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

Note 1 - Accounting Policies and Methods of Application

General

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

The ~~year-end condensed statement~~December 31, 2009 Condensed Statement of ~~financial position~~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~~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~~Condensed Consolidated Financial Statements reflect all adjustments of a normal recurring nature that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. You should read these ~~condensed consolidated financial statements~~Condensed Consolidated Financial Statements in conjunction with our ~~consolidated financial statements~~Consolida ted Financial Statements and related notes included in Item 8 of ~~o ur~~our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 4, 2010.

Due to the seasonal nature of our business, our results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2010 and 2009, and our financial condition as of December 31, 2009, and ~~June~~September 30, 2010 and 2009, 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~~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.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and ~~judgments~~assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience 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 regulatory infrastructure program accruals, ERC ~~liability~~liabilit y accruals, allowance for uncollectible accounts, ~~contingen cies,~~contingencies, pension and postretirement obligations, derivative and hedging activities and provision for income taxes. Our actual results could differ from ~~our~~those 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~~Condensed Consolidated Statements of ~~financial position~~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, 2010, December 31, 2009 and ~~June~~September 30, 2009, the collateral that wholesale services would have 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.

~~Regulatory Assets and Liabilities~~

We have recorded regulatory assets and liabilities in our condensed consolidated statements of financial position in accordance with authoritative guidance related to regulated operations. Our regulatory assets and liabilities, and associated liabilities for our unrecovered regulatory infrastructure program costs, unrecovered ERC and the derivative financial instrument assets and liabilities for Elizabethtown Gas’ hedging program, are summarized in the following table.

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June 30, Dec. 31, June 30,
In millions 2010 2009 2009
Regulatory assets
Unrecovered regulatory infrastructure program costs $ 303 $ 266 $ 215
Unrecovered ERC 164 172 160
Unrecovered postretirement benefit costs 10 10 10
Unrecovered seasonal rates - 11 -
Other 36 27 28
Total regulatory assets 513 486 413
Associated assets
Derivative financial instruments 23 11 21
Total regulatory and associated assets $ 536 $ 497 $ 434
Regulatory liabilities
Accumulated removal costs $ 186 $ 183 $ 199
Deferred natural gas costs 23 30 52
Derivative financial instruments 23 11 21
Regulatory tax liability 16 17 18
Unamortized investment tax credit 12 13 14
Deferred seasonal rates 9 - 9
Other 20 17 17
Total regulatory liabilities 289 271 330
Associated liabilities
Regulatory infrastructure program costs 242 210 163
ERC 128 133 120
Total associated liabilities 370 343 283
Total regulatory and associated liabilities $ 659 $ 614 $ 613
Regulatory Assets and Liabilities

Note 2 – Derivative Financial Instruments

The following table sets forth, by level within the fair value hierarchy, our derivative financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2010, December 31, 2009 and June 30, 2009. As required by the authoritative guidance, derivative financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

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

~~FORWARD-LOOKING STATEMENTS~~The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the notes to the Condensed Consolidated Financial Statements in this quarterly filing, as well as our Annual Report.

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.~~statements within the meaning of the U.S. federal securities laws and are subject to uncertainties and risks. Senior officers and ~~other~~othe r 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 ~~sub ject~~subject to future events, risks and uncertainties, and there are numerous factors - many beyond our control - that could cause our actual results to ~~differ~~vary significantly from our expectations.

Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation including any changes related to climate change; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, unexpected change in project costs, including the cost of funds to finance these projects; the impact of acquisitions and divestitures; direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including 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, 2009, among others, could cause our business, results of operations or financial condition in 2010 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~~undertake no obligation to publicly update ~~these statements to reflect subsequent circumstances~~ or ~~events.~~revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required under U.S. federal securities law.

Overview

We are an energy services holding company whose principal business is the distribution of natural gas through our regulated natural gas distribution business. As of ~~June~~September 30, 2010, our six utilities serve approximately ~~2.3~~2.2 million end-use customers.

We are also involved in several related and complementary businesses, including retail natural gas marketing to end-use customers in Georgia, Ohio and Florida; natural gas asset management and related logistics activities for each of our utilities as well as for non-affiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability underground natural gas storage assets. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services, energy investments and a non-operating corporate segment.

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

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

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

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

Our retail energy operations segment, which consists primarily of SouthStar, uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. Our Sequent subsidiary within our wholesale services segment generally has greater opportunity to capture operating margin due to price volatility as a result of extreme weather. Our energy investments segment’s primary activity is our natural gas storage business, which develops, acquires and operates high-deliverability salt-dome storage assets in the Gulf Coast region of the United States. While this business also can generate additional revenue during times of peak market demand for natural gas storage services, the majority of our storage services ~~are~~ar e covered under medium to long-term contracts with third parties at a fixed market rate. For additional information on our operating segments see Item 1, “Business” of our Annual Report on Form 10-K for the year ended December 31, ~~2009, filed with the SEC on February 4, 2010.~~2009.

Changes in commodity prices subject a significant portion of our operations to earnings variability. Our ~~nonutility~~non-utility businesses principally use physical and financial arrangements to reduce the risks associated with both weather-related seasonal fluctuations in market conditions and changing commodity prices. For more information on our derivative financial instruments see Note 2.

Executive Summary

Regulatory strategy

We continue to actively pursue a regulatory strategy that improves customer service and reduces the lag between our investments in infrastructure and the recovery of those investments through various rate mechanisms.

If our rate design proposals are not approved, we will continue to work cooperatively with our regulators, legislators and others to create a framework that is conducive to our business goals and the interests of our customers and shareholders. For additional information on our regulatory strategy see Item 1, “Business” under the caption “Regulatory Planning” of our Annual Report on Form 10-K for the year ended December 31, ~~2009, filed with the SEC on February 4, 2010.~~2009.

In 2009, Elizabethtown Gas received approval to increase its annual base rates by $3 million and reduce its overall composite depreciation rate from 3.20% to 2.58%, which equates to an annual reduction in depreciation expenses of approximately $5 million. However, such approval from the New Jersey BPU did not address our proposed decoupling rate design but instead established a separate procedural schedule to consider our proposal. We will continue to work with the New Jersey BPU on the proposed decoupling program and evaluate our proposal relative to feedback and comments received from the New Jersey BPU. Based on the process, we could determine that the decoupling proposal no longer meets the needs of our customers and of Elizabethtown Gas, resulting in us delaying our proposal. WeW e expect to reach resolution on our proposed decoupling and ~~en ergy-efficiency~~energy-efficiency programs at Elizabethtown Gas in ~~2010.~~ 2011.

Additionally, effective June 1, 2010, Chattanooga Gas received approval to increase its annual base rates by less than $1 million. Chattanooga Gas also received approval for a one-time $1 million recovery of prior legal expenses.

In 2010, these approved regulatory actions will increase EBIT by approximately $10 million, which is based on the approved new rates for Elizabethtown Gas for all of 2010 and Chattanooga Gas from June 2010 through December 2010. The following provide additional information on our rate cases.

~~Atlanta Gas Light~~ In May 2010, Atlanta Gas Light filed its rate case request with the Georgia Commission, which would ~~increase~~have increased the average annual residential natural gas bill by about 3%. ~~The higher revenues requested in the filing would support ongoing operations and are based on the following:~~

·	~~reset the company's return on equity ($19 million),~~

·	~~fund new customer service initiatives ($13 million),~~

·	~~retain a portion of savings~~In early October 2010, Atlanta Gas Light reduced this request from ~~our acquisitions benefiting Atlanta Gas Light customers ($14 million), and~~

·	~~restructure depreciation expenses ($8 million).~~

~~If approved, these changes totaling~~ $54 million ~~would go into effect~~to $48 million to reflect more current economic conditions.

In October 2010, the Georgia Commission voted and approved an annual increase of $27 million in base rate revenues which will become effective in November ~~2010 and would~~2010. These new rates will be reflected in Atlanta Gas ~~Light's~~Light’s base rate ~~charge~~charges assessed to customers by ~~the Marketers. We anticipate a~~their Marketer. The decision by the Georgia Commission ~~in November 2010.~~

~~Chattanooga~~includes an overall rate of return of 8.10%, a return on equity of 10.75% and a capital structure of 51% common equity. The Georgia Commission also adopted a new acquisition synergy sharing policy that allows Atlanta Gas In May 2010, the Tennessee Authority approved new base rates for Chattanooga Gas, which went into effect on June 1, 2010. These new rates include energy-efficiency and conservation programs, as well as a mechanism to recover lost revenue resulting from these programs, updated depreciation rates that resulted in decreased depreciation expense of $2 million annually, and Light the recovery of ~~approximately $1 million in prior legal expenses that was recognized in the second quarter~~50% of ~~2010. The approved rate adjustment includes a reduction in the authorized return~~net synergy savings achieved on ~~equity from 10.2% to 10.05%. This decoupled rate design is the first such program~~future acquisitions for a ~~utility~~period of ten years. The policy also allows Atlanta Gas Light to recover 25%, or $4 million annually, in ~~Tennessee.~~
acquisition synergy savings it co ntinues to achieve from the 2004 NUI acquisition through December 2015.

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The annual rate increase also includes approximately $10 million in new customer service and safety oriented programs in which Atlanta Gas Light will invest in technology and hire additional employees to support the programs. The decision also restores the standard depreciation methodology used to calculate net salvage value of utility assets resulting in an increase in depreciation expenses of approximately $2 million. The decision also provides for the temporary recovery of the social responsibility fee from the Universal Service Fund. This fee, which is a discount program for low income senior citizens, was previously funded exclusively from customers through a monthy bill surcharge. In total, these approved regulatory actions will result in an annual increase of approximately 1% to the average residential natural gas bill. A final written order is expected to be issued within 30 days, at which time parties to the case have 10 days to file for reconsideration of the decision with the Georgia Commission. While we are still evaluating the impact of the decision, the new rates are not expected to have a material impact to our 2010 results of operations.

Capital projects

We continue to focus aggressively on capital discipline and cost control, while moving ahead with projects and initiatives that we expect will have current and future benefits and provide an appropriate return on invested capital.The following provide updates on some of our larger capital projects.

Atlanta Gas Light The Georgia Commission has approved Atlanta Gas Light’s ~~Strategic Infrastructure Development and Enhancement (STRIDE)~~STRIDE program. As approved, STRIDE is comprised of the ~~on going~~ongoing pipeline replacement program and the new Integrated System Reinforcement Program. The Georgia Commission approved the Integrated System Reinforcement Program’s initial three years’ expenditures estimated at approximately $176 million. The purpose of this program is to upgrade Atlanta Gas Light’s distribution system and liquefied natural gas facilities in Georgia, improve its system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Under STRIDE, Atlanta Gas Light would be ~~required~~re quired to file an updated ten-year forecast of infrastructure requirements along with a new three-year construction plan every three years for review and approval by the Georgia Commission. STRIDE is a new umbrella program that incorporates our existing pipeline replacement program, which was initiated in 1998 and is scheduled to be completed in December 2013.

In January 2010, the Georgia Commission approved the Integrated Customer Growth Program under STRIDE which authorized Atlanta Gas Light to invest up to an additional $45 million of expenditures to extend Atlanta Gas Light’s pipeline facilities to serve customers without pipeline access and create new economic development opportunities in Georgia. The Integrated Customer Growth Program was approved as a three-year pilot program under STRIDE, and the recovery of the approved surcharge, which was extended until 2025.

The following table provides ~~more~~additional information on our expenditures under these programs during the ~~six~~nine months ended ~~June~~September 30, 2010.

In millions
Pipeline replacement program	$	32	$	55
Integrated System Reinforcement Program		4		28
Integrated Customer Growth Program		1		2
Total	$	37	$	85

Elizabethtown Gas The New Jersey BPU has approved an accelerated enhanced infrastructure program for Elizabethtown Gas which began in 2009 and is scheduled to be completed in 2011. This program was created in response to the New Jersey Governor’s request for ~~utilities~~utility companies to assist in the economic recovery by increasing infrastructure investments. A regulatory cost recovery mechanism has been 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 beb e trued-up and any remaining costs not previously collected will be included in base rates. Elizabethtown Gas spent approximately ~~$26~~$41 million in the ~~six~~nine months ended ~~June~~September 30, 2010. For more information on our regulatory infrastructure programs see Note 1 in our consolidated financial statements and ~~relate d~~related notes as filed in Item 8 of our Form 10-K for the year ended December 31, ~~2009, filed with the SEC on February 4, 2010.~~2009.

Golden Triangle Storage Our Golden Triangle Storage project ~~will consist~~consists of a new salt-dome storage facility in the Gulf Coast region of the U.S. ~~with~~designed for 12 Bcf of working natural gas capacity and total cavern capacity of 18 Bcf. The facility potentially can be expanded to a total of five caverns with 38 Bcf of working natural gas storage capacity in the future. ~~It is also expected that~~ Golden Triangle Storage ~~will build an approximately~~completed a nine-mile dual 24” natural gas pipeline ~~to connect~~connecting the storage facility with three interstate and three intrastate pipelines. ~~We expect the~~The first cavern with 6 Bcf of working capacity ~~to be in~~was completed and began commercial service in ~~the third quarter of 2010 and the~~September 2010.The second cavern with an expected 6 Bcf of ~~working~~wor king capacity is expected to be inplaced into commercial service in mid 2012. There have been no material changes to our cost estimate. We have spent approximately ~~$71~~$94 million in capital expenditures for this project in the ~~six~~nine months ended ~~June~~September 30, 2010.

Jefferson Island In June 2010, Jefferson Island filed a permit application with the Louisiana Department of Natural Resources to expand its natural gas storage facility through the addition of two caverns. We anticipate receiving approval ~~by March 31,~~in 2011. The ~~new~~ caverns ~~are expected to take three to five years to construct and will~~would expand the working gas capacity at Jefferson Island from 7.5 Bcf to approximately 19.5 Bcf.

~~Customer growth~~

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Customer growth

We continue to see challenging economic conditions in all of the areas we serve, evidenced by high rates of unemployment and a depressed housing market with high inventories, ~~and~~ significantly reduced new home ~~construction.~~construction and a slow-down in new commercial developments. As a result, we have experienced slight customer losses in our distribution operations and retail energy operations ~~segments, a trend we expect to continue through the remainder of 2010.~~

For the six months ended June 30, 2010, our distribution operations customer loss rate was less than (0.1)%, compared to (0.3)% for the same period last year. Our customer counts continue to be impacted by both slow growth in the residential housing markets and a slow down in new commercial developments.segments. This trend has been offset slightly by customer attrition mitigation strategies at all of our utilities. For the nine months ended September 30, 2010, our distribution operations customer loss rate was (0.1)%, compared to (0.3)% for the same period last year.

~~Additionally, we~~We expect these economic conditions will continue to impact our customers’ household incomes during the upcoming winter heating season, driving the increased potential for lower operating revenues due to customer conservation and higher bad debt expense from customers’ inability to pay their natural gas bills. As a result, we continue to work with regulators and state agencies in each of our jurisdictions to educate customers throughout the year about energy costs in advance of the winter heating season, and to ensure that those customers who qualify receive support through various energy assistance programs.

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We continue to mitigate these current economic conditions through our use of a variety of targeted marketing programs to attract new customers and to retain existing ones. These efforts include working to add residential customers, multifamily complexes and commercial customers who use natural gas for purposes other than space heating, as well as evaluating and launching new natural gas related programs, products and services to enhance customer growth, mitigate customer attrition and increase operating revenues. These programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities.

In addition, we partner with numerous third-party entities such as builders, realtors, plumbers, mechanical contractors, architects and engineers to market the benefits of natural gas appliances and to identify potential retention options early in the process for those customers who might consider converting to alternative fuels. We use analytical predictive models to identify and target these customers who might consider switching from natural gas to other sources of energy in order to retain them as a customer.

We have seen a 2% decline in average customer count in Georgia at SouthStar for the ~~six~~nine months ended ~~June~~September 30, 2010. This reflects some improvement from last year when SouthStar experienced a 4% decline in average customer count. These declines reflect some of the same economic conditions that have affected our utility businesses, as well as a more competitive retail market for natural gas in Georgia.

The Georgia retail natural gas market is currently comprised of nine Marketers, of which SouthStar has the leading market ~~share.~~share, based on the average number of customers. SouthStar’s market share, based on the average number of customers in Georgia, during the ~~six~~nine months ended ~~June~~September 30, 2010 was 33%, which was consistent with its market share in 2009. This stability in SouthStar’s market share reflects an improvement over last year when it experienced a decline from a 35% market share in 2008. Over the last couple of years, increased competition, volatility in natural gas prices and the heavy promotion of fixed price plans by SouthStar’s competitors has resulted in increased pressure on retail natural gas prices charged to its customers. Accordingly, ~~SouthStar’s~~SouthStar ’s residential and commercial customers have been migrating to fixed price plans, which, ~~have~~combined with the increased competition from other Marketers, has impacted SouthStar’s customer growth. In ~~ad dition,~~addition, SouthStar’s operating margin under these fixed price-plans is lower than variable price plans. SouthStar uses hedges for customers who are on fixed price plans to manage its exposure to commodity price risk. While we have continued to experience customers migrating to fixed price plans, we have seen some stabilization in 2010 of the number of customers on fixed price plans as compared to last year. ~~We expect these trends to continue for the remainder of 2010.~~

~~In Ohio, during the second quarter of 2010, SouthStar experienced a decline in customer equivalents as some of the agreements allowing it to supply natural gas to customers in Ohio expired.~~ SouthStar expanded into the Ohio market in 2006, principally through being awarded supply agreements, but has continued its expansion in Ohio through attracting customers using retail choice programs. As the Ohio deregulated market has continued to evolve, we have experienced increased competition with respect to being awarded new supply agreements and being able to attract new retail choice customers. We still believe that Ohio is a growth market for us, but due to the increased competition we will continue to monitor and evaluate other states where natural gas choice programs may offer potential future markets and sources for growth.

Capital market plan

Our capital market plan ~~over the next 6 months~~ includes maintaining our total debt to total capitalization targets between 50% and 60%, and the ~~renewal of our $1 billion Credit Facility, the renewal of the letter of credit agreements which provide credit support for our variable-rate gas facility revenue bonds and~~ refinancing of $300 million in 7.125% senior notes that are set to mature in January 2011.

~~Over the past two years~~In September 2010, we replaced our previous Credit Facility with a number of financial institutions have experienced significant financial distress, resulting in the write-down of assets and the need to raise additional capital. As a result, the cost of credit has increased overall for many companies as financial institutions have required higher returns to be compensated for their own rising costs of capital and additional market risk in an uncertain economy. Due to these significant changes, we expect thenew Credit Facility that supports our commercial paper program. The terms of ~~any renewed facilities or financing arrangements to be different than those under our existing~~the new Credit Facility ~~which was put into place~~includes a $250 million sub-facility for letters of credit. Under the agreement, we may borrow up to $1 billion with an option to increase to $1.25 billion. This Credit Facility matures in ~~2006 when~~September 2013. In October 2010, we remarketed $160 million aggregate principal amount of four series of variable rate gas facilities and industrial development refunding revenue bonds that we had repurchased in June and September 2010 using commercial paper proceeds. The proceeds from the ~~overall cost of credit was much lower on a relative basis. Specifically, we expect most lenders~~remarketing were used to ~~offer credit commitments of a shorter duration than the 5-year term under our existing Credit Facility.~~repay commercial paper borrowings.

~~We have not yet determined the ultimate size of our anticipated new Credit Facility relative to our current $1 billion level; however, we expect to refinance at least $1 billion.~~ For additional information on our Credit Facility and our capital market plan see “Liquidity and Capital Resources” under the caption “Cash Flow from Financing Activities” and “Short-term Debt”.
See also Note 5 to our consolidated financial statements.

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Energy marketing activities

Sequent’s expected natural gas withdrawals from physical salt dome and reservoir storage are presented in the following table along with the operating revenues expected at the time of ~~withdrawal.~~withdrawal for September 2010 and September 2009. Sequent’s expected operating revenues are net of the estimated impact of regulatory profit sharing and reflect the amounts that are realizable in future periods based on its expected inventory withdrawal schedule and forward natural gas prices at ~~June~~September 30, ~~2010.~~2010 and 2009. A portion of Sequent’s storage inventory is economically hedged with futures contracts, which results in realization of a substantially fixed margin, timing notwithstanding.

							Withdrawal schedule
	Withdrawal schedule (in Bcf)				Expected		(in Bcf)					Expected
	Salt dome (WACOG $4.22)		Reservoir (WACOG $4.01)		operating revenues (in millions)		Salt dome (WACOG $3.87)		Reservoir (WACOG $3.92)			operating revenues (in millions)
2010
Third quarter		-		10	$	5
Fourth quarter		2		8		7		3		6		$	1
2011
First quarter		1		11		13		-		17			4
Total		3		29	$	25
Second quarter								-		(1	)		1
Total at Sept. 30, 2010								3		22		$	6
Total at Sept. 30, 2009								3		23		$	45

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Results of Operations

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

(2)	Includes intercompany eliminations.

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

(2)	Includes intercompany eliminations.

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(1)	Includes charges recoverable through rate rider mechanisms.

(2)	In accordance with GAAP, these items are not reflected in our ~~condensed consolidated statements~~Condensed Consolidated Statements of ~~financial position.~~Financial Position.

(3)

Charges recoverable through a natural gas cost recovery mechanism or alternatively billed to Marketers, and includes demand charges associated with Sequent. Also includes SouthStar’s gas natural gas purchase commitments of 159 Bcf at floating gas prices calculated using forward natural gas prices as of ~~June~~September 30, 2010, and are valued at ~~$70~~$38 million.

(4)

Floating rate debt is based on the interest rate as of ~~June~~September 30, 2010, and the maturity of the underlying debt instrument. As of ~~June~~September 30, 2010, we have ~~$40~~$33 million of accrued interest on our ~~condensed consolidated statements~~Condensed Consolidated Statements of ~~financial position~~Financial Position that will be paid over the next 12 months.

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

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·	Regulatory Infrastructure Program Liabilities

·	Environmental Remediation Liabilities

·	Derivatives and Hedging Activities

·	Pension and Other Postretirement Plans

Item 3. Quantitative and Qualitative Disclosures

About Market Risk

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

Our Risk Management Committee (RMC) is responsible for establishing the overall risk management policies and monitoring compliance with, and adherence to, the terms within these policies, including approval and authorization levels and delegation of these levels. Our RMC consists of members of senior management who monitor open natural gas price risk positions and other types of risk, corporate exposures, credit exposures and overall results of our risk management activities. It is chaired by our chief risk officer, who is responsible for ensuring that appropriate reporting mechanisms exist for the RMC to perform its monitoring functions. Our risk management activities and related accounting treatment for our derivative financial instruments are described in further detail in Note 2.2 .

Natural Gas Price Risk

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

SouthStar routinely utilizes various types of derivative financial instruments to mitigate certain natural gas price and weather risk inherent in the natural gas industry. This includes the active management of storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. SouthStar uses these hedging instruments to lock in economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize its exposure to declining operating margins.

The following tables illustrate the change in the net fair value of the derivative financial instruments during the three and six months ended June 30, 2010 and 2009, and provide details of the net fair value of derivative financial instruments outstanding as of June 30, 2010.

Three months ended June 30,
In millions 2010 2009
Net fair value of derivative financial instruments outstanding at beginning of period $ (7 ) $ (22 )
Derivative financial instruments realized or otherwise settled during period 4 17
Change in net fair value of derivative financial instruments 1 -
Net fair value of derivative financial instruments outstanding at end of period (2 ) (5 )
Netting of cash collateral 5 15
Cash collateral and net fair value of derivative financial instruments outstanding at end of period $ 3 $ 10

Six months ended June 30,
In millions 2010 2009
Net fair value of derivative financial instruments outstanding at beginning of period $ 3 $ (17 )
Derivative financial instruments realized or otherwise settled during period (3 ) 18
Change in net fair value of derivative financial instruments (2 ) (6 )
Net fair value of derivative financial instruments outstanding at end of period (2 ) (5 )
Netting of cash collateral 5 15
Cash collateral and net fair value of derivative financial instruments outstanding at end of period $ 3 $ 10

~~Glossary of Key Terms~~

~~Table of Contents~~

~~The sources of SouthStar’s net fair value of its natural gas-related derivative financial instruments at June 30, 2010, are as follows:~~

In millions
Prices actively quoted
(Level 1) (1)

Significant other observable inputs (Level 2) (2)

Mature through 2010 (3)
$ (2 ) $ -

~~(1)~~

~~Valued using NYMEX futures prices.~~

~~(2)~~

Values primarily related to basis transactions that represent the commodity from NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers and were immaterial as of June 30, 2010.

~~(3)~~

~~Excludes cash collateral amounts.~~

SouthStar routinely utilizes various types of financial and other instruments to mitigate certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts and swap agreements. The following tables include the fair values and average values of SouthStar’s derivative instruments as of the dates indicated. SouthStar bases the average values on monthly averages for the six months ended June 30, 2010 and 2009.

Derivative financial instruments average fair values (1) at June 30,

In millions 2010 2009
Asset $ 3 $ 11
Liability 14 28

~~(1) Excludes cash collateral amounts.~~

Derivative financial instruments fair values netted with cash collateral at
In millions
June 30,
2010

Dec. 31,
2009

June 30,
2009

Asset $ 3 $ 21 $ 10
Liability - - -

~~Value at Risk~~ A 95% confidence interval is used to evaluate VaR exposure. A 95% confidence interval means that over the holding period, an actual loss in portfolio value is not expected to exceed the calculated VaR more than 5% of the time. We calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price distribution, price volatility, confidence interval and holding period. Our VaR may not be comparable to a similarly titled measure of another company because, although VaR is a common metric in the energy industry, there is no established industry standard for calculating VaR or for the assumptions underlying such calculations. SouthStar’s portfolio of positions for the six months ended Ju ne 30, 2010 and 2009 had quarterly average 1-day holding period VaRs of less than $100,000 and its high, low and period end 1-day holding period VaR were immaterial.

Wholesale Services Sequent routinely utilizes various types of derivative financial instruments to mitigate certain natural gas price risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts and financial swap agreements.

The following tables include the fair values and average values of Sequent’s derivative financial instruments as of the dates indicated. Sequent bases the average values on monthly averages for the six months ended June 30, 2010 and 2009.

Derivative financial instruments average values (1) at June 30,

In millions 2010 2009
Asset $ 194 $ 176
Liability 39 84

~~(1)~~

~~Excludes cash collateral amounts.~~

Derivative financial instruments fair values netted with cash collateral at
In millions
June 30,
2010

Dec. 31,
2009

June 30,
2009

Asset $ 174 $ 208 $ 183
Liability 37 51 18

Sequent experienced a decrease in the net fair value of its outstanding contracts of $31 million during the six months ended June 30, 2010 and $26 million during the six months ended June 30, 2009, due to changes in the fair value of derivative financial instruments utilized in its energy marketing and risk management activities and contract settlements.

The following tables illustrate the change in the net fair value of Sequent’s derivative financial instruments during the three and six months ended June 30, 2010 and 2009, and provide details of the net fair value of contracts outstanding as of June 30, 2010.

Three months ended June 30,
In millions 2010 2009
Net fair value of derivative financial instruments outstanding at beginning of period $ 84 $ 7
Derivative financial instruments realized or otherwise settled during period 6 33
Change in net fair value of derivative financial instruments (3 ) 16
Net fair value of derivative financial instruments outstanding at end of period 87 56
Netting of cash collateral 50 109
Cash collateral and net fair value of derivative financial instruments outstanding at end of period $ 137 $ 165

~~Glossary of Key Terms~~

~~Table of Contents~~

Six months ended June 30,
In millions 2010 2009
Net fair value of derivative financial instruments outstanding at beginning of period $ 118 $ 82
Derivative financial instruments realized or otherwise settled during period (57 ) (78 )
Change in net fair value of derivative financial instruments 26 52
Net fair value of derivative financial instruments outstanding at end of period 87 56
Netting of cash collateral 50 109
Cash collateral and net fair value of derivative financial instruments outstanding at end of period $ 137 $ 165

~~The sources of Sequent’s net fair value of its natural gas-related derivative financial instruments at June 30, 2010, are as follows:~~

In millions
Prices actively quoted
(Level 1) (1)

Significant other observable inputs
(Level 2) (2)

Mature through
2010 $ (1 ) $ 36
2011 – 2012 (22 ) 67
2013 – 2015 (1 ) 8
Total derivative financial instruments (3)
$ (24 ) $ 111

~~(1)~~

~~Valued using NYMEX futures prices and other quoted sources.~~

~~(2)~~

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

~~(3)~~

~~Excludes cash collateral amounts.~~

~~Value at Risk~~ Sequent’s open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the chief risk officer. Because Sequent generally manages physical gas assets and economically protects its positions by hedging in the futures markets, its open exposure is generally immaterial, permitting Sequent to operate within relatively low VaR limits. Sequent employs daily risk testing, using both VaR and stress testing, to evaluate the risks of its open positions.

Sequent’s management actively monitors open natural gas positions and the resulting VaR. Sequent continues to maintain a relatively matched book, where its total buy volume is close to sell volume with minimal open natural gas price risk. Based on a 95% confidence interval and employing a 1-day holding period for all positions, Sequent’s portfolio of positions for the three and six months ended June 30, 2010 and 2009 had the following VaRs.

Three months ended June 30, Six months ended June 30,
In millions 2010 2009 2010 2009
Period end $ 1.9 $ 2.6 $ 1.9 $ 2.6
Average 1.3 2.2 1.4 2.1
High 2.4 3.1 3.0 3.3
Low 0.8 1.7 0.7 1.3

Energy Investments We use derivative financial instruments to reduce our exposure to the risk of changes ~~with~~in the price of natural gas that will be purchased in future periods for pad gas and additional volumes of gas used to de-water the cavern (de-water gas) during the construction of storage caverns. Pad gas includes volumes of non-working natural gas used to maintain the operational integrity of the caverns. De-water gas is used to remove water from the cavern in anticipation of commercial service and will be sold after completion of de-watering. We also use derivative financial instruments for asset optimization purposes. As

Consolidated The following tables include the fair values and average values of ~~June 30, 2010, these~~our consolidated derivative financial instruments ~~had hedged approximately 4 Bcf~~as of ~~natural gas.~~ the dates indicated. We base the average values on monthly averages for the nine months ended September 30, 2010 and 2009.

	Derivative financial instruments average values (1) at September 30,
In millions	2010		2009
Asset	$	233	$	206
Liability		99		123

(1)	Excludes cash collateral amounts.

	Derivative financial instruments fair values netted with cash collateral at
In millions	Sept. 30, 2010		Dec. 31, 2009		Sept. 30, 2009
Asset	$	269	$	240	$	177
Liability		90		62		31

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, 2010

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-14174

AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)

Georgia	58-2210952
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Ten Peachtree Place NE, Atlanta, Georgia 30309
(Address and zip code of principal executive offices)

404-584-4000
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

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

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

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

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

Class	Outstanding as of ~~July 19,~~October 26, 2010
Common Stock, $5.00 Par Value	~~77,930,719~~78,041,667

AGL Capital	AGL Capital Corporation
AGL Networks	AGL Networks, LLC
Atlanta Gas Light	Atlanta Gas Light Company
Bcf	Billion cubic feet
Chattanooga Gas	Chattanooga Gas Company
Credit Facility	$1.0 billion credit agreement of AGL Capital
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes financing costs, including interest and debt and income tax expense each of which we evaluate on a consolidated level; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, earnings before income taxes, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP
ERC	Environmental remediation costs associated with our distribution operations segment which are generally recoverable through ~~rates mechanisms~~surcharges to customers
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
GNG	Georgia Natural Gas, the name under which SouthStar does business in Georgia
Golden Triangle Storage	Golden Triangle Storage, Inc.
Hampton Roads	Virginia Natural Gas’ pipeline project which connects its northern and southern systems
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
Jefferson Island	Jefferson Island Storage & Hub, LLC
LOCOM	Lower of weighted average cost or current market price
Magnolia	Magnolia Enterprise Holdings, Inc.
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as operating revenues minus cost of gas, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our ~~condensed consolidated statements~~Condensed Consolidated Statements of ~~income.~~Income. Operating margin should not be considered an alternative to, or more meaningful than, operating income as determined in accordance with GAAP
OTC	Over-the-counter
Piedmont	Piedmont Natural Gas
PP&E	Property, plant and equipment
Regulatory Infrastructure Program	Programs that update or expand our distribution systems and liquefied natural gas facilities to improve system reliability and meet operational flexibility and growth. These programs include the pipeline replacement program and ~~STRIDE~~the Strategic Infrastructure Development and Enhancement (STRIDE) program at Atlanta Gas Light and Elizabethtown Gas’ utility infrastructure enhancements program.
S&P	Standard & Poor’s Ratings Services
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
SouthStar	SouthStar Energy Services LLC
~~Tennessee Authority~~	~~Tennessee Regulatory Authority, the state regulatory agency for Chattanooga Gas~~
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 ~~goods~~gas

				As of							As of
In millions		June 30, 2010		Dec. 31, 2009		June 30, 2009			Sept. 30, 2010		Dec. 31, 2009		Sept. 30, 2009
Current assets
Cash and cash equivalents		$	16	$	26	$	12		$	14	$	26	$	21
Inventories, net (Note 1)										668		672		651
Receivables
Energy marketing receivables (Note 1)			520		615		276			453		615		216
Gas, unbilled and other receivables			161		362		209			126		362		145
Less allowance for uncollectible accounts			21		14		19
Less: allowance for uncollectible accounts										19		14		16
Total receivables			660		963		466			560		963		345
Inventories, net (Note 1)			560		672		532
Derivative financial instruments – current portion (Note 1 and Note 2)			160		188		177			212		188		146
Unrecovered regulatory infrastructure program costs – current portion (Note 1)			44		43		41
Unrecovered environmental remediation costs – current portion (Note 1)			8		11		14
Recoverable regulatory infrastructure program costs – current portion (Note 1)										43		43		40
Recoverable environmental remediation costs – current portion (Note 1 and Note 6)										7		11		13
Other current assets			69		97		74			124		97		102
Total current assets			1,517		2,000		1,316			1,628		2,000		1,318
Long-term assets and other deferred debits
Property, plant and equipment			6,150		5,939		5,685			6,139		5,939		5,791
Less accumulated depreciation			1,849		1,793		1,729
Less: accumulated depreciation										1,846		1,793		1,761
Property, plant and equipment-net			4,301		4,146		3,956			4,293		4,146		4,030
Goodwill			418		418		418			418		418		418
Unrecovered regulatory infrastructure program costs (Note 1)			259		223		174
Unrecovered environmental remediation costs (Note 1)			156		161		146
Recoverable regulatory infrastructure program costs (Note 1)										244		223		169
Recoverable environmental remediation costs (Note 1)										154		161		142
Derivative financial instruments (Note 1 and Note 2)			49		52		37			57		52		31
Other			78		74		73			84		74		75
Total long-term assets and other deferred debits			5,261		5,074		4,804			5,250		5,074		4,865
Total assets		$	6,778	$	7,074	$	6,120		$	6,878	$	7,074	$	6,183
Current liabilities
Short-term debt (Note 5 and Note 8)									$	675	$	602	$	310
Energy marketing trade payable (Note 1)		$	599	$	524	$	317			516		524		245
Short-term debt (Note 5)			394		602		418
Current portion of long-term debt (Note 5)			300		-		-			300		-		-
Accounts payable – trade			171		237		167			132		196		129
Accrued expenses			99		132		107			101		132		102
Derivative financial instruments – current portion (Note 1 and Note 2)										80		52		27
Accrued regulatory infrastructure program costs – current portion (Note 1)			67		55		50			65		55		55
Derivative financial instruments – current portion (Note 1 and Note 2)			67		52		36
Accrued environmental remediation liabilities – current portion (Note 1 and Note 6)			16		25		19			21		25		21
Other current liabilities			141		145		167			174		186		155
Total current liabilities			1,854		1,772		1,281			2,064		1,772		1,044
Long-term liabilities and other deferred credits
Long-term debt (Note 5)			1,553		1,974		1,675
Long-term debt (Note 5 and Note 8)										1,514		1,974		1,975
Accumulated deferred income taxes			729		695		609			727		695		644
Accumulated removal costs (Note 1)			186		183		199			187		183		194
Accrued regulatory infrastructure program costs (Note 1)			175		155		113			159		155		100
Accrued pension obligations (Note 3)			146		159		187			147		159		187
Accrued environmental remediation liabilities (Note 1 and Note 6)			123		119		114			116		119		109
Accrued postretirement benefit costs (Note 3)			34		38		44			32		38		41
Derivative financial instruments (Note 1 and Note 2)			8		10		3			10		10		4
Other long-term liabilities and other deferred credits			143		150		136			108		150		138
Total long-term liabilities and other deferred credits			3,097		3,483		3,080			3,000		3,483		3,392
Total liabilities and other deferred credits			4,951		5,255		4,361			5,064		5,255		4,436
Commitments and contingencies (Note 6)
Equity
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized			1,810		1,780		1,732			1,798		1,780		1,719
Noncontrolling interest (Note 4)			17		39		27			16		39		28
Total equity			1,827		1,819		1,759			1,814		1,819		1,747
Total liabilities and equity		$	6,778	$	7,074	$	6,120		$	6,878	$	7,074	$	6,183
See Notes to Condensed Consolidated Financial Statements (Unaudited).	See Notes to Condensed Consolidated Financial Statements (Unaudited).							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	2010			2009			2010			2009			2010			2009			2010			2009
Operating revenues	$	359		$	377		$	1,362		$	1,372		$	346		$	307		$	1,708		$	1,679
Operating expenses
Cost of gas		141			152			712			741			120			99			832			840
Operation and maintenance		119			119			244			244			114			115			358			359
Depreciation and amortization		39			39			79			78			40			40			119			118
Taxes other than income taxes		12			12			26			24			10			10			36			34
Total operating expenses		311			322			1,061			1,087			284			264			1,345			1,351
Operating income		48			55			301			285			62			43			363			328
Other income		-			3			2			5
Other (expense) income														(1	)		2			1			7
Interest expense, net		(26	)		(24	)		(54	)		(49	)		(27	)		(26	)		(81	)		(75	)
Earnings before income taxes		22			34			249			241			34			19			283			260
Income tax expense		8			13			90			85			13			7			103			92
Net income		14			21			159			156			21			12			180			168
Less net income attributable to the noncontrolling interest (Note 4)		-			1			11			17
Less net (loss) income attributable to the noncontrolling interest (Note 4)														(1	)		-			10			17
Net income attributable to AGL Resources Inc.	$	14		$	20		$	148		$	139		$	22		$	12		$	170		$	151
Per common share data (Note 1)
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	0.17		$	0.26		$	1.91		$	1.81		$	0.29		$	0.16		$	2.20		$	1.97
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	0.17		$	0.26		$	1.90		$	1.81		$	0.29		$	0.16		$	2.19		$	1.97
Cash dividends declared per common share	$	0.44		$	0.43		$	0.88		$	0.86		$	0.44		$	0.43		$	1.32		$	1.29
Weighted-average number of common shares outstanding (Note 1)
Basic		77.4			76.7			77.3			76.8			77.5			76.9			77.3			76.7
Diluted		77.8			76.9			77.7			76.9			77.9			77.2			77.7			76.9

	AGL Resources Inc. Shareholders																						AGL Resources Inc. Shareholders
	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 Dec. 31, 2008		76.9	$	390	$	676		$	763		$	(134	)	$	(43	)	$	32		$	1,684			76.9	$	390	$	676		$	763		$	(134	)	$	(43	)	$	32		$	1,684
Net income		-		-		-			139			-			-			17			156			-		-		-			151			-			-			17			168
Other comprehensive loss		-		-		-			-			(3	)		-			(2	)		(5	)		-		-		-			-			-			-			(1	)		(1	)
Dividends on common stock ($0.86 per share)		-		-		-			(66	)		-			(2	)		-			(68	)
Dividends on common stock ($1.29 per share)																								-		-		-			(99	)		-			3			-			(96	)
Distributions to noncontrolling interest (Note 4)		-		-		-			-			-			-			(20	)		(20	)		-		-		-			-			-			-			(20	)		(20	)
Issuance of treasury shares		0.4		-		(6	)		(3	)		-			17			-			8			0.5		-		(6	)		(4	)		-			15			-			5
Stock-based compensation expense (net of tax) (Note 1)		-		-		4			-			-			-			-			4			-		-		7			-			-			-			-			7
Balance as of June 30, 2009		77.3	$	390	$	674		$	833		$	(137	)	$	(28	)	$	27		$	1,759
Balance as of Sept. 30, 2009																								77.4	$	390	$	677		$	811		$	(134	)	$	(25	)	$	28		$	1,747

	June 30,		Dec. 31,		June 30,
In millions	2010		2009		2009
Regulatory assets
Unrecovered regulatory infrastructure program costs	$	303	$	266	$	215
Unrecovered ERC		164		172		160
Unrecovered postretirement benefit costs		10		10		10
Unrecovered seasonal rates		-		11		-
Other		36		27		28
Total regulatory assets		513		486		413
Associated assets
Derivative financial instruments		23		11		21
Total regulatory and associated assets	$	536	$	497	$	434
Regulatory liabilities
Accumulated removal costs	$	186	$	183	$	199
Deferred natural gas costs		23		30		52
Derivative financial instruments		23		11		21
Regulatory tax liability		16		17		18
Unamortized investment tax credit		12		13		14
Deferred seasonal rates		9		-		9
Other		20		17		17
Total regulatory liabilities		289		271		330
Associated liabilities
Regulatory infrastructure program costs		242		210		163
ERC		128		133		120
Total associated liabilities		370		343		283
Total regulatory and associated liabilities	$	659	$	614	$	613

	Sept. 30,		Dec. 31,		Sept. 30,
In millions	2010		2009		2009
Regulatory assets
Recoverable regulatory infrastructure program costs	$	287	$	266	$	209
Recoverable ERC		161		172		155
Recoverable natural gas costs		11		-		-
Recoverable seasonal rates		10		11		10
Recoverable postretirement benefit costs		9		10		10
Other		42		27		27
Total regulatory assets		520		486		411
Associated assets
Derivative financial instruments		30		11		13
Total regulatory and associated assets	$	550	$	497	$	424
Regulatory liabilities
Accumulated removal costs	$	187	$	183	$	194
Derivative financial instruments		30		11		13
Regulatory tax liability		16		17		17
Unamortized investment tax credit		12		13		13
Deferred natural gas costs		9		30		26
Other		23		17		18
Total regulatory liabilities		277		271		281
Associated liabilities
Regulatory infrastructure program costs		224		210		155
ERC		125		133		118
Total associated liabilities		349		343		273
Total regulatory and associated liabilities	$	626	$	614	$	554

		Three months ended June 30,					Three months ended September 30,
In millions		2010		2009			2010		2009
Denominator for basic earnings per share (1)			77.4		76.7			77.5		76.9
Assumed exercise of restricted stock, restricted stock units and stock options			0.4		0.2			0.4		0.3
Denominator for diluted earnings per share			77.8		76.9			77.9		77.2
(1) Daily weighted-average shares outstanding.	(1) Daily weighted-average shares outstanding.					(1) Daily weighted-average shares outstanding.

	Six months ended June 30,					Nine months ended September 30,
In millions	2010		2009			2010		2009
Denominator for basic earnings per share (1)		77.3		76.8			77.3		76.7
Assumed exercise of restricted stock, restricted stock units and stock options		0.4		0.1			0.4		0.2
Denominator for diluted earnings per share		77.7		76.9			77.7		76.9
(1) Daily weighted-average shares outstanding.
(1) Daily weighted-average shares outstanding.					(1) Daily weighted-average shares outstanding.

	Recognition and Measurement
Accounting Treatment	Statement of Financial Position	Income Statement
Cash flow hedge	Recorded at fair value	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings

Not designated as hedges	Recorded at fair value	The gain or loss on the derivative instrument is recognized in earnings
	Elizabethtown ~~Gas'~~Gas’ derivative financial instruments are recorded as a regulatory asset or liability until included in natural gas costs	The gain or loss on these derivative instruments ~~are~~is reflected in natural gas costs and ~~are~~is ultimately included in billings to customers
	Change in fair value of the derivative instrument is recorded as an adjustment to book value	Change in fair value of the derivative instrument is recognized in earnings

	Recurring fair values Derivative financial instruments
	June 30, 2010					December 31, 2009					June 30, 2009
In millions	Assets		Liabilities			Assets (1)		Liabilities			Assets		Liabilities
Quoted prices in active markets (Level 1)	$	34	$	(55	)	$	36	$	(37	)	$	34	$	(105	)
Significant other observable inputs (Level 2)		148		(50	)		172		(52	)		140		(18	)
Netting of cash collateral		27		30			30		27			40		84
Total carrying value (2) (3)	$	209	$	(75	)	$	238	$	(62	)	$	214	$	(39	)

	Recurring fair values Derivative financial instruments
	September 30, 2010					December 31, 2009					September 30, 2009
In millions	Assets (1)		Liabilities			Assets (1)		Liabilities			Assets (1)		Liabilities
Quoted prices in active markets (Level 1)	$	43	$	(91	)	$	36	$	(37	)	$	41	$	(78	)
Significant other observable inputs (Level 2)		193		(59	)		172		(52	)		115		(17	)
Netting of cash collateral		31		60			30		27			18		64
Total carrying value (2) (3)	$	267	$	(90	)	$	238	$	(62	)	$	174	$	(31	)

Natural gas contracts
	As of									As of
In Bcf	June 30, 2010 (1)			Dec. 31, 2009			June 30, 2009			September 30, 2010 (1)			December 31, 2009			September 30, 2009
Hedge designation:
Cash flow		5			5			4			(1	)		5			4
Not designated		244			108			124			208			108			63
Total		249			113			128			207			113			67
Hedge position:
Short		(1,571	)		(1,518	)		(995	)		(1,664	)		(1,518	)		(1,064	)
Long		1,820			1,631			1,123			1,871			1,631			1,131
Net long position		249			113			128			207			113			67

	For the three months ended June 30,							For the six months ended June 30,						For the three months ended September 30,						For the nine months ended September 30,
In millions		2010			2009				2010		2009			2010			2009				2010			2009

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		$	(3	)	$	(12	)	$	(10	)	$	(16	)	$	(3	)	$	(8	)		$	(13	)	$	(25	)

Not designated as hedges under authoritative guidance related to derivatives and hedging
Natural gas contracts – fair value adjustments recorded in operating revenues (1)			(2	)		16			16			52			40			8				63			50
Natural gas contracts – net fair value adjustments recorded in cost of gas (2)			(1	)		-			(3	)		(1	)		(1)			-				(3	)		-
Total gains on derivative instruments		$	(6	)	$	4		$	3		$	35		$	36		$	-			$	47		$	25

In millions	As of June 30, 2010			As of September 30, 2010
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	$	(3	)	$	(5	)
Interest rate swaps – expected net loss to be reclassified from OCI into interest expense as the net loss is amortized over next twelve months (1)		(1	)		(2	)

	Three months ended June 30,						Three months ended September 30,
In millions	2010			2009			2010			2009
Service cost	$	2		$	2		$	3		$	2
Interest cost		7			6			7			7
Expected return on plan assets		(7	)		(8	)		(7	)		(6	)
Amortization of prior service cost		-			-			(1	)		(1	)
Recognized actuarial loss		2			3			3			2
Net pension benefit cost	$	4		$	3		$	5		$	4

	Six months ended June 30,						Nine months ended September 30,
In millions	2010			2009			2010			2009
Service cost	$	5		$	4		$	8		$	6
Interest cost		14			13			21			20
Expected return on plan assets		(15	)		(15	)		(22	)		(21	)
Amortization of prior service cost		(1	)		(1	)		(2	)		(2	)
Recognized actuarial loss		5			5			8			7
Net pension benefit cost	$	8		$	6		$	13		$	10

	As of December 31, 2009
In millions	Consolidated		SouthStar (1)		%	(2)
Current assets	$	2,000	$	238	12	%
Long-term assets and other deferred debits		5,074		9	-
Total assets	$	7,074	$	247	3	%
Current liabilities	$	1,772	$	96	5	%
Long-term liabilities and other deferred credits		3,483		-	-
Equity		1,819		151	8
Total liabilities and equity	$	7,074	$	247	3	%

	As of June 30, 2009
In millions	Consolidated		SouthStar (1)		%	(2)
Current assets	$	1,316	$	140	11	%
Long-term assets and other deferred debits		4,804		9	-
Total assets	$	6,120	$	149	2	%
Current liabilities	$	1,281	$	47	4	%
Long-term liabilities and other deferred credits		3,080		-	-
Equity		1,759		102	6
Total liabilities and equity	$	6,120	$	149	2	%

	As of September 30, 2009
In millions	Consolidated		SouthStar (1)		%	(2)
Current assets	$	1,318	$	148	11	%
Long-term assets and other deferred debits		4,865		10	-
Total assets	$	6,183	$	158	3	%
Current liabilities	$	1,044	$	50	5	%
Long-term liabilities and other deferred credits		3,392		-	-
Equity		1,747		108	6
Total liabilities and equity	$	6,183	$	158	3	%

	Commitments due before December 31,						Commitments due before December 31,
In millions	Total		2010		2011 & thereafter		Total		2010		2011 & thereafter
Standby letters of credit and performance and surety bonds	$	16	$	7	$	9	$	15	$	1	$	14

In millions	Identifiable and total assets (1)			Goodwill
Distribution operations	$	5,230		$	404
Retail energy operations		261			-
Wholesale services		1,168			-
Energy investments		454			14
Corporate and intercompany eliminations (2)		(39	)		-
Consolidated AGL Resources Inc.	$	7,074		$	418

Weather	Weather
Heating degree days (1)	Heating degree days (1)															Heating degree days (1)
		Three months ended June 30,			2010 vs. normal colder		2010 vs. 2009 colder		Six months ended June 30,			2010 vs. normal colder		2010 vs. 2009 colder			Nine months ended September 30,						2010 vs. normal colder			2010 vs. 2009 colder
		Normal	2010	2009	(warmer)		(warmer)		Normal	2010	2009	(warmer)		(warmer)			Normal		2010		2009		(warmer)			(warmer)
Georgia	Georgia	140	70	181	(50	)%	(61	)%	1,646	2,022	1,615	23	%	25	%			1,652		2,022		1,621		22	%		25	%
New Jersey	New Jersey	481	325	473	(32	)%	(31	)%	3,013	2,722	3,100	(10	)%	(12	)%			3,036		2,725		3,137		(10	)%		(13	)%
Virginia	Virginia	270	192	256	(29	)%	(25	)%	2,103	2,221	2,244	6	%	(1	)%			2,107		2,221		2,247		5	%		(1	)%
Florida	Florida	15	1	21	(93	)%	(95	)%	397	743	390	87	%	91	%			397		743		390		87	%		91	%
Tennessee	Tennessee	168	94	200	(44	)%	(53	)%	1,874	2,210	1,864	18	%	19	%			1,881		2,212		1,871		18	%		18	%
Maryland	Maryland	491	375	473	(24	)%	(21	)%	3,009	2,852	3,085	(5	)%	(8	)%			3,036		2,857		3,118		(6	)%		(8	)%
Ohio	Ohio	431	294	433	(32	)%	(32	)%	3,033	3,125	2,985	3	%	5	%			3,074		3,153		3,026		3	%		4	%
(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 2001 through June 30, 2010.
(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 2001 through September 30, 2010.																	(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 2001 through September 30, 2010.

Customers	Customers	Three months ended June 30,									Six months ended June 30,										Three months ended September 30,									Nine months ended September 30,
		2010			2009			% change			2010			2009			% change				2010			2009			% change			2010			2009			% change
Distribution Operations	Distribution Operations
Average end-use customers (in thousands)	Average end-use customers (in thousands)
Atlanta Gas Light	Atlanta Gas Light		1,560			1,565			(0.3	)%		1,564			1,571			(0.4	)%			1,520			1,525			(0.3	)%		1,549			1,556			(0.4	)%
Elizabethtown Gas	Elizabethtown Gas		274			274			-			275			274			0.4	%			274			272			0.7	%		274			274			-
Virginia Natural Gas	Virginia Natural Gas		275			272			1.1	%		276			274			0.7	%			272			269			1.1	%		275			272			1.1	%
Florida City Gas	Florida City Gas		104			103			1.0	%		104			103			1.0	%			103			103			-			104			103			1.0	%
Chattanooga Gas	Chattanooga Gas		62			62			-			62			62			-				60			60			-			62			61			1.6	%
Elkton Gas	Elkton Gas		6			6			-			6			6			-				6			6			-			6			6			-
Total	Total		2,281			2,282			-			2,287			2,290			(0.1	)%			2,235			2,235			-			2,270			2,272			(0.1	)%
Operation and maintenance expense per customer	Operation and maintenance expense per customer	$	38		$	39			(3	)%	$	76		$	75			1	%		$	38		$	38			-	%	$	114		$	112			2	%
EBIT per customer	EBIT per customer	$	30		$	28			7	%	$	90		$	84			7	%		$	25		$	21			19	%	$	115		$	106			8	%

Retail Energy Operations	Retail Energy Operations
Average customers (in thousands)	Average customers (in thousands)
Georgia	Georgia		503			510			(1	)%		505			514			(2	)%			487			496			(2	)%		499			508			(2	)%
Ohio and Florida (1)	Ohio and Florida (1)		71			110			(36	)%		88			104			(15	)%			66			106			(38	)%		81			105			(23	)%
Total	Total		574			620			(7	)%		593			618			(4	)%			553			602			(8	)%		580			613			(5	)%
Market share in Georgia	Market share in Georgia		33	%		33	%		-			33	%		33	%		-				33	%		33	%		-			33	%		33	%		-

(1)	A portion of the Ohio customers represents customer equivalents, which are computed by the actual delivered volumes divided by the expected average customer usage.

(1) A portion of the Ohio customers represents customer equivalents, which are computed by the actual delivered volumes divided by the expected average customer usage.																				(1) A portion of the Ohio customers represents customer equivalents, which are computed by the actual delivered volumes divided by the expected average customer usage.

Volumes	Three months ended June 30,							Six months ended June 30,
In billion cubic feet (Bcf)	2010		2009		% change			2010		2009		% change
Volumes In billion cubic feet (Bcf)															Three months ended September 30,							Nine months ended September 30,
															2010		2009		% change			2010		2009		% change
Distribution Operations
Firm		26		29		(10	)%		148		128		16	%		21		20		5	%		169		148		14	%
Interruptible		22		23		(4	)%		49		49		-			22		23		(4	)%		70		72		(3	)%
Total		48		52		(8	)%		197		177		11	%		43		43		-			239		220		9	%

Retail Energy Operations
Georgia firm		4		5		(20	)%		28		23		22	%		3		3		-			31		26		19	%
Ohio and Florida		1		2		(50	)%		7		7		-			1		1		-			7		8		(13	%)

Wholesale Services
Daily physical sales (Bcf/day)		3.9		2.6		50	%		4.4		2.8		57	%		4.5		2.7		67	%		4.4		2.8		57	%

In millions	Operating margin (1)			Operating expenses		EBIT (1)			Operating margin (1)		Operating expenses			EBIT (1)
2010													��
Distribution operations	$	198		$	130	$	69		$	183	$	128		$	55
Retail energy operations		18			17		1			10		19			(9	)
Wholesale services		(9	)		11		(20	)		26		12			15
Energy investments		12			11		-			6		5			1
Corporate (2)		(1	)		1		(2	)		1		-			(1	)
Consolidated	$	218		$	170	$	48		$	226	$	164		$	61

In millions
EBIT for second quarter of 2009				$	63
EBIT for third quarter of 2009										$	48

Operating margin
Increased revenues from the Hampton Roads pipeline project	$	5					$	6
Increased revenues from Magnolia pipeline project								2
Increased regulatory infrastructure program revenue at Atlanta Gas Light		2						1
Increased revenues from Magnolia pipeline project		1
Increased enhanced infrastructure program revenue at Elizabethtown Gas								1
Increase in operating margin					8						10

Operating expenses
Increased payroll and incentive compensation expenses	$	(2	)				$	(5	)
Increased depreciation expenses		(1	)
Unrecoverable ERC liability recorded in 2009		3
Decreased legal fees		1
Decreased marketing and outside services expenses								2
Other		(1	)					2
Net change in operating expenses					-
Other expense					(2	)
EBIT for second quarter of 2010				$	69
Increase in operating expenses											(1	)
Decrease in other income, primarily from the regulatory allowance for funds used during construction of the Hampton Roads pipeline project at Virginia Natural Gas, which was completed in 2009											(2	)
EBIT for third quarter of 2010										$	55

In millions
EBIT for six months of 2009				$	193
EBIT for nine months of 2009										$	241

Operating margin
Increased revenues from the Hampton Roads pipeline project	$	10					$	16
Increased revenues from Magnolia pipeline project		3						5
Increased regulatory infrastructure program revenue at Atlanta Gas Light		3						3
Increased revenues from new rates and enhanced infrastructure program revenue at Elizabethtown Gas								3
Increased revenues from higher usage at Florida City Gas due to colder weather		2						2
Other		2						1
Increase in operating margin					20						30

Operating expenses
Increased payroll and incentive compensation expenses	$	(6	)				$	(11	)
Increased depreciation expenses		(3	)					(3	)
Unrecoverable ERC liability recorded in 2009		3						3
Decreased marketing and outside services expenses								2
Decreased legal fees		1						1
Other		(1	)					1
Increase in operating expenses					(6	)					(7	)
Other expenses					(2	)
EBIT for six months of 2010				$	205
Decrease in other income, primarily from the regulatory allowance for funds used during construction of the Hampton Roads pipeline project at Virginia Natural Gas, which was completed in 2009											(4	)
EBIT for nine months of 2010										$	260

	Jun. 30, 2010			Dec. 31, 2009			Jun. 30, 2009			Sept. 30, 2010			Dec. 31, 2009			Sept. 30, 2009
Short-term debt		17	%		14	%		11	%		23	%		14	%		8	%
Long-term debt		38			45			43			35			45			49
Total debt		55			59			54			58			59			57
Equity		45			41			46			42			41			43
Total capitalization		100	%		100	%		100	%		100	%		100	%		100	%

					2011 &		2013 &		2015 &						2011 &		2013 &		2015 &
In millions	Total		2010		2012		2014		thereafter		Total		2010		2012		2014		thereafter
Recorded contractual obligations:

Long-term debt	$	1,553	$	-	$	17	$	225	$	1,311	$	1,514	$	-	$	17	$	225	$	1,272
Short-term debt		694		300		394		-		-		975		674		301		-		-
Regulatory infrastructure program costs (1)		242		36		154		52		-		224		18		154		52		-
Environmental remediation liabilities (1)		139		16		58		36		29		137		6		64		38		29
Total	$	2,628	$	352	$	623	$	313	$	1,340	$	2,850	$	698	$	536	$	315	$	1,301

Unrecorded contractual obligations and commitments (2):

Pipeline charges, storage capacity and gas supply (3)	$	2,013	$	280	$	774	$	399	$	560	$	1,930	$	140	$	804	$	418	$	568
Interest charges (4)		964		56		176		156		576		937		27		176		157		577
Operating leases		110		16		45		16		33		93		6		40		16		31
Asset management agreements (5)		25		11		14		-		-		23		6		16		1		-
Standby letters of credit, performance / surety bonds		16		7		8		1		-		15		1		14		-		-
Total	$	3,128	$	370	$	1,017	$	572	$	1,169	$	2,998	$	180	$	1,050	$	592	$	1,176

In millions		Prices actively quoted (Level 1) (1)				Significant other observable inputs (Level 2) (2)
Mature through 2010 (3)		$	(2	)		$	-

	Derivative financial instruments fair values netted with cash collateral at
In millions	June 30, 2010		Dec. 31, 2009		June 30, 2009
Asset	$	3	$	21	$	10
Liability		-		-		-