1.	I have reviewed this quarterly report on Form 10-Q of AGL Resources Inc.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
	(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
	(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

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 23, 2012
Common Stock, $5.00 Par Value	117,782,207

		Page
Glossary of Key Terms		3

Item Number.
	PART I - FINANCIAL INFORMATION

1	Condensed Consolidated Financial Statements (Unaudited)	4
	Condensed Consolidated Statements of Financial Position	4
	Condensed Consolidated Statements of Income	5
	Condensed Consolidated Statements of Comprehensive Income	6
	Condensed Consolidated Statements of Equity	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Condensed Consolidated Financial Statements	9
	Note 1 - Organization and Basis of Presentation	9
	Note 2 - Significant Accounting Policies and Methods of Application	9
	Note 3 - Merger with Nicor	14
	Note 4 - Fair Value Measurements	16
	Note 5 - Derivative Instruments	16
	Note 6 - Employee Benefit Plans	19
	Note 7 - Debt and Credit Facilities	20
	Note 8 - Non-Wholly Owned Entities	21
	Note 9 - Commitments, Guarantees and Contingencies	22
	Note 10 - Segment Information	25
2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
	Forward-Looking Statements	28
	Overview	29
	Executive Summary	29
	Results of Operations	32
	Liquidity and Capital Resources	40
	Critical Accounting Policies and Estimates	45
	Accounting Developments	45
3	Quantitative and Qualitative Disclosures About Market Risk	45
4	Controls and Procedures	48
	PART II - OTHER INFORMATION

1	Legal Proceedings	48
1A	Risk Factors	48
2	Unregistered Sales of Equity Securities and Use of Proceeds	49
6	Exhibits	49

	SIGNATURE	50

	AGL Resources Inc. Shareholders
	Common stock				Additional paid-in			Retained			Accumulated other comprehensive			Treasury			Noncontrolling
In millions, except per share amounts	Shares		Amount		capital			earnings			loss			shares			interest			Total
Balance as of December 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		0			(105	)		0			0			0			(105	)
Distributions to noncontrolling interest		0.0		0		0			0			0			0			(16	)		(16	)
Stock granted, share-based compensation, net of forfeitures		0.0		0		(5	)		0			0			0			0			(5	)
Stock issued, dividend reinvestment plan		0.2		1		6			0			0			0			0			7
Stock issued, share-based compensation, net of forfeitures		0.3		2		12			0			0			(2	)		0			12
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 September 30, 2011		78.5	$	394	$	650		$	977		$	(151	)	$	(6	)	$	17		$	1,881

In millions	September 30, 2012		December 31, 2011		September 30, 2011
Money market funds (1)	$	69	$	59	$	0
Corporate bonds (2)		6		6		0
Other investments (2)		4		7		0
Total	$	79	$	72	$	0

	Three months ended September 30,				Nine months ended September 30,
In millions	2012		2011		2012		2011
Retail operations	$	0	$	0	$	3	$	0
Wholesale services		0		9		18		9
Midstream operations		0		0		1		0

	Three months ended September 30,					Nine months ended September 30,
In millions (except per share amounts)	2012		2011			2012		2011
Net income (loss) attributable to AGL Resources Inc.	$	9	$	(3	)	$	173	$	139
Denominator:
Basic weighted average number of shares outstanding (1)		117.1		78.1			116.9		77.9
Effect of dilutive securities		0.4		0.0			0.4		0.5
Diluted weighted average number of shares outstanding		117.5		78.1			117.3		78.4

Basic and diluted earnings (loss) per share
Basic	$	0.08	$	(0.04	)	$	1.48	$	1.79
Diluted	$	0.08	$	(0.04	)	$	1.48	$	1.78
(1) Daily weighted average shares outstanding.

In millions
Current assets	$	59
Other noncurrent assets, excluding goodwill		567
Current liabilities		(107	)
Other noncurrent liabilities		(1,138	)

In millions	Distribution operations		Retail operations		Midstream operations		Cargo shipping		Consolidated
AGL Resources’ legacy goodwill	$	400	$	0	$	14	$	0	$	414
Merger with Nicor		1,191		122		0		90		1,403
Total goodwill	$	1,591	$	122	$	14	$	90	$	1,817

In millions	Fair Value		Weighted average amortization period
Trade names:
Retail operations	$	29	15 years
Cargo shipping		15	15 years

Customer relationships:
Retail operations		53	10 years
Cargo shipping		4	18 years
Total	$	101

In millions, except per share amounts	Twelve months ended December 31, 2011		Nine months ended September 30, 2011
Total revenues	$	4,680	$	3,410
Net income attributable to AGL Resources Inc.	$	304	$	201
Basic earnings per common share	$	2.62	$	1.74
Diluted earnings per common share	$	2.61	$	1.73

	Recurring fair values Derivative instruments
	September 30, 2012						December 31, 2011					September 30, 2011
In millions		Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)		$	11	$	(55	)	$	11	$	(145	)	$	8	$	(72	)
Significant other observable inputs (Level 2)			100		(33	)		229		(68	)		120		(39	)
Netting of cash collateral			47		46			32		115			27		52
Total carrying value (2) (3)		$	158	$	(42	)	$	272	$	(98	)	$	155	$	(59	)
Interest rate derivatives
Significant other observable inputs (Level 2)		$	0	$	0		$	13	$	(13	)	$	13	$	0

Natural gas contracts

In Bcf	September 30, 2012 (1) (2)			December 31, 2011 (2)			September 30, 2011
Hedge designation:
Cash flow		7			5			4
Not designated		35			186			161
Total		42			191			165
Hedge position:
Short		(1,994	)		(1,680	)		(1,624	)
Long		2,036			1,871			1,789
Net long position		42			191			165

In millions	Probabilistic model cost estimates (1)		Engineering estimates (1)		Amount recorded		Expected costs over next twelve months
Illinois	$	193 - $443	$	50	$	242	$	26
New Jersey		112 - 202		2		111		19
Georgia and Florida		50 - 102		9		62		9
North Carolina		n/a		11		11		7
Total	$	355 - $747	$	72	$	426	$	61

In millions	Identifiable and total assets (1)		Goodwill
Distribution operations	$	11,020	$	1,586
Retail operations		501		124
Wholesale services		1,214		2
Midstream operations		635		16
Cargo shipping		481		77
Other (2)		62		8
Consolidated	$	13,913	$	1,813

Withdrawal schedule	Total storage (in Bcf)		Expected operating revenues (in millions)
2012
Fourth quarter		25	$	28
2013
First quarter		26		28
Second quarter		3		4
Third quarter		3		4
Fourth quarter		1		1
Total at September 30, 2012		58	$	65
Total at September 30, 2011		25	$	6

Dollars in millions	Utility	Expenditures in 2012		Expenditures since project inception		Miles of pipe replaced		Year project began		Anticipated year of completion
Pipeline replacement program	Atlanta Gas Light	$	81	$	648		2,610		1998		2013
Integrated System Reinforcement Program	Atlanta Gas Light		69		211		n/a		2009		2012
Integrated Customer Growth Program	Atlanta Gas Light		14		26		n/a		2010		2012
Enhanced infrastructure program	Elizabethtown Gas		14		103		96		2009		2012
Accelerated infrastructure program	Virginia Natural Gas		9		9		24		2012		2017
Total		$	187	$	997		2,730

Weather
Heating degree days (1)
	Nine months ended September 30,						2012 vs. normal			2012 vs. 2011
	Normal		2012		2011		colder (warmer)			colder (warmer)
Illinois		3,610		2,973		4,082		(18	)%		(27	)%
Georgia		1,591		1,056		1,602		(34	)%		(34	)%
Virginia		2,057		1,460		2,092		(29	)%		(30	)%
New Jersey		2,993		2,380		2,949		(20	)%		(19	)%
Florida		365		220		244		(40	)%		(10	)%
Tennessee		1,826		1,313		1,849		(28	)%		(29	)%
Maryland		2,999		2,448		3,026		(18	)%		(19	)%
Ohio		3,035		2,564		3,093		(16	)%		(17	)%


Customers (average end-use customers (in thousands))	Three months ended September 30,									Nine months ended September 30,
	2012			2011			% change			2012			2011			% change
Distribution Operations

Nicor Gas		2,181			n/a			n/a			2,188			n/a			n/a
Atlanta Gas Light		1,522			1,518			0.3	%		1,544			1,546			(0.1	)%
Virginia Natural Gas		279			275			1.5	%		280			278			0.7	%
Elizabethtown Gas		276			275			0.4	%		277			276			0.4	%
Florida City Gas		104			103			1.0	%		104			103			1.0	%
Chattanooga Gas		61			61			0.0	%		62			62			0.0	%
Elkton Gas		6			6			0.0	%		6			6			0.0	%
Total		4,429			2,238						4,461			2,271

Retail Operations
Georgia		477			482			(1	)%		487			491			(1	)%
Illinois		414			n/a			n/a			429			n/a			n/a
Ohio and Florida (2)		63			94			(33	)%		119			87			37	%
Indiana		37			n/a			n/a			37			n/a			n/a
Other		6			n/a			n/a			6			n/a			n/a
Total		997			576						1,063			578
Market share in Georgia		32.0	%		32.5	%					32.1	%		32.4	%


Volumes	Three months ended September 30,									Nine months ended September 30,
	2012			2011			% change			2012		2011		% change
Distribution Operations In Bcf
Firm		75			20			n/a			408		147		n/a
Interruptible		26			25			4	%		79		78		1	%
Total		101			45			n/a			487		225		n/a

Retail Operations (In Bcf)
Georgia firm		3			3			0	%		20		26		(23	)%
Ohio and Florida		1			1			0	%		6		6		0	%

Wholesale Services
Daily physical sales (Bcf/day)		5.3			4.9			8	%		5.4		5.1		6	%
Cargo Shipping (TEU’s - in thousands)
Shipments		43			n/a			n/a			124		n/a		n/a
	As of September 30,
		2012			2011
Midstream Operations
Working natural gas capacity (In Bcf)		30.3			13.5
% of firm capacity under subscription by third parties (3)		48	%		67	%

In millions
EBIT - for third quarter of 2011	$	70

Operating margin
Increased margin from Nicor Gas as a result of the Nicor merger in December 2011		132
Increased regulatory infrastructure program revenues at Atlanta Gas Light		3
Decreased revenues from lower usage at Elizabethtown Gas		(1	)
Other		1
Increase in operating margin		135

Operating expenses
Increased expenses for Nicor Gas as a result of the Nicor merger in December 2011		117
Increased incentive compensation expenses		9
Increased depreciation expense		1
Increased pension and health benefits expenses		2
Decreased outside services, bad debt, legal and other expenses		(4	)
Increase in operating expenses		125
EBIT - for third quarter of 2012	$	80

In millions
EBIT - for nine months of 2011	$	285

Operating margin
Increased margin from Nicor Gas as a result of the Nicor merger in December 2011		465
Increased regulatory infrastructure program revenues at Atlanta Gas Light		8
Decreased revenues from lower usage and weather normalization at Virginia Natural Gas, Elizabethtown Gas and Florida City Gas		(4	)
Increase in operating margin		469

Operating expenses
Increased expenses for Nicor Gas as a result of the Nicor merger in December 2011		379
Increased incentive compensation expenses		7
Increased depreciation expense		7
Increased pension and health benefits expenses		7
Decreased bad debt expense		(7	)
Decreased outside services, legal and other expenses		(10	)
Increase in operating expenses		383
Increased other income		3
EBIT - for nine months of 2012	$	374

	AGL Resources						Nicor Gas
	September 30,						September 30,
	2012			2011			2012			2011
Debt-to-capitalization ratio		56	%		57	%		51	%		n/a

In millions	Period end balance outstanding (1)		Daily average balance outstanding (2)		Minimum balance outstanding (2)		Largest balance outstanding (2)
Commercial paper - AGL Capital	$	875	$	729	$	578	$	925
Commercial paper - Nicor Gas		173		116		0		456
Current portion of long-term debt		225		147		15		240
Current portion of capital leases		1		2		1		2
Total short-term debt and current portion of long-term debt and capital leases	$	1,274	$	994	$	594	$	1,623

	Derivative instruments average values (1) at September 30,
In millions	2012		2011
Asset	$	213	$	177
Liability		97		46

	Derivative instruments fair values netted with cash collateral at
In millions	Sept. 30, 2012		Dec. 31, 2011		Sept. 30, 2011
Asset	$	159	$	288	$	168
Liability		42		110		59

In millions	Prices actively quoted (Level 1) (1)			Significant other observable inputs (Level 2) (2)
Mature through 2012	$	(28	)	$	20
Mature 2013 - 2014		(14	)		46
Mature 2015 - 2017		(2	)		2
Total derivative instruments (3)	$	(44	)	$	68

	Gross receivables						Gross payables
	Sept. 30,		Dec. 31,		Sept. 30,		Sept. 30,		Dec. 31,		Sept. 30,
In millions	2012		2011		2011		2012		2011		2011
Netting agreements in place:
Counterparty is investment grade	$	293	$	395	$	364	$	201	$	255	$	275
Counterparty is non-investment grade		15		23		8		20		47		22
Counterparty has no external rating		87		184		133		223		288		280
No netting agreements in place:
Counterparty is investment grade		1		4		4		0		0		6
Counterparty has no external rating		1		1		3		0		0		3
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position	$	397	$	607	$	512	$	444	$	590	$	586

Date: November 1, 2012	/s/ John W. Somerhalder II
	Chairman, President and Chief Executive Officer

Date: November 1, 2012	/s/ Andrew W. Evans
	Executive Vice President and Chief Financial Officer