Edgar Filing: AGL RESOURCES INC

form_10-q.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

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

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

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

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

Class	Outstanding as of July 25, 2012
Common Stock, $5.00 Par Value	117,515,999

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended June 30, 2012

TABLE OF CONTENTS

				Page(s)
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 (Unaudited)		9
			Note 1 – Organization and Basis of Presentation		9
			Note 2 – Significant Accounting Policies and Methods of Application		9
			Note 3 – Merger with Nicor		15
			Note 4 – Fair Value Measurements		16
			Note 5 – Derivative Instruments		17
			Note 6 – Employee Benefit Plans		20
			Note 7 – Debt and Credit Facilities		21
			Note 8 – Non-Wholly Owned Entities		22
			Note 9 – Commitments, Guarantees and Contingencies		23
			Note 10 – Segment Information		25
	2		Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
			Forward-Looking Statements		29
			Overview		29
			Executive Summary		30
			Results of Operations		33
			Liquidity and Capital Resources		40
			Critical Accounting Policies and Estimates		44
	3		Quantitative and Qualitative Disclosures About Market Risk		45
	4		Controls and Procedures		47
			PART II – OTHER INFORMATION

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

			SIGNATURE		50

Glossary of Key Terms

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GLOSSARY OF KEY TERMS

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
Henry Hub	A major interconnection point of natural gas pipelines in Erath, Louisiana where NYMEX natural gas future contracts are priced
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
LIBOR	London Inter-Bank Offered Rate
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, a cargo container leasing company in which we have an investment
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

Glossary of Key Terms

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PART 1 – Financial Information

Item 1. Financial Statements

AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(UNAUDITED)

	As of
In millions	June 30, 2012		December 31, 2011		June 30, 2011
Current assets
Cash and cash equivalents	$	87	$	69	$	21
Short-term investments		61		53		0
Receivables
Gas, unbilled and other receivables		349		692		181
Energy marketing receivables		347		607		614
Less allowance for uncollectible accounts		39		15		22
Total receivables		657		1,284		773
Inventories		549		750		544
Derivative instruments – current portion		181		226		111
Regulatory assets – current portion		146		131		71
Other current assets		199		233		83
Total current assets		1,880		2,746		1,603
Long-term assets and other deferred debits
Property, plant and equipment		10,091		9,779		6,447
Less accumulated depreciation		2,004		1,879		1,860
Property, plant and equipment, net		8,087		7,900		4,587
Goodwill		1,813		1,813		418
Regulatory assets – noncurrent portion		1,128		1,079		543
Derivative instruments – noncurrent portion		45		62		29
Other long-term assets and other deferred debits		321		313		37
Total long-term assets and other deferred debits		11,394		11,167		5,614
Total assets	$	13,274	$	13,913	$	7,217
Current liabilities
Short-term debt	$	731	$	1,321	$	142
Current portion of long-term debt and capital leases		231		17		12
Energy marketing trade payables		383		590		681
Accounts payable – trade		248		294		130
Accrued regulatory infrastructure program costs – current portion		158		131		90
Customer deposits and credit balances		139		152		39
Accrued expenses		138		162		112
Regulatory liabilities – current portion		137		112		66
Accrued environmental remediation liabilities – current portion		59		37		20
Derivative instruments – current portion		58		99		22
Other current liabilities		178		169		85
Total current liabilities		2,460		3,084		1,399
Long-term liabilities and other deferred credits
Long-term debt		3,334		3,561		2,164
Accumulated deferred income taxes		1,509		1,445		853
Regulatory liabilities – noncurrent portion		1,453		1,405		296
Accrued environmental remediation liabilities		371		290		171
Accrued other retirement benefit costs		296		320		32
Accrued pension obligations		221		238		152
Accrued regulatory infrastructure program costs		119		145		168
Derivative instruments – noncurrent portion		8		11		7
Other long-term liabilities and other deferred credits		74		75		61
Total long-term liabilities and other deferred credits		7,385		7,490		3,904
Total liabilities and other deferred credits		9,845		10,574		5,303
Commitments, guarantees and contingencies (see Note 9)
Equity
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized		3,412		3,318		1,896
Noncontrolling interest		17		21		18
Total equity		3,429		3,339		1,914
Total liabilities and equity	$	13,274	$	13,913	$	7,217
See Notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three months ended						Six months ended
	June 30,						June 30,
In millions, except per share amounts	2012			2011			2012			2011
Operating revenues (includes revenue taxes of $14 and $55 for the three and six months in 2012)	$	686		$	375		$	2,090		$	1,253
Operating expenses
Cost of goods sold		240			134			959			589
Operation and maintenance		218			119			463			248
Depreciation and amortization		102			42			206			83
Taxes other than income taxes		32			12			96			25
Nicor merger expenses		3			8			13			10
Total operating expenses		595			315			1,737			955
Operating income		91			60			353			298
Other income		9			2			13			3
Interest expense, net		(45	)		(32	)		(92	)		(61	)
Earnings before income taxes		55			30			274			240
Income tax expense		20			11			100			87
Net income		35			19			174			153
Less net income attributable to the noncontrolling interest		1			1			10			11
Net income attributable to AGL Resources Inc.	$	34		$	18		$	164		$	142
Per common share data
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	0.28		$	0.23		$	1.40		$	1.83
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	0.28		$	0.23		$	1.40		$	1.82
Cash dividends declared per common share	$	0.46		$	0.45		$	0.82		$	0.90
Weighted-average number of common shares outstanding
Basic		116.9			77.9			116.8			77.8
Diluted		117.2			78.5			117.1			78.3

See Notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)

	Three months ended						Six months ended
	June 30,						June 30,
In millions	2012			2011			2012			2011
Net income	$	35		$	19		$	174		$	153
Other comprehensive income (loss), net of tax
Retirement benefit plans
Reclassification of losses and prior service costs to net benefit cost (net of income tax of $3 and $4 for the three and six months ended June 30, 2012)		7			0			8			0
Retirement benefit plans, net		7			0			8			0
Cash flow hedges, net of tax
Net derivative instrument losses (gains) arising during the period (net of income tax of $3 and $1 for the three and six months ended June 30, 2012)		4			0			2			(1	)
Cash flow hedges, net		4			0			2			(1	)
Other comprehensive income (loss), net of tax		11			0			10			(1	)
Comprehensive income		46			19			184			152
Less comprehensive income attributable to noncontrolling interest		(1	)		(1	)		(10	)		(11	)
Comprehensive income attributable to AGL Resources Inc.	$	45		$	18		$	174		$	141

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

	AGL Resources Inc. Shareholders
	Common stock				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		142			0			0			11			153
Other comprehensive loss		0.0		0		0		0			(1	)		0			0			(1	)
Dividends on common stock ($0.90 per share)		0.0		0		2		(70	)		0			0			0			(68	)
Distributions to noncontrolling interest		0.0		0		0		0			0			0			(16	)		(16	)
Benefit, dividend reinvestment and stock purchase plans		0.4		2		8		0			0			(2	)		0			8
Purchase of treasury shares		0.0		0		0		0			0			(2	)		0			(2	)
Stock-based compensation expense (net of tax)		0.0		0		4		0			0			0			0			4
Balance as of June 30, 2011		78.4	$	393	$	645	$	1,015		$	(151	)	$	(6	)	$	18		$	1,914

	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, 2011		117.0	$	586	$	1,989	$	967		$	(217	)	$	(7	)	$	21		$	3,339
Net income		0.0		0		0		164			0			0			10			174
Other comprehensive income		0.0		0		0		0			10			0			0			10
Dividends on common stock ($0.82 per share)		0.0		0		0		(96	)		0			0			0			(96	)
Distributions to noncontrolling interest		0.0		0		0		0			0			0			(14	)		(14	)
Benefit, dividend reinvestment and stock purchase plans		0.5		3		9		0			0			(1	)		0			11
Stock-based compensation expense (net of tax)		0.0		0		5		0			0			0			0			5
Balance as of June 30, 2012		117.5	$	589	$	2,003	$	1,035		$	(207	)	$	(8	)	$	17		$	3,429

See Notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six months ended
	June 30,
In millions	2012			2011
Cash flows from operating activities
Net income	$	174		$	153
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		206			83
Deferred income taxes		56			64
Change in derivative instrument assets and liabilities		18			49
Changes in certain assets and liabilities
Receivables, other than energy marketing		367			215
Inventories, net of temporary LIFO liquidation		242			95
Energy marketing receivables and trade payables, net		53			111
Prepaid taxes		33			(1	)
Trade payables, other than energy marketing		(46	)		(46	)
Other – net		(21	)		(63	)
Net cash flow provided by operating activities		1,082			660
Cash flows from investing activities
Expenditures for property, plant and equipment		(350	)		(196	)
Net cash flow used in investing activities		(350	)		(196	)
Cash flows from financing activities
Net payments and borrowings of short-term debt		(590	)		(589	)
Dividends paid on common shares		(96	)		(68	)
Distribution to noncontrolling interest		(14	)		(16	)
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			495
Other		(14	)		11
Net cash flow used in financing activities		(714	)		(467	)
Net increase (decrease) in cash and cash equivalents		18			(3	)
Cash and cash equivalents at beginning of period		69			24
Cash and cash equivalents at end of period	$	87		$	21
Cash paid during the period for
Interest	$	86		$	56
Income taxes	$	4		$	10

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

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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 9, 2011, we closed our merger with Nicor and created a combined company with increased scale and scope in the distribution, storage and transportation of natural gas. As such, the businesses acquired as part of the merger are included for 2012, but not for the three and six months ended or as of June 30, 2011 in our unaudited Condensed Consolidated Financial Statements. See Note 3 for additional information.

As a result of the Nicor merger, AGL Resources shareholders of record as of the close of business on December 8, 2011, received a pro rata dividend for the stub period, accruing from November 19, 2011. The dividend payments made in February 2012 were reduced by this stub period dividend.

The December 31, 2011 Condensed Consolidated 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 unaudited 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 unaudited Condensed Consolidated Financial Statements in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K.

Due to the seasonal nature of our business and other factors, our results of operations and our financial condition for the periods presented 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 unaudited Condensed Consolidated Financial Statements include our accounts, the accounts of our wholly owned subsidiaries, the accounts of our majority owned and controlled subsidiaries and the accounts of our consolidated variable interest entity (VIE) for which we are the primary beneficiary. For unconsolidated entities that we do not control, but exercise significant influence over, we use the equity method of accounting and our proportionate share of income or loss is recorded in the unaudited Condensed Consolidated Statements of Income. See Note 8 for additional information. 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

Our accounting policies are described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K. There were no significant changes to our accounting policies during the six months ended June 30, 2012.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures. 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.

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Investments

Our investments in debt and equity securities are as follows:

In millions	June 30, 2012		December 31, 2011		June 30, 2011
Money market funds	$	76	$	59	$	0
Corporate bonds		5		6		0
Other investments		6		7		0
Total	$	87	$	72	$	0

Investments in debt and equity securities are classified on the unaudited Condensed Consolidated Statements of Financial Position as follows:

In millions	June 30, 2012		December 31, 2011		June 30, 2011
Cash and cash equivalents	$	17	$	9	$	0
Short-term investments		61		53		0
Other long-term assets and other deferred debits		9		10		0
Total	$	87	$	72	$	0

Investments categorized as trading (including money market funds) totaled $76 million at June 30, 2012 and $59 million at December 31, 2011.

Corporate bonds and certain other investments are categorized as held-to-maturity. The contractual maturities of the held-to-maturity investments at June 30, 2012 are as follows:

	Years to maturity
In millions	Less than 1 year		1-5 years		5-10 years		Total
Held-to-maturity investments	$	2	$	5	$	0	$	7

Our investments also include certain investments, including certificates of deposit and bank accounts, maintained to fulfill statutory or contractual requirements. These investments totaled $2 million at June 30, 2012 and $3 million at December 31, 2011. Gains or losses included in earnings resulting from the sale of investments were not significant.

Inventories

Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during interim periods that are expected to be restored prior to year-end are charged to cost of goods sold at the estimated annual replacement cost, and the difference between this cost and the actual liquidated LIFO layer cost is recorded as a temporary LIFO inventory liquidation. This is classified in other current liabilities on our unaudited Condensed Consolidated Statements of Financial Position. The inventory decrement as of June 30, 2012 is expected to be restored prior to year-end. Interim inventory decrements not expected to be restored prior to year-end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated.

Our retail operations, wholesale services and midstream operations segments 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. Consequently, as a result of declining natural gas prices during the six months ended June 30, 2012, retail operations, wholesale services and midstream operations recorded LOCOM adjustments to cost of goods sold in the following amounts, to reduce the value of their inventories to market value.

	Three months ended June 30,				Six months ended June 30,
In millions	2012		2011		2012		2011
Retail operations	$	0	$	0	$	3	$	0
Wholesale services		0		0		18		0
Midstream operations		0		0		1		0

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 our wholesale services segment 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 settled net, but are recorded on a gross basis in our unaudited Condensed Consolidated Statements of Financial Position as energy marketing receivables and energy marketing payables.

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Our wholesale services segment has some trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of June 30, 2012, December 31, 2011 and June 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.

Fair Value Measurements

We have several financial and nonfinancial assets and liabilities subject to fair value measures. The financial assets and liabilities include cash and cash equivalents, receivables, derivative assets and liabilities, accounts payable and debt. The carrying values of cash and cash equivalents, short and long-term investments, derivative assets and liabilities, short-term debt, other current assets and liabilities and accrued interest approximate fair value. The nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 4 to our Consolidated Financial Statements and related notes included in Item 8 of our 2011 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 valuing 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 to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the reliability of those inputs in accordance with the fair value hierarchy.

Natural Gas Derivative Instruments

The fair value of the natural gas derivative instruments that we use to manage exposures arising from changing natural gas prices reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 5 for additional derivative disclosures.

Distribution Operations Nicor Gas, subject to review by the Illinois Commission, and Elizabethtown Gas, in accordance with a directive from the New Jersey BPU, enter into derivative instruments to hedge the impact of market fluctuations in natural gas prices. In accordance with the authoritative guidance related to derivatives and hedging, such derivative transactions are accounted for at fair value each reporting period in our unaudited Condensed Consolidated Statements of Financial Position. In accordance with regulatory requirements, any realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. Thus, hedge accounting is not elected and, in accordance with accounting guidance pertaining to rate-regulated entities, unrealized changes in the fair value of these derivative instruments are deferred or accrued as regulatory assets or liabilities until the related revenue is recognized.

Nicor Gas also enters into swap agreements to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for company use. These derivative instruments are carried at fair value. To the extent hedge accounting is not elected, changes in such fair values are immediately recorded in the current period as operation and maintenance expense.

Retail Operations We have designated a portion of our derivative instruments, consisting of financial swaps to manage the risk associated with forecasted natural gas purchases and sales, as cash flow hedges under the authoritative guidance related to derivatives and hedging. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period as the settlement of the underlying hedged item.

We currently have minimal hedge ineffectiveness defined as when the gains or losses on the hedging instrument do not offset the losses or gains on the hedged item. This cash flow hedge ineffectiveness is recorded in cost of goods sold in our unaudited Condensed Consolidated Statements of Income in the period in which it occurs. We have not designated the remainder of our derivative instruments as hedges under the authoritative guidance related to derivatives and hedging and, accordingly, we record changes in the fair value of such instruments within cost of goods sold in our Consolidated Statements of Income in the period of change.

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We enter into weather derivative contracts as economic hedges of operating margins in the event of warmer than normal weather in the Heating Season. We account for these contracts using the intrinsic value method under the authoritative guidance related to financial instruments. These weather derivative instruments do not qualify for accounting hedge designation and accordingly changes in value are reflected in cost of goods sold on our unaudited Condensed Consolidated Statements of Income.

Wholesale Services We purchase natural gas for storage when the difference in 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 other 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 other OTC derivatives to capture the price differential or location 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 futures contracts meet the definition of derivatives under the authoritative guidance related to derivatives and hedging and are accounted for 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 guidance.

The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis we utilize for the derivatives used to mitigate the natural gas price risk associated with our storage portfolio. Further, we incur monthly demand charges for the contracted storage and transportation capacity, and payments associated with asset management agreements and record these demand charges in our unaudited Condensed Consolidated Statements of Income in the period they are incurred. This difference in accounting can result in volatility in our reported earnings, even though the economic margin is essentially unchanged from the date the transactions were consummated.

Midstream Operations During the construction of our storage caverns, we use derivative instruments to reduce our exposure to the risk of changes in the price of natural gas that will be purchased in future periods for gas associated with bringing our facilities into service, including pad gas that is considered to be a component of the storage cavern’s construction costs. We use derivative instruments to economically hedge operational and optimization purchases and sales and these instruments do not qualify as cash flow hedges.

We have designated as cash flow hedges, those derivative instruments executed to manage the risk with the purchase of pad gas. Any derivative gains or losses arising from the cash flow hedges will remain in accumulated OCI until the pad gas is sold, which will not occur until the storage caverns are decommissioned. The fair value of these derivative instruments currently has minimal hedge ineffectiveness which is recorded in cost of goods sold in our Consolidated Statements of Income in the period in which it occurs.

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our 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. The increase in weighted average shares is primarily due to the issuance of 38.2 million shares in connection with the Nicor merger.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The vesting of certain shares of the restricted stock and restricted stock units depends on the satisfaction of defined performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods.

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The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. common shareholders for the periods presented, if performance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised:

	Three months ended June 30,				Six months ended June 30,
In millions (except per share amounts)	2012		2011		2012		2011
Net income attributable to AGL Resources Inc.	$	34	$	18	$	164	$	142
Denominator:
Basic weighted average number of shares outstanding (1)		116.9		77.9		116.8		77.8
Effect of dilutive securities		0.3		0.6		0.3		0.5
Diluted weighted average number of shares outstanding		117.2		78.5		117.1		78.3

Basic and diluted earnings per share
Basic	$	0.28	$	0.23	$	1.40	$	1.83
Diluted	$	0.28	$	0.23	$	1.40	$	1.82
(1) Daily weighted average shares outstanding.

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

	June 30,
In millions	2012		2011
Three months ended		0.6		0.0
Six months ended		0.0		0.0

The increase in the number of shares that were excluded from the computation for the three months ended June 30, 2012 is primarily the result of a decrease in the average market value of our common shares compared to the same period during 2011.

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 in the current period are capitalized as regulatory assets when it is probable that such costs or 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. 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.

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

In millions	June 30, 2012 (1)		December 31, 2011 (2)		June 30, 2011
Regulatory assets - current
Recoverable regulatory infrastructure program costs	$	47	$	48	$	47
Recoverable retirement benefit costs		27		29		0
Recoverable ERC		30		7		7
Other		42		47		17
Total regulatory assets - current		146		131		71
Regulatory assets - long-term
Recoverable ERC		428		351		215
Recoverable regulatory infrastructure program costs		313		305		281
Recoverable retirement benefit costs		232		262		9
Long-term debt fair-value adjustment		94		99		0
Unamortized losses on reacquired debt		20		21		10
Other		41		41		28
Total regulatory assets - long-term		1,128		1,079		543
Total regulatory assets	$	1,274	$	1,210	$	614
Regulatory liabilities - current
Accrued natural gas costs	$	73	$	53	$	49
Bad debt rider		31		30		0
Accumulated removal costs		14		14		0
Other		19		15		17
Total regulatory liabilities - current		137		112		66
Regulatory liabilities - long-term
Accumulated removal costs		1,366		1,321		253
Unamortized investment tax credit		31		32		11
Regulatory income tax liability		25		27		15
Bad debt rider		18		14		0
Other		13		11		17
Total regulatory liabilities - long-term		1,453		1,405		296
Total regulatory liabilities	$	1,590	$	1,517	$	362

(1)

The increase in regulatory assets and liabilities from December 31, 2011, includes an increase in our recoverable ERC due to a $103 million increase in the estimates of our ERC liabilities primarily related to Nicor Gas’ former operating sites in Illinois. See Note 9 – Commitments, Guarantees and Contingencies for additional ERC disclosures.

(2)	The increase in regulatory assets and liabilities from June 30, 2011, includes $545 million related to the addition of Nicor Gas’ regulatory assets and includes $1,330 million related to the addition of Nicor Gas’ regulatory liabilities.

As of June 30, 2012, 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 2011 Form 10-K.

Accounting Developments

On January 1, 2012, we adopted authoritative guidance related to fair value measurements. The guidance expands the qualitative and quantitative disclosures required for Level 3 significant unobservable inputs. The guidance also limits the application of the highest and best use premise to non-financial assets and liabilities. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 4 for additional fair value disclosures.

On January 1, 2012, we adopted authoritative guidance related to comprehensive income. The guidance eliminates the option to present OCI in the unaudited Condensed Consolidated Statements of Equity, but allows companies to elect to present net income and OCI in one continuous statement (unaudited Condensed Consolidated Statements of Comprehensive Income) or in two consecutive statements. This guidance does not change any of the components of net income or OCI and earnings per share will still be calculated based on net income. This guidance did not have a material impact on our unaudited Condensed Consolidated Financial Statements.

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Note 3 – Merger with Nicor

On December 9, 2011, we completed our $2.5 billion merger with Nicor. The preliminary allocation of the total purchase consideration transferred to the fair value of assets acquired and liabilities assumed included adjustments for the fair value of Nicor’s assets and liabilities. During the second quarter of 2012, we completed our evaluation of the ERC liabilities for our sites in Illinois, which resulted in an increase of $109 million in the liability from the amount recorded in our initial purchase price allocation. As these costs are recoverable from our customers as they are paid, we have recorded a regulatory asset associated with the recorded liabilities, which is reflected in our table of purchase price allocation for Nicor Gas’ regulatory assets and liabilities below. See Note 9 – Commitments, Guarantees and Contingencies for additional ERC discussion. The preliminary allocation of the purchase price is presented in the following table.

In millions
Current assets	$	932
Property, plant and equipment		3,202
Goodwill		1,395
Other noncurrent assets, excluding goodwill		900
Current liabilities		(1,170	)
Long-term debt		(599	)
Other noncurrent liabilities		(2,157	)
Total purchase consideration	$	2,503

The estimated fair values of the assets acquired and the liabilities assumed were determined based on the accounting guidance for fair value measurements under GAAP. The estimated fair value measurements assume the highest and best use of the assets by market participants, considering the use of the asset that is physically possible, legally permissible and financially feasible at the measurement date. Modifications to the purchase price allocation may occur as a result of our continuing review of the assumptions and estimates underlying the preliminary allocation of the purchase price.

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.

In millions
Current assets	$	36
Other noncurrent assets, excluding goodwill		586
Current liabilities		(80	)
Other noncurrent liabilities		(1,137	)

For all other assets and liabilities acquired from Nicor, we considered the income, market and cost approaches to fair valuation. The income approach estimates the fair value by discounting the projected future cash flows at our weighted average cost of capital. We utilized this approach to obtain the business enterprise values for each reporting unit. Additionally, we used the income approach to determine the fair values for intangible trade names and customer relationships assets.

The market approach is based on the premise that the fair value can be determined through the use of prices and other relevant information generated by the market transactions involving identical or comparable assets or liabilities. Finally, the cost approach utilizes the concept of replacement cost as an indicator of fair value. We applied the market and cost approach to estimate the fair value of the property, plant and equipment. Our valuations included a $31 million step-up for Nicor’s non-regulatory property, plant and equipment. This was primarily related to the vessels and related equipment at our cargo shipping segment. The excess of the purchase price paid over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill, which is not deductible for tax purposes.

Within our operating expenses, we recognized merger expenses of $3 million ($2 million net of tax) for the three months ended June 30, 2012 compared to $8 million ($5 million net of tax) recorded by AGL Resources during the same period in 2011. We recognized $13 million ($8 million net of tax) of merger expenses during the six months ended June 30, 2012 compared to $10 million ($6 million net of tax) recorded by AGL Resources for the same period in 2011. These costs were expensed as incurred. In addition, our 2011 unaudited Condensed Consolidated Statements of Income include incremental debt issuance costs and interest expense related to financing the cash portion of the purchase consideration in advance of the merger closing date. The amount included for the three months ended June 30, 2011 was $5 million ($3 million net of tax) and the amount included for the six months ended June 30, 2011 was $8 million ($5 million net of tax).

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Pro forma financial information The following unaudited pro forma financial information reflects our consolidated results of operations as if the merger with Nicor had taken place on January 1, 2011. The unaudited pro forma information has been calculated after conforming our accounting policies and adjusting Nicor’s results to reflect the depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, debt and intangible assets had been applied on January 1, 2011, together with the consequential tax effects.

AGL Resources and Nicor together incurred approximately $96 million of costs directly related to the merger in the twelve months ended December 31, 2011 and $20 million was incurred in the six months ended June 30, 2011. These expenses are excluded from the pro forma earnings presented below.

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the pro forma events taken place on the dates indicated, or of the future consolidated results of operations of the combined company.

In millions, except per share amounts	Twelve months ended December 31, 2011		Six months ended June 30, 2011
Total revenues	$	4,680	$	2,767
Net income attributable to AGL Resources Inc.	$	304	$	200
Basic earnings per common share	$	2.62	$	1.72
Diluted earnings per common share	$	2.61	$	1.71

Note 4 – Fair Value Measurements

The methods used to determine the fair value of our assets and liabilities are described within Note 2 – Significant Accounting Policies and Methods of Application.

Derivative Instruments

The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were accounted for at fair value on a recurring basis as of the periods presented. See Note 5 – Derivative Instruments for additional derivative instrument information.

	Recurring fair values Derivative instruments
	June 30, 2012						December 31, 2011					June 30, 2011
In millions	Assets			Liabilities			Assets (1)		Liabilities			Assets		Liabilities
Natural gas derivatives
Quoted prices in active markets (Level 1)		$	9	$	(103	)	$	11	$	(145	)	$	1	$	(52	)
Significant other observable inputs (Level 2)			148		(48	)		229		(68	)		99		(17	)
Netting of cash collateral			52		85			32		115			37		40
Total carrying value (2) (3)		$	209	$	(66	)	$	272	$	(98	)	$	137	$	(29	)
Interest rate derivatives
Significant other observable inputs (Level 2)		$	17	$	0		$	13	$	(13	)	$	3	$	0

(1)	$3 million at December 31, 2011 associated with weather derivatives have been excluded as they are accounted for based on intrinsic 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.

Money Market Funds

In millions		June 30, 2012				December 31, 2011				June 30, 2011
Money market funds (1)		$	76			$	59			$	0

(1)	Recorded at fair value and classified as Level 1 within the fair value hierarchy.

Debt

Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which are recorded at acquisition date fair value. We estimate the fair value of our debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. The following table presents the amortized cost and fair value of our long-term debt as of the following periods.

In millions		June 30, 2012	December 31, 2011		June 30, 2011
Long-term debt amortized cost (1)	$	3,564	$	3,576	$	2,174
Long-term debt fair value (1) (2)	$	4,043	$	3,938	$	2,339

(1)	June 30, 2012 includes current portion of long-term debt of $230 million while December 31, 2011 includes current portion of long-term debt of $15 million as well as the debt assumed in the Nicor merger with a stepped-up carrying value of $594 million.

(2)	Valued using Level 2 inputs.

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Note 5 – Derivative Instruments

A description of our objectives and strategies for using derivative instruments, related accounting policies and methods used to determine their fair value are described in Note 2 – Significant Accounting Policies and Methods of Application. See Note 4 – Fair Value Measurements for additional fair value disclosures.

Certain of our derivative instruments contain credit-risk-related or other contingent features that could increase the payments for collateral we post in the normal course of business when our financial instruments are in net liability positions. As of June 30, 2012 for agreements with such features, derivative instruments with liability fair values totaled approximately $66 million for which we had posted no collateral to our counterparties. In addition, our energy marketing receivables and payables, which also have credit-risk-related or other contingent features, are discussed in Note 2. Our derivative instrument activities are included within operating cash flows as an adjustment to net income and were $18 million for the six months ended June 30, 2012 and $49 million for the six months ended June 30, 2011. See Note 4 – Fair Value Measurements for additional derivative instrument information.

The following table summarizes the various ways in which we account for our derivative instruments and the impact on our Consolidated Financial Statements.

	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 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

Distribution Operations

Unrealized changes in the fair value of these derivative instruments are deferred as regulatory assets or liabilities respectively within our unaudited Condensed Consolidated Statements of Financial Position until recovered from customers. The following amounts represent realized losses incurred.

	Three months ended June 30,				Six months ended June 30,
In millions	2012		2011		2012		2011
Nicor Gas	$	25		n/a	$	26		n/a
Elizabethtown Gas		7		5		16		13

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Quantitative Disclosures Related to Derivative Instruments

As of the periods presented, our derivative 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	June 30, 2012 (1) (2)			December 31, 2011 (2)			June 30, 2011
Hedge designation:
Cash flow		7			5			1
Not designated		47			186			191
Total		54			191			192
Hedge position:
Short		(2,018	)		(1,680	)		(1,559	)
Long		2,072			1,871			1,751
Net long position		54			191			192

(1)	Approximately 98% of these contracts have durations of two years or less and the remaining 2% expire between 2 to 6 years.

(2)	Volumes related to Nicor Gas exclude variable-priced contracts, which are accounted for as derivatives, but whose fair values are not directly impacted by changes in commodity prices.

Derivative Instruments Impact 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)

June 30, 2012

December 31, 2011

June 30, 2011

Designated as cash flow and fair value hedges
Asset Instruments
Current natural gas contracts	Derivative instruments assets and liabilities – current portion	$	6		$	9		$	1
Interest rate swap agreements	Derivative instruments assets – long-term portion		17			13			3
Liability Instruments
Current natural gas contracts	Derivative instruments assets and liabilities – current portion		(7	)		(12	)		(2	)
Interest rate swap agreements	Derivative instruments liabilities – long-term portion		0			(13	)		0
Total			16			(3	)		2
Not designated as cash flow hedges
Asset Instruments
Current natural gas contracts	Derivative instruments assets and liabilities – current portion		493			706			286
Noncurrent natural gas contracts	Derivative instruments assets and liabilities		69			133			69
Liability Instruments
Current natural gas contracts	Derivative instruments assets and liabilities – current portion		(489	)		(689	)		(263	)
Noncurrent natural gas contracts	Derivative instruments assets and liabilities		(66	)		(116	)		(60	)
Total			7			34			32
Total derivative instruments		$	23		$	31		$	34

(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 $137 million as of June 30, 2012, $147 million as of December 31, 2011 and $77 million as of June 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.

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Derivative Instruments on the Unaudited Condensed Consolidated Statements of Income

The following table presents the gain or (loss) on derivative instruments in our unaudited Condensed Consolidated Statements of Income for the three and six months ended June 30, 2012 and 2011:

	For the three months ended June 30,						For the six months ended June 30,
In millions	2012			2011				2012		2011

Designated as cash flow hedges
Natural gas contracts – gain (loss) reclassified from OCI into cost of goods sold for settlement of hedged item	$	3		$	(1	)	$	4			$	(1	)
Natural gas contracts – gain (loss) reclassified from OCI into operation and maintenance for settlement of hedged item		1			0			1				0
Natural gas contracts – loss recognized in OCI (effective portion)		(1	)		0			0				0
Interest rate swaps – loss recognized in OCI		(1	)		0			(3	)			0

Not designated as hedges
Natural gas contracts – net gain fair value adjustments recorded in operating revenues (1)		15			10			19				16
Natural gas contracts – net loss fair value adjustments recorded in cost of goods sold (2)		(1	)		0			(3	)			(1	)
Total gains (losses) on derivative instruments	$	16		$	9		$	18			$	14

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

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

Any amounts recognized in operating income, related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur, were immaterial for the six months ended June 30, 2012 and 2011.

Our expected net loss to be reclassified from OCI into cost of goods sold, operation and maintenance expense, and operating revenues and recognized in our unaudited Condensed Consolidated Statements of Income over the next 12 months is $3 million. These pre-tax deferred losses are recorded in OCI related to natural gas derivative contracts. The expected losses are based upon the fair values of these financial instruments at June 30, 2012.

There have been no other significant changes to our derivative instruments, as described in Note 2 and Note 4 to our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K.

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Note 6 - Employee Benefit Plans

Pension Benefits

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

	Three months ended June 30,							Six months ended June 30,
In millions			2012			2011				2012			2011
Service cost		$	7		$	4			$	14		$	7
Interest cost			11			7				22			14
Expected return on plan assets			(16	)		(8	)			(32	)		(16	)
Net amortization of prior service cost			0			0				(1	)		(1	)
Recognized actuarial loss			8			3				17			7
Net pension benefit cost		$	10		$	6			$	20		$	11

Other Defined Retirement Benefits

We sponsor two defined benefit retirement health care plans for our eligible employees, the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan) and the Nicor Gas Welfare Benefit Plan (Nicor Gas Welfare Plan). Eligibility for these benefits is based on age and years of service.

Following are the cost components of our other retirement benefit costs for the periods indicated:

	Three months ended June 30,						Six months ended June 30,
In millions	2012			2011			2012			2011
Service cost	$	1		$	0		$	2		$	0
Interest cost		4			2			8			3
Expected return on plan assets		(2	)		(2	)		(3	)		(3	)
Net amortization of prior service cost		0			(1	)		(1	)		(2	)
Recognized actuarial loss		2			0			5			1
Net benefit cost	$	5		$	(1	)	$	11		$	(1	)

In the second quarter of 2012, the estimated benefit obligation for the Nicor Gas Welfare Plan decreased to $263 million as a result of final updated census data and claims costs. As of December 31, 2011, the Nicor Gas Welfare Plan benefit obligation was $283 million.

Contributions

Our employees generally do not contribute to these pension and other retirement plans, however, Nicor Gas and AGL Resources employees who retire before they reach 65 years of age make nominal contributions to their health care plan. 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 contribute in excess of the minimum required amount. 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 over the next five years. As a result, we expect to have additional flexibility with respect to the amount of contributions to our pension plans through 2014.

The Act contains funding requirements for single employer defined benefit pension plans and establishes 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 allows us to measure our required minimum contributions based on a funding target of 100% in 2011 and 2012. During the first six months of 2012, we contributed $24 million to the AGL Retirement Plan and the NUI Retirement Plan and $44 million during the same period last year. For more information on our pension plans, see Note 11 to our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K.

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Note 7 – Debt and Credit Facilities

The following table provides maturity dates, weighted average interest rates and amounts outstanding for our various debt securities and facilities that are included in our unaudited Condensed Consolidated Statements of Financial Position. For additional information on our debt, see Note 7 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.

			June 30, 2012							June 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	%	$	731	$	869		0.4	%	$	142
Commercial paper- Nicor Gas		n/a		0.5			0		452		n/a			n/a
Total short-term debt				0.5	%	$	731	$	1,321		0.4	%	$	142
Current portion of long-term debt and capital leases
Current portion of long-term debt		2012-2013		4.7	%	$	230	$	15		8.4	%	$	10
Current portion of capital leases		2013		4.9			1		2		4.9			2
Total current portion of long-term debt and capital leases				4.7	%	$	231	$	17		7.9	%	$	12
Long-term debt – excluding current portion

Senior notes		2015-2041		5.1	%	$	2,325	$	2,550		5.5	%	$	1,775
First mortgage bonds		2016-2038		5.6			500		500		n/a			n/a
Gas facility revenue bonds		2022-2033		1.2			200		200		1.2			200
Medium-term notes		2017-2027		7.8			181		181		7.8			186
Capital leases		n/a		n/a			0		0		4.2			3
Total principal long-term debt				5.0	%	$	3,206	$	3,431		5.0	%	$	2,164
Fair value adjustment of long-term debt		2016-2038		n/a		$	110	$	112		n/a			0
Unamortized debt premium, net		n/a		n/a			18		18		n/a			n/a
Total non-principal long-term debt				n/a		$	128	$	130		n/a			0
Total long-term debt						$	3,334	$	3,561				$	2,164

Total debt						$	4,296	$	4,899				$	2,318

(1)	Interest rates are calculated based on the daily average balance outstanding.

(2)	Weighted average interest rate was 0.5% as of June 30, 2012 and 0.3% as of June 30, 2011.

(3)

Fair value adjustment of the first mortgage bonds relates to the step up to fair value of the long-term debt assumed in the Nicor merger and was $94 million as of June 30, 2012 and $99 million as of December 31, 2011. Fair value adjustment related to interest rate hedges was $16 million as of June 30, 2012 and $13 million as of December 31, 2011. There were no fair value adjustments of long-term debt as of June 30, 2011.

Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month; however, our goal is to maintain these ratios at levels between 50% and 60%. These ratios, as calculated in accordance with the debt covenants include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash pension adjustments, other post-retirement benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the periods presented.

	June 30, 2012			December 31, 2011			June 30, 2011
AGL Credit Facility		54	%		58	%		53	%
Nicor Gas Credit Facility		43	%		60	%		n/a

The credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations and other matters customarily restricted in such agreements.

Default Provisions

Our credit facilities and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. The most important default events include:

·	a maximum leverage ratio

·	insolvency events and nonpayment of scheduled principal or interest payments

·	acceleration of other financial obligations

·	change of control provisions

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We have no triggering 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 triggering events. We were in compliance with all existing debt provisions and covenants, both financial and non-financial, for all periods presented.

Note 8 – Non-Wholly Owned Entities

As of June 30, 2012, we had ownership interests in SouthStar, Triton, Horizon Pipeline and Sawgrass Storage.

Variable Interest Entities

On a quarterly basis we evaluate all of our owner interests to determine if they represent a VIE as defined by the authoritative accounting guidance on consolidation, and if so, which party is the primary beneficiary. We have determined that SouthStar, a joint venture owned by us and Piedmont, is the only VIE for which we are the primary beneficiary, which requires us to consolidate its assets, liabilities and Statements of Income. See Note 10 to our Consolidated Financial Statements and related notes included in Item 8 of our 2011 Form 10-K. Earnings from SouthStar in 2012 and 2011 were allocated entirely in accordance with the ownership interests.

SouthStar’s financial results are seasonal in nature, with earnings depending to a great extent on the first and fourth quarters of each year. SouthStar’s current assets consist primarily of natural gas inventory, derivative instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in AGL Capital’s commercial paper program. See Note 2 for additional discussions of SouthStar’s inventories. SouthStar’s restricted assets consist of customer deposits and were immaterial as of June 30, 2012 and 2011. SouthStar’s current liabilities consist primarily of accrued natural gas costs, other accrued expenses, customer deposits, derivative instruments and payables to us from its participation in AGL Capital’s commercial paper program.

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 that such contracts were terminated. As a result, our maximum exposure to a loss at SouthStar is considered to be immaterial. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. With the exception of our corporate guarantees, we have not entered into any arrangements that could require us to provide financial support to SouthStar.

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 instruments.

Cash flows used in our investing activities include capital expenditures of $1 million for SouthStar for the six months ended June 30, 2012 and 2011 and $2 million for the year ended December 31, 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 six months ended June 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.

		June 30, 2012						December 31, 2011						June 30, 2011
					%						%						%
In millions	Consolidated		SouthStar (1)		(2)		Consolidated		SouthStar (1)		(2)		Consolidated		SouthStar (1)		(2)
Current assets	$	1,880	$	145	8	%	$	2,746	$	210	8	%	$	1,603	$	164	10	%
Long-term assets and other deferred debits		11,394		9	0			11,167		9	0			5,614		9	0
Total assets	$	13,274	$	154	1	%	$	13,913	$	219	2	%	$	7,217	$	173	2	%
Current liabilities	$	2,460	$	37	2	%	$	3,084	$	77	2	%	$	1,399	$	52	4	%
Long-term liabilities and other deferred credits		7,385		0	0			7,490		0	0			3,904		0	0
Total Liabilities		9,845		37	0			10,574		77	1			5,303		52	1
Equity		3,429		117	3			3,339		142	4			1,914		121	6
Total liabilities and equity	$	13,274	$	154	1	%	$	13,913	$	219	2	%	$	7,217	$	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.

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	Three months ended				Six months ended
	June 30,				June 30,
In millions	2012		2011		2012		2011
Operating revenues	$	99	$	116	$	314	$	406
Operating expenses
Cost of goods sold		80		100		213		300
Operation and maintenance		12		14		31		34
Depreciation and amortization		1		0		1		1
Taxes other than income taxes		1		1		2		1
Total operating expenses		94		115		247		336
Operating income	$	5	$	1	$	67	$	70

Equity Method Investments

Income from our equity method investments is classified as other income on our unaudited Condensed Consolidated Statements of Income. For the three and six months ended June 30, 2012, this included investment income from Triton of $3 million and $6 million, investment income from Horizon Pipeline of $1 million and $1 million, and an immaterial amount of investment income from our other equity method investments. For more information about our equity method investments, see Note 10 to our Consolidated Financial Statements under Item 8 included in our 2011 Form 10-K.

Note 9 - Commitments, Guarantees and Contingencies

There were no significant changes to our contractual obligations described in Note 11 of our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K other than those related to ERC remediation costs and SNG contracts as described below.

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.

Substitute Natural Gas

In 2011, Illinois enacted laws that required Nicor Gas and other large utilities in Illinois to elect to either sign contracts to purchase SNG from coal gasification plants to be constructed in Illinois or instead file rate cases with the Illinois Commission in 2012, 2014 and 2016.

On September 30, 2011, Nicor Gas signed an agreement to purchase approximately 25 Bcf of SNG annually for a 10-year term beginning as early as 2015. The agreement required, among other things, the developer to begin construction of the SNG plant by July 1, 2012. The developer did not meet this deadline and, as a result, the agreement automatically terminated.

Additionally, on October 11, 2011, the Illinois Power Agency (IPA) approved the form of a draft 30-year contract for the purchase by Nicor Gas of approximately 20 Bcf per year of SNG from a second proposed plant beginning as early as 2018. 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. We have appealed the Illinois Commission’s decision to an Illinois appellate court. Neither Nicor Gas nor the developer has yet signed the form of contract approved by the Illinois Commission. In May 2012, the Illinois legislature passed a bill that directs the Illinois Commission to approve a final form of contract that differs in certain respects from the form the Illinois Commission approved in its July 11, 2012 order and that purports to address issues raised in the DuPage County litigation. Unless vetoed by the Governor of Illinois, which must be acted on by August 10, 2012, this bill will become law. If the bill becomes law, it is not clear what, if any, effect it will have on the pending litigation concerning this SNG project.

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The purchase price of the SNG that may be produced from this proposed coal gasification plant may significantly exceed market prices for natural gas and is expected to be dependent upon a variety of factors, including the developer’s financing, plant construction costs and volumes sold, which is currently not determinable. The Illinois law pertaining to this plant provides that the price paid for SNG purchased from the plant is to be considered prudent and not subject to review or disallowance by the Illinois Commission. As such, Illinois law effectively requires Nicor Gas’ customers to provide subordinated financial support to the developer.

Contingencies and Guarantees

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. We have certain subsidiaries that enter into various financial and performance guarantees and indemnities providing assurance to third parties. We believe the likelihood of payment under our guarantees and indemnities is remote. No liability has been recorded for such guarantees and indemnifications.

Environmental Matters

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 our current and former operating sites. The following table provides more information on the costs related to remediation of our former operating sites.

In millions	Probabilistic model cost estimate range		Engineering estimates		Amount recorded		Expected costs over next twelve months
Illinois	$	193 – $443	$	50	$	243	$	27
New Jersey		112 – 202		2		114		17
Georgia and Florida		50 – 102		9		62		10
North Carolina		n/a		11		11		5
Total	$	355 – $747	$	72	$	430	$	59

Our ERC liabilities are estimates of future remediation costs for our former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, which is generally the case when remediation has not commenced or during the early years of a remediation effort. For those elements of the program where we cannot perform engineering estimates, there remains considerable variability in future cost estimates. Accordingly, we have established a probabilistic model to determine a range of potential expenditures to remediate and monitor our former operating sites. We cannot at this time identify any single number within this range as a better estimate of likely future costs, and we generally have recorded the low end of the range for our probabilistic cost estimates.

As we conduct the actual remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering assumptions, which we refine and update on an ongoing basis. During the second quarter of 2012, we completed our probabilistic models and engineering estimates for our sites in Illinois, which primarily contributed to the $103 million increase from the amount recorded at December 31, 2011. These costs are recoverable from our customers as they are paid and, accordingly, we have recorded a regulatory asset associated with the recorded liabilities. For more information on our environmental remediation costs, see Note 11 of our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.

Litigation

We are involved in litigation arising in the normal course of business. Although in some cases the company is unable to estimate the amount of loss reasonably possible in addition to any amounts already recognized, it is possible that the resolution of these contingencies, either individually or in aggregate, will require the company to take charges against, or will result in reductions in, future earnings. It is the opinion of management that the resolution of these contingencies, either individually or in aggregate, could be material to earnings in a particular period but will not have a material adverse effect on our consolidated financial position or cash flows. For additional litigation information, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K.

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.

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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 June 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 Judges will issue a proposed decision. There is no date scheduled for the issuance of that proposed decision.

We are unable to predict the outcome of the Illinois Commission’s review or our potential exposure. Since the PBR plan and historical gas costs are still under Illinois Commission review, the final outcome could be materially different than the amount reflected in our financial statements as of June 30, 2012.

Other In addition to the matters set forth above, we are involved with legal or administrative proceedings before various courts and agencies with respect to our service warranty product actions, general claims, taxes, environmental, gas cost prudence reviews, an IAGO investigation and an investigation by the United States Environmental Protection Agency regarding the presence of polychlorinated biphenyl (PCB) contaminated liquids in Nicor Gas’s distribution system and other matters. Although we are unable to determine the ultimate outcome of these other contingencies, the final disposition of these matters is not expected to have a material adverse impact on our liquidity or financial condition. We believe that these amounts are appropriately reflected in our financial statements, including the recording of appropriate liabilities when reasonably estimable.

Note 10 – Segment Information

Our operating segments have changed as a result of our merger with Nicor and amounts from prior periods have been reclassified between the segments to reflect these changes. Our results for the three and six months ended June 30, 2012 include the activity of the Nicor legacy companies whereas our results for the three and six months ended June 30, 2011 do not. Our operating segments comprise revenue-generating components of our company for which we produce separate financial 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 five operating segments – distribution operations, retail operations, wholesale services, midstream operations, cargo shipping and one non-operating segment, other.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland. 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 operations segment includes retail natural gas marketing to end-use customers primarily in Georgia as well as various businesses that market retail energy-related products and services to residential and small business customers in Illinois. Additionally, our retail operations segment provides warranty protection solutions to customers and customer move connection services for utilities. Our wholesale services segment includes natural gas asset management and related logistics activities for each of our utilities, except Nicor Gas, as well as for nonaffiliated companies, natural gas storage arbitrage and related activities. Our midstream operations segment includes our non-utility storage and pipeline operations, including the development and operation of high-deliverability natural gas storage assets.

Our cargo shipping segment transports containerized freight between Florida, the eastern coast of Canada, the Bahamas and the Caribbean region. The cargo shipping segment also includes amounts related to cargo insurance coverage sold to its customers and other third parties. The 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.

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Our other segment includes intercompany eliminations and aggregated subsidiaries that are not significant enough on a stand-alone basis and that do not fit into one of our other five operating segments.

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

You should not consider EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income, earnings before income taxes and net income for the three and six months ended June 30, 2012 and 2011, are presented below.

	Three months ended June 30,				Six months ended June 30,
In millions	2012		2011		2012		2011
Operating income	$	91	$	60	$	353	$	298
Other income		9		2		13		3
EBIT		100		62		366		301
Interest expense, net		45		32		92		61
Earnings before income taxes		55		30		274		240
Income taxes		20		11		100		87
Net income	$	35	$	19	$	174	$	153

Information by segment on our Statements of Financial Position as of December 31, 2011, is as follows:

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

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

(2)	Our other segment’s assets consist primarily of cash and cash equivalents and PP&E 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 three and six months ended June 30, 2012 and 2011 are shown in the following tables. Note that our segments have changed as a result of our merger with Nicor and amounts from prior periods have been reclassified between the segments to reflect these changes.

Three months ended June 30, 2012

In millions	Distribution operations		Retail operations		Wholesale services			Midstream operations		Cargo shipping			Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	449	$	136	$	7		$	18	$	80		$	(4	)	$	686
Intercompany revenues (1)		41		0		0			0		0			(41	)		0
Total operating revenues		490		136		7			18		80			(45	)		686
Operating expenses
Cost of goods sold		131		93		4			7		51			(46	)		240
Operation and maintenance		152		25		11			4		26			0			218
Depreciation and amortization		86		3		0			4		6			3			102
Nicor merger expenses		0		0		0			0		0			3			3
Taxes other than income taxes		25		1		1			2		1			2			32
Total operating expenses		394		122		16			17		84			(38	)		595
Operating income (loss)		96		14		(9	)		1		(4	)		(7	)		91
Other income		4		0		0			1		3			1			9
EBIT	$	100	$	14	$	(9	)	$	2	$	(1	)	$	(6	)	$	100
Capital expenditures	$	146	$	2	$	0		$	17	$	1		$	13		$	179

Three months ended June 30, 2011

In millions	Distribution operations		Retail operations		Wholesale services			Midstream operations		Cargo shipping		Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	236	$	117	$	9		$	11	$	0	$	2		$	375
Intercompany revenues (1)		41		0		0			0		0		(41	)		0
Total operating revenues		277		117		9			11		0		(39	)		375
Operating expenses
Cost of goods sold		70		100		1			2		0		(39	)		134
Operation and maintenance		89		15		12			4		0		(1	)		119
Depreciation and amortization		36		0		1			2		0		3			42
Nicor merger expenses		0		0		0			0		0		8			8
Taxes other than income taxes		9		1		0			1		0		1			12
Total operating expenses		204		116		14			9		0		(28	)		315
Operating income (loss)		73		1		(5	)		2		0		(11	)		60
Other income		1		0		0			0		0		1			2
EBIT	$	74	$	1	$	(5	)	$	2	$	0	$	(10	)	$	62
Capital expenditures	$	87	$	0	$	1		$	8	$	0	$	6		$	102

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Six months ended June 30, 2012

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping			Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	1,443	$	399	$	71	$	34	$	164		$	(21	)	$	2,090
Intercompany revenues (1)		87		0		0		0		0			(87	)		0
Total operating revenues		1,530		399		71		34		164			(108	)		2,090
Operating expenses
Cost of goods sold		660		259		34		12		101			(107	)		959
Operation and maintenance		325		57		24		9		54			(6	)		463
Depreciation and amortization		174		7		1		6		12			6			206
Nicor merger expenses		0		0		0		0		0			13			13
Taxes other than income taxes		82		2		2		3		3			4			96
Total operating expenses		1,241		325		61		30		170			(90	)		1,737
Operating income (loss)		289		74		10		4		(6	)		(18	)		353
Other income		5		0		0		1		6			1			13
EBIT	$	294	$	74	$	10	$	5	$	0		$	(17	)	$	366

Identifiable and total assets (2)	$	10,829	$	452	$	895	$	685	$	471		$	(58	)	$	13,274
Goodwill	$	1,586	$	124	$	2	$	16	$	77		$	8		$	1,813
Capital expenditures	$	268	$	4	$	0	$	59	$	1		$	18		$	350

Six months ended June 30, 2011

In millions	Distribution operations		Retail operations		Wholesale services		Midstream operations		Cargo shipping		Other and intercompany eliminations (3)			Consolidated
Operating revenues from external parties	$	741	$	407	$	62	$	41	$	0	$	2		$	1,253
Intercompany revenues (1)		79		0		0		0		0		(79	)		0
Total operating revenues		820		407		62		41		0		(77	)		1,253
Operating expenses
Cost of goods sold		338		301		4		23		0		(77	)		589
Operation and maintenance		179		35		28		8		0		(2	)		248
Depreciation and amortization		72		1		1		4		0		5			83
Nicor merger expenses		0		0		0		0		0		10			10
Taxes other than income taxes		18		1		1		2		0		3			25
Total operating expenses		607		338		34		37		0		(61	)		955
Operating income (loss)		213		69		28		4		0		(16	)		298
Other income		2		0		0		0		0		1			3
EBIT	$	215	$	69	$	28	$	4	$	0	$	(15	)	$	301

Identifiable and total assets (2)	$	5,592	$	189	$	1,038	$	476	$	0	$	(78	)	$	7,217
Goodwill	$	404	$	0	$	0	$	14	$	0	$	0		$	418
Capital expenditures	$	167	$	1	$	1	$	15	$	0	$	12		$	196

(1)

Intercompany revenues – wholesale services records its energy marketing and risk management revenues on a net basis and its total operating revenues include intercompany revenues of $49 million and $137 million for the three and six months ended June 30, 2012 and $102 million and $249 million for the three and six months ended June 30, 2011.

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

(3)	Our other segment’s assets consist primarily of cash and cash equivalents, PP&E and 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 our unaudited Condensed Consolidated Financial Statements in this quarterly filing, as well as our 2011 Form 10-K. Results for the interim periods presented are not necessarily indicative of the results to be expected for the full fiscal period due to seasonal and other factors.

Forward-Looking Statements

Certain expectations and projections regarding our future performance referenced in this 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 United States 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," “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.

We caution readers that the important factors described elsewhere in this report, among others, could cause our business, results of operations or financial condition 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 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 United States federal securities law.

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 June 30, 2012, our seven utilities served 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 in Georgia, Illinois, 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.

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The operating revenues and EBIT of our distribution operations and retail 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, revenue taxes, 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.

Our retail operations businesses, including SouthStar, Nicor Advanced Energy and Nicor Solutions, generate earnings through the sale of natural gas to residential, commercial and industrial customers, primarily in Georgia and Illinois where we capture spreads between wholesale and retail natural gas prices. We also offer our customers energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder than normal weather and/or changes in natural gas prices. We charge a fee or premium for these services. Our retail operations businesses also provide warranty protection solutions to customers in Illinois and Ohio through Nicor Services.

Our wholesale services segment consists of our wholly owned subsidiaries Sequent and Compass Energy (Compass). Sequent is involved in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing of natural gas across the United States and in Canada. Nicor Enerchange, which was integrated into Sequent subsequent to the Nicor merger, expands Sequent’s wholesale marketing of natural gas supply services in the Midwest, primarily in the northern Illinois market, and enables Sequent to serve commercial and industrial customers in this market. Further, Sequent manages Nicor Solutions’ and Nicor Advanced Energy’s product risks, including the purchase of natural gas supplies. Compass provides natural gas supply and services to commercial, industrial and governmental customers primarily in Kentucky, Ohio, Pennsylvania, Virginia and West Virginia.

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 is expected to be completed in the second half of 2012. Central Valley, located in northern California, began commercial operations and providing services to firm customers during the second quarter 2012.

Our cargo shipping segment, which joined our business as part of the Nicor merger, consists of Tropical Shipping, multiple wholly owned foreign subsidiaries of Tropical Shipping that are treated as disregarded entities for United States income tax purposes, Seven Seas, a wholly owned domestic cargo insurance company, and an equity investment in Triton, a cargo container leasing business. For additional information on our operating segments see Item 1, “Business” of our 2011 Form 10-K.

Executive Summary

Merger with Nicor On December 9, 2011, we closed the merger with Nicor. We are now the nation’s largest natural gas-only distribution company based on customer count. We continue to focus on the successful integration of the Nicor companies. Upon closing the merger with Nicor, we reclassified some of our operating segments to be consistent with how management views and manages our business.

For additional information on the Nicor merger see Note 3 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein and Item 1, “Business” as well as Note 3 to our Consolidated Financial Statements under Item 8 of our 2011 Form 10-K.

Legislative and regulatory update We continue to actively pursue a regulatory strategy that improves customer service and reduces the lag between our investments in infrastructure and the recovery of those investments through various rate mechanisms. If our rate design proposals are not approved, we will continue to work cooperatively with regulators, legislators and others to create a framework that is conducive to our business goals and the interests of our customers and shareholders.

On December 20, 2011, the Virginia Commission approved an annual increase of $11 million in base rate revenues for Virginia Natural Gas and established an authorized return on equity of 10% with an overall return on rate base set at 7.38%. Additionally, $3 million of costs previously recovered through base rates will now be recovered through the company’s gas cost recovery rate. Customer’s bills were credited to refund the difference between the final approved rates and interim rate increase, which began with usage on and after October 1, 2011. The new rate is expected to increase the average residential customer’s monthly bill by less than $3.50 per month depending on usage.

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Customer growth initiatives While there has been some improvement in the economic conditions within the areas we serve, we continue to see depressed housing markets with high inventories and significantly reduced new home construction. As a result, we have experienced only slight customer gains in the distribution operations and retail operations segments for the six months ended June 30, 2012. Excluding Nicor Gas, our year-over-year consolidated utility customer growth rate was flat for the six months ended June 30, 2012 and 2011. We anticipate overall competition and customer trends in 2012 to be similar to our 2011 results.

Impact of weather During the three and six months ended June 30, 2012, we experienced weather that was 11% - 47% warmer than normal across our service territory. This resulted in a significantly reduced demand for natural gas, which negatively impacted our distribution operations, retail operations and wholesale services segments. For the six months ended June 30, 2012, the weather in Illinois was 18% warmer than normal and in Georgia it was 34% warmer than normal. This warmer weather reduced our expected operating margins by $15 million at distribution operations and by $10 million at retail operations as compared to normal weather.

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 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.

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 to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. The following table and discussions provide updates on some of our larger capital projects at our distribution operations segment. These programs update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2012 are discussed in ‘Liquidity and Capital Resources’ under the caption ‘Cash Flows from Financing Activities’ in our 2011 Form 10-K.

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	$	39	$	606		2,576		1998		2013
Integrated System Reinforcement Program	Atlanta Gas Light		39		181		n/a		2009		2012
Integrated Customer Growth Program	Atlanta Gas Light		9		21		n/a		2010		2012
Enhanced infrastructure program	Elizabethtown Gas		8		97		92		2009		2012
Total		$	95	$	905		2,668

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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.

Virginia Natural Gas In January 2012, Virginia Natural Gas filed an accelerated infrastructure replacement program with the Virginia Commission. The program was filed in accordance with a Virginia statute providing a regulatory cost recovery mechanism to recover the costs associated with certain infrastructure replacement programs. The Virginia Commission approved this program in June 2012 for a five-year period, which includes a maximum allowance for capital expenditure of $25 million per year, not to exceed $105 million in total over the five-year period. The program is subject to annual review by the Virginia Commission. We will begin recovering these costs through a rate rider in August 2012.

Elizabethtown Gas The New Jersey BPU-approved the 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. 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. Costs associated with the investment in this program are recovered through periodic adjustments to base rates. In July 2012, we filed for an extension of the program up to $135 million in additional spend over five years.

Energy Marketing Activities Sequent’s expected natural gas withdrawals from storage are presented in the following table along with the operating revenues expected at the time of withdrawal. Sequent’s expected operating revenues exclude storage demand charges but are net of the estimated impact of profit sharing under our asset management agreements and reflect the amounts that are realizable in future periods based on the inventory withdrawal schedule and forward natural gas prices at June 30, 2012 and 2011. The amount in storage as of June 30, 2012, had a WACOG of $2.30. 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	Total storage (in Bcf)		Expected operating revenues (in millions)
2012
Third quarter		9	$	5
Fourth quarter		21		18
2013
First quarter		21		19
Second quarter		3		3
Third quarter		1		2
Total at June 30, 2012		55	$	47
Total at June 30, 2011		29	$	11

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 $23 million in 2012 and $24 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 25 Bcf, a $1.00 increase in the 2013 forward NYMEX prices could result in a $24 million reduction to Sequent’s reported operating revenues for the year ending December 31, 2012, after regulatory sharing but would increase in 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 $24 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 six months ended June 30, 2012, we have recorded $20 million in gains associated with the hedging of our transportation portfolio or $16 million higher as compared to the six months ended June 30, 2011. These hedge gains primarily relate to forward transportation positions for the second half 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 year will be lower since a significant portion of the previously expected revenues were recognized through the recording of the associated transportation hedge gains.

For more information on Sequent’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk of our 2011 Form 10-K.”

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Results of Operations

We generate the majority of our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, to residential, commercial and industrial customers from the date of the last bill to the end of the reporting period. No individual customer or industry accounts for a significant portion of our revenues.

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 goods sold and revenue tax expense in distribution operations. Operating margin excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes, and the gain or loss on the sale of our assets, if any. These items are included in our calculation of operating income as reflected in our unaudited Condensed Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income and 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 basis.

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 June 30,									Six months ended June 30,
In millions	2012			2011			Change			2012			2011			Change
Operating revenues	$	686		$	375		$	311		$	2,090		$	1,253		$	837
Cost of goods sold		(240	)		(134	)		(106	)		(959	)		(589	)		(370	)
Revenue tax expense (1)		(13	)		0			(13	)		(54	)		0			(54	)
Operating margin		433			241			192			1,077			664			413
Revenue tax expense (1)		13			0			13			54			0			54
Operating expenses (2)		(352	)		(173	)		(179	)		(765	)		(356	)		(409	)
Nicor merger expenses (3)		(3	)		(8	)		5			(13	)		(10	)		(3	)
Operating income		91			60			31			353			298			55
Other income		9			2			7			13			3			10
EBIT		100			62			38			366			301			65
Interest expense, net (3)		(45	)		(32	)		(13	)		(92	)		(61	)		(31	)
Earnings before income taxes		55			30			25			274			240			34
Income tax expense		(20	)		(11	)		(9	)		(100	)		(87	)		(13	)
Net income		35			19			16			174			153			21
Less net income attributable to the noncontrolling interest		1			1			0			10			11			(1	)
Net income attributable to AGL Resources Inc.	$	34		$	18		$	16		$	164		$	142		$	22

(1)	Adjustment for revenue tax expenses for Nicor Gas, which are passed directly through to customers.

(2)

Excludes expenses associated with the merger with Nicor of $3 million ($2 million net of tax) and $13 million ($8 million net of tax) for the three and six months ended June 30, 2012 and $8 million ($5 million net of tax) and $10 million ($6 million net of tax) for the three and six months ended June 30, 2011.

(3)

Expenses associated with the Nicor merger are part of operating expenses, but are shown separately to better compare year-over-year results. Our 2011 merger expenses include debt issuance costs and interest expenses on pre-funding the cash portion of the purchase consideration of $5 million ($3 million net of tax) for the three months ended June 30, 2011 and $8 million ($5 million net of tax) for the six months ended June 30, 2011.

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For the second quarter of 2012, our net income attributable to AGL Resources Inc. increased by $16 million or 89% compared to the same period last year. The increase was primarily the result of increased operating margins at distribution operations due to operating margin at Nicor Gas as a result of the merger and increased regulatory infrastructure program revenues at Atlanta Gas Light. These increases were offset by warmer weather. Additionally, our retail operations experienced an increase in operating margin resulting from operating margin at Nicor Services, Nicor Solutions and Nicor Advanced Energy as a result of the Nicor merger. This was offset by decreases at SouthStar due to warmer weather. These net increases were partially offset by lower EBIT at wholesale services due to significantly lower margins resulting from continuing low natural gas price volatility and low price spreads. Additionally, during the three months ended June 30, 2012, we recorded $5 million ($3 million net of tax) less expenses associated with the merger with Nicor than we did during the same period last year. These costs are expensed as incurred. The variances for each operating segment for second quarter 2012 compared to second quarter 2011 are discussed on the following pages.

For the six months ended June 30, 2012, our net income attributable to AGL Resources Inc. increased by $22 million or 15% compared to the same period last year. The increase was primarily the result of similar items that impacted our second quarter results. Additionally, during the six months ended June 30, 2012, we recorded $3 million ($2 million net of tax) more expenses associated with the merger with Nicor than we did during the same period last year. These costs are expensed as incurred. The variances for each operating segment for year-to-date 2012 compared to year-to-date 2011 are discussed on the following pages.

Our interest expense increased by $13 million or 41% for the second quarter 2012 compared to the second quarter of 2011. Our interest expense increased by $31 million or 51% for the six months ending June 30, 2012 compared to the same period in 2011. These increases were the result of higher average debt outstanding; primarily the result of the additional long-term debt issued to fund the Nicor merger and the long-term debt assumed in the transaction.

Our income tax expense increased by $9 million or 82% for the second quarter of 2012 compared to the second quarter of 2011. The increase was primarily due to higher consolidated earnings as previously discussed. Our income tax expense increased by $13 million or 15% for the six months ending June 30, 2012 compared to the same period of 2011. Our income tax expense is determined from earnings before income taxes less net income attributable to noncontrolling interest.

Selected weather, customer and volume metrics as of and for the three and six months ended June 30, 2012 and 2011, which we consider to be some of the key performance indicators for our operating segments, 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 warmer than normal weather across our service territories during the first half of 2012 had a significant negative impact on demand for natural gas in our distribution operations and retail operations segments.

Volume metrics for distribution operations and retail operations, as shown in the following table, present the effects of weather and our customers’ demand for natural gas compared to prior year. 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.

Wholesale services’ daily physical sales volumes represent the daily average natural gas volumes sold to its customers. Within our midstream operations 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. Our cargo shipping segment measures the volume of shipments during the period in TEUs, and we continue to seek opportunities to maximize the utilization of our containers and vessels.

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Weather Heating degree days (1)
	Three months ended June 30,						2012 vs. normal colder			2012 vs. 2011 colder			Six months ended June 30,						2012 vs. normal colder				2012 vs. 2011 colder
	Normal		2012		2011		(warmer)			(warmer)			Normal		2012		2011			(warmer)			(warmer)
Illinois		617		542		755		(12	)%		(28	)%		3,519		2,900		3,954			(18	)%		(27	)%
Georgia		136		72		130		(47	)%		(45	)%		1,588		1,055		1,600			(34	)%		(34	)%
New Jersey		458		376		379		(18	)%		(1	)%		2,973		2,360		2,928			(21	)%		(19	)%
Virginia		254		181		183		(29	)%		(1	)%		2,054		1,456		2,091			(29	)%		(30	)%
Florida		15		9		3		(40	)%		200	%		365		220		244			(40	)%		(10	)%
Tennessee		167		102		173		(39	)%		(41	)%		1,821		1,307		1,846			(28	)%		(29	)%
Maryland		471		415		366		(12	)%		13	%		2,973		2,407		2,996			(19	)%		(20	)%
Ohio		415		368		394		(11	)%		(7	)%		2,990		2,487		3,010			(17	)%		(17	)%

Customers (average end-use customers - in thousands)	Three months ended June 30,									Six months ended June 30,
	2012			2011			% change			2012			2011			% change
Distribution Operations
Nicor Gas		2,190			n/a			n/a	%		2,191			n/a			n/a	%
Atlanta Gas Light		1,548			1,552			(0.3	)%		1,555			1,561			(0.4	)%
Elizabethtown Gas		277			276			0.4	%		277			276			0.4	%
Virginia Natural Gas		281			278			1.1	%		282			279			1.1	%
Florida City Gas		104			104			0.0	%		104			104			0.0	%
Chattanooga Gas		62			62			0.0	%		63			62			1.6	%
Elkton Gas		6			6			0.0	%		6			6			0.0	%
Total		4,468			2,278						4,478			2,288

Retail Operations
Georgia		488			492			(0.8	)%		491			495			(0.8	)%
Illinois		429			n/a			n/a			429			n/a			n/a
Ohio and Florida (2)		73			95			(23	)%		103			84			23	%
Indiana		40			n/a			n/a			40			n/a			n/a
Other		3			n/a			n/a			3			n/a			n/a
Total		1,033			587						1,066			579
Market share in Georgia		32	%		32	%		0	%		32	%		32	%		0	%

Volumes	Three months ended June 30,									Six months ended June 30,
	2012			2011			% change			2012		2011		% change
Distribution Operations In billion cubic feet (Bcf)
Firm		93			26			n/a	%		333		128		n/a	%
Interruptible		26			26			0			53		53		0
Total		119			52			n/a	%		386		181		n/a	%

Retail Operations (In Bcf)
Georgia firm		3			4			(25	)%		17		22		(23	)%
Ohio and Florida		1			1			0	%		5		5		0	%

Wholesale Services
Daily physical sales (Bcf/day)		4.9			4.7			4	%		5.4		5.2		4	%
Cargo Shipping (TEU’s – in thousands)
Shipments		40			n/a			n/a	%		81		n/a		n/a	%
	As of June 30,
		2012			2011
Midstream Operations
Working natural gas capacity (In Bcf)		24.3			13.5
% of capacity under subscription by third parties (3)		58	%		44	%

(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 June 30, 2012, except for Illinois, where normal represents a ten-year average from 1998 through 2007, which was established in our last rate case.

(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. On April 1, 2012, our contract to serve approximately 50,000 customer equivalent ended.

(3)	Our percent of capacity under subscription does not include 3 Bcf of subscriptions with Sequent at June 30, 2012 and 4 Bcf at June 30, 2011.

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Second quarter 2012 compared to Second quarter 2011

Operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables for the second quarter ended June 30, 2012 and 2011.

	2012							2011
In millions	Operating margin (1) (2)		Operating expenses (2) (3)		EBIT (1)			Operating margin (1)		Operating expenses (3)		EBIT (1)
Distribution operations	$	346	$	250	$	100		$	207	$	134	$	74
Retail operations		43		29		14			17		16		1
Wholesale services		3		12		(9	)		8		13		(5	)
Midstream operations		11		10		2			9		7		2
Cargo shipping		29		33		(1	)		0		0		0
Other		1		8		(6	)		0		11		(10	)
Consolidated	$	433	$	342	$	100		$	241	$	181	$	62

(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”. Please note that our segments have changed as a result of our merger with Nicor and amounts presented from 2011 have been reclassified among the segments to reflect these changes. See Note 10 to our unaudited Condensed Consolidated Financial Statements for additional segment information.

(2)	Operating margin and expense for 2012 are adjusted for revenue tax expense for Nicor Gas which is passed directly through to customers.

(3)	Includes $3 million in merger expenses associated with the merger with Nicor during the second quarter of 2012 and $13 million for the same period in 2011.

Distribution Operations

Our distribution operations segment is the largest component of our business and is subject to regulation and oversight by agencies in each of the seven states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return for our shareholders.

With the exception of Atlanta Gas Light, our second 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. With the exception of Nicor Gas, we have various mechanisms, such as weather normalization mechanisms, at all of our utilities that limit our exposure to weather changes within typical ranges in all of our utilities’ respective service areas. The expected operating margin contribution at our distribution operations segment was negatively impacted by warmer than normal weather by approximately $2 million in the second quarter. This primarily impacted Nicor Gas, whose operations are not reflected in our 2011 results. Distribution operations’ EBIT increased by $26 million or 35% compared to last year as shown in the following table.

In millions
EBIT – for second quarter of 2011	$	74

Operating margin
Increased margin from Nicor Gas as a result of the Nicor merger in December 2011		139
Increased regulatory infrastructure program revenues at Atlanta Gas Light		2
Decreased revenues from lower usage at Virginia Natural Gas and Elizabethtown Gas		(3	)
Other		1
Increase in operating margin		139

Operating expenses
Increased expenses for Nicor Gas as a result of the Nicor merger in December 2011		120
Increased depreciation expense		3
Increased pension and health benefits expenses		2
Decreased other expenses		(9	)
Increase in operating expenses		116
Increased other income		3
EBIT – for second quarter of 2012	$	100

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Retail Operations

Our retail operations segment, which consists of SouthStar and several businesses that provide energy-related products and services to retail markets, also is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. Retail operations’ EBIT increased by $13 million compared to last year as shown in the following table.

In millions
EBIT – for second quarter of 2011	$	1

Operating margin
Increased margin as a result of the Nicor merger in December 2011		25
Increase related to reduction of transportation and gas costs and higher retail price spreads at SouthStar		3
Decreased average customer usage primarily due to warmer weather at SouthStar		(2	)
Increase in operating margin		26

Operating expenses
Increased expenses as a result of the Nicor merger in December 2011		15
Decreased bad debt and other expenses		(2	)
Increase in operating expenses		13
EBIT – for second quarter of 2012	$	14

Wholesale Services

Our wholesale services segment is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services and wholesale marketing. EBIT for our wholesale services segment is impacted by volatility in the natural gas market arising from a number of factors including weather fluctuations and changes in supply or demand for natural gas in different regions of the country. Wholesale services’ EBIT decreased by $4 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 second quarter of 2011	$	(5	)

Operating margin
Change in value on transportation hedges		14
Change in commercial activity driven by lower transportation values		(6	)
Change in value on storage hedges		(13	)
Decrease in operating margin		(5	)

Operating expenses
Decreased outside services and other expenses		(1	)
Decrease in operating expenses		(1	)
EBIT – for second quarter of 2012	$	(9	)

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.

Change in storage and transportation hedges Seasonal (storage) and geographical location (transportation) spreads were higher as compared to prior year. However, overall natural gas price volatility remained low during the second quarter of 2012. Transportation hedge gains in the second quarter of 2012 were primarily due to larger geographical location spreads at the time the hedges of our transportation positions were executed and the subsequent compression of regional transportation spreads. Storage hedge losses in the second quarter of 2012 were primarily due to larger seasonal spreads at the time the hedges of our storage positions were executed and the subsequent upward movement of natural gas prices.

The following table indicates the components of wholesale services’ operating margin for the three months ended.

	June 30,
In millions	2012			2011
Gain on transportation hedges	$	18		$	4
Commercial activity recognized		(6	)		0
(Loss) or gain on storage hedges		(9	)		4
Operating margin	$	3		$	8

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Midstream Operations

Our midstream operations segment’s primary activity is operating non-utility storage and pipeline facilities including the development, acquisition and operation of high-deliverability underground natural gas storage assets. 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 at fixed market rates. Midstream operations’ EBIT was flat compared to last year as shown in the following table.

In millions
EBIT – for second quarter of 2011	$	2

Operating margin
Increased margin as a result of higher firm revenues at Golden Triangle Storage and Central Valley that was acquired in connection with the Nicor merger in December 2011 offset by lower firm revenues at Jefferson Island due to re-contracting 3 Bcf at lower rates on April 1, 2012		2
Increase in operating margin		2

Operating expenses
Increased property taxes, depreciation and other expenses		3
Increase in operating expenses		3
Increased other income		1
EBIT – for second quarter of 2012	$	2

Cargo Shipping

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 second quarter of 2012.

Six months ended June 30, 2012 compared to six months ended June 30, 2011

Operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables for the six months ended June 30, 2012 and 2011.

	2012								2011
In millions	Operating margin (1) (2)			Operating expenses (2) (3)		EBIT (1)			Operating margin (1)		Operating expenses (3)		EBIT (1)
Distribution operations	$	816		$	527	$	294		$	482	$	269	$	215
Retail operations		140			66		74			106		37		69
Wholesale services		37			27		10			58		30		28
Midstream operations		22			18		5			18		14		4
Cargo shipping		63			69		0			0		0		0
Other		(1	)		17		(17	)		0		16		(15	)
Consolidated	$	1,077		$	724	$	366		$	664	$	366	$	301

2.	Operating margin and expense for 2012 are adjusted for revenue tax expense for Nicor Gas which is passed directly through to customers.

3.	Includes $13 million in merger expenses associated with the merger with Nicor during the six months ended June 30, 2012 and $18 million for the same period in 2011.

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Distribution Operations

Distribution operations’ EBIT increased by $79 million or 37% compared to last year as shown in the following table.

In millions
EBIT – for six months of 2011	$	215

Operating margin
Increased margin from Nicor Gas as a result of the Nicor merger in December 2011		332
Increased regulatory infrastructure program revenues at Atlanta Gas Light		5
Decreased revenues from lower usage and weather normalization at Virginia Natural Gas, Elizabethtown Gas and Florida City Gas,		(3	)
Increase in operating margin		334

Operating expenses
Increased expenses for Nicor Gas as a result of the Nicor merger in December 2011		261
Increased depreciation expense		6
Increased pension and health benefits expenses		5
Decreased bad debt expense		(4	)
Decreased other expenses		(10	)
Increase in operating expenses		258
Increased other income		3
EBIT – for six months of 2012	$	294

Retail Operations

Retail operations’ EBIT increased by $5 million or 7% compared to last year as shown in the following table.

In millions
EBIT – for six months of 2011	$	69

Operating margin
Increased margin as a result of the Nicor merger in December 2011		39
Increase related to reduction of transportation and gas costs and higher retail price spreads partially offset by unfavorable customer portfolio at SouthStar		8
Decreased average customer usage primarily due to warmer weather, net of weather derivatives at SouthStar		(10	)
Change in LOCOM adjustment at SouthStar		(3	)
Increase in operating margin		34

Operating expenses
Increased expenses as a result of the Nicor merger in December 2011		31
Decreased bad debt and other expenses		(2	)
Increase in operating expenses		29
EBIT – for six months of 2012	$	74

Wholesale Services

Wholesale services’ EBIT decreased by $18 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 six months of 2011	$	28

Operating margin
Change in value on transportation hedges		16
Change in value on storage hedges		4
Storage inventory write-down (LOCOM) in 2012, net of estimated current period recoveries		(12	)
Change in commercial activity driven by mild weather, lower storage and transportation price spreads		(29	)
Decrease in operating margin		(21	)

Operating expenses
Decreased incentive and other expenses, offset by slightly higher payroll and benefits		(3	)
Decrease in operating expenses		(3	)
EBIT – for six months of 2012	$	10

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The following table indicates the components of wholesale services’ operating margin for the six months ended.

	June 30,
In millions	2012			2011
Commercial activity recognized	$	23		$	52
Gain on transportation hedges		20			4
Gain on storage hedges		6			2
Inventory LOCOM, net of estimated current period recoveries		(12	)		0
Operating margin	$	37		$	58

Midstream Operations

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

In millions
EBIT – for six months of 2011	$	4

Operating margin
Increased margin as a result of the Nicor merger in December 2011 driven by firm revenues, hedge gains, offset in part by inventory LOCOM adjustment at Central Valley		4
Increase in operating margin		4

Operating expenses
Increased property taxes, depreciation and other expenses		4
Increase in operating expenses		4
Increased other income		1
EBIT – for six months of 2012	$	5

Cargo Shipping

Cargo shipping segment operated at a break-even level of EBIT for the six months ended June 30, 2012. Because of the highly seasonal nature of its business, a high percentage of its annual EBIT has historically been generated in the fourth quarter.

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 programs, which are supported by the AGL Credit Facility and the Nicor Gas 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 is focused on maintaining strong Consolidated Statements 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 issuance 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 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. Nicor Gas is restricted by regulation in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Dividends to AGL Resources are allowed only to the extent of Nicor Gas’ retained earnings balance, which was $497 million at June 30, 2012.

We believe the amounts available to us under our senior notes, AGL Credit Facility and Nicor Gas 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, capital expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments, common share repurchases and other cash needs through the next several years. Our ability to satisfy our working capital requirements and our 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 and demand for natural gas and operational risks.

Glossary of Key Terms

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As of June 30, 2012, we had $76 million of cash and short and long-term investments on our unaudited Condensed Consolidated Statements of Financial Position that were generated from Tropical Shipping. This cash and the investments are not available for use by our other operations unless we repatriate a portion of Tropical Shipping’s earnings in the form of a dividend that would be subject to a significant amount of United States income tax. See Note 12 to our Consolidated Financial Statements under Item 8 included in our 2011 Form 10-K for additional information on our income taxes.

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies and other factors. See Item 1A, “Risk Factors,” in our 2011 Form 10-K for additional information on items that could impact our liquidity and capital resource requirements.

Credit Ratings Our borrowing costs and our ability to obtain adequate and cost-effective financing are directly impacted by our credit ratings as well as the availability of financial markets. Credit ratings are important to our 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 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. The rating agencies regularly review our performance, prospects and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, our corporate ratings and our ratings outlook. 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 and each rating should be evaluated independently of other ratings.

Factors we consider important in assessing our credit ratings include our Consolidated Statements of Financial Position leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any agreements that would require us to issue equity based on credit ratings or other trigger events. The following table summarizes our credit ratings as of June 30, 2012, and reflects no change from December 31, 2011.

AGL Resources

Nicor Gas

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

Corporate rating

BBB+

n/a

A-

BBB+

n/a

Commercial paper

A-2

P-2

A-2

P-2

F-1

Senior unsecured

BBB+

Baa1

A-

BBB+

A+

Senior secured

n/a

AA-

Ratings outlook

Stable

Our credit ratings depend largely on our financial performance, and a downgrade in our current ratings, particularly below investment grade, would increase our borrowing costs and could 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 could decrease.

Default Provisions Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. Our credit facilities contain customary events of default, including, but not limited to, the failure to pay any interest or principal when due, the failure to furnish financial statements within the timeframe established by each debt facility, the failure to comply with certain affirmative and negative covenants, cross-defaults to certain other material indebtedness in excess of specified amounts, incorrect or misleading representations or warranties, insolvency or bankruptcy, fundamental change of control, the occurrence of certain Employee Retirement Income Security Act events, judgments in excess of specified amounts and certain impairments to the guarantee.

Our credit facilities contain certain non-financial covenants that, among other things, restrict liens and encumbrances, loans and investments, acquisitions, dividends and other restricted payments, asset dispositions, mergers and consolidations, and other matters customarily restricted in such agreements.

Our credit facilities each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month. This ratio, as defined within our debt agreements, includes standby letters of credit, performance/surety bonds and excludes accumulated OCI items related to non-cash pension adjustments, other post-retirement benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the periods presented.

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	AGL Resources						Nicor Gas
	June 30,						June 30,
	2012			2011			2012			2011
Debt-to-capitalization ratio		54	%		53	%		43	%		n/a

We were in compliance with all of our debt provisions and covenants, both financial and non-financial, for all periods presented.

Our ratio of total debt to total capitalization, on a consolidated basis, 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 ratio of total debt to total capitalization 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 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein. The components of our capital structure, as of the dates indicated, are provided in the following table.

	June 30, 2012			December 31, 2011			June 30, 2011
Short-term debt		10	%		16	%		4	%
Long-term debt		46			43			51
Total debt		56			59			55
Equity		44			41			45
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.

	Six months ended June 30,
In millions	2012			2011			Variance
Net cash provided by (used in):
Operating activities	$	1,082		$	660		$	422
Investing activities		(350	)		(196	)		(154	)
Financing activities		(714	)		(467	)		(247	)
Net increase (decrease) in cash and cash equivalents		18			(3	)		21
Cash and cash equivalents at beginning of period		69			24			45
Cash and cash equivalents at end of period	$	87		$	21		$	66

Cash Flow from Operating Activities Our increase in cash from operations primarily related to the recovery of working capital from the companies acquired in the December 2011 merger with Nicor. This was offset by an increase in working capital requirements at wholesale services of $64 million.

Cash Flow from Investing Activities The increased PP&E expenditures of $154 million, or 79%, was primarily due to $90 million of PP&E expenditures at Nicor Gas and $45 million of PP&E expenditures at Central Valley. Both of these subsidiaries were acquired from our merger with Nicor in December 2011. Additionally, capital expenditures increased by $11 million for pipeline replacement projects at Atlanta Gas Light, $5 million for accelerated infrastructure replacement program projects at Virginia Natural Gas and $3 million for utility infrastructure enhancements at Elizabethtown Gas.

Cash Flow from Financing Activities The increased use of cash for our financing activities for the six months ended June 30, 2012 compared to the same period in 2011 was primarily a result of $200 million of long-term debt we issued in 2011 in anticipation of paying out the cash consideration for the Nicor merger. Additionally, dividends paid on common shares increased $28 million due to the increase in common shares used to fund the equity portion of the consideration paid in the Nicor merger.

As of June 30, 2012, our variable-rate debt was 27% of our total debt, compared to 36%, as of December 31, 2011 and 24% as of June 30, 2011. The decrease from December 31, 2011 was primarily due to decreased commercial paper borrowings. The increase from June 30, 2011 was primarily due to the proceeds from the $200 million long-term debt issuance used to repay commercial paper borrowings in 2011. As of June 30, 2012, our commercial paper borrowings of $731 million were 45% lower than as of December 31, 2011, primarily a result of lower working capital requirements. For more information on our debt, see Note 7 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein.

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Short-term Debt Our short-term debt as of June 30, 2012 was comprised of borrowings under our commercial paper programs and current portions of our senior notes and capital leases.

In millions	Period end balance outstanding (1)		Daily average balance outstanding (2)		Minimum balance outstanding (2)		Largest balance outstanding (2)
Commercial paper - AGL Capital	$	731	$	697	$	578	$	922
Commercial paper - Nicor Gas		0		144		0		456
Current portion of long-term debt		230		108		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	$	962	$	951	$	594	$	1,620

(1)	As of June 30, 2012.

(2)	For the six months ended June 30, 2012. The minimum and largest balances outstanding for each short-term debt instrument occurred at different times during the year. As such, the total balances are not indicative of actual borrowings on any one day during the six months.

The largest, minimum and daily average balances borrowed under our commercial paper programs are important when assessing the intra-period fluctuation of our short-term borrowings and potential liquidity risk. The fluctuations are due to our seasonal cash requirements.

Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected injection plan, a $1 NYMEX price change could result in a $110 million change of working capital requirements. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position. Based on current natural gas prices and our expected purchases during the upcoming injection season, we believe that we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.

The lenders under our credit facilities and lines of credit are major financial institutions with $2.2 billion of committed balances and all have investment grade credit ratings as of June 30, 2012. 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.

Long-term Debt Our long-term debt matures more than one year from June 30, 2012, and consisted of medium-term notes: Series A, Series B, and Series C, which we issued under an indenture during December 1989, senior notes, first mortgage bonds and gas facility revenue bonds.

Noncontrolling Interest We recorded cash distributions for SouthStar’s dividend distributions to Piedmont of $14 million for the six months ended June 30, 2012 and $16 million for the same period in 2011.The primary reason for the reduction in the distribution to Piedmont during the current year is due to decreased earnings for 2012 compared to 2011.

Dividends on Common Stock Our common stock dividend payments were $96 million for the six months ended June 30, 2012 and $68 million for the same period in 2011. The increase is primarily due to the 38.2 million shares issued in conjunction with the Nicor merger and the annual dividend increase of $0.04 per share. However, as a result of the Nicor merger, AGL Resources shareholders of record as of the close of business on December 8, 2011, received a pro rata dividend of $0.0989 per share for the stub period, accruing from November 19, 2011 totaling $7 million. The dividend payments made in February 2012 were reduced by this stub period dividend.

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of business 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.

There were no significant changes to our contractual obligations described in Note 11 of our Consolidated Financial Statements and related notes in Item 8 of our 2011 Form 10-K other than the revised ERC remediation costs and termination of the SNG contract.

Pension and other retirement plan obligations In the first six months of 2012, we contributed $24 million to our qualified pension plans and an additional $8 million in July 2012 for a total of $32 million during 2012. In the six months ended June 30, 2011, we contributed $44 million to these qualified pension plans and an additional $6 million in July 2011 for a total of $50 million during 2011. Based on the current funding status of these plans, we would be required to make a minimum contribution to the plans of $7 million over 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, we expect to have additional flexibility with respect to the amount of contributions to our pension plans to our pension plans through 2014.

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During the six months ended June 30, 2012, we recorded net periodic benefit costs of $31 million related to our defined benefit retirement plans compared to $10 million during the same period last year. We estimate that during the remainder of 2012, we will record net periodic benefit costs in the range of $29 million to $32 million, a $20 million to $21 million increase compared to 2011.

Substitute natural gas In 2011, Illinois enacted laws that required Nicor Gas and other large utilities in Illinois to elect to either sign contracts to purchase SNG from coal gasification plants to be constructed in Illinois or instead file rate cases with the Illinois Commission in 2012, 2014 and 2016.

Additionally, on October 11, 2011, the Illinois Power Agency (IPA) approved the form of a draft 30-year contract for the purchase by Nicor Gas of approximately 20 Bcf per year of SNG from a second proposed plant beginning as early as 2018. 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. We have appealed the Illinois Commission’s decision to an Illinois appellate court. Neither Nicor Gas nor the developer has yet signed the form of contract approved by the Illinois Commission. In May 2012, the Illinois legislature passed a bill that directs the Illinois Commission to approve a final form of contract that differs in certain respects from the form the Illinois Commission approved in its July 11, 2012 order and that purports to address issues raised in the DuPage County litigation. Unless vetoed by the Governor of Illinois by August 10, 2012, this bill will become law. If the bill becomes law, it is not clear what, if any, effect it will have on the pending litigation concerning this SNG project.

Critical Accounting Policies and Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts in our unaudited Condensed Consolidated Financial Statements and accompanying notes. Those judgments and estimates have a significant effect on our financial statements primarily due to the need to make estimates about the effects of matters that are inherently uncertain. Actual results could differ from those estimates. We frequently reevaluate our judgments and estimates that are based upon historical experience and various other assumptions that we believe to be reasonable under the circumstances.

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 Operations in our 2011 Form 10-K, except for the $103 million increase to our ERC liabilities as discussed in Note 9 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein. Our critical accounting estimates used in the preparation of our unaudited Condensed Consolidated Financial Statements include the following:

· Regulatory Infrastructure Program Liabilities

· Environmental Remediation Costs

· Derivatives and Hedging Activities

· Goodwill and Intangible Assets

· Contingencies

· Pension and Other Retirement Plans

· Income Taxes

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to risks associated with natural gas prices, interest rates, credit and fuel prices. 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 fuel price risk is primarily in cargo shipping, which is partially reduced through fuel surcharges. Our use of derivative instruments is governed by a risk management policy, approved and monitored by our Risk Management Committee (RMC), which prohibits the use of derivatives for speculative purposes.

Our 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 instruments are described in further detail in Note 5 of our unaudited Condensed Consolidated Financial Statements.

Natural Gas Price Risk

The following tables include the fair values and average values of our consolidated derivative instruments as of the dates indicated. We base the average values on monthly averages for the six months ended June 30, 2012 and 2011.

	Derivative instruments average values (1) at June 30,
In millions	2012		2011
Asset	$	257	$	183
Liability		116		41

(1) Excludes cash collateral amounts.

	Derivative instruments fair values netted with cash collateral at
In millions	Jun 30, 2012		Dec. 31, 2011		Jun. 30, 2011
Asset	$	226	$	288	$	140
Liability		66		110		29

The following table illustrates the change in the net fair value of our derivative instruments during the periods presented, and provide details of the net fair value of contracts outstanding as of the dates presented.

	Three months ended						Six months ended
	June 30,						June 30,
In millions	2012			2011			2012			2011
Net fair value of derivative instruments outstanding at beginning of period	$	(46	)	$	24		$	30		$	55
Derivative instruments realized or otherwise settled during period		46			(6	)		(18	)		(54	)
Net fair value of derivative instruments acquired during period		0			0			3			0
Change in net fair value of derivative instruments		23			16			8			33
Net fair value of derivative instruments outstanding at end of period		23			34			23			34
Netting of cash collateral		137			77			137			77
Cash collateral and net fair value of derivative instruments outstanding at end of period	$	160		$	111		$	160		$	111

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The sources of our net fair value at June 30, 2012, are as follows.

In millions	Prices actively quoted (Level 1) (1)			Significant other observable inputs (Level 2) (2)
Mature through 2012	$	(66	)	$	42
Mature 2013 – 2014		(24	)		55
Mature 2015 – 2017		(4	)		21
Total derivative instruments (3)	$	(94	)	$	118

(1) Valued using NYMEX futures prices.

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

(3) Excludes cash collateral amounts.

Value-at-risk 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 our open positions. Our VaR is determined on a 95% confidence interval and a 1-day holding period. In simple terms, this means that 95% of the time, the risk of loss from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated.

We actively monitor open commodity positions and the resulting VaR. We also continue to maintain a relatively matched book, where our total buy volume is close to our 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 positions for the periods presented had the following VaRs.

	Three months ended				Six months ended
	June 30,				June 30,
In millions	2012		2011		2012		2011
Period end	$	1.9	$	1.5	$	1.9	$	1.5
Average		2.4		1.3		2.5		1.3
High		3.6		1.9		4.8		1.9
Low		1.7		0.9		1.7		0.9

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $1.1 billion of variable-rate debt outstanding at June 30, 2012, a 100 basis point change in market interest rates would have resulted in an increase in pretax interest expense of $11 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 $250 million from a fixed rate to a variable-rate obligation. The interest rate resets quarterly based on LIBOR plus 3.9%.

On March 31, 2012, our forward-starting interest rate swaps totaling $90 million that were redesignated as cash flow hedges upon the close of the Nicor merger matured.

Interest rate swaps help us achieve our desired mix of variable to fixed rate debt (i.e. variable debt target of 20% to 45% of total debt). Any gain or loss on these interest rate swaps is deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the life of the related debt. For additional information, see Note 5 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein.

Credit Risk

Wholesale Services We have established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. We also utilize master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When we are engaged in more than one outstanding derivative transaction with the same counterparty and we also have 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 our credit risk. We also use other netting agreements with certain counterparties with whom we conduct significant transactions. Master netting agreements enable us to net certain assets and liabilities by counterparty. We also net across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions.

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Additionally, we may require counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for our 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, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not have investment grade ratings.

We have a concentration of credit risk as measured by our 30-day receivable exposure plus forward exposure. As of June 30, 2012, our top 20 counterparties represented approximately 57% of the total counterparty exposure of $314 million, derived by adding together the top 20 counterparties’ exposures, exclusive of customer deposits, and dividing by the total of our counterparties’ exposures.

As of June 30, 2012, our counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of BBB+, which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P 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.

	Gross receivables						Gross payables
	Jun. 30,		Dec. 31,		Jun. 30,		Jun. 30,		Dec. 31,		Jun. 30,
In millions	2012		2011		2011		2012		2011		2011
Netting agreements in place:
Counterparty is investment grade	$	266	$	395	$	388	$	186	$	255		293
Counterparty is non-investment grade		9		23		8		11		47		29
Counterparty has no external rating		70		184		212		185		288		357
No netting agreements in place:
Counterparty is investment grade		2		4		6		1		0		2
Counterparty has no external rating		0		1		0		0		0		0
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position	$	347	$	607	$	614	$	383	$	590		681

We have 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, we would need to post collateral to continue transacting business with some of its counterparties. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements with our counterparties would have totaled $26 million at June 30, 2012, which would not have a material impact to our 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 2011 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 under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of June 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 June 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.

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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 quarter ended June 30, 2012, 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. In addition, we are party, as both plaintiff and defendant, to a number of lawsuits related to our business on an ongoing basis. Management believes that the outcome of all regulatory proceedings and litigation in which we are currently involved will not have a material adverse effect on our consolidated financial condition. For more information regarding some of these proceedings, see Note 9 to our unaudited Condensed Consolidated Financial Statements under the caption “Litigation.”

Item 1A. Risk Factors

For information regarding our risk factors see the factors discussed in Part I, "Item 1A. Risk Factors" in our 2011 Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2011 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.

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

The following table sets forth information about purchases of our common stock by us and any affiliated purchasers during the three months ended June 30, 2012. 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
April 2012		0	$	0.00
May 2012		5,000		38.50
June 2012		0		0.00
Total second quarter		5,000	$	38.50

(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 5,000 shares for such purposes in the second quarter of 2012. As of June 30, 2012, we had purchased a total of 388,591 of the 600,000 shares authorized for purchase, leaving 211,409 shares available for purchase under this program.

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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.


10.1	Third Amendment, dated as of May 21, 2012, to Reimbursement Agreement, dated as of October 14, 2010, 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 Statement of Computation of Ratio of Earnings to Fixed Charges. (Exhibit 10.1, AGL Resources Inc. Form 8-K dated May 21, 2012).

10.2	Third Amendment, dated as of May 21, 2012, to Reimbursement Agreement, dated as of October 14, 2010, 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. (Exhibit 10.2, AGL Resources Inc. Form 8-K dated May 21, 2012).

10.3	Third Amendment, dated as of May 21, 2012, to Reimbursement Agreement, dated as of October 14, 2010, 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. (Exhibit 10.3, AGL Resources Inc. Form 8-K dated May 21, 2012).

10.4	Third Amendment, dated as of May 21, 2012, to Reimbursement Agreement, dated as of October 14, 2010, 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. (Exhibit 10.4, AGL Resources Inc. Form 8-K dated May 21, 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. (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) unaudited Condensed Consolidated Statements of Financial Position at June 30, 2012, December 31,2011 and June 30,2011; (iii) unaudited Condensed Consolidated Statements of Income for the three and six months ended June 30, 2012 and 2011; (iv) unaudited Condensed Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2012 and 2011; (v) unaudited Condensed Consolidated Statements of Equity for the six months ended June 30, 2012 and 2011; (vi) unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011; and (vii) Notes to unaudited 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: August 1, 2012 /s/ Andrew W. Evans

Executive Vice President and Chief Financial Officer

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