The year-end condensed statement of financial position data was derived from our audited financial statements, but does not include all disclosures required by GAAP. We have prepared the accompanying unaudited condensed consolidated financial statements under the rules of the SEC. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. However, the condensed consolidated financial statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. For a glossary of key terms, ~~and referenced accounting standards,~~ see page 3. You should read these condensed consolidated financial statements in conjunction with our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.

Due to the seasonal nature of our business, our results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2009 and 2008, and our financial condition as of December 31, 2008, and ~~June~~September 30, 2009 and 2008, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Basis of Presentation

Our condensed consolidated financial statements include our accounts, the accounts of our majority-owned and controlled subsidiaries and the accounts of variable interest entities for which we are the primary beneficiary. This means that our accounts are combined with our subsidiaries’ accounts. We have eliminated any intercompany profits and transactions in consolidation; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, and we evaluate our estimates on an ongoing basis. Each of our estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing financial accounting literature or in the development of estimates that impact our financial statements. The most significant estimates include our PRP accruals, ~~environmental~~ERC liability accruals, allowance for uncollectible accounts, ~~and other allowance for~~ contingencies, pension and postretirement obligations, derivative and hedging activities, unbilled revenues and provision for income taxes. Our actual results could differ from our estimates, and such differences could be material.

Energy Marketing Receivables and Payables

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

Our wholesale services segment has some trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. No collateral has been posted under such provisions since our credit ratings have always exceeded the minimum requirements. As of ~~June~~September 30, 2009, December 31, 2008 and ~~June~~September 30, 2008, the collateral that wholesale services would behave been required to post 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 impaired.

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Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our condensed consolidated statements of financial position in accordance with ~~SFAS 71. Our~~authoritative guidance related to regulated operations. These regulatory assets and liabilities, ~~and associated liabilities for our unrecovered PRP costs, unrecovered ERC and~~along with the associated assets and liabilities, ~~for Elizabethtown Gas’ derivative financial instruments,~~ are summarized in the following table. ~~For more information on our derivative financial instruments, see Note 3.~~

~~Glossary~~

~~Table of Contents~~

~~Stock-Based Compensation~~

In the first six months of 2009, we issued grants of approximately 250,000 stock options and 211,000 restricted stock units, which will result in the recognition of approximately $2 million of stock-based compensation expense in 2009. No material share awards have been granted to employees whose compensation is subject to capitalization. We use the Black-Scholes pricing model to determine the fair value of the options granted. On an annual basis, we evaluate the assumptions and estimates used to calculate our stock-based compensation expense.

There have been no significant changes to our stock-based compensation, as described in Note 4 to our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.

~~Comprehensive Income~~

Our comprehensive income or loss includes net income plus OCI, which includes other gains and losses affecting equity that GAAP excludes from net income. Such items consist primarily of gains and losses on certain derivatives designated as cash flow hedges and unfunded or overfunded pension and postretirement obligation adjustments. Our cumulative comprehensive income or loss that has been excluded from net income is reported as accumulated other comprehensive loss within our condensed consolidated statement of equity.

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Note 6 - Debt

Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by, or filings with, state and federal regulatory bodies, including state public service commissions, the SEC and the FERC pursuant to the Energy Policy Act of 2005. The following table ~~provides information on~~shows the carrying amounts of our ~~various~~long-term debt ~~securities.~~included in our condensed consolidated statements of financial position. We estimate the fair value using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we considered our currently assigned ratings for unsecured debt of BBB+ by S&P, Baa1 by Moody’s and A- by Fitch. For more information on our debt, see Note 6 in our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.

									Outstanding as of
In millions	Year(s) due		Weighted average interest rate (1)			Interest rate (2)			September 30, 2009		December 31, 2008		September 30, 2008
Short-term debt
Commercial paper	2009			0.8	%		0.6	%	$	309	$	273	$	198
Capital leases	2009			4.9			4.9			1		1		1
Credit Facility		-		-			-			-		500		485
SouthStar line of credit		-		-			-			-		75		55
Sequent lines of credit (3)		-		-			-			-		17		20
Pivotal Utility line of credit (3)		-		-			-			-		-		10
Total short-term debt				0.9	%		0.6	%	$	310	$	866	$	769
Long-term debt - net of current portion
Senior notes	2011-2034			5.9	%		4.5-7.1	%	$	1,575	$	1,275	$	1,275
Gas facility revenue bonds	2022-2033			1.2			0.2-5.3			200		200		200
Medium-term notes	2012-2027			7.8			6.6-9.1			196		196		196
Capital leases	2013			4.9			4.9			4		4		4
Total long-term debt (4)				5.5	%		5.5	%	$	1,975	$	1,675	$	1,675

Total debt				4.6	%		4.8	%	$	2,285	$	2,541	$	2,444

Outstanding as of
In millions Year(s) due
Interest rate (1)

Weighted average interest rate(2)

June 30,
2009

Dec. 31,
2008

June 30,
2008

Short-term debt
Commercial paper 2009 0.6 % 0.9 % $ 417 $ 273 $ 465
Credit Facilities - - - - 500 -
SouthStar line of credit - - - - 75 -
Sequent lines of credit (3)
- - - - 17 38
Pivotal Utility line of credit - - - - - 9
Capital leases 2009 4.9 4.9 1 1 1
Total short-term debt 0.6 % 1.0 % $ 418 $ 866 $ 513
Long-term debt - net of current portion
Senior notes 2011-2034 4.5-7.1 % 5.9 % $ 1,275 $ 1,275 $ 1,275
Gas facility revenue bonds 2022-2033 0.1-5.3 1.3 200 200 161
Medium-term notes 2012-2027 6.6-9.1 7.8 196 196 196
Capital leases 2013 4.9 4.9 4 4 5
Total long-term debt 5.5 % 5.5 % $ 1,675 $ 1,675 $ 1,637

Total debt 4.5 % 4.5 % $ 2,093 $ 2,541 $ 2,150
(1) As of June 30, 2009.
(2) For the six months ended June 30, 2009.
(3) In June 2009, Sequent’s $25 million unsecured line of credit expired.

(1)	For the nine months ended September 30, 2009.

(2)	As of September 30, 2009.

(3)	Sequent’s $25 million line of credit expired in June 2009. Pivotal Utility’s $15 million line of credit expired in October 2008.

(4)	Our estimated fair value was $2,116 million as of September 30, 2009, $1,647 million as of December 31, 2008 and $1,671 million as of September 30, 2008.

In August 2009, AGL Capital issued $300 million of 10-year senior notes at an interest rate of 5.25%. The net proceeds from the offering were approximately $297 million. We used the net proceeds from the sale of the senior notes to repay a portion of our short-term debt.

Default Events

Our Credit Facility financial covenants require us to maintain a ratio of total debt to total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. Our ratio of total debt to total capitalization calculation contained in our debt covenant includes standby letters of credit, surety bonds and the exclusion of other comprehensive income pension adjustments. Adjusting for these items, our debt-to-equity calculation, as defined by our Credit Facility, was 55% at September 30, 2009, 59% at December 31, 2008 and 58% at September 30, 2008. These amounts are within our required and targeted ranges. Our debt-to-equity calculation, as calculated from our condensed consolidated statements of financial position, was 57% at September 30, 2009, 60% at December 31, 2008 and 58% at September 30, 2008.

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

·	a maximum leverage ratio

·	insolvency events and nonpayment of scheduled principal or interest payments

·	acceleration of other financial obligations

·	change of control provisions

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

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Note 7 - Commitments and Contingencies

Contractual Obligations and Commitments

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities 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. As we do for other subsidiaries, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations. There were no significant changes to our contractual obligations described in Note 7 to our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our contingent financial commitments as of ~~June~~September 30, 2009.

	Commitments due before December 31,						Commitments due before December 31,
In millions	Total		2009		2010 & thereafter		Total		2009		2010 & thereafter
Standby letters of credit and performance and surety bonds	$	23	$	15	$	8	$	26	$	9	$	17

Litigation

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

Information on the Jefferson Island Storage & Hub, LLC vs. State of Louisiana litigation is described in Note 7 to our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009. In April 2009, the trial court ruled that the legislation that restricted Jefferson Island’s ability to use water from the Chicot aquifer to expand its existing storage facility is unconstitutional and invalid.

In ~~addition,~~August 2009, Jefferson Island announced that it had negotiated a tentative agreement with the state of Louisiana that, subject to approval, would resolve the pending lawsuit between the parties over a disputed mineral lease. A finalized agreement will enable Jefferson Island to resume its plan to expand the existing natural gas storage facility. The state Mineral Board must approve the agreement in order for it to be valid, and a decision could come during the fourth quarter of 2009. The parties also jointly requested that the trial court delay the previously scheduled ~~a trial in~~ September 2009 ontrial date which would have resolved Jefferson Island’s claim that it is authorized to expand the facility under its mineral ~~lease.~~lease while the parties work through this approval process. The ultimate resolution ~~of such litigation~~ cannot be determined, but it is not expected to have a material adverse effect on our condensed consolidated financial position, results of operations or cash flows.

~~Glossary~~

~~Table of Contents~~

In February 2008, the consumer affairs staff of the Georgia Commission alleged that GNG charged its customers on variable rate plans prices for natural gas that were in excess of the published price, that it failed to give proper notice regarding the availability of potentially lower price plans and that it changed its methodology for computing variable rates. GNG asserted that it fully complied with all applicable rules and regulations, that it properly charged its customers on variable rate plans the rates on file with the Georgia Commission, and that, consistent with its terms and conditions of service, it routinely switched customers who requested to move to another price plan for which they qualified. In order to resolve this matter GNG agreed to pay ~~$2.5~~approximately $3 million in the form of credits to customers, or as directed by the Georgia Commission, which was recorded in our statements of consolidated income for the year ended December 31, 2008.

In February 2008, a class action lawsuit was filed in the Superior Court of Fulton County in the State of Georgia against GNG containing similar allegations to those asserted by the Georgia Commission staff and seeking damages on behalf of a class of GNG customers. This lawsuit was dismissed in September 2008. The plaintiffs appealed the dismissal of the lawsuit and, in May 2009, the Georgia Court of Appeals reversed the lower court’s order. In June 2009, GNG filed a petition for reconsideration with the Georgia Supreme Court. In October 2009 the Georgia Supreme Court ~~and GNG is waiting~~agreed to ~~hear whether it will~~ review the Court of Appeals’ decision. If the Court of Appeals’ decision is not reversed, the parties will proceed with the litigation at the trial court.

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In March 2008, a second class action suit was filed against GNG in the State Court of Fulton County in the State of Georgia, regarding monthly service charges. This lawsuit alleges that GNG arbitrarily assigned customer service charges rather than basing each customer service charge on a specific credit score. GNG asserts that no violation of law or Georgia Commission rules has occurred, that this lawsuit is without merit and has filed motions to dismiss this class action suit on various grounds. This lawsuit was dismissed with prejudice in March 2009. In April 2009, the plaintiffs appealed the decision but in June 2009, the plaintiffs withdrew their appeal of the courts dismissal order in exchange for GNG withdrawing and dropping all claims for attorney’s fees and costs in connection with the trial and appellate proceedings.

In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against us asking the court to enter a judgment declaring that our right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We reached a settlement agreement with Piedmont that dismissed the lawsuit and will result in a restructuring of the ownership interests in the SouthStar joint venture. Under the terms of the agreement, which has been approved by the boards of directors of both companies, we will purchase an additional 15% ownership share in the joint venture from Piedmont for $58 million. As a result, we will own 85% of the SouthStar joint venture, and will be entitled to 85% of the annual earnings from the business, while Piedmont will retain the remaining 15% share. As part of the agreement, our interest will remain a noncontrolling interest and we will not have any further option rights to Piedmont’s remaining 15% ownership interest. The effective date of the transaction will be January 1, 2010. The agreement was approved by the Georgia Commission in October 2009.

In May 2009, Pivotal Utility Holdings Inc., through its operating entity Elizabethtown Gas, was served as a responsible party, along with several hundred other entities, in litigation associated with the investigation and cleanup of the Passaic River and Newark Bay in New Jersey. The Plaintiffs, Maxus Energy Corporation and Tierra Solutions, Inc., who are among parties who have been ordered to address contamination in those water bodies, assert that historical operations of Elizabethtown Gas' former manufactured gas plants contributed to contamination at issue. We have not evaluated Plaintiffs' claims but do not believe that Elizabethtown Gas' historical operations would have had any significant impact in either the Passaic River or Newark Bay. At the present time, ~~the Company~~we cannot estimate the amount of any loss, if any, associated with this claim. In addition, we believe that any amounts associated with this claim would be subject to ~~our Remediation Adjustment Clause~~Elizabethtown Gas’ remediation adjustment clause that ~~covers,~~allows it to recover through the rate mechanism, subject to stated limitations, costs associated with environmental remediation cost investigation and cleanup.

Environmental Remediation Costs

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. For more information on our environmental remediation costs, see Note 7 in our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.The following table provides more information on our former operating sites:

~~Atlanta Gas Light~~

In millions	Cost estimate range		Amount recorded		Expected costs over next twelve months
Georgia and Florida	$	53 - 98	$	53	$	10
New Jersey		65 - 110		65		9
North Carolina		12 - 21		12		2
Total	$	130 - 229	$	130	$	21

We have identified ~~ten~~13 former operating sites in Georgia and ~~three sites of predecessor companies in~~ Florida where ~~the Company~~Atlanta Gas Light owned or operated all or part of these sites. ~~We are required to investigate possible environmental contamination at those sites and, if necessary, clean up any contamination.~~ As of December 31, 2008, the soil and sediment remediation program was complete for all Georgia sites, although groundwater cleanup continues. For elements of the program where we still cannot provide engineering cost estimates, considerable variability remains in future cost estimates. ~~As of June 30, 2009~~

Additionally, we have ~~recorded a liability equal to the low end of the range of $56 million, an $18 million increase from December 31, 2008. Atlanta Gas Light expects $10 million to be incurred over the next 12 months.~~

~~Elizabethtown Gas~~ ~~We are associated with~~identified 6 former operating sites in New Jersey ~~North Carolina and other states.~~where Elizabethtown Gas owned or operated all or part of these sites. Material cleanups of these sites have not been completed nor are precise estimates available for future cleanup costs and therefore considerable variability remains in future cost estimates. ~~For the New Jersey sites, cleanup cost estimates range from $65 million to $110 million. As of June 30, 2009, we~~We have ~~recorded a liability equal to the low end of the range of $65 million, a $7 million increase from December 31, 2008. Elizabethtown Gas expects $7 million to be incurred over the next 12 months.~~

We also ~~own~~identified a site in ~~Elizabeth City,~~ North Carolina, ~~that~~which is subject to a remediation order by the North Carolina Department of Energy and Natural Resources. Cleanup cost estimates range from $12 million to $21 million. As of June 30, 2009, we had recorded a liability equal to the low end of the range of $12 million, a $2 million increase from December 31, 2008. We expect $2 million to be incurred over the next 12 months. ThereResources, and there are ~~currently~~ no cost recovery mechanisms for the environmental ~~remediation sites in North Carolina.~~remediation.

~~Glossary~~

~~Table of Contents~~

Review of Compliance with FERC Regulations

In 2008 we conducted an internal review of our compliance with FERC interstate natural gas pipeline capacity release rules and regulations. Independent of our internal review, we also received data requests from FERC’s Office of Enforcement relating specifically to compliance with the FERC’s capacity release posting and bidding requirements. In June 2009, we reached a settlement agreement with the FERC. This settlement agreement did not have a material financial impact to our condensed consolidated results of operations, cash flows or financial position.

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Note 8 - Segment Information

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

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

You should not consider 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 EBIT may not be comparable to a similarly titled measure of another company. The following table contains the reconciliations of EBIT to operating income, earnings ~~(loss)~~ before income taxes and net income ~~(loss)~~ attributable to AGL Resources Inc. for the three and ~~six~~nine months ended ~~June~~September 30, 2009 and 2008.

	Three months ended June 30,						Three months ended September 30,
In millions	2009			2008			2009			2008
Operating revenues	$	377		$	444		$	307		$	539
Operating expenses		322			438			264			413
Operating income		55			6			43			126
Other income		3			3			2			2
EBIT		58			9			45			128
Interest expense, net		(24	)		(26	)		(26	)		(29	)
Earnings (loss) before income taxes		34			(17	)
Income tax expense (benefit)		13			(7	)
Net income (loss)		21			(10	)
Net income attributable to the noncontrolling interest		1			1
Net income (loss) attributable to AGL Resources Inc.	$	20		$	(11	)
Earnings before income taxes								19			99
Income tax expense								7			39
Net income								12			60
Net loss attributable to the noncontrolling interest								-			(5	)
Net income attributable to AGL Resources Inc.							$	12		$	65

	Six months ended June 30,						Nine months ended September 30,
In millions	2009			2008			2009			2008
Operating revenues	$	1,372		$	1,456		$	1,679		$	1,995
Operating expenses		1,087			1,262			1,351			1,675
Operating income		285			194			328			320
Other income		5			4			7			6
EBIT		290			198			335			326
Interest expense, net		(49	)		(56	)		(75	)		(85	)
Earnings before income taxes		241			142			260			241
Income tax expense		85			47			92			86
Net income		156			95			168			155
Net income attributable to the noncontrolling interest		17			17			17			12
Net income attributable to AGL Resources Inc.	$	139		$	78		$	151		$	143

In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against us asking the court to enter a judgment declaring that our right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We have reached a settlement agreement that will dismiss the lawsuit and will result in a restructuring of the ownership interests in the SouthStar joint venture. Under the terms of the agreement, which has been approved by the boards of directors of both companies, we will purchase an additional 15% ownership share in the joint venture from Piedmont for $58 million. As a result, we will own 85% of the SouthStar joint venture, and will be entitled to 85% of the annual earnings from the business, while Piedmont will retain the remaining 15% share. As part of the agreement, our interest will remain a noncontrolling interest and we will not have any further option rights to Piedmont’s remaining 15% ownership interest. The effective date of the transaction will be January 1, 2010, and the agreement is subject to approval by the Georgia Commission.

In July 2009, Atlanta Gas Light filed a request with the Georgia Commission to postpone its scheduled filing of a rate case in November 2009 until as late as June 2010. In July 2009, the Georgia Commission approved the request to postpone the filing until April 1, 2010, but no later than June 1, 2010.

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

FORWARD-LOOKING STATEMENTS

Certain expectations and projections regarding our future performance referenced in this Management’s Discussion and Analysis of Financial Condition and Results of Operations section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC or otherwise release to the public and on our website are forward-looking statements. 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,” "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 several factors - many beyond our control - that could cause our results to differ significantly from our expectations.

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

We caution readers that, in addition to the important factors described elsewhere in this report, the factors set forth in Item 1A, “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2008, among others, could cause our business, results of operations or financial condition in 2009 and thereafter to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or that are not described in our Form 10-K or in this report that could cause results to differ significantly from our expectations.

Forward-looking statements are only as of the date they are made. We do not update these statements to reflect subsequent circumstances or events.

Overview

We are an energy services holding company whose principal business is the distribution of natural gas through our regulated natural gas distribution business and the sale of natural gas to end-use customers primarily in Georgia through our retail natural gas marketing business. As of ~~June~~September 30, 2009, our six utilities serve approximately 2.3 million end-use customers, making us the largest distributor of natural gas in the southeastern and mid-Atlantic regions of the United States based on customer count. Although our retail natural gas marketing business is not subject to the same regulatory framework as our utilities, it is an integral part of the framework for providing natural gas service to end-use customers in Georgia.

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

~~Glossary~~

~~Table of Contents~~

Executive Summary

We intend to continue executing our plan for long-term earnings and dividend growth. Central to that plan is the execution of our regulatory planning through the filing of rate cases and other regulatory requests to recover the investments we have made, and should continue to make, to enhance our infrastructure and improve customer service. Further, we are collaborating with regulatory agencies and other companies to promote and encourage conservation through innovative rate design mechanisms that we believe are positioning our utility businesses to benefit in an economic recovery.

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We continue to explore select opportunities to expand our businesses in strategic areas and maintain a disciplined approach around current capital projects. Our major capital projects - our Golden Triangle Storage natural gas storage facility project and our Hampton Roads Crossing and Magnolia pipeline connection projects - are ~~on schedule~~expected to be completed by year-end and be within budget. In these challenging economic conditions, we continue to aggressively focus on capital discipline and cost control, while moving ahead with projects and initiatives that we expect to have current and future benefits and provide an appropriate return on capital.

During the last half of 2008 and continuing into 2009, natural gas prices declined significantly, reflecting the decline in the United States economy, increasing natural gas supplies and above-average storage volumes, among other factors. These lower gas prices resulted in significantly lower levels of working capital necessary for our operating segments to purchase their natural gas inventories as compared to recent inventory injection seasons. We may experience increased pressure on our working capital requirements and borrowing capacity under our existing Credit Facility should natural gas prices return to levels experienced in 2008.

Distribution Operations

Our distribution operations segment is the largest component of our business and includes six natural gas local distribution utilities. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities and include:

·	Atlanta Gas Light in Georgia

·	Chattanooga Gas in Tennessee

·	Elizabethtown Gas in New Jersey

·	Elkton Gas in Maryland

·	Florida City Gas in Florida

·	Virginia Natural Gas in Virginia

Each utility operates subject to regulations of the state regulatory agencies in its service territories with respect to rates charged to our customers, maintenance of accounting records and various other service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. Rates are set at levels that generally should allow us to recover all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return for our shareholders. Rate base generally consists of the original cost of utility plant in service, working capital and certain other assets; less accumulated depreciation on utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.

Customer growth declined slightly in our distribution operations segment in the first ~~six~~nine months of 2009 relative to last year, a trend we expect to continue through the end of 2009. For the ~~six~~nine months ended ~~June~~September 30, 2009, our year-over-year consolidated utility customer growth rate was slightly negative or (0.3)%, compared to ~~0.3%~~0.1% positive growth for the same period of 2008. We anticipate overall customer growth in 2009 to be flat to negative, primarily as a result of much slower growth in the residential housing markets throughout most of our service territories and the effects of a weak economy on our commercial and industrial customers. ~~Over the last~~As compared to 3 years ago, we have reduced our customer attrition rates. As a result, we believe we should be well positioned when the economy recovers.

The weak economy ~~also impacted~~is expected to continue to impact a significantly larger portion of consumer household incomes during the ~~most recent~~upcoming winter heating season. ~~As a~~However, natural gas prices and the WACOG of our natural gas inventories have declined significantly since last year, which is expected will result ~~we incurred additional~~in lower average customer bills and no significant increases in our bad debt expense and increased customer conservation. We expect these factors may continue to adversely impact our results of operations during the current economic situation. However, we expect operational and collections efforts combined with regulatory mechanisms in place in most of our jurisdictions to help mitigate some of our exposure to these factors.

The risks of increased bad debt expense and decreased operating margins from conservation are minimized at our largest utility, Atlanta Gas Light, as a result of its straight-fixed variable rate structure. In addition, customers in Georgia buy their natural gas from Marketers rather than from Atlanta Gas Light. Our credit exposure at Atlanta Gas Light is primarily related to the provision of services to the Marketers, but that exposure is mitigated, because we obtain security support in an amount equal to a minimum of no less than two times a Marketer’s highest month’s estimated bill. At our other utilities, while customer conservation could adversely impact our operating margins, we utilize measures to collect delinquent accounts and continue to be rigorous in monitoring and mitigating the impact of these expenses. ~~Due to the timing of usage and billing, the full effects of the most recent heating season will not be known until several months following the end of the heating season.~~

We ~~worked~~work with regulators and state agencies in each of our jurisdictions to educate customers about ~~higher~~ energy costs in advance of the winter heating season, in particular, to ensure that those customers ~~qualified~~qualifying for the Low Income Home Energy Assistance Program and other similar programs receive any needed assistance and we expect to continue this focus for the foreseeable future.

~~Glossary~~

~~Table of Contents~~

Distribution Operations - regulatory planning

In 2010 and 2011, we expect to file base rate cases in three of our six jurisdictions. Over the past several years our utilities have been fulfilling their long-term commitments to rate freezes, which ~~begin~~began expiring in 2009. As these rate cases are filed, we plan to seek rate reforms that encourage conservation and “decoupling.” In traditional rate designs, our utilities’ recovery of a significant portion of their fixed customer service costs is tied to assumed natural gas volumes used by our customers. We believe separating, or decoupling, the recovery of these fixed costs from the natural gas deliveries will align the interests of our customers and utilities by encouraging energy conservation, achieving rate stability for our customers and ensuring stable returns for our shareholders. These rate case filings are required due to settlements we reached with the applicable state authority in previous rate case or acquisition proceedings. The expected filing dates and dates for which current rates are expected to be effective are outlined in the chart below:

Company	Expected filing date (2)		Current rates effective until
Atlanta Gas Light (1)		Q2 2010		Q2Q4 2010
~~Virginia Natural Gas~~		~~Q2 2010~~		~~Q3 2011~~
Chattanooga Gas		Q2 2010		Q1 2011
Virginia Natural Gas		Q1 2011		Q3 2011

(1)	In July 2009, Atlanta Gas Light filed a request with the Georgia Commission to postpone its scheduled filing of a rate case in November ~~2009. This~~2009.This request was approved by the Georgia Commission which agreed to postpone the filing until April 1, 2010, but no later than June 1, 2010.

(2)	Subject to change.

Glossary of Key Terms

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Elizabethtown Gas After a 5-year rate freeze and in accordance with the New Jersey ~~Commission’s~~BPU’s order, we filed a rate case in March 2009 with a proposed effective date of January 1, 2010. Our initial request was an annual increase to base rates of $25 million. The filing also included energy conservation programs and a proposed Efficiency Usage and Adjustment mechanism (EUA), which is a form of decoupling, including weather normalization. In traditional rate designs, our utilities’ recovery of a significant portion of their fixed customer service costs is tied to assumed natural gas volumes used by our customers. We believe separating, or decoupling, the recovery of these fixed costs from the natural gas deliveries will align the interests of our customers and utilities by encouraging energy conservation, achieving rate stability for our customers and ensuring stable returns for our shareholders. If the EUA is approved, the current weather normalization clause would be suspended.

In June 2009, and in accordance with New Jersey rate case rules that require the filing of quarterly updates to a case, we filed a revised request for a $17 million annual increase to base rates. The primary driver of the reduced request was a revision to our depreciation rates. ~~Our revised requested increase consists of:~~

·	~~increased carrying costs associated with increased rate base ($9 million)~~

·	~~increased operating expenses, including higher bad debt expenses and other ($5 million)~~

·	~~increased return on equity from 10% to 11.25% and return on rate base from 7.95% to 8.41% ($3 million)~~

In August 2009, the New Jersey Department of the Public Counsel, Division of Rate Counsel (Rate Counsel) filed testimony recommending a base rate decrease of $13 million. We are currently in settlement discussions with the Rate Counsel and the New Jersey BPU’s staff, and we expect all parties to come to an acceptable agreement that will be considered by the New Jersey BPU before the end of 2009.

Distribution Operations - capital projects

In June 2009, Atlanta Gas Light filed a request for a Strategic Infrastructure Development and Enhancement (STRIDE) program with the Georgia Commission to upgrade its distribution system and liquefied natural gas facilities to improve system reliability and create a platform to meet operational flexibility needs and forecasted growth. Under the program, Atlanta Gas Light would be required to file a ten-year infrastructure plan every three years for review and approval by the Georgia Commission. The program merges with Atlanta Gas Light’s existing Pipeline Replacement Program (PRP), which was initiated in 1998 and is scheduled to end in December 2013.

In October 2009, the Georgia Commission approved the initial three years of the STRIDE program, estimated at approximately $176 million, which will increase the existing $1.95 monthly PRP charge for Atlanta Gas Light’s customers by $0.39 beginning in October 2009. Beginning October 2010, the rates will increase by an additional $0.39 for a total of $0.78 per month, and beginning in October 2011, the rates will increase by an additional $0.40 per month for a total of $1.18 per month. The increased charges are subject to review and modification by the Georgia Commission every three years. Further, in October 2009 and subsequent to the Georgia Commission’s approval of the STRIDE program, an organization representing members in Georgia has filed a Motion for Reconsideration of the order approving the program with the Georgia Commission, as well as an appeal to the State Superior Court for a review of the Georgia Commission’s ruling that the organization did not have discovery rights in the STRIDE program proceeding. Pursuant to the Georgia Commission’s approval order, neither of these filings prevents the STRIDE program from going into effect. We cannot predict what action, if any, the Georgia Commission or the State Superior Court will take in response to these filings. For more information on Atlanta Gas Light’s PRP program, see Note 1 in our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.

In April 2009, the New Jersey ~~Commission~~BPU approved an accelerated $60 million enhanced infrastructure program for Elizabethtown Gas which ~~is expected to start~~started this year and is scheduled to be completed in 2011. This program was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. A regulatory cost recovery mechanism will be established with estimated rates put into effect at the beginning of each year. At the end of the program the regulatory cost recovery mechanism will be trued-up and any remaining costs not previously collected will be included in base rates. Elizabethtown Gas expects that approximately ~~$20~~$18 million in capital expenditures for this program will occur in 2009.

In June 2009, Atlanta Gas Light filed a request for a Strategic Infrastructure Development and Enhancement (STRIDE) program with the Georgia Commission to upgrade its distribution system and liquefied natural gas facilities to improve system reliability and create a platform to meet operational flexibility needs and forecasted growth. Under the program, Atlanta Gas Light would be required to file a ten-year infrastructure plan every three years for review and approval by the Georgia Commission. Atlanta Gas Light is seeking approval of the initial three years of the program through 2012, which includes infrastructure improvements of approximately $176 million.

In July 2009, the Georgia Commission established a procedural schedule to consider our STRIDE program request. Under such schedule, we expect a decision by the end of this year. If approved, the program would merge with Atlanta Gas Light’s existing Pipeline Replacement Program (PRP), which was initiated in 1998 and is scheduled to end in December 2013. Under the proposed STRIDE program, the existing $1.95 monthly PRP charge for residential customers would increase by 95 cents beginning in October 2009. Small commercial customers, who pay $5.85 per month under the current PRP rate design set by the Georgia Commission, would pay an additional $2.85 per month. The increased charges would be in effect subject to review and modification by the Georgia Commission every three years. For more information on Atlanta Gas Light’s PRP program, see Note 1 in our recast consolidated financial statements and related notes as filed on Form 8-K with the SEC on July 13, 2009, and in our Form 10-K for the year ended December 31, 2008, filed with the SEC on February 5, 2009.

Retail Energy Operations

Our retail energy operations segment consists of SouthStar, a joint venture currently owned 70% by us and 30% by Piedmont. SouthStar markets natural gas and related services to retail customers on an unregulated basis, principally in Georgia, as well as to commercial and industrial customers in Alabama, Florida, Ohio, Tennessee, North Carolina and South Carolina. SouthStar is the largest marketer of natural gas in Georgia with an approximate 33% market share based on customer count.

~~Glossary~~

~~Table of Contents~~

Although our ownership interest in the SouthStar partnership is currently 70%, the majority of SouthStar's earnings in Georgia are currently allocated, by contract, 75% to us and 25% to Piedmont. SouthStar’s earnings related to customers in Ohio and Florida are currently allocated 70% to us and 30% to Piedmont. We record the earnings allocated to Piedmont as a noncontrolling interest in our condensed consolidated statements of income, and we record Piedmont’s portion of SouthStar’s capital as a noncontrolling interest in our condensed consolidated statements of financial position. The majority of SouthStar’s earnings allocated to us for the ~~three and six~~nine months ended ~~June~~September 30, 2009, were largely at the 75% contractual rate.

Glossary of Key Terms

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In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against us asking the court to enter a judgment declaring that our right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We ~~have~~ reached a settlement agreement with Piedmont that ~~will dismiss~~dismissed the lawsuit and will result in a restructuring of the ownership interests in the SouthStar joint venture. Under the terms of the agreement, which has been approved by the boards of directors of both companies, we will purchase an additional 15% ownership share in the joint venture from Piedmont for $58 million. As a result, we will own 85% of the SouthStar joint venture, and will be entitled to 85% of the annual earnings from the business, while Piedmont will retain the remaining 15% share. As part of the agreement, our interest will remain a noncontrolling interest and we will not have any further option rights to Piedmont’s remaining 15% ownership interest. The agreement was approved by the Georgia Commission in October 2009 and the effective date of the transaction will be January 1, ~~2010, and the agreement is subject to approval by the Georgia Commission.~~

2010.

Customers Three months ended Six months ended
June 30, June 30,
2009 2008 % change 2009 2008 % change
Distribution Operations
Average end-use customers (in thousands)
Atlanta Gas Light 1,565 1,574 (0.6 )% 1,571 1,578 (0.4 )%
Chattanooga Gas 62 62 - 62 62 -
Elizabethtown Gas 274 273 0.4 % 274 274 -
Elkton Gas 6 6 - 6 6 -
Florida City Gas 103 104 (1.0 )% 103 104 (1.0 )%
Virginia Natural Gas 272 272 - 274 273 0.4 %
Total 2,282 2,291 (0.4 )% 2,290 2,297 (0.3 )%
Operation and maintenance per customer $ 39 $ 36 8 % $ 75 $ 74 1 %
EBIT per customer $ 28 $ 25 12 % $ 84 $ 78 8 %

Retail Energy Operations
Average customers in Georgia (in thousands)
510 535 (5 )% 514 535 (4 )%
Market share in Georgia 33 % 35 % (6 )% 33 % 35 % (6 )%

Three months ended Six months ended
Volumes June 30, June 30,
In billion cubic feet (Bcf) 2009 2008 % change 2009 2008 % change
Distribution Operations
Firm 29 29 - 128 127 1 %
Interruptible 23 25 (8 )% 49 54 (9 )%
Total 52 54 (4 )% 177 181 (2 )%

Retail Energy Operations
Georgia firm 5 5 - 23 24 (4 )%
Ohio and Florida 2 1 100 % 7 3 133 %

Wholesale Services
Daily physical sales (Bcf/day) 2.6 2.4 8 % 2.8 2.5 12 %

Glossary of Key Terms

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~~Second quarter~~Three months ended September 30, 2009 compared to ~~second quarter~~three months ended September 30, 2008

Segment information Operating ~~revenues, operating~~ margin, operating expenses and EBIT information for each of our segments are contained in the following table for the three months ended ~~June~~September 30, 2009 and 2008.

In millions	Operating revenues			Operating margin (1)		Operating expenses		EBIT (1)			Operating margin (1)		Operating expenses		EBIT (1)
2009
Distribution operations	$	275		$	190	$	130	$	63		$	173	$	127	$	48
Retail energy operations		125			23		18		5			14		16		(2	)
Wholesale services		2			2		13		(11	)		10		12		(2	)
Energy investments		10			10		8		2			11		8		3
Corporate (2)		(35	)		-		1		(1	)		-		2		(2	)
Consolidated	$	377		$	225	$	170	$	58		$	208	$	165	$	45

In millions Operating revenues Operating margin (1) Operating expenses EBIT (1)
2008
Distribution operations $ 345 $ 180 $ 123 $ 57
Retail energy operations 177 24 18 6
Wholesale services (51 ) (53 ) 12 (65 )
Energy investments 19 18 8 10
Corporate (2)
(46 ) - 2 1
Consolidated $ 444 $ 169 $ 163 $ 9

~~(1)~~

~~These are non-GAAP measures. A reconciliation of operating margin and EBIT to our operating~~

~~income, earnings before income taxes and net income attributable to AGL Resources Inc. is located in~~

~~“Results of Operations” herein.~~

~~(2)~~

~~Includes intercompany eliminations.~~

~~Operating margin~~ Our operating margin for the second quarter of 2009 increased by $56 million or 33% compared to the same period last year. This increase was primarily due to increased operating margins at wholesale services and distribution operations, offset by lower operating margins at energy investments.

Distribution operations’ operating margin increased by $10 million or 6% compared to last year. The following table indicates the significant changes in distribution operations’ operating margin for the three months ended June 30, 2009 compared to the prior year period.

In millions
Operating margin for second quarter of 2008 $ 180
Increased margins from gas storage carrying amounts at Atlanta Gas Light 4
Prior year revision in estimated unbilled natural gas volumes and slightly higher customer growth and usage at Elizabethtown Gas 4
Higher PRP revenues at Atlanta Gas Light 1
Other 1
Operating margin for second quarter of 2009 $ 190

Retail energy operations’ operating margin decreased by $1 million or 4%. The following table indicates the significant changes in retail energy operations’ operating margin for the three months ended June 30, 2009 compared to 2008.

In millions
Operating margin for second quarter of 2008 $ 24
Higher contributions from the management of storage and transportation assets largely due to declining natural gas prices in 2009 offset by a prior year favorable pipeline rate order true-up 3
Lower operating margins in Ohio and Florida (1 )
Change in retail pricing plan mix and decrease in average number of customers (3 )
Operating margin for second quarter of 2009 $ 23

Wholesale services’ operating margin increased $55 million compared to the second quarter of 2008 primarily due to $13 million in reported hedge gains as a result of decreases in forward NYMEX natural gas prices and the narrowing of transportation basis spreads in the current period, compared to $55 million in reported hedge losses due to rising forward NYMEX natural gas prices and expanding transportation basis spreads in 2008. In addition, commercial activity decreased $13 million due to lower volatility in the marketplace during the quarter as compared to last year. The following table indicates the components of wholesale services’ operating margin for the three months ended June 30, 2009 and 2008.

In millions 2009 2008
Commercial activity $ (11 ) $ 2
Gain (loss) on transportation hedges 11 (7 )
Gain (loss) on storage hedges 2 (48 )
Operating margin $ 2 $ (53 )

Energy investments’ operating margin decreased by $8 million or 44% compared to last year. The following table indicates the significant changes in energy investments’ operating margin for the three months ended June 30, 2009 compared to the prior year period.

In millions
Operating margin for second quarter of 2008 $ 18
Decreased operating margin contribution at AGL Networks, primarily as a result of a network expansion project completed in 2008 (7 )
Decreased interruptible margins at Jefferson Island (1 )
Operating margin for second quarter of 2009 $ 10

~~Operating expenses~~ Our operating expenses for the second quarter of 2009 increased $7 million or 4% as compared to the second quarter of 2008. The following table indicates the significant changes in our operating expenses.

In millions
Operating expenses for second quarter of 2008 $ 163
Increased environmental remediation costs at distribution operations 2
Increased pension and postretirement expenses at distribution operations 2
Increased depreciation expense at distribution operations and energy investments 2
Other 1
Operating expenses for second quarter of 2009 $ 170

~~Glossary~~

~~Table of Contents~~

~~Interest expense~~ Interest expense decreased by $2 million or 8% for the three months ended June 30, 2009, primarily due to the decrease in short-term interest rates partially offset by higher average debt outstanding as indicated in the following table.

Three months ended
June 30,

In millions 2009 2008 Change
Average debt outstanding (1) $ 1,996 $ 1,853 $ 143
Average rate 4.8 % 5.6 % (0.8 )%

~~(1) Daily average of all outstanding debt.~~

~~Six months 2009 compared to six months 2008~~

~~Segment information~~ ~~Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the six months ended June 30, 2009 and 2008.~~

In millions Operating revenues Operating margin (1) Operating expenses EBIT (1)
2009
Distribution operations $ 882 $ 442 $ 254 $ 193
Retail energy operations 468 107 39 68
Wholesale services 70 61 34 27
Energy investments 20 20 16 4
Corporate (2)
(68 ) 1 3 (2 )
Consolidated $ 1,372 $ 631 $ 346 $ 290

In millions	Operating revenues			Operating margin (1)			Operating expenses		EBIT (1)			Operating margin (1)			Operating expenses		EBIT (1)
2008
Distribution operations	$	1,021		$	428		$	249	$	180		$	171		$	113	$	59
Retail energy operations		552			106			38		68			(5	)		16		(21	)
Wholesale services		(34	)		(38	)		26		(64	)		101			15		86
Energy investments		30			29			14		15			10			7		3
Corporate (2)		(113	)		(1	)		3		(1	)		1			1		1
Consolidated	$	1,456		$	524		$	330	$	198		$	278		$	152	$	128

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies and other factors. See Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2008, for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities.

	Six months ended June. 30,						Nine months ended September 30,
In millions	2009			2008			2009			2008
Net cash provided by (used in):
Operating activities	$	731		$	359		$	686		$	172
Investing activities		(207	)		(166	)		(314	)		(254	)
Financing activities		(528	)		(193	)		(367	)		74
Net decrease in cash and cash equivalents	$	(4	)	$	-
Net increase (decrease) in cash and cash equivalents							$	5		$	(8	)

Cash Flow from Operating Activities In the first ~~six~~nine months of 2009, our net cash flow provided from operating activities was ~~$731~~$686 million, an increase of ~~$372~~$514 million or ~~104%~~299% from the same period in 2008. This increase was primarily a result of ~~a larger decrease~~the recovery of working capital during 2009 that was deployed in ~~inventory in 2009 than~~ 2008 ~~primarily related~~due to higher natural gas commodity prices. A primary contributor to the ~~higher cost~~recovery of working capital was a $272 million increase in cash from our inventory ~~sold~~withdrawals and $125 million increase in ~~2009. This was partially offset by increased~~cash from the collection of our natural gas receivables. In addition, we received $101 million from decreased cash collateral requirements for our derivative financial instrument activities at Sequent and SouthStar due to the change in hedge values ~~due to the downward shift in the~~as forward NYMEX curve prices shifted downward in 2009.

The downward shift in the forward curve results in unrealized losses on the hedging instruments, comprised primarily of exchange traded derivatives, associated with anticipated natural gas purchases. We maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts. These unrealized losses are substantially offset by gains on derivative instruments utilized to hedge the price risk associated with the anticipated sale of these natural gas purchases. The anticipated economics of these transactions will ultimately be realized in the period when the natural gas is bought and sold.

Cash Flow from Investing Activities Our investing activities consisted of PP&E expenditures of ~~$207~~$314 million for the ~~six~~nine months ended ~~June~~September 30, 2009 and ~~$166~~$254 million for the same period in 2008. The increase of ~~$41~~$60 million or ~~25%~~24% in PP&E expenditures was primarily due to a $35 million increase at distribution operations ~~which included higher~~and a $28 million increase at energy investments.

The increased expenditures at distribution operations include $43 million in increased spending ~~primarily for~~at Virginia Natural Gas’ Hampton Roads Crossing pipeline project connecting its northern and southern systems. In addition, Elizabethtown Gas’ enhanced infrastructure program resulted in a $10 million increase compared to 2008, as the program started earlier this year. These increases were offset by reduced expenditures of $16 million for the PRP at Atlanta Gas Light.

~~Glossary~~

~~Table of Contents~~

~~Additionally, our~~The increases at energy ~~investments’ PP&E expenditures increased $11 million~~investments were primarily ~~from increased expenditures at~~due to Golden Triangle ~~Storage on our planned~~Storage’s natural gas storage ~~facility~~facility. The increases at distribution operations and energy investments were partially offset by decreased ~~telecommunication expenditures at AGL Networks which expanded its Phoenix network in 2008. These~~ PP&E ~~expenditure increases were partially offset by decreased~~ expenditures at retail energy operations of $6 million primarily due to decreased spending on information technology assets compared to 2008, when ~~the segment~~GNG transitioned to a new customer care and call center vendor.

Cash Flow from Financing Activities Our cash used in financing activities ~~are~~was $367 million for the nine months ended September 30, 2009 compared to cash provided of $74 million for the same period in 2008. The increased cash use of $441 million was primarily ~~composed of borrowings and payments of~~due to increased short-term debt payments of ~~medium-term notes, issuances~~$556 million in 2009 compared to net borrowings of $189 million for the same period in 2008. This was partially offset by our issuance of $300 million of senior notes ~~distributions to noncontrolling interests, cash dividends on our common stock, and purchases and issuances of treasury shares.~~ in August 2009.

Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of equity and debt securities. This strategy includes active management of the percentage of total debt relative to total capitalization, appropriate mix of debt with fixed to floating interest rates (our variable-rate debt target is 20% to 45% of total debt), as well as the term and interest rate profile of our debt securities. As of ~~June~~September 30, 2009, our variable-rate debt was ~~28%~~21% of our total debt, compared to ~~29%~~38% as of ~~June~~September 30, 2008. ~~We may issue additional long-term debt in 2009 in consideration of our working capital needs and capital expenditure plans to maintain an appropriate mix of fixed to floating debt.~~

We also work to maintain or improve our credit ratings to manage our existing financing costs effectively and enhance our ability to raise additional capital on favorable terms. Factors we consider important in assessing our credit ratings include our 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~~September 30, 2009, and reflects no change from December 31, 2008.

S&P

Moody’s

Fitch

Corporate rating

A-

Commercial paper

A-2

P-2

F-2

Senior unsecured

BBB+

Baa1

A-

Ratings outlook

Stable

Glossary of Key Terms

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Our credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. If the rating agencies downgrade our ratings, particularly below investment grade, it may significantly limit our access to the commercial paper market and our borrowing costs would increase. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources would decrease.

Default events Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. Our most important default events include maintaining covenants with respect to a maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, and acceleration of other financial obligations and change of control provisions.

Our Credit ~~Facilities have~~Facility has financial covenants that require us to maintain a ratio of total debt to total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. Our ratio of total debt to total capitalization calculation contained in our debt covenant includes ~~noncontrolling interest,~~ standby letters of credit, surety bonds and the exclusion of other comprehensive income pension adjustments. Our debt to total capitalization calculation, as defined by our Credit ~~Facilities~~Facility was ~~53%~~55% at ~~June~~September 30, 2009, ~~and~~ 59% at December 31, 2008 and ~~56%~~58% at ~~June~~September 30, 2008. These amounts are within our required and targeted ranges. Our debt to total capitalization ratios as calculated from our condensed consolidated statements of financial position, as of the dates indicated, are summarized in the following table.

	June 30, 2009			Dec. 31, 2008			June 30, 2008			Sept. 30, 2009			Dec. 31, 2008			Sept. 30, 2008
Short-term debt		11	%		20	%		13	%		8	%		20	%		18	%
Long-term debt		43			40			43			49			40			40
Total debt		54			60			56			57			60			58
Equity		46			40			44			43			40			42
Total capitalization		100	%		100	%		100	%		100	%		100	%		100	%

Sequent has certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, Sequent would need to post collateral to continue transacting business with some of its counterparties. If such collateral were not posted, Sequent’s ability to continue transacting business with these counterparties would be impaired. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $9$6 million at ~~June~~September 30, 2009, which would not have a material impact to our condensed consolidated results of operations, cash flows or financial condition.

There have been no other significant changes to our credit risk related to our other segments, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2008.

Glossary of Key Terms

Table of Contents

Item 4. Controls and Procedures

(a) Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of ~~June~~September 30, 2009, 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~~September 30, 2009, in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

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

~~Glossary~~

~~Table of Contents~~

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities and litigation incidental to the business. For information regarding pending federal and state regulatory matters, see “Note 7 - Commitments and Contingencies” contained in Item 1 of Part I under the caption “Notes to Condensed Consolidated Financial Statements (Unaudited).”

In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against us asking the court to enter a judgment declaring that our right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We have reached a settlement agreement with Piedmont that will dismiss the lawsuit and will result in a restructuring of the ownership interests in the SouthStar joint venture. Under the terms of the agreement, which has been approved by the boards of directors of both companies, we will purchase an additional 15% ownership share in the joint venture from Piedmont for $58 million. As a result, we will own 85% of the SouthStar joint venture, and will be entitled to 85% of the annual earnings from the business, while Piedmont will retain the remaining 15% share. As part of the agreement, our interest will remain a noncontrolling interest and we will not have any further option rights to Piedmont’s remaining 15% ownership interest. The agreement was approved by the Georgia Commission in October 2009 and the effective date of the transaction will be January 1, ~~2010, and the agreement is subject to approval by the Georgia Commission.~~

2010.

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

Glossary of Key Terms

Table of Contents

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

~~There were no~~The following table sets forth information about purchases of our common stock by us and any affiliated purchasers during the three months ended ~~June~~September 30, 2009.

~~Glossary~~

~~Table~~ 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 ~~Contents~~

~~Item 4. Submission of Matters to a Vote of Security Holders~~

~~The annual meeting~~ ~~of shareholders was held in Atlanta, Georgia on April 29, 2009. Holders of an aggregate of 77,086,652~~additional shares ~~of our common~~that may be repurchased, and we may terminate or limit the stock repurchase program at any time. We currently anticipate holding the ~~close of business on February 20, 2009, were entitled to vote at the meeting, of which 67,422,393 or 87.46% of the eligible voting~~repurchased shares ~~were represented in person or by proxy. At the annual meeting, our shareholders were presented with three proposals,~~ as ~~set forth in our proxy statement. Our shareholders voted as follows:~~treasury shares.

~~Proposal 1 –~~ ~~Election of Directors~~

For Withheld
Charles R. Crisp 66,657,056 765,337
Wyck A. Knox, Jr. 66,480,924 941,469
Dennis M. Love 66,344,672 1,077,721
Charles H. McTier 66,595,675 826,718
Henry C. Wolf 66,683,058 739,335

The term of office of each of the following directors continued after the meeting: Sandra N. Bane, Thomas D. Bell, Jr., Arthur E. Johnson, Dean R. O’Hare, D. Raymond Riddle, James A. Rubright, John W. Somerhalder II, Felker W. Ward, Jr. and Bettina M. Whyte.

~~Proposal 2 –~~ ~~Amend our articles of incorporation to eliminate the classification of the board of directors.~~

Period	Total number of shares purchased (1) (2)		Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (2)		Maximum number of shares that may yet be purchased under the publicly announced plans or programs (2)
July 2009		-	$	-		-		4,950,951
August 2009		2,443		33.64		-		4,950,951
September 2009		-		-		-		4,950,951
Total third quarter		2,443	$	33.64		-

~~For~~(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 2,443 shares for such purposes in the third quarter of 2009. As of September 30, 2009, we had purchased a total of 324,860 of the 600,000 shares authorized for purchase, leaving 275,140 shares available for purchase under this program.

(2)	~~65,838,999~~
~~Against~~		~~970,551~~
~~Abstain~~		~~612,843~~
~~Broker Non-Votes~~		-	On February 3, 2006, we announced that our Board of Directors had authorized a plan to repurchase up to a total of 8 million shares of our common stock, excluding the shares remaining available for purchase in connection with the Officer Plan as described in note (1) above, over a five-year period.

~~Proposal 3~~Item 5. Other Information

In connection with the settlement reached with Piedmont previously described under “Item 1 – ~~Ratification~~Legal Proceedings,” on July 29, 2009, GNG entered into a Third Amendment to the Amended and Restated Limited Liability Company Agreement by and between GNG and Piedmont. The material terms of the ~~appointment of PricewaterhouseCoopers LLP~~third Amendment, which is filed herewith as ~~our independent registered public accounting firm for 2009.~~

~~For~~			~~66,987,874~~
~~Against~~			~~158,500~~
~~Abstain~~			~~276,019~~
~~Broker Non-Votes~~			-

Exhibit 10.1, are summarized in the second paragraph under “Item 1 – Legal Proceedings” above, which summary is incorporated by reference under this Item 5.

Item 6. Exhibits

~~3.1(a)~~1.1

~~Amended~~Underwriting Agreement, dated August 5, 2009, by and ~~Restated Articles of Incorporation filed November 2, 2005, with the Secretary of State~~among AGL Capital Corporation, as issuer, AGL Resources Inc., as guarantor, and Wells Fargo Securities, LLC, for itself and on behalf of the ~~state of Georgia~~several underwriters listed on Schedule A thereto (Exhibit ~~3.1,~~1.1, AGL Resources, Inc. Form 8-K dated ~~November, 2005)~~August 5, 2009).

~~3.1(b)~~4.1

~~Articles of Amendment to the Amended and Restated Articles of Incorporation filed May 4, 2009, with the Secretary of State of the state of Georgia.~~Specimen AGL Capital Corporation, 5.25% Senior Notes due 2019 (Exhibit 4.1, AGL Resources, Inc. Form 8-K dated August 5, 2009).

4.2	Form of Guarantee of AGL Resources Inc. dated as of August 10, 2009 regarding the AGL Capital Corporation 5.25% Senior Notes due 2019 (Exhibit 4.2, AGL Resources, Inc. Form 8-K dated August 5, 2009).

10.1	Third Amendment to Amended and Restated Limited Liability Company Agreement, dated July 29, 2009, by and between Georgia Natural Gas Company and Piedmont Energy ~~Company.~~Company (Exhibit 10, AGL Resources, Inc. Form 10-Q for the quarter ended June 30, 2009).

10.2	Environmental Services Agreement, dated July 16, 2009, by and between Atlanta Gas Light Company and MACTEC Engineering and Consulting, Inc.

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.

Glossary of Key Terms

Table of Contents

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~~September 30, 2009

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 ¨ 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 24,~~October 22, 2009
Common Stock, $5.00 Par Value	~~77,278,942~~77,398,732

TABLE OF CONTENTS
			Page(s)
Glossary of Key Terms				3

Item
Number

		PART 1 – FINANCIAL INFORMATION		4-46

	1	Condensed Consolidated Financial Statements (Unaudited)		4-24
		Condensed Consolidated Statements of Financial Position		4
		Condensed Consolidated Statements of Income		5
		Condensed Consolidated Statements of Equity		6
		Condensed Consolidated Statements of Comprehensive Income (Loss)		7
		Condensed Consolidated Statements of Cash Flows		8
		Notes to Condensed Consolidated Financial Statements		9 – 24
		Note 1 – Accounting Policies and Methods of Application		9 – 11
		Note 2 – Fair Value Measurements		11 – 13
		Note 3 – Derivative Financial Instruments		13 – 16
		Note 4 – Employee Benefit Plans		17 – 18
		Note 5 – Variable Interest Entity		18
		Note 6 – Debt		19
		Note 7 – Commitments and Contingencies		20 – 21
		Note 8 – Segment Information		22 – 24
	2	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25 – 41
		Forward-Looking Statements		25
		Overview		25
		Executive Summary		25 – 26
		Distribution Operations		26 – 27
		Retail Energy Operations		27 – 28
		Wholesale Services		28 – 29
		Energy Investments		30
		Corporate		30
		Results of Operations		30 – 36
		Liquidity and Capital Resources		36 – 39
		Critical Accounting Policies and Estimates		40
		Accounting Developments		40 – 41
	3	Quantitative and Qualitative Disclosures About Market Risk		41 – 44
	4	Controls and Procedures		45

		PART II – OTHER INFORMATION		45 – 46

	1	Legal Proceedings		45
	2	Unregistered Sales of Equity Securities and Use of Proceeds		46
	5	Other Information		46
	6	Exhibits		46

		SIGNATURE		47

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

Item
Number

		PART 1 – FINANCIAL INFORMATION		4-44

	1	Condensed Consolidated Financial Statements (Unaudited)		4-24
		Condensed Consolidated Statements of Financial Position		4
		Condensed Consolidated Statements of Income		5
		Condensed Consolidated Statements of Equity		6
		Condensed Consolidated Statements of Comprehensive Income (Loss)		7
		Condensed Consolidated Statements of Cash Flows		8
		Notes to Condensed Consolidated Financial Statements		9 – 24
		Note 1 – Accounting Policies and Methods of Application		9 – 11
		Note 2 – Fair Value Measurements		11 – 13
		Note 3 – Derivative Financial Instruments		13 – 16
		Note 4 – Employee Benefit Plans		17 – 18
		Note 5 – Equity		18
		Note 6 – Debt		19
		Note 7 – Commitments and Contingencies		19 – 21
		Note 8 – Segment Information		21 – 23
		Note 9 – Subsequent Events		24
	2	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25 – 40
		Forward-Looking Statements		25
		Overview		25
		Executive Summary		26
		Distribution Operations		26 – 27
		Retail Energy Operations		27 – 28
		Wholesale Services		28 – 30
		Energy Investments		30
		Corporate		30
		Results of Operations		30 – 36
		Liquidity and Capital Resources		36 – 39
		Critical Accounting Policies and Estimates		39
		Accounting Developments		39 – 40
	3	Quantitative and Qualitative Disclosures About Market Risk		41 – 44
	4	Controls and Procedures		44

		PART II – OTHER INFORMATION		45 – 46

	1	Legal Proceedings		45
	2	Unregistered Sales of Equity Securities and Use of Proceeds		45
	4	Submission of Matters to a Vote of Security Holders		46
	6	Exhibits		46

		SIGNATURE		47

AGL Capital	AGL Capital Corporation
AGL Networks	AGL Networks, LLC
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Chattanooga Gas	Chattanooga Gas Company
Credit ~~Facilities~~Facility	Credit ~~agreements~~agreement supporting our commercial paper program
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes interest expense, and income tax expense; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, operating income, net income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP
~~EITF~~	~~Emerging Issues Task Force~~
ERC	Environmental remediation costs associated with our distribution operations segment which are generally recoverable through rates mechanisms
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
~~FIN~~	~~FASB Interpretation Number~~
Fitch	Fitch Ratings
~~FSP~~	~~FASB Staff Position~~
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission
GNG	Georgia Natural Gas, the name under which SouthStar does business in Georgia
~~GNGC~~	~~Georgia Natural Gas Company, our wholly-owned subsidiary that owns our current 70% interest in SouthStar~~
Golden Triangle Storage	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of the effects of weather on our businesses, calculated when the average daily actual temperatures are less than a baseline temperature of 65 degrees Fahrenheit.
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems when weather is ~~colder~~colder.
Jefferson Island	Jefferson Island Storage & Hub, LLC
LOCOM	Lower of weighted average cost or current market price
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Moody’s	Moody’s Investors Service
New Jersey ~~Commission~~BPU	New Jersey Board of Public Utilities
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as revenues minus cost of gas, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our condensed consolidated statements of income. Operating margin should not be considered an alternative to, or more meaningful than, operating income, net income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP
OTC	Over-the-counter
Piedmont	Piedmont Natural Gas Company, Inc.
Pivotal Utility	Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PP&E	Property, plant and equipment
PRP	Pipeline replacement program for Atlanta Gas Light
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
~~SFAS~~	~~Statement of Financial Accounting Standards~~
SouthStar	SouthStar Energy Services LLC
VaR	Value at risk is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability
Virginia Natural Gas	Virginia Natural Gas, Inc.
WACOG	Weighted average cost of gas
WNA	Weather normalization adjustment

~~FIN 46 & FIN 46R~~	~~FIN 46, “Consolidation of Variable Interest Entities”~~
~~EITF 99-2~~	~~EITF 99-2, "Accounting for Weather Derivatives"~~
~~FSP EITF 03-6-1~~	~~FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”~~
~~FSP FAS 132(R)-1~~	~~FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets”~~
~~FSP FAS 133-1~~	~~FSP No. FAS 133-1, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133”~~
~~FSP FAS 140-4~~	~~FSP No. FAS 140-4, “Disclosures by Public Entities about Transfers of Financial Assets”~~
~~FSP FAS 157-3~~	~~FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”~~
~~FSP FAS 157-4~~	~~FSP No. FAS 157-4, “Determining Whether a Market Is Not Active and a Transaction Is Not Distressed”~~
~~SFAS 71~~	~~SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”~~
~~SFAS 133~~	~~SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”~~
~~SFAS 141~~	~~SFAS No. 141, “Business Combinations”~~
~~SFAS 157~~	~~SFAS No. 157, “Fair Value Measurements”~~
~~SFAS 160~~	~~SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements”~~
~~SFAS 161~~	~~SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of SFAS 133”~~
~~SFAS 162~~	~~SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”~~
~~SFAS 165~~	~~SFAS No. 165, “Subsequent Events”~~
~~SFAS 166~~	~~SFAS No. 166, “Accounting for Transfers of Financial Assets”~~
~~SFAS 167~~	~~SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”~~
~~SFAS 168~~	~~SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”~~

			As of
In millions, except share data	Sept. 30, 2009		Dec. 31, 2008		Sept. 30, 2008
Current assets
Cash and cash equivalents	$	21	$	16	$	11
Inventories, net (Note 1)		651		663		811
Receivables
Energy marketing receivables (Note 1)		216		549		535
Gas, unbilled and other receivables		145		472		206
Less allowance for uncollectible accounts		16		16		17
Total receivables		345		1,005		724
Derivative financial instruments – current portion (Note 2 and Note 3)		146		207		172
Unrecovered pipeline replacement program costs – current portion (Note 1)		40		41		40
Unrecovered environmental remediation costs – current portion (Note 1)		13		18		20
Other current assets		102		92		162
Total current assets		1,318		2,042		1,940
Long-term assets and other deferred debits
Property, plant and equipment		5,791		5,500		5,377
Less accumulated depreciation		1,761		1,684		1,651
Property, plant and equipment-net		4,030		3,816		3,726
Goodwill		418		418		418
Unrecovered pipeline replacement program costs (Note 1)		169		196		202
Unrecovered environmental remediation costs (Note 1)		142		125		124
Derivative financial instruments (Note 2 and Note 3)		31		38		16
Other		75		75		78
Total long-term assets and other deferred debits		4,865		4,668		4,564
Total assets	$	6,183	$	6,710	$	6,504
Current liabilities
Short-term debt (Note 6)	$	310	$	866	$	769
Energy marketing trade payables (Note 1)		245		539		568
Accounts payable - trade		155		202		181
Accrued expenses		102		113		83
Accrued pipeline replacement program costs – current portion (Note 1)		55		49		43
Customer deposits		43		50		39
Derivative financial instruments – current portion (Note 2 and Note 3)		27		50		34
Accrued environmental remediation liabilities – current portion (Note 1 and Note 7)		21		17		16
Other current liabilities		86		97		89
Total current liabilities		1,044		1,983		1,822
Long-term liabilities and other deferred credits
Long-term debt (Note 6)		1,975		1,675		1,675
Accumulated deferred income taxes		644		571		625
Accumulated removal costs (Note 1)		194		178		176
Accrued pension obligations (Note 4)		187		199		43
Accrued environmental remediation liabilities (Note 1 and Note 7)		109		89		89
Accrued pipeline replacement program costs (Note 1)		100		140		152
Accrued postretirement benefit costs (Note 4)		41		46		19
Derivative financial instruments (Note 2 and Note 3)		4		6		8
Other long-term liabilities and other deferred credits		138		139		142
Total long-term liabilities and other deferred credits		3,392		3,043		2,929
Total liabilities and other deferred credits		4,436		5,026		4,751
Commitments and contingencies (Note 7)
Equity
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,719		1,652		1,724
Noncontrolling interest (Note 5)		28		32		29
Total equity		1,747		1,684		1,753
Total liabilities and equity	$	6,183	$	6,710	$	6,504
See Notes to Condensed Consolidated Financial Statements (Unaudited).

				As of
In millions, except share data	June 30, 2009			December 31, 2008			June 30, 2008
Current assets
Cash and cash equivalents	$	12		$	16		$	19
Inventories, net (Note 1)		532			663			708
Receivables
Energy marketing receivables (Note 1)		276			549			807
Gas, unbilled and other receivables		209			472			258
Less allowance for uncollectible accounts		(19	)		(16	)		(19	)
Total receivables		466			1,005			1,046
Derivative financial instruments – current portion (Note 2 and Note 3)		177			207			107
Unrecovered pipeline replacement program costs – current portion (Note 1)		41			41			37
Unrecovered environmental remediation costs – current portion (Note 1)		14			18			20
Other current assets		74			92			106
Total current assets		1,316			2,042			2,043
Long-term assets and other deferred debits
Property, plant and equipment		5,685			5,500			5,284
Less accumulated depreciation		1,729			1,684			1,621
Property, plant and equipment-net		3,956			3,816			3,663
Goodwill		418			418			420
Unrecovered pipeline replacement program costs (Note 1)		174			196			216
Unrecovered environmental remediation costs (Note 1)		146			125			130
Derivative financial instruments (Note 2 and Note 3)		37			38			25
Other		73			75			94
Total long-term assets and other deferred debits		4,804			4,668			4,548
Total assets	$	6,120		$	6,710		$	6,591
Current liabilities
Short-term debt (Note 6)	$	418		$	866		$	513
Energy marketing trade payables (Note 1)		317			539			927
Accounts payable - trade		167			202			158
Accrued expenses		107			113			106
Deferred natural gas costs (Note 1)		52			25			20
Accrued pipeline replacement program costs – current portion (Note 1)		50			49			48
Customer deposits		48			50			33
Derivative financial instruments – current portion (Note 2 and Note 3)		36			50			112
Accrued environmental remediation liabilities – current portion (Note 1 and Note 7)		19			17			15
Other current liabilities		67			72			47
Total current liabilities		1,281			1,983			1,979
Long-term liabilities and other deferred credits
Long-term debt (Note 6)		1,675			1,675			1,637
Accumulated deferred income taxes		609			571			604
Accumulated removal costs (Note 1)		199			178			175
Accrued pension obligations (Note 4)		187			199			44
Accrued environmental remediation liabilities (Note 1 and Note 7)		114			89			92
Accrued pipeline replacement program costs (Note 1)		113			140			162
Accrued postretirement benefit costs (Note 4)		44			46			21
Derivative financial instruments (Note 2 and Note 3)		3			6			13
Other long-term liabilities and other deferred credits		136			139			144
Total long-term liabilities and other deferred credits		3,080			3,043			2,892
Commitments and contingencies (Note 7)
Equity (Note 5)
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,732			1,652			1,686
Noncontrolling interest		27			32			34
Total equity		1,759			1,684			1,720
Total liabilities and equity	$	6,120		$	6,710		$	6,591
See Notes to Condensed Consolidated Financial Statements (Unaudited).

	Three months ended						Six months ended						Three months ended						Nine months ended
	June 30,						June 30,						September 30,						September 30,
In millions, except per share amounts	2009			2008			2009			2008			2009			2008			2009			2008
Operating revenues	$	377		$	444		$	1,372		$	1,456		$	307		$	539		$	1,679		$	1,995
Operating expenses
Cost of gas		152			275			741			932			99			261			840			1,193
Operation and maintenance		119			114			244			233			115			104			359			337
Depreciation and amortization		39			38			78			74			40			38			118			112
Taxes other than income taxes		12			11			24			23			10			10			34			33
Total operating expenses		322			438			1,087			1,262			264			413			1,351			1,675
Operating income		55			6			285			194			43			126			328			320
Other income		3			3			5			4			2			2			7			6
Interest expense, net		(24	)		(26	)		(49	)		(56	)		(26	)		(29	)		(75	)		(85	)
Earnings (loss) before income taxes		34			(17	)		241			142
Income tax expense (benefit)		13			(7	)		85			47
Net income (loss)		21			(10	)		156			95
Less net income attributable to the noncontrolling interest (Note 5)		1			1			17			17
Net income (loss) attributable to AGL Resources Inc.	$	20		$	(11	)	$	139		$	78
Earnings before income taxes														19			99			260			241
Income tax expense														7			39			92			86
Net income														12			60			168			155
Less net (loss) income attributable to the noncontrolling interest (Note 5)														-			(5	)		17			12
Net income attributable to AGL Resources Inc.													$	12		$	65		$	151		$	143
Per common share data (Note 1)
Basic earnings (loss) per common share attributable to AGL Resources Inc. common shareholders	$	0.26		$	(0.15	)	$	1.81		$	1.02
Diluted earnings (loss) per common share attributable to AGL Resources Inc. common shareholders	$	0.26		$	(0.15	)	$	1.81		$	1.01
Basic earnings per common share attributable to AGL Resources Inc. common shareholders													$	0.16		$	0.85		$	1.97		$	1.87
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders													$	0.16		$	0.85		$	1.97		$	1.87
Cash dividends declared per common share	$	0.43		$	0.42		$	0.86		$	0.84		$	0.43		$	0.42		$	1.29		$	1.26
Weighted-average number of common shares outstanding (Note 1)
Basic		76.7			76.2			76.8			76.2			76.9			76.4			76.7			76.2
Diluted		76.9			76.2			76.9			76.4			77.2			76.6			76.9			76.5

	AGL Resources Inc. Common Shareholders Equity																					AGL Resources Inc. Common Shareholders Equity
	Common stock				Premium on common		Earnings			Accumulated other comprehensive			Treasury			Noncontrolling						Common stock				Premium on common			Earnings			Accumulated other comprehensive			Treasury			Noncontrolling
In millions, except per share amounts	Shares		Amount		stock		reinvested			loss			shares			interest			Total			Shares		Amount		stock			reinvested			loss			shares			interest			Total
Balance as of December 31, 2007		76.4	$	390	$	667	$	680		$	(13	)	$	(63	)	$	47		$	1,708			76.4	$	390	$	667		$	680		$	(13	)	$	(63	)	$	47		$	1,708
Net income		-		-		-		78			-			-			17			95			-		-		-			143			-			-			12			155
Other comprehensive loss		-		-		-		-			(1	)		-			-			(1	)		-		-		-			-			(1	)		-			-			(1	)
Dividends on common stock ($0.84 per share)		-		-		-		(64	)		-			-			-			(64	)
Dividends on common stock ($1.26 per share)																							-		-		-			(96	)		-			3			-			(93	)
Distributions to noncontrolling interest		-		-		-		-			-			-			(30	)		(30	)		-		-		-			-			-			-			(30	)		(30	)
Issuance of treasury shares		0.3		-		-		(3	)		-			11			-			8			0.4		-		(1	)		(4	)		-			12			-			7
Stock-based compensation expense (net of taxes) (Note 5)		-		-		4		-			-			-			-			4
Balance as of June 30, 2008		76.7	$	390	$	671	$	691		$	(14	)	$	(52	)	$	34		$	1,720
Stock-based compensation expense (net of taxes) (Note 1)																							-		-		7			-			-			-			-			7
Balance as of September 30, 2008																							76.8	$	390	$	673		$	723		$	(14	)	$	(48	)	$	29		$	1,753

	June 30		Dec. 31		June 30
In millions	2009		2008		2008
Regulatory assets
Unrecovered PRP costs	$	215	$	237	$	253
Unrecovered ERC		160		143		150
Unrecovered postretirement benefit costs		10		11		11
Unrecovered seasonal rates		-		11		-
Unrecovered natural gas costs		-		19		22
Elizabethtown Gas derivative financial instruments		-		-		35
Other		28		30		28
Total regulatory assets		413		451		499
Associated assets
Elizabethtown Gas derivative financial instruments		21		23		-
Total regulatory and associated assets	$	434	$	474	$	499
Regulatory liabilities
Accumulated removal costs	$	199	$	178	$	175
Deferred natural gas costs		52		25		20
Elizabethtown Gas derivative financial instruments		21		23		-
Deferred seasonal rates		9		-		9
Regulatory tax liability		18		19		19
Unamortized investment tax credit		14		14		15
Other		17		22		20
Total regulatory liabilities		330		281		258
Associated liabilities
PRP costs		163		189		210
ERC		120		96		97
Elizabethtown Gas derivative financial instruments		-		-		35
Total associated liabilities		283		285		342
Total regulatory and associated liabilities	$	613	$	566	$	600

	Sept. 30		Dec. 31		Sept. 30
In millions	2009		2008		2008
Regulatory assets
Unrecovered PRP costs	$	209	$	237	$	242
Unrecovered ERC		155		143		144
Unrecovered postretirement benefit costs		10		11		11
Unrecovered seasonal rates		10		11		10
Unrecovered natural gas costs		-		19		33
Other		27		30		31
Total regulatory assets		411		451		471
Associated assets
Derivative financial instruments		13		23		15
Total regulatory and associated assets	$	424	$	474	$	486
Regulatory liabilities
Accumulated removal costs (1)	$	194	$	178	$	176
Deferred natural gas costs		26		25		14
Derivative financial instruments		13		23		15
Regulatory tax liability		17		19		19
Unamortized investment tax credit		13		14		15
Other		18		22		21
Total regulatory liabilities		281		281		260
Associated liabilities
PRP costs		155		189		195
ERC		118		96		95
Total associated liabilities		273		285		290
Total regulatory and associated liabilities	$	554	$	566	$	550

	Three months ended September 30,
In millions	2009		2008
Denominator for basic earnings per share (1)		76.9		76.4
Assumed exercise of restricted stock, restricted stock units and stock options		0.3		0.2
Denominator for diluted earnings per share		77.2		76.6
(1) Daily weighted-average shares outstanding.

In millions	Carrying amount		Estimated fair value
As of June 30, 2009	$	1,676	$	1,725
As of December 31, 2008		1,676		1,647
As of June 30, 2008		1,638		1,635

	Recurring fair values Natural gas derivative financial instruments
	September 30, 2009					December 31, 2008					September 30, 2008
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Quoted prices in active markets (Level 1)	$	41	$	(78	)	$	52	$	(117	)	$	59	$	(32	)
Significant other observable inputs (Level 2)		115		(17	)		154		(28	)		102		(36	)
Netting of cash collateral		18		64			35		89			26		26
Total carrying value (2)	$	174	$	(31	)	$	241	$	(56	)	$	187	$	(42	)

	Natural gas contracts (in Bcf)								Natural gas contracts (in Bcf)
Hedge designation under SFAS 133	Distribution operations		Retail energy operations		Wholesale services		Consolidated
Hedge designation									Distribution operations		Retail energy operations		Wholesale services		Energy investments		Consolidated
Cash flow		-		4		-		4		-		2		-		2		4
Not designated		17		8		99		124		18		9		36		-		63
Total		17		12		99		128		18		11		36		2		67

	Three months ended June 30, 2009					Six months ended June 30, 2009					Three months ended September 30, 2009					Nine months ended September 30, 2009
In millions	Retail energy operations			Wholesale services		Retail energy operations			Wholesale services		Retail energy operations			Wholesale services		Retail energy operations			Wholesale services
Designated as cash flow hedges under SFAS 133

Designated as cash flow hedges under authoritative guidance related to derivatives and hedging
Natural gas contracts – loss reclassified from OCI into cost of gas for settlement of hedged item	$	(12	)	$	-	$	(16	)	$	-	$	(8	)	$	-	$	(25	)	$	-

Not designated as hedges under SFAS 133:
Not designated as hedges under authoritative guidance related to derivatives and hedging:
Natural gas contracts – fair value adjustments recorded in operating revenues (1)		-			16		-			52		-			8		-			50
Natural gas contracts – fair value adjustments recorded in cost of gas (2)		-			-		(1	)		-		-			-		-			-
Total (losses) gains on derivative instruments	$	(12	)	$	16	$	(17	)	$	52	$	(8	)	$	8	$	(25	)	$	50

In millions	Retail energy operations
Designated as hedges under SFAS 133
Natural gas contracts – expected net loss reclassified from OCI into cost of gas for settlement of hedged item:
Next twelve months	$	(18	)
Thereafter		-
Total	$	(18	)

In millions	Retail energy operations
Designated as hedges under authoritative guidance related to derivatives and hedging
Natural gas contracts – expected net loss reclassified from OCI into cost of gas for settlement of hedged item over next twelve months	$	(11	)

In millions		Three months ended September 30, 2009				Nine months ended September 30, 2009
Elizabethtown Gas recognized losses on its derivative financial instruments reclassified to deferred natural gas costs		$	(10	)		$	(30	)

		As of June 30, 2009													As of September 30, 2009 (2)
In millions	Statements of financial position location (1)	Distribution operations			Retail energy operations			Wholesale services			Consolidated (2)			Statements of financial position location (1)	Distribution operations			Retail energy operations			Wholesale services			Energy investments		Consolidated
Designated as cash flow hedges under SFAS 133:

Designated as cash flow hedges under authoritative guidance related to derivatives and hedging														Designated as cash flow hedges under authoritative guidance related to derivatives and hedging

Asset Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion	$	-		$	13		$	-		$	13		Derivative financial instruments assets and liabilities – current portion	$	-		$	14		$	-		$	-	$	14
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		-			-			-			-		Derivative financial instruments assets and liabilities		-			-			-			1		1
Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		-			(18	)		-			(18	)	Derivative financial instruments assets and liabilities – current portion		-			(8	)		-			-		(8	)
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		-			-			-			-		Derivative financial instruments assets and liabilities		-			-			-			-		-
Total			-			(5	)		-			(5	)			-			6			-			1		7

Not designated as hedges under SFAS 133:
Not designated as hedges under authoritative guidance related to derivatives and hedging:														Not designated as hedges under authoritative guidance related to derivatives and hedging:

Asset Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		20			4			393			417		Derivative financial instruments assets and liabilities – current portion		12			3			353			-		368
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		1			-			63			64		Derivative financial instruments assets and liabilities		1			-			59			-		60
Liability Financial Instruments
Current natural gas contracts	Derivative financial instruments assets and liabilities – current portion		(20	)		(4	)		(368	)		(392	)	Derivative financial instruments assets and liabilities – current portion		(12	)		(4	)		(323	)		-		(339	)
Noncurrent natural gas contracts	Derivative financial instruments assets and liabilities		(1	)		-			(32	)		(33	)	Derivative financial instruments assets and liabilities		(1	)		-			(34	)				(35	)
Total			-			-			56			56				-			(1	)		55			-		54
Total derivative financial instruments		$	-		$	(5	)	$	56		$	51		Total derivative financial instruments	$	-		$	5		$	55		$	1	$	61

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	5,138		$	404
Retail energy operations		315			-
Wholesale services		970			-
Energy investments		353			14
Corporate and intercompany eliminations (2)		(66	)		-
Consolidated AGL Resources Inc.	$	6,710		$	418

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

			Withdrawal schedule (in Bcf)				Withdrawal schedule (in Bcf)
	Salt dome (WACOG $3.65)		Reservoir (WACOG $3.38)		Expected operating revenues (in millions)		Salt dome (WACOG $3.48)		Reservoir (WACOG $3.36)		Expected operating revenues (in millions)
2009
Third quarter		1		7	$	2
Fourth quarter		3		6		12		3		11	$	23
2010
First quarter		-		5		8		-		10		18
Second quarter		-		1		1		-		1		3
Third quarter								-		1		1
Total		4		19	$	23		3		23	$	45

		Three months ended June 30,								Six months ended June 30,								Three months ended September 30,								Nine months ended September 30,
In millions, except per share data	In millions, except per share data	2009		2008			Change			2009		2008			Change			2009		2008			Change			2009		2008		Change
Operating revenues		$	377	$	444		$	(67	)	$	1,372		$	1,456	$	(84	)	$	307	$	539		$	(232	)	$	1,679	$	1,995	$	(316	)
Cost of gas			152		275			(123	)		741			932		(191	)		99		261			(162	)		840		1,193		(353	)
Operating margin (1)			225		169			56			631			524		107			208		278			(70	)		839		802		37
Operating expenses			170		163			7			346			330		16			165		152			13			511		482		29
Operating income			55		6			49			285			194		91			43		126			(83	)		328		320		8
Other income			3		3			-			5			4		1			2		2			-			7		6		1
EBIT (1)			58		9			49			290			198		92			45		128			(83	)		335		326		9
Interest expense, net			24		26			(2	)		49			56		(7	)		26		29			(3	)		75		85		(10	)
Earnings (loss) before income taxes			34		(17	)		51			241			142		99
Income tax expense (benefit)			13		(7	)		20			85			47		38
Net income (loss)			21		(10	)		31			156			95		61
Net income attributable to the noncontrolling interest			1		1			-			17			17		-
Net income (loss) attributable to AGL Resources Inc.		$	20	$	(11	)	$	31		$	139		$	78	$	61
Earnings before income taxes																			19		99			(80	)		260		241		19
Income tax expense																			7		39			(32	)		92		86		6
Net income																			12		60			(48	)		168		155		13
Net (loss) income attributable to the noncontrolling interest																			-		(5	)		(5	)		17		12		5
Net income attributable to AGL Resources Inc.																		$	12	$	65		$	(53	)	$	151	$	143	$	8

Earnings (loss) per common share
Earnings per common share
Basic – attributable to AGL Resources Inc. common shareholders		$	0.26	$	(0.15	)	$	0.41		$	1.81		$	1.02	$	0.79		$	0.16	$	0.85		$	(0.69	)	$	1.97	$	1.87	$	0.10
Diluted – attributable to AGL Resources Inc. common shareholders		$	0.26	$	(0.15	)	$	0.41		$	1.81		$	1.01	$	0.80		$	0.16	$	0.85		$	(0.69	)	$	1.97	$	1.87	$	0.10
Weighted-average number of common shares outstanding
Basic			76.7		76.2			0.5			76.8			76.2		0.6			76.9		76.4			0.5			76.7		76.2		0.5
Diluted			76.9		76.2			0.7			76.9			76.4		0.5			77.2		76.6			0.6			76.9		76.5		0.4


Weather
Heating degree days (1)	Heating degree days (1)																										Heating degree days (1)
		Three months ended June 30,						2009 vs. normal colder			2009 vs. 2008 colder			Six months ended June 30,						2009 vs. normal colder			2009 vs. 2008 colder					Nine months ended September 30,										2009 vs. normal colder				2009 vs. 2008 colder
		Normal		2009		2008		(warmer)			(warmer)		Normal			2009		2008			(warmer)		(warmer)					Normal			2009			2008				(warmer)				(warmer)
Georgia																													1,600			1,621			1,654				1	%			(2	)%
New Jersey																													3,058			3,137			2,918				3	%			8	%
Virginia																													2,083			2,247			1,880				8	%			20	%
Florida			17		21		18		24	%	17	%			349		390		215		12	%		81	%	349				390			215			12	%			81	%
Georgia			152		181		144		19	%	26	%			1,593		1,615		1,654		1	%		(2	)%
Tennessee																													1,824			1,871			1,888				3	%			(1	)%
Maryland			505		473		471		(6	)%	-				3,015		3,085		2,810		2	%		10	%	3,052				3,118			2,828			2	%			10	%
New Jersey			501		473		475		(6	)%	-				3,028		3,100		2,897		2	%		7	%
Tennessee			176		200		167		14	%	20	%			1,816		1,864		1,888		3	%		(1	)%
Virginia			277		256		279		(8	)%	(8	)%			2,077		2,244		1,880		8	%		19	%
(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 2000 through 2009.	(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 2000 through 2009.																										(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 2000 through 2009.

Customers	Three months ended September 30,									Nine months ended September 30,
	2009			2008			% change			2009			2008			% change
Distribution Operations
Average end-use customers (in thousands)
Atlanta Gas Light		1,525			1,536			(0.7	)%		1,556			1,564			(0.5	)%
Elizabethtown Gas		272			272			-			274			273			0.4	%
Virginia Natural Gas		269			268			0.4	%		272			271			0.4	%
Florida City Gas		103			103			-			103			104			(1.0	)%
Chattanooga Gas		60			60			-			61			61			-
Elkton Gas		6			6			-			6			6			-
Total		2,235			2,245			(0.4	)%		2,272			2,279			(0.3	)%
Operation and maintenance expense per customer	$	38		$	32			19	%	$	112		$	106			6	%
EBIT per customer	$	21		$	26			(19	)%	$	106		$	105			1	%

Retail Energy Operations
Average customers in Georgia (in thousands)		496			518			(4	)%		508			529			(4	)%
Market share in Georgia		33	%		34	%		(3	)%		33	%		35	%		(6	)%

Volumes In billion cubic feet (Bcf)	Three months ended September 30,							Nine months ended September 30,
	2009		2008		% change			2009		2008		% change
Distribution Operations
Firm		20		20		-			148		147		1	%
Interruptible		23		24		(4	)%		72		78		(8	)%
Total		43		44		(2	)%		220		225		(2	)%

Retail Energy Operations
Georgia firm		3		3		-			26		27		(4	)%
Ohio and Florida		1		-		100	%		8		3		167	%

Wholesale Services
Daily physical sales (Bcf/day)		2.7		2.6		4	%		2.8		2.5		12	%



	Three months ended							Six months ended
Volumes	June 30,							June 30,
In billion cubic feet (Bcf)	2009		2008		% change			2009		2008		% change
Distribution Operations
Firm		29		29		-			128		127		1	%
Interruptible		23		25		(8	)%		49		54		(9	)%
Total		52		54		(4	)%		177		181		(2	)%

Retail Energy Operations
Georgia firm		5		5		-			23		24		(4	)%
Ohio and Florida		2		1		100	%		7		3		133	%

Wholesale Services
Daily physical sales (Bcf/day)		2.6		2.4		8	%		2.8		2.5		12	%

In millions
Operating margin for second quarter of 2008	$	180
Increased margins from gas storage carrying amounts at Atlanta Gas Light		4
Prior year revision in estimated unbilled natural gas volumes and slightly higher customer growth and usage at Elizabethtown Gas		4
Higher PRP revenues at Atlanta Gas Light		1
Other		1
Operating margin for second quarter of 2009	$	190

In millions
Operating margin for second quarter of 2008	$	24
Higher contributions from the management of storage and transportation assets largely due to declining natural gas prices in 2009 offset by a prior year favorable pipeline rate order true-up		3
Lower operating margins in Ohio and Florida		(1	)
Change in retail pricing plan mix and decrease in average number of customers		(3	)
Operating margin for second quarter of 2009	$	23

In millions
Operating margin for second quarter of 2008	$	18
Decreased operating margin contribution at AGL Networks, primarily as a result of a network expansion project completed in 2008		(7	)
Decreased interruptible margins at Jefferson Island		(1	)
Operating margin for second quarter of 2009	$	10

In millions
Operating expenses for second quarter of 2008	$	163
Increased environmental remediation costs at distribution operations		2
Increased pension and postretirement expenses at distribution operations		2
Increased depreciation expense at distribution operations and energy investments		2
Other		1
Operating expenses for second quarter of 2009	$	170

In millions
Operating margin for six months of 2008	$	428
Increased margins from gas storage carrying amounts at Atlanta Gas Light		7
Higher PRP revenues at Atlanta Gas Light		3
Prior year revision in estimated unbilled natural gas volumes at Elizabethtown Gas		3
All other, net		1
Operating margin for six months of 2009	$	442