Edgar Filing: AGL RESOURCES INC

Form 10-Q 3/31/07

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 March 31, 2007

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. (Check one): Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer ¨

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 April 25, 2007
Common Stock, $5.00 Par Value		77,794,028

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended March 31, 2007

TABLE OF CONTENTS

Item Number		Page(s)

	PART I - FINANCIAL INFORMATION	3-30

1	Condensed Consolidated Financial Statements (Unaudited)	3-6
	Condensed Consolidated Balance Sheets	3
	Condensed Consolidated Statements of Income	4
	Condensed Consolidated Statements of Common Shareholders’ Equity	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to Condensed Consolidated Financial Statements	7-15
	Note 1 - Accounting Policies and Methods of Application	7-9
	Note 2 - Risk Management	9
	Note 3 - Regulatory Assets and Liabilities	10
	Note 4 - Employee Benefit Plans	10-11
	Note 5 - Common Shareholders’ Equity	11
	Note 6 - Debt	12
	Note 7 - Commitments and Contingencies	13
	Note 8 - Income Taxes	13
	Note 9 - Segment Information	14-15
2	Management's Discussion and Analysis of Financial Condition and Results of Operations	16-28
	Forward-Looking Statements	16
	Overview	16-17
	Results of Operations	17-24
	AGL Resources	17-19
	Distribution Operations	20
	Retail Energy Operations	21
	Wholesale Services	22-23
	Energy Investments	23-24
	Corporate	24
	Liquidity and Capital Resources	24-27
	Critical Accounting Policies and Estimates	28
	Accounting Developments	28
3	Quantitative and Qualitative Disclosures About Market Risk	28-30
4	Controls and Procedures	30

	PART II - OTHER INFORMATION

1	Legal Proceedings	31
2	Unregistered Sales of Equity Securities and Use of Proceeds	31
6	Exhibits	31

	SIGNATURE	32

PART I - Financial Information Item 1. Financial Statements
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

			As of
In millions, except share data	March 31, 2007		December 31, 2006		March 31, 2006
Current assets
Cash and cash equivalents	$	29	$	20	$	18
Energy marketing receivables		437		505		405
Receivables (less allowance for uncollectible accounts of $19 at March 31, 2007, $15 at Dec. 31, 2006 and $21 at March 31, 2006)		389		375		408
Inventories		382		597		432
Energy marketing and risk management assets		33		159		61
Unrecovered pipeline replacement program costs		27		27		26
Unrecovered environmental remediation costs		26		27		31
Other		71		112		77
Total current assets		1,394		1,822		1,458
Property, plant and equipment
Property, plant and equipment		5,041		4,976		4,831
Less accumulated depreciation		1,571		1,540		1,484
Property, plant and equipment-net		3,470		3,436		3,347
Deferred debits and other assets
Goodwill		420		420		422
Unrecovered pipeline replacement program costs		239		247		273
Unrecovered environmental remediation costs		137		143		157
Other		64		79		79
Total deferred debits and other assets		860		889		931
Total assets	$	5,724	$	6,147	$	5,736
Current liabilities
Energy marketing trade payables	$	509	$	510	$	476
Payables		160		213		148
Accrued expenses		118		120		126
Short-term debt		111		539		472
Customer deposits		42		42		36
Accrued pipeline replacement program costs		37		35		35
Energy marketing and risk management liabilities		28		41		46
Deferred purchased gas adjustment		25		24		24
Accrued environmental remediation costs		11		13		12
Other		60		90		86
Total current liabilities		1,101		1,627		1,461
Accumulated deferred income taxes		580		544		427
Long-term liabilities
Accrued pipeline replacement program costs		193		202		226
Accumulated removal costs		164		162		156
Accrued environmental remediation costs		84		83		84
Accrued pension obligations		81		78		90
Accrued postretirement benefit costs		29		32		54
Other		154		146		162
Total long-term liabilities		705		703		772
Commitments and contingencies (Note 7)
Minority interest		37		42		33
Capitalization
Long-term debt		1,623		1,622		1,458
Common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,678		1,609		1,585
Total capitalization		3,301		3,231		3,043
Total liabilities and capitalization	$	5,724	$	6,147	$	5,736

See Notes to Condensed Consolidated Financial Statements (Unaudited).

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

	Three months ended
	March 31,
In millions, except per share amounts	2007			2006
Operating revenues	$	973		$	1,044
Operating expenses
Cost of gas		595			655
Operation and maintenance		116			117
Depreciation and amortization		35			34
Taxes other than income		11			10
Total operating expenses		757			816
Operating income		216			228
Other income (expense)		1			(2	)
Interest expense, net		(31	)		(30	)
Minority interest		(22	)		(19	)
Earnings before income taxes		164			177
Income taxes		62			67
Net income	$	102		$	110

Basic earnings per common share	$	1.31		$	1.42
Diluted earnings per common share	$	1.30		$	1.41
Cash dividends accrued per common share	$	0.41		$	0.37
Weighted-average number of common shares outstanding
Basic		77.5			77.9
Diluted		77.9			78.2

See Notes to Condensed Consolidated Financial Statements (Unaudited).

AGL RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY (UNAUDITED)

						Premium on						Other			Shares
	Common Stock					common			Earnings			comprehensive			Held in
In millions, except per share amount	Shares			Amount		stock			reinvested			loss			Treasury			Total
Balance as of December 31, 2006		77.7		$	390	$	664		$	601		$	(32	)	$	(14	)	$	1,609
Comprehensive income:
Net income		-			-		-			102			-			-			102
Unrealized loss from hedging activities (net of tax benefit of $3)		-			-		-			-			(5	)		-			(5	)
Total comprehensive income																			97
Dividends on common shares ($0.41 per share)		-			-		-			(32	)		-			-			(32	)
Issuance of treasury shares		0.4			-		(2	)		(3	)		-			13			8
Purchase of treasury shares		(0.2	)		-		-			-			-			(7	)		(7	)
Stock-based compensation expense (net of tax benefit of $1)		-			-		3			-			-			-			3
Balance as of March 31, 2007		77.9		$	390	$	665		$	668		$	(37	)	$	(8	)	$	1,678

See Notes to Condensed Consolidated Financial Statements (Unaudited).

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

	Three months ended
	March 31,
In millions	2007			2006
Cash flows from operating activities
Net income	$	102		$	110
Adjustments to reconcile net income to net cash flow provided by operating activities
Change in risk management assets and liabilities		113			(12	)
Deferred income taxes		40			6
Depreciation and amortization		35			34
Minority interest		22			19
Changes in certain assets and liabilities
Inventories		215			111
Receivables		54			407
Payables		(54	)		(415	)
Other - net		15			24
Net cash flow provided by operating activities		542			284
Cash flows from investing activities
Property, plant and equipment expenditures		(53	)		(47	)
Other		-			5
Net cash flow used in investing activities		(53	)		(42	)
Cash flows from financing activities
Net payments and borrowings of short-term debt		(417	)		(205	)
Dividends paid on common shares		(32	)		(29	)
Distribution to minority interest		(23	)		(22	)
Payments of long-term debt		(11	)		-
Purchase of treasury shares		(7	)		(4	)
Issuance of treasury shares		8			-
Sale of common stock		-			4
Other		2			-
Net cash flow used in financing activities		(480	)		(256	)
Net increase (decrease) in cash and cash equivalents		9			(14	)
Cash and cash equivalents at beginning of period		20			32
Cash and cash equivalents at end of period	$	29		$	18
Cash paid during the period for
Interest	$	32		$	23
Income taxes	$	1		$	12

See Notes to Condensed Consolidated Financial Statements (Unaudited).

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,” or the “company” mean consolidated AGL Resources Inc. and its subsidiaries (AGL Resources).

The year-end condensed balance sheet was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America (GAAP). We have prepared the accompanying unaudited condensed consolidated financial statements under the rules of the Securities and Exchange Commission (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 that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. You should read these condensed consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 7, 2007.

Due to the seasonal nature of our business, our results of operations for the three months ended March 31, 2007 and 2006 and our financial position as of December 31, 2006 and March 31, 2007 and 2006 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.

We currently own a noncontrolling 70% financial interest in SouthStar Energy Services, LLC (SouthStar), and Piedmont Natural Gas Company (Piedmont) owns the remaining 30%. Our 70% interest is noncontrolling because all significant management decisions require approval by both owners. We record the earnings allocated to Piedmont as a minority interest in our consolidated statements of income and we record Piedmont’s portion of SouthStar’s capital as a minority interest in our consolidated balance sheets.

We are the primary beneficiary of SouthStar’s activities and have determined that SouthStar is a variable interest entity as defined by Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities,” as revised in December 2003 (FIN 46R). We determined that SouthStar is a variable interest entity because our equal voting rights with Piedmont are not proportional to our economic obligation to absorb 75% of any losses or residual returns from SouthStar (except those losses and returns related to customers in Ohio and Florida). Earnings related to customers in Ohio and Florida are allocated 70% to us and 30% to Piedmont. In addition, SouthStar obtains substantially all its transportation capacity for delivery of natural gas through our wholly owned subsidiary, Atlanta Gas Light Company (Atlanta Gas Light).

Inventories

For our distribution operations subsidiaries, we record natural gas stored underground at weighted-average cost. For Sequent Energy Management, L.P. (Sequent), SouthStar and Jefferson Island Storage & Hub, LLC (Jefferson Island), we account for natural gas inventory at the lower of weighted-average cost or market (LOCOM).

Sequent, SouthStar and Jefferson Island evaluate the average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the average cost are other than temporary. For any declines considered to be other than temporary, we record adjustments to reduce the weighted-average cost of the natural gas inventory to market price. Sequent, SouthStar and Jefferson Island did not record adjustments in the first quarter of 2007. Sequent recorded a $5 million net adjustment in the first quarter of 2006. SouthStar did not record an adjustment in the first quarter of 2006 and Jefferson Island’s adjustment was immaterial.

Stock-Based Compensation

Effective January 1, 2006, we adopted SFAS 123(R), “Share Based Payment” (SFAS 123R). On January 30, 2007, we issued grants of approximately 664,000 stock options and 124,000 restricted stock units, which will result in the recognition of approximately $2 million of stock-based compensation expense in 2007. 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 5 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

Comprehensive Income

Our comprehensive income includes net income plus other comprehensive income (OCI), which includes other gains and losses affecting shareholders’ equity that GAAP excludes from net income. Such items consist primarily of unrealized gains and losses on certain derivatives designated as cash flow hedges and unfunded pension and postretirement obligations. The following table illustrates our OCI activity.

Three months ended March 31,

In millions	2007			2006
Cash flow hedges:
Net derivative unrealized gains arising during the period (net of $- and $5 in taxes)	$	1		$	7
Less reclassification of realized gains included in income (net of $3 and $3 in taxes)		(6	)		(5	)
Total	$	(5	)	$	2

Earnings per Common Share

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

We derive our potential dilutive common shares by calculating the number of shares issuable under restricted stock, restricted share units and stock options. The future issuance of shares underlying the restricted stock and restricted share units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends upon whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. The following table shows the calculation of our diluted shares, assuming restricted stock and restricted stock units currently awarded under the plan ultimately vest and stock options currently exercisable at prices below the average market prices are exercised.

	Three months ended March 31,
In millions	2007		2006
Denominator for basic earnings per share (1)		77.5		77.9
Assumed exercise of restricted stock, restricted stock units and stock options		0.4		0.3
Denominator for diluted earnings per share		77.9		78.2

(1)	Daily weighted-average shares outstanding.

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 literature or in the development of estimates that impact our financial statements. The most significant estimates include our regulatory accounting, pipeline replacement program (PRP) accruals, environmental liability accruals, allowance for contingencies, pension and postretirement obligations, derivative and hedging activities and provision for income taxes. Our actual results could differ from our estimates.

Accounting Developments

SFAS 157 In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 establishes a framework for measuring fair value and requires expanded disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements. However, it eliminates inconsistencies in the guidance provided in previous accounting pronouncements.

SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including financial statements for an interim period within that fiscal year. All valuation adjustments will be recognized as cumulative-effect adjustments to the opening balance of retained earnings for the fiscal year in which SFAS 157 is initially applied. We are currently evaluating the impact that SFAS 157 will have on our consolidated results of operations, cash flows and financial position.

SFAS 159 In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Liabilities” (SFAS 159), which is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. SFAS 159 establishes a framework to measure fair value for eligible financial assets and liabilities and is intended to reduce earnings volatility. Adoption of SFAS 159 is not required and we currently have no financial assets or liabilities that are eligible for this treatment.

Note 2 - Risk Management

Our risk management activities are monitored by our Risk Management Committee (RMC). The RMC consists of members of senior management and is charged with reviewing and enforcing our risk management activities. Our risk management policies limit the use of derivative financial instruments and physical hedges within pre-defined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following derivative financial instruments and physical hedges to manage commodity price, interest rate and weather risks:

·	forward contracts

·	futures contracts

·	options contracts

·	financial swaps

·	treasury locks

·	weather derivative contracts

·	storage and transportation capacity transactions

There have been no significant changes to our risk management activities, as described in Note 2 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

Note 3 - Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our condensed consolidated balance sheets in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). Our regulatory assets and liabilities, and associated liabilities for our unrecovered PRP costs, unrecovered environmental remediation costs (ERC) and the associated assets and liabilities of our Elizabethtown Gas hedging program are summarized in the table below.

In millions	March 31, 2007		Dec. 31, 2006		March 31, 2006
Regulatory assets
Unrecovered PRP costs	$	266	$	274	$	299
Unrecovered ERC		163		170		188
Unrecovered postretirement benefit costs		12		13		13
Elizabethtown Gas hedging program		-		16		-
Unrecovered seasonal rates		-		11		-
Unrecovered purchased gas adjustment		-		14		-
Other		14		13		8
Total regulatory assets		455		511		508
Associated assets
Elizabethtown Gas hedging program		1		-		3
Total regulatory and associated assets	$	456	$	511	$	511
Regulatory liabilities
Accumulated removal costs	$	164	$	162	$	156
Deferred purchased gas adjustment		25		24		24
Deferred seasonal rates		22		-		23
Regulatory tax liability		22		22		15
Unamortized investment tax credit		17		18		19
Elizabethtown Gas hedging program		1		-		3
Other		14		10		6
Total regulatory liabilities		265		236		246
Associated liabilities
PRP costs		230		237		261
ERC		86		87		87
Elizabethtown Gas hedging program		-		16		-
Total associated liabilities		316		340		348
Total regulatory and associated liabilities	$	581	$	576	$	594

There have been no significant changes to our regulatory assets and liabilities as described in Note 3 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

Note 4 - Employee Benefit Plans

SFAS 158 In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158). We adopted SFAS 158 prospectively on December 31, 2006. SFAS 158 requires that we recognize all obligations related to defined benefit pensions and other postretirement benefits. This statement requires that we quantify the plans’ funding status as an asset or a liability on our consolidated balance sheets.

SFAS 158 requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We are also required to recognize as a component of OCI the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit cost as explained in SFAS No. 87, “Employers’ Accounting for Pensions,” or SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.”

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

	Three months ended
	March 31,
In millions	2007			2006
Service cost	$	2		$	2
Interest cost		6			6
Expected return on plan assets		(8	)		(8	)
Amortization of prior service cost		(1	)		-
Recognized actuarial loss		2			2
Net cost	$	1		$	2

Our employees do not contribute to these retirement plans. We fund the plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the minimum required amount. We calculate the minimum amount of funding using the projected unit credit cost method. The Pension Protection Act (the Act) of 2006 contains new funding requirements for single employer defined benefit pension plans. The Act establishes a 100% funding target for plan years beginning after December 31, 2007. However, a delayed effective date of 2011 may apply if the pension plan meets the following targets: 92% funded in 2008; 94% funded in 2009; and 96% funded in 2010. No contribution is required for the qualified plans in 2007.

Postretirement Benefits The AGL Postretirement Plan covers all eligible AGL Resources employees who were employed as of June 30, 2002, if they reach retirement age while working for us. The state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery. Effective December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law. This act provides for a prescription drug benefit under Medicare (Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

On July 1, 2004, the AGL Postretirement Plan was amended to remove prescription drug coverage for Medicare-eligible retirees effective January 1, 2006.

We sponsor two defined benefit postretirement health care plans for our eligible employees: the AGL Resources Inc. Postretirement Health Care Plan and the NUI Corporation Postretirement Health Care Plan. Eligibility for these benefits is based on age and years of service. The following are the combined cost components of these two postretirement benefit plans for the periods indicated:

	Three months ended
	March 31,
In millions	2007			2006
Service cost	$	-		$	-
Interest cost		1			2
Expected return on plan assets		(1	)		(1	)
Amortization of prior service cost		(1	)		(1	)
Net cost	$	(1	)	$	-

Employee Savings Plan Benefits

We sponsor the Retirement Savings Plus Plan (RSP), a defined contribution benefit plan that allows eligible participants to make contributions to their accounts up to specified limits. Under the RSP, we made matching contributions to participant accounts of $2 million and $2 million in the first quarter of 2007 and 2006, respectively.

We also sponsor the Nonqualified Savings Plan (NSP), an unfunded, nonqualified plan similar to the RSP. The NSP provides an opportunity for eligible employees who could reach the maximum contribution amount in the RSP to contribute additional amounts for retirement savings. Our contributions to the NSP have not been significant in any year.

Note 5 - Common Shareholders’ Equity

Share Repurchase Program

In March 2001, our Board of Directors approved the purchase of up to 600,000 shares of our common stock to be used for issuances under the Officer Incentive Plan. In the quarter ended March 31, 2007, we purchased 7,667 shares. As of March 31, 2007, we had purchased a total of 294,234 shares, leaving 305,766 shares authorized for purchase.

In February 2006, our Board of Directors authorized a plan to purchase up to 8 million shares of our outstanding common stock over a five-year period. These purchases are intended to offset share issuances under our employee and non-employee director incentive compensation plans and our dividend reinvestment and stock purchase plans. Stock purchases under this program may be made in the open market or in private transactions at times and in amounts that we deem appropriate. There is no guarantee as to the exact number of shares that we will purchase, and we can terminate or limit the program at any time. We will hold the purchased shares as treasury shares. As of March 31, 2007, we had repurchased a total of 1,207,800 shares at a weighted-average price of $37.32. During the quarter ended March 31, 2007, we repurchased 180,300 shares at a weighted-average price of $41.06.

Note 6 - Debt

Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies, including state public service commissions, the SEC and the Federal Energy Regulatory Commission (FERC). The following table provides more information on our various securities. Our financing consists of the short and long-term debt indicated in the following table. There have been no significant changes to our debt since December 31, 2006, which was described in Note 7 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

						Outstanding as of:
In millions	Year(s) due		Int. rate (1)			Mar. 31, 2007			Dec. 31, 2006			Mar. 31, 2006
Short-term debt
Commercial paper (2)		2007		5.4	%	$	96		$	508		$	291
Sequent lines of credit (3)		2007		5.7			7			2			25
Pivotal Utility Holdings, Inc. line of credit (4)		2007		5.7			7			17			-
Capital leases		2007		4.9			1			1			1
Current portion of long-term debt		2007		7.0			-			11			-
Notes payable to Trusts		2006		8.0			-			-			155
Total short-term debt (5)				5.4	%	$	111		$	539		$	472
Long-term debt - net of current portion
Senior notes		2011-2034		4.5-7.1	%	$	1,150		$	1,150		$	975
Gas facility revenue bonds, net of unamortized issuance costs		2022-2033		3.6-5.7			199			199			199
Medium-term notes		2012-2027		6.6-9.1			196			196			208
Notes payable to Trusts		2037		8.2			77			77			77
Capital leases		2013		4.9			6			6			6
AGL Capital interest rate swaps		2011		9.0			(5	)		(6	)		(7	)
Total long-term debt (5)				6.1	%	$	1,623		$	1,622		$	1,458

Total debt (5)				6.0	%	$	1,734		$	2,161		$	1,930

(1)	As of March 31, 2007.

(2)	The daily weighted-average interest rates were 5.4% and 4.6% for the three months ended March 31, 2007 and 2006, respectively.

(3)	The daily weighted-average interest rates were 5.7% and 5.1% for the three months ended March 31, 2007 and 2006, respectively.

(4)	The daily weighted-average interest rate was 5.7% for the three months ended March 31, 2007.

(5)	Weighted-average interest rate, including interest rate swaps if applicable and excluding debt issuance and other financing-related costs.

Note 7 - Commitments and Contingencies

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. 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. There were no significant changes to our contractual obligations which were described in Note 8 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006.

Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our expected contingent financial commitments as of March 31, 2007.

	Commitments due before Dec. 31,
In millions		Total		2007		2008 & thereafter
Standby letters of credit and performance and surety bonds	$	14	$	7	$	7

Litigation

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

There have been no significant changes in the Jefferson Island litigation or the estimate of $8 million in incurred unusable costs if the Louisiana Department of Natural Resources was successful in terminating our lease and causing us to cease Jefferson Island’s expansion project, which was described in Note 8 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006. We believe the ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Note 8 - Income Taxes

In July 2006, the FASB issued FIN 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109, Accounting for Income Taxes. The Interpretation addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. We adopted the provisions of FIN 48 on January 1, 2007. At the date of adoption, and as of March 31, 2007, we do not have a liability for unrecognized tax benefits.

We recognize accrued interest and penalties related to unrecognized tax benefits in operating expenses in the condensed consolidated statements of income, which is consistent with the recognition of these items in prior reporting periods. As of January 1, 2007, the company did not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

We file a U.S. federal consolidated income tax return and various state income tax returns. We are no longer subject to income tax examinations by the Internal Revenue Service or any state for years before 2002.

As of March 31, 2007, there are no unrecognized tax benefits and we do not currently anticipate that the total amount of unrecognized tax benefits will significantly increase or decrease by the end of 2007.

Note 9 - Segment Information

Our four operating segments are as follows:

·	Distribution operations consists primarily of:

o	Atlanta Gas Light

o	Chattanooga Gas Company (Chattanooga Gas)

o	Elizabethtown Gas

o	Elkton Gas

o	Florida City Gas

o	Virginia Natural Gas, Inc. (Virginia Natural Gas)

·	Retail energy operations consists of SouthStar

·	Wholesale services consists of Sequent

·	Energy investments consists primarily of:

o	AGL Networks, LLC

o	Jefferson Island

o	Pivotal Propane of Virginia (Pivotal Propane)

o	Golden Triangle Storage, Inc.

We treat corporate, our fifth segment, as a non-operating business segment, and it currently includes AGL Resources, AGL Services Company and the effect of intercompany eliminations. We eliminated intercompany sales for the three months ended March 31, 2007 and 2006 from our condensed consolidated statements of income.

We evaluate segment performance based primarily on the non-GAAP measure of earnings before interest and taxes (EBIT), which includes the effects of corporate expense allocations. EBIT is a non-GAAP measure that includes operating income, other income and minority interest. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated level. We believe 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 we believe is directly relevant to the efficiency of those operations.

You should not consider EBIT an alternative to, or a more meaningful indicator of our operating performance than, operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income and net income for the three months ended March 31, 2007 and 2006 are presented in the following table.

	Three months ended March 31,
In millions	2007			2006
Operating revenues	$	973		$	1,044
Operating expenses		757			816
Operating income		216			228
Other income (expense)		1			(2	)
Minority interest		(22	)		(19	)
EBIT		195			207
Interest expense		(31	)		(30	)
Earnings before income taxes		164			177
Income taxes		62			67
Net income	$	102		$	110

Balance sheet information at December 31, 2006, is as follows:


In millions	Identifiable and total assets (1)		Goodwill
Distribution operations	$	4,565	$	406
Retail energy operations		298		-
Wholesale services		849		-
Energy investments		373		14
Corporate and intercompany eliminations (2)		62		-
Consolidated AGL Resources	$	6,147	$	420

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

(2) Our corporate segment’s assets consist primarily of intercompany eliminations, cash

and cash equivalents and property, plant and equipment

Summarized income statement information, identifiable and total assets, goodwill and property, plant and equipment expenditures as of and for the three months ended March 31, 2007 and 2006 by segment are shown in the following tables.

Three months ended March 31, 2007


In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intercompany eliminations (3)			Consolidated AGL Resources
Operating revenues from external parties	$	592	$	354		$	19	$	9	$	(1	)	$	973
Intercompany revenues (1)		59		-			-		-		(59	)		-
Total operating revenues		651		354			19		9		(60	)		973
Operating expenses
Cost of gas		403		251			-		-		(59	)		595
Operation and maintenance		88		17			9		5		(3	)		116
Depreciation and amortization		29		1			1		1		3			35
Taxes other than income taxes		9		-			-		1		1			11
Total operating expenses		529		269			10		7		(58	)		757
Operating income (loss)		122		85			9		2		(2	)		216
Other income		1		-			-		-		-			1
Minority interest		-		(22	)		-		-		-			(22	)
EBIT	$	123	$	63		$	9	$	2	$	(2	)	$	195

Identifiable and total assets (2)	$	4,524	$	284		$	730	$	375	$	(189	)	$	5,724
Goodwill	$	406	$	-		$	-	$	14	$	-		$	420
Capital expenditures for property, plant and equipment	$	41	$	-		$	1	$	4	$	7		$	53

Three months ended March 31, 2006


In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intercompany eliminations (3)			Consolidated AGL Resources
Operating revenues from external parties	$	596	$	390		$	48	$	10	$	-		$	1,044
Intercompany revenues (1)		44		-			-		-		(44	)		-
Total operating revenues		640		390			48		10		(44	)		1,044
Operating expenses
Cost of gas		395		296			5		2		(43	)		655
Operation and maintenance		85		18			11		5		(2	)		117
Depreciation and amortization		29		1			-		1		3			34
Taxes other than income taxes		8		-			-		-		2			10
Total operating expenses		517		315			16		8		(40	)		816
Operating income (loss)		123		75			32		2		(4	)		228
Other income		-		(2)			-		-		-			(2)
Minority interest		-		(19	)		-		-		-			(19	)
EBIT	$	123	$	54		$	32	$	2	$	(4	)	$	207

Identifiable and total assets (2)	$	4,547	$	308		$	693	$	329	$	(141	)	$	5,736
Goodwill	$	408	$	-		$	-	$	14	$	-		$	422
Capital expenditures for property, plant and equipment	$	33	$	1		$	1	$	1	$	11		$	47

(1)	Intercompany revenues - Wholesale services records its energy marketing and risk management revenue on a net basis. Wholesale services’ total operating revenues include intercompany revenues of $168 million and $176 million for the three months ended March 31, 2007 and 2006, respectively.

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

(3)	Our corporate segment’s assets consist primarily of intercompany eliminations, cash and cash equivalents and property, plant and equipment.

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 Securities and Exchange Commission (SEC), are forward-looking statements. 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," "indicate," "intend," "may," “outlook,” "plan," "predict," "project,” "seek," "should," "target," "will," "would," or similar expressions. 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; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; 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 and general economic conditions; uncertainties about environmental issues and the related impact of such issues; the impact of changes in weather 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 that are 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 “Risk Factors” in Item 1a, “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2006, among others, could cause our business, results of operations or financial condition in 2007 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, and 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 in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia - 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 April 2007, our six utilities serve 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 retail framework for providing gas service to end-use customers in the state of Georgia.

We also engage in natural gas asset management and related logistics activities for our own utilities as well as for nonaffiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability underground natural gas storage assets. We also own and operate a small telecommunications business that constructs and operates conduit and fiber infrastructure within select metropolitan areas. 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 business. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services and energy investments - and a non-operating corporate segment.

For the three months ended March 31, 2007, we derived approximately 95% of our earnings before interest and taxes (EBIT) from our regulated natural gas distribution business and the sale of natural gas to end-use customers primarily in Georgia through SouthStar Energy Services LLC, (SouthStar). The remaining 5% of our EBIT was principally derived from our wholesale services segment.

Distribution Operations - The distribution operations segment is the largest component of our business and includes utilities in six states. These utilities are subject to regulation and oversight by state agencies in each state that 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. These agencies also are charged with establishing mechanisms by which our utilities can earn a reasonable return for our shareholders.

With the exception of our Atlanta Gas Light Company (Atlanta Gas Light) subsidiary in Georgia, earnings in our distribution operations segment can be affected by customer consumption patterns that are a function of weather conditions and price levels for natural gas. Atlanta Gas Light charges rates to its customers primarily as monthly fixed charges. Our non-Georgia jurisdictions have various regulatory mechanisms to provide us with a reasonable opportunity to recover our costs, but they are not direct offsets to the potential impacts on earnings of weather and customer consumption.

Weather conditions directly influence the volumes of natural gas delivered by our utilities. In our New Jersey, Virginia and Tennessee utilities, the tariffs contain weather normalization adjustment (WNA) provisions that are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer than normal and decreasing amounts charged when weather is colder than normal. The WNA is most effective in a reasonable temperature range relative to normal weather using historical averages.

Retail Energy Operations - Our retail energy operations segment consists of SouthStar, the largest marketer of natural gas in Georgia. SouthStar’s operations are sensitive to seasonal weather, natural gas prices, and customer growth and consumption patterns similar to those affecting our utility operations. SouthStar’s retail pricing strategies and use of various hedging strategies, such as futures, options, swaps, weather derivative instruments and other risk management tools, help to ensure retail customer costs are covered to mitigate the potential effect of these issues on its operations and to provide a reasonable profit.

Wholesale Services - Our wholesale services segment, which consists of Sequent Energy Management, L.P. (Sequent), takes advantage of arbitrage opportunities within the gas supply, storage and transportation markets to generate earnings, and its profitability is related to volatility in these markets. Market volatility arises from a number of factors, such as weather fluctuations or the change in supply of, or demand for, natural gas in different regions of the country. Sequent seeks to capture value from the price disparity across geographic locations and various time horizons. In doing so, Sequent also seeks to mitigate the risks associated with this volatility and protect its margin through a variety of risk management and hedging activities.

Energy Investments - Our energy investments segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which operates a high-deliverability salt-dome storage asset in the Gulf Coast region of the United States and is actively pursuing expansion of the existing facility and the development of new salt-dome storage assets in this region. While this business also can generate additional revenue during times of peak market demand for natural gas storage services, the majority of its storage services are covered under medium to long-term contracts at a fixed market rate.

Results of Operations - AGL Resources

Operating Margin and EBIT We evaluate segment performance using the measures of operating margin and EBIT, which includes the effects of corporate expense allocations. EBIT is a non-GAAP measure that includes operating income, other income and expenses and minority interest. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated level. Operating margin is also a non-GAAP measure that is 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 statements of consolidated income.

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

Our operating margin and EBIT are not measures that are considered to be calculated in accordance with accounting principles generally accepted in the United States of America (GAAP). You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our operating margin or EBIT measures may not be comparable to similarly titled measures of other companies.

Seasonality The operating revenues and EBIT of our distribution operations, retail energy operations and wholesale services 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. Occasionally in the summer, Sequent's operating margins are impacted due to peak usage by power generators in response to summer energy demands. 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.

Seasonality also affects the comparison of certain balance sheet items, such as receivables, unbilled revenue, inventories and short-term debt across quarters. However, these items are comparable when reviewing our annual results. Accordingly, we have presented the condensed consolidated balance sheet as of March 31, 2006, to provide comparisons of these items to December 31, 2006, and March 31, 2007.

Hedging Changes in commodity prices subject a significant portion of our operations to earnings variability. Our nonutility businesses principally use physical and financial arrangements to economically hedge the risks associated with both seasonal fluctuations in market conditions and changing commodity prices. In addition, because these economic hedges may not qualify, or are not designated, for hedge accounting treatment, our reported earnings for the wholesale services and retail energy operations segments reflect changes in the fair values of certain derivatives. These values may change significantly from period to period and are reflected as mark-to-market adjustments within our operating margin.

Elizabethtown Gas utilizes certain derivatives in accordance with a directive from the New Jersey Board of Public Utilities (New Jersey Commission) to create a hedging program to hedge the impact of market fluctuations in natural gas prices. These derivative products are marked to market value each reporting period. In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in purchased gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset (loss) or liability (gain), as appropriate, in our condensed consolidated balance sheets.

Revenues We generate nearly all our operating revenues through the sale, distribution and storage of natural gas. We include in our condensed consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period.

First quarter 2007 compared to first quarter 2006

The following table sets forth a reconciliation of our operating margin and EBIT to our operating income and net income, together with other consolidated financial information for the three months ended March 31, 2007 and 2006.

	Three months ended March 31,
In millions, except per share amounts	2007			2006			Change
Operating revenues	$	973		$	1,044		$	(71	)
Cost of gas		595			655			(60	)
Operating margin (1)		378			389			(11	)
Operating expenses		162			161			1
Operating income		216			228			(12	)
Other income (expense)		1			(2	)		3
Minority interest		(22	)		(19	)		3
EBIT (1)		195			207			(12	)
Interest expense		31			30			1
Earnings before income taxes		164			177			(13	)
Income taxes		62			67			(5	)
Net income	$	102		$	110		$	(8	)

Basic earnings per share	$	1.31		$	1.42		$	(0.11	)
Diluted earnings per share	$	1.30		$	1.41		$	(0.11	)
Weighted-average number of common shares outstanding
Basic		77.5			77.9			(0.4	)
Diluted		77.9			78.2			(0.3	)

(1) These are non-GAAP measurements.

Segment information Operating revenues, operating margin and EBIT information for each of our segments are contained in the following table for the three months ended March 31, 2007 and 2006.

In millions	Operating revenues			Operating margin (1)			EBIT(1)
2007
Distribution operations	$	651		$	248		$	123
Retail energy operations		354			103			63
Wholesale services		19			19			9
Energy investments		9			9			2
Corporate (2)		(60	)		(1	)		(2	)
Consolidated	$	973		$	378		$	195
2006
Distribution operations	$	640		$	245		$	123
Retail energy operations		390			94			54
Wholesale services		48			43			32
Energy investments		10			8			2
Corporate (2)		(44	)		(1	)		(4	)
Consolidated	$	1,044		$	389		$	207

(1) These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income

and net income is contained in “Results of Operations - AGL Resources.”

(2) Includes intercompany eliminations.

Our earnings per share and net income for the three months ended March 31, 2007, were lower than the prior year primarily due to lower contribution from our wholesale services business, partially offset by an increase from retail energy operations.

Consolidated EBIT for the first quarter of 2007 decreased by $12 million or 6% from the same period last year, of which $23 million resulted from decreased EBIT at wholesale services. This was partially offset by increased EBIT of $9 million at retail energy operations.

Our operating margin decreased $11 million or 3% from 2006. The following table indicates the significant changes in our operating margin.

In millions
Operating margin for the first quarter of 2006	$	389
Decreased wholesale services commercial activities		(16)
Net change in the fair value of hedges at wholesale services		(13)
Increased operating margin at retail energy operations		9
Wholesale services inventory lower of weighted-average cost or market (LOCOM) adjustments		5
Increased operating margin at distribution operations		3
Increased operating margin at Pivotal Jefferson Island Storage & Hub, LLC (Jefferson Island)		1
Operating margin for the first quarter of 2007	$	378

Wholesale services’ operating margin decreased $24 million due to a $13 million loss in the value of hedge positions and a $16 million reduction in commercial activity due in part to mild weather and deferral of planned storage withdrawals, partially offset by the absence of the prior year’s $5 million LOCOM adjustment to gas inventories. This decrease was offset by increased operating margin at retail energy operations of $9 million due primarily to an increase in average customer usage, an increase in the average number of customers and advancement into the Ohio market. Distribution operations’ operating margin increased $3 million primarily due to customer growth, more normalized weather and higher consumption per customer in 2007 as compared to 2006. Energy investments’ margin increased $1 million due to higher interruptible margins at Jefferson Island.

Operating expenses increased $1 million or 1% from 2006. The following table indicates the significant changes in our operating expenses.

In millions
Operating expenses for first quarter of 2006	$	161
Decreased compensation costs at wholesale services		(1	)
Gain on asset sales in 2006		3
Increased marketing expenses primarily at Atlanta Gas Light		2
Lower bad debt expense at SouthStar		(2	)
Other, net		(1	)
Operating expenses for first quarter of 2007	$	162

Operating expenses increased $4 million at distribution operations and $1 million at energy investments. The increase at distribution operations was primarily due to the gain on asset sales in 2006 which reduced its operating expenses in that year and increased marketing expenses primarily at Atlanta Gas Light. These were offset by $2 million of lower bad debt expense at SouthStar and a decrease of $1 million at wholesale services due to lower compensation costs.

Interest Expense The increase of $1 million or 3% was due primarily to higher short-term interest rates.

	Three months ended March 31,
In millions	2007			2006			Change
Average debt outstanding (1)	$	1,994		$	1,995		$	(1	)
Average rate		6.2	%		6.0	%		0.2	%

(1)	Daily average of all outstanding debt.

Based on $316 million of variable-rate debt, which includes $111 million of our short-term debt, $100 million of variable-rate senior notes and $105 million of variable-rate gas facility revenue bonds outstanding at March 31, 2007, a 100 basis point change in market interest rates from 5.9% to 6.9% would have resulted in an increase in pretax interest expense for the three months ended March 31, 2007, of $3 million.

Income Taxes The decrease in income tax expense of $5 million or 7% for the first quarter of 2007 compared to the same period in 2006 was due to lower corporate earnings in the first quarter of 2007 offset by a slightly higher effective tax rate of 37.9% for 2007 as compared to 37.7% in 2006.

Distribution Operations

Distribution operations includes our six natural gas local distribution utility companies that construct, manage and maintain natural gas pipelines and distribution facilities and serve 2.3 million end-use customers. Our distribution utilities include:

·	Atlanta Gas Light

·	Elizabethtown Gas

·	Virginia Natural Gas, Inc.(Virginia Natural Gas)

·	Florida City Gas

·	Chattanooga Gas Company (Chattanooga Gas)

·	Elkton Gas

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 should generally allow for the recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return on common equity. Rate base generally consists of the original cost of utility plant in service, working capital, inventories and certain other assets; less accumulated depreciation on utility plant in service, net of deferred income tax liabilities and certain other deductions.

We continuously monitor the performance of our utilities to determine whether rates need to be adjusted through the regulatory process. We have long-term fixed rate settlements in our three largest franchises.

Updates The following is a summary of significant developments with regard to our distribution operations segment that have occurred since we filed our 2006 Annual Report on Form 10-K on February 7, 2007.

Collective Bargaining Agreements In February 2007, a collective bargaining agreement representing 21 Chattanooga Gas employees by the Utility Workers Union of America, Local No. 461 was decertified. In April 2007, a collective bargaining agreement representing 8 Elizabethtown Gas employees by the Communications Workers of America, Local No. 1023 was decertified.

As a result, these 29 employees are no longer represented by a bargaining agreement and now fall under our standard human resources pay and benefit plans and policies.

The following table provides operational information for the three months ended March 31, 2007 and 2006.

	2007		2006
Heating degree days					% Colder / (Warmer	)
Florida		264		357	(26	)%
Georgia		1,312		1,393	(6	)%
Maryland		2,503		2,251	11	%
New Jersey		2,594		2,274	14	%
Tennessee		1,513		1,558	(3	)%
Virginia		1,742		1,642	6	%
Throughput in billion cubic feet (Bcf)		125		119	5	%

Results of operations for our distribution operations segment for the three months ended March 31, 2007 and 2006 are shown in the following table.

In millions	2007		2006		Change
Operating revenues	$	651	$	640	$	11
Cost of gas		403		395		8
Operating margin (1)		248		245		3
Operating expenses		126		122		4
Operating income		122		123		(1	)
Other income		1		-		1
EBIT (1)	$	123	$	123	$	-

Metrics
Average end-use customers (in thousands)		2,295		2,279		1	%
Operation and maintenance expenses per customer	$	38	$	37		3	%
EBIT per customer	$	54	$	54		-	%
(1) These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in “Results of Operations - AGL Resources.”

First quarter 2007 compared to first quarter 2006

Operating margin increased $3 million or 1% in the three months ended March 31, 2007, as compared to the same period in 2006. Operating margin at Atlanta Gas Light increased $2 million primarily due to customer growth. Virginia Natural Gas and Elizabethtown Gas each increased $1 million, primarily due to customer growth, reduced customer conservation and slightly colder weather. These increases were offset by a $1 million decrease at Chattanooga Gas due to the rate settlement agreement in December 2006, which resulted in a shift of operating margins from the winter period to summer months.

Operating expenses increased $4 million or 3% in 2007, as compared to the same period in 2006, primarily due to a $3 million gain on the sale of properties in 2006 and increased marketing expenses of $2 million, primarily at Atlanta Gas Light. This was offset by decreased information technology costs.

Retail Energy Operations

Our retail energy operations segment consists of SouthStar, a joint venture owned 70% by us and 30% by Piedmont Natural Gas Company, Inc. (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, Tennessee, North Carolina and South Carolina. During the third quarter of 2006, SouthStar entered into agreements to supply natural gas to customers located in Ohio and Florida starting in the fourth quarter of 2006.

Although our ownership interest in the SouthStar partnership is 70%, the majority of SouthStar's earnings in Georgia are allocated by contract 75% to us and 25% to Piedmont. Earnings related to customers in Ohio and Florida are allocated 70% to us and 30% to Piedmont. We record the earnings allocated to Piedmont as a minority interest in our condensed consolidated statements of income, and we record Piedmont’s portion of SouthStar’s capital as a minority interest in our condensed consolidated balance sheets.

Results of operations for our retail energy operations segment for the three months ended March 31, 2007 and 2006 are shown in the following table.


In millions	2007			2006			Change
Operating revenues	$	354		$	390		$	(36	)
Cost of sales		251			296			(45	)
Operating margin (1)		103			94			9
Operating expenses		18			19			(1	)
Operating income		85			75			10
Other expense		-			2			(2	)
Minority interest (2)		22			19			3
EBIT (1)	$	63		$	54		$	9

Metrics
Average customers (in thousands)		549			536			2	%
Market share in Georgia		36	%		35	%		3	%
Natural gas volumes (Bcf)
Georgia - firm		18.5			17.2			8	%
Georgia - interruptible		5.9			8.3			(29	%)
Ohio and Florida		2.3			-			N/A

(1) These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our

operating income and net income is contained in “Results of Operations - AGL Resources.”

(2) Minority interest adjusts our earnings to reflect our share of SouthStar’s earnings.

Operating margin increased $9 million or 10% for the three months ended March 31, 2007, as compared to the same period last year. This increase was largely driven by approximately an $8 million increase in average customer usage, $3 million from the Ohio market that SouthStar entered into in August of 2006 and $2 million from an increase in the average number of customers. Operating margin was favorably impacted by higher retail price spreads but was largely offset by lower contributions from the optimization of storage and transportation assets and commodity risk management activities. Operating margin was further impacted by approximately $3 million due to weather that was 6% warmer than last year, largely offset by net gains on weather derivatives of approximately $3 million.

Operating expenses decreased $1 million or 5% primarily due to lower bad debt expense of $2 million, offset by a slight increase in depreciation expense due to the implementation of an energy trading and risk management system in the fourth quarter of 2006.

Other expense decreased $2 million due to a $2 million charitable contribution in 2006. Retail energy operations did not make a similar contribution in 2007.

Minority interest increased $3 million as a result of a $10 million increase in operating income in 2007 as compared to 2006.

Wholesale Services

Wholesale services consists of Sequent, our subsidiary involved in asset management and optimization, transportation, storage, producer and peaking services and wholesale marketing. Sequent’s asset management business focuses on capturing economic value from idle or underutilized natural gas assets. These assets are typically amassed by companies via investments in, or contractual rights to, natural gas transportation and storage assets. Margin is typically created in this business by participating in transactions that balance the needs of varying markets and time horizons.

Sequent provides customers with natural gas from the major producing regions and market hubs primarily in the eastern and mid-continental United States. Sequent purchases transportation and storage capacity to meet its delivery requirements and customer obligations in the marketplace. Sequent’s customers benefit from its logistics expertise and ability to deliver natural gas at prices that are advantageous relative to other alternatives available to its customers.

In 2006, Sequent entered into an agreement which should facilitate the expansion of its operations into the western United States and Canada. Sequent continues to work on projects and transactions to extend its operating territory and is entering into agreements with longer tenors, as well as evaluating opportunities to expand its business focus and models.

Updates The following is a summary of significant developments with regard to our wholesale services segment that have occurred since we filed our 2006 Annual Report on Form 10-K on February 7, 2007.

Energy Marketing and Risk Management Activities The tables below illustrate the change in the net fair value of Sequent’s derivative instruments and energy-trading contracts during the three months ended March 31, 2007 and 2006, and sources of the net fair value of contracts outstanding as of March 31, 2007.

In millions	2007			2006
Net fair value of contracts outstanding at beginning of period	$	119		$	(13	)
Contracts realized or otherwise settled during period		(103	)		27
Change in net fair value of contracts		(12	)		6
Net fair value of contracts outstanding at end of period	$	4		$	20

The sources of Sequent’s net fair value at March 31, 2007, are as follows:

In millions	Prices actively quoted			Prices provided by other external sources
Maturity less than one year	$	(8	)	$	6
Maturity 1-2 years		-			1
Maturity greater than three years		-			5
Total net fair value	$	(8	)	$	12

The “Prices actively quoted” category represents Sequent’s positions in natural gas, which are valued exclusively using New York Mercantile Exchange (NYMEX) futures prices. “Prices provided by other external sources” are transactions that represent the cost to transport the commodity from a NYMEX delivery point to the contract delivery point. Sequent’s basis spreads are primarily based on quotes obtained either directly from brokers or through electronic trading platforms.

At March 31, 2007, Sequent’s commodity-related derivative financial instruments represented purchases (long) of 629 Bcf and sales (short) of 580 Bcf, with approximately 91% and 96% scheduled to mature in less than two years and the remaining 9% and 4% in three to nine years, respectively. At March 31, 2007, the fair value of these derivatives was reflected in our condensed consolidated balance sheet as an asset of $29 million and a liability of $25 million.

Storage Inventory Outlook The following graph presents the NYMEX forward natural gas prices as of March 31, 2007 and December 31, 2006, for the period of April 2007 through March 2008, and reflects the prices at which Sequent could buy natural gas at the Henry Hub for delivery in the same time period. The Henry Hub, located in Louisiana, is the largest centralized point for natural gas spot and futures trading in the United States. NYMEX uses the Henry Hub as the point of delivery for its natural gas futures contracts. Many natural gas marketers also use the Henry Hub as their physical contract delivery point or their price benchmark for spot trades of natural gas.

Sequent’s expected withdrawals from physical salt dome and reservoir storage are presented in the table below along with the expected operating margin. Sequent’s expected operating margin is net of the impact of regulatory sharing and reflects the amounts that it would expect to realize in future periods based on the inventory withdrawal schedule and forward natural gas prices at March 31, 2007. Sequent’s storage inventory is fully hedged with futures, which results in an overall locked-in margin, timing notwithstanding. Sequent’s physical salt dome and reservoir volumes are presented in NYMEX equivalent contract units of 10,000 million British thermal units (MMBtu’s).

	Q2 2007		Q3 2007		Q4 2007		Q1 2008		Total
Salt dome		161		-		38		117		316
Reservoir		162		138		257		267		824
Total volumes		323		138		295		384		1,140
Expected operating margin (in millions) (1)	$	3	$	2	$	10	$	13	$	28

(1) This is a non-GAAP measurement.

As of March 31, 2007, the weighted-average cost of natural gas in inventory was $7.25 for physical salt dome storage and $5.52 for physical reservoir storage.

Sequent’s inventory level and pricing as of March 31, 2007, should result in an operating margin contribution of approximately $15 million in 2007 and $13 million in 2008 if all factors were to remain the same. This could change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months. Based upon Sequent’s current projection of year-end storage positions at December 31, 2007, a $1.00 change in the first quarter 2008 forward NYMEX prices would result in a $3 million impact to Sequent’s reported EBIT for the year ending December 31, 2007, after regulatory sharing.

Results of Operations for our wholesale services segment for the three months ended March 31, 2007 and 2006 are as follows:

In millions	2007		2006		Change
Operating revenues	$	19	$	48	$	(29	)
Cost of sales		-		5		(5	)
Operating margin (1)		19		43		(24	)
Operating expenses		10		11		(1	)
EBIT (1)	$	9	$	32	$	(23	)

Metrics
Physical sales volumes (Bcf/day)		2.4		2.1		14	%

(1) These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our

operating income and net income is contained in “Results of Operations - AGL Resources.”

The following table indicates the significant changes in operating margin for the three months ended March 31, 2007 and 2006:

In millions	2007			2006
(Loss) gain on storage hedges	$	(6	)	$	5
Gain on transportation hedges		-			2
Commercial activity		25			41
Inventory LOCOM		-			(5	)
Operating margin	$	19		$	43

Operating margin decreased $24 million or 56%. Approximately $13 million of the decrease was due to changes in forward NYMEX natural gas prices resulting in accounting losses of $6 million on storage hedge positions, compared with hedge gains of $7 million during the prior-year quarter. An additional $16 million was due to lower commercial activity during the quarter as compared to the prior year, due to milder weather and the deferral of planned storage withdrawals to late in 2007 and early 2008. Partially offsetting these reductions was the lack of a LOCOM adjustment in 2007 which had impacted the prior year’s first quarter results by $5 million.

Operating expenses decreased $1 million or 9% primarily due to $3 million lower incentive compensation costs associated with a lower operating margin quarter over quarter partially offset by higher payroll and other expenses.

Energy Investments

Our energy investments segment includes:

·	Jefferson Island

·	Pivotal Propane of Virginia, Inc. (Pivotal Propane)

·	AGL Networks, LLC (AGL Networks)

·	Golden Triangle Storage, Inc. (Golden Triangle Storage)

Updates The following is a summary of significant developments with regard to our energy investments segment that have occurred since we filed our 2006 Annual Report on Form 10-K on February 7, 2007.

Golden Triangle Storage

In December 2006, we announced plans whereby our wholly-owned subsidiary, Golden Triangle Storage, will build an approximate $180 million natural gas storage facility in the Beaumont, Texas area. The project will consist of two underground salt dome storage caverns approximately a half-mile to a mile below ground that will hold about 12 Bcf of working natural gas, or 17 Bcf total storage capacity.

In April 2007, Golden Triangle Storage announced its intention to hold a non-binding open season for service offerings at the proposed facility. The first cavern is projected for full commercial operations in 2011, with the second cavern commencing commercial operations in 2013. The open season is currently being conducted for the project’s entire 12 Bcf of working gas capacity and will conclude in May 2007. In 2007, Golden Triangle Storage plans to apply for regulatory approval from the Federal Energy Regulatory Commission (FERC). The FERC will serve as the lead agency overseeing the participation of a number of other federal, state and local agencies in reviewing and permitting the facility.

Results of operations for our energy investments segment for the three months ended March 31, 2007 and 2006 are shown in the following table.

In millions	2007		2006		Change
Operating revenues	$	9	$	10	$	(1	)
Cost of sales		-		2		(2	)
Operating margin (1)		9		8		1
Operating expenses		7		6		1
EBIT (1)	$	2	$	2	$	-

(1) These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our

operating income and net income is contained in “Results of Operations - AGL Resources.”

Operating margin increased $1 million or 13% largely due to increased revenues at Jefferson Island as compared to the prior year in part due to an increase in interruptible margin opportunities.

Operating expenses increased $1 million or 17% due to development expenses at Golden Triangle Storage.

Corporate

Our corporate segment includes our nonoperating business units, including AGL Services Company (AGSC) and AGL Capital Corporation (AGL Capital).

We allocate substantially all of AGSC’s and AGL Capital’s operating expenses and interest costs to our operating segments in accordance with state regulations. Our corporate segment also includes intercompany eliminations for transactions between our operating business segments. Our EBIT results include the impact of these allocations to the various operating segments.

Results of operations for our corporate segment for the three months ended March 31, 2007 and 2006 are detailed in the following tables. As a nonoperating segment, corporate’s comparative EBIT variances for the indicated periods primarily reflect the relative change in various general and administrative expenses, such as payroll, benefits and incentives, insurance, fleet services and outside services, net of the costs allocated and charged to our operating segments.

In millions	2007			2006			Change
Operating revenues (1)	$	(60	)	$	(44	)	$	(16	)
Cost of sales (1)		(59	)		(43	)		(16	)
Operating margin (1) (2)		(1	)		(1	)		-
Operating expenses		1			3			(2	)
EBIT (2)	$	(2	)	$	(4	)	$	2

(1)	Includes intercompany eliminations.

(2)	These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in “Results of Operations - AGL Resources.”

The following table summarizes the major components of operating expenses.

In millions	2007			2006			Change
Payroll	$	14		$	13		$	1
Benefits and incentives		7			8			(1	)
Outside services		10			11			(1	)
All other expenses		11			13			(2	)
Allocations		(41	)		(42	)		1
Total operating expenses	$	1		$	3		$	(2	)

Liquidity and Capital Resources

To meet our capital and liquidity requirements we rely on operating cash flow; short-term borrowings under our commercial paper program, which is backed by our Credit Facility; borrowings under Sequent’s, SouthStar’s and Pivotal Utility Holdings, Inc. (Pivotal Utility) lines of credit; and borrowings or stock issuances in the long-term capital markets. Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions, the SEC and the FERC. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. The availability of borrowings under our Credit Facility is limited and subject to a total debt-to-capital ratio financial covenant specified within the Credit Facility, which we currently meet. We believe these sources will be sufficient for our working capital needs, debt service obligations and scheduled capital expenditures for the foreseeable future.

We will continue to evaluate the need to increase our available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by the rating agencies and other factors. Additionally, our liquidity and capital resource requirements may change in the future due to a number of other factors, some of which we cannot control. These factors include:

·	the seasonal nature of the natural gas business and our resulting short-term borrowing requirements, which typically peak during colder months

·	increased gas supplies required to meet our customers’ needs during cold weather

·	changes in wholesale prices and customer demand for our products and services

·	regulatory changes and changes in ratemaking policies of regulatory commissions

·	contractual cash obligations and other commercial commitments

·	interest rate changes

·	pension and postretirement funding requirements

·	changes in income tax laws

·	margin requirements resulting from significant increases or decreases in our commodity prices

·	operational risks

·	the impact of natural disasters, including weather

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities. 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. The following table illustrates our expected future contractual obligations as of March 31, 2007.

			Payments due before December 31,
					2008		2010		2012
					&		&		&
In millions	Total		2007		2009		2011		thereafter
Pipeline charges, storage capacity and gas supply (1) (2) (3)	$	1,970	$	410	$	661	$	424	$	475
Long-term debt (4)		1,623		-		2		302		1,319
Interest charges (5)		1,367		75		196		176		920
PRP costs (6)		230		27		82		85		36
Operating leases (7)		160		26		45		34		55
Short-term debt		111		111		-		-		-
ERC (6)		95		8		21		54		12
Total	$	5,556	$	657	$	1,007	$	1,075	$	2,817

(1) Charges recoverable through a purchase gas adjustment mechanism or alternatively billed to marketers selling retail gas in Georgia and certificated by the Georgia Commission. Also includes demand charges associated with Sequent. (2) A subsidiary of NUI Corporation entered into two 20-year agreements for the firm transportation and storage of natural gas during 2003 with annual aggregate demand charges of approximately $5 million. As a result of our acquisition of NUI and in accordance with SFAS No. 141, “Business Combinations,“ we valued the contracts at fair value and established a long-term liability that will be amortized over the remaining lives of the contracts. (3) Amount includes SouthStar gas commodity purchase commitments of 21.6 Bcf at floating gas prices calculated using forward natural gas prices as of March 31, 2007, and is valued at $175 million. (4) Includes $77 million of notes payable to Trusts redeemable in 2007. (5) Floating rate debt is based on the interest rate as of March 31, 2007, and the maturity of the underlying debt instrument. (6) Includes charges recoverable through rate rider mechanisms. (7) We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with SFAS No. 13, “Accounting for Leases.” However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein.

We also have incurred various financial commitments in the normal course of business. Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our expected contingent financial commitments as of March 31, 2007.

			Commitments due before Dec. 31, 2008 &
			Commitments due before Dec. 31, 2008 &
In millions	Total		2007		thereafter
Standby letters of credit, performance/ surety bonds	$	14	$	7	$	7

Cash Flow from Operating Activities In the first quarter of 2007, our net cash flow provided from operating activities was $542 million, an increase of $258 million or 91% from the same period in 2006. This was primarily a result of decreased working capital requirements, principally driven by increased recovery of $104 million of cash for our natural gas inventories. During 2006, due to higher natural gas commodity prices, the cash used for our injections of natural gas inventories were higher than the same period in 2005. Additionally, due to colder weather in 2007 in New Jersey and Maryland, our inventory volumes at March 31, 2007, were approximately 5% lower than the same time last year. In addition, our operating cash flow was favorably impacted by a $125 million change in our energy marketing and risk management assets, primarily related to settlements of Sequent’s derivative positions.

Cash Flow from Investing Activities Our investing activities consisted primarily of property, plant and equipment (PP&E) expenditures. The increase of $6 million or 13% in PP&E expenditures for the three months ended March 31, 2007, compared to the same period last year was primarily due to an increase in pipeline replacement program expenditures. This was offset by decreased information technology expenditures. Additionally in 2006, we received approximately $5 million for the sale of land associated with former operating sites.

Cash Flow from Financing Activities Our financing activities are primarily composed of borrowings and payments of short-term debt, payments of medium-term notes, borrowings of senior notes, distributions to minority interests, cash dividends on our common stock issuances, and purchases and issuances of treasury shares. 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 debt target is 25% to 45% of total debt), as well as the term and interest rate profile of our debt securities. As of March 31, 2007, our variable rate debt was $316 million or 18% of our total debt. This included $111 million of variable-rate short-term debt, $100 million of variable-rate senior notes and $105 million of variable-rate gas facility revenue bonds. As of March 31, 2006, our variable rate debt was 27% of our total debt. The decrease in our variable rate debt from last year was due to reduced working capital requirements which were used to reduce our commercial paper borrowings. During the upcoming inventory injection season, we expect our variable rate debt as a percentage of total debt to increase within our target range.

We also work to maintain or improve our credit ratings on our debt to effectively manage our existing financing costs and enhance our ability to raise additional capital on favorable terms. Factors we consider important in assessing our credit ratings include our balance sheet 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 table below summarizes our credit ratings as of March 31, 2007, and reflects no change from last year.

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

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.

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 Facility’s financial covenant requires 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%. We are currently in compliance with all existing debt provisions and covenants. For more information on our debt, see Note 6 “Debt.”

Short-term Debt Our short-term debt is composed of borrowings under our commercial paper program, lines of credit at Sequent, SouthStar and Pivotal Utility, the current portion of our medium-term notes and the current portion of our capital leases. Our short-term debt financing generally increases between June and December because our payments for natural gas and pipeline capacity are generally made to suppliers prior to the collection of accounts receivable from our customers. We typically reduce short-term debt balances in the spring because a significant portion of our current assets are converted into cash at the end of the winter heating season.

Our total cash and available liquidity under our Credit Facility as of the dates indicated are shown in the following table.

In millions	Mar. 31, 2007		Mar. 31, 2006
Unused availability under the Credit Facility	$	1,000	$	850
Cash and cash equivalents		29		18
Total cash and available liquidity under the Credit Facility	$	1,029	$	868

As of March 31, 2007 and 2006, we had no outstanding borrowings under the Credit Facility. However, the availability of borrowings and unused availability under our Credit Facility is limited and subject to conditions specified within the Credit Facility, which we currently meet. These conditions include:

·	the maintenance of a ratio of total debt to total capitalization of no greater than 70%

·	the continued accuracy of representations and warranties contained in the agreement

Long-term Debt In January 2007, we used proceeds from the sale of commercial paper to redeem $11 million of 7% medium-term notes previously scheduled to mature in January 2015. In 2007, pending approval by the State of New Jersey Board of Public Utilities, we intend to refinance $55 million of our gas facility revenue bonds scheduled to mature in June 2032.

We believe that accomplishing our capitalization objectives and maintaining sufficient cash flow are necessary to maintain our investment-grade credit ratings and to allow us access to capital at reasonable costs. The components of our capital structure, as of the dates indicated, are summarized in the following table:

In millions	March 31, 2007				December 31, 2006				March 31, 2006
Short-term debt	$	110	3	%	$	527	14	%	$	316	9	%
Current portion of long-term debt		1	-			12	-			156	4
Long-term debt (1)		1,623	48			1,622	43			1,458	42
Total debt		1,734	51			2,161	57			1,930	55
Common shareholders’ equity		1,678	49			1,609	43			1,585	45
Total capitalization	$	3,412	100	%	$	3,770	100	%	$	3,515	100	%

(1)	Net of interest rate swaps.

Critical Accounting Policies and Estimates

The preparation of our financial statements 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 base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates on an ongoing basis, and our actual results may differ from these estimates. Our critical accounting policies used in the preparation of our condensed consolidated financial statements include the following:

·	Pipeline Replacement Program

·	Environmental Remediation Liabilities

·	Derivatives and Hedging Activities

·	Contingencies

·	Pension and Other Postretirement Plans

·	Income Taxes

Each of our critical accounting policies and estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. There have been no significant changes to our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006.

Accounting Developments

For information regarding accounting developments, see "Note 1 - Accounting Policies and Methods of Application."

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to risks associated with commodity prices, interest rates and credit. Commodity price risk is defined as the potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity. 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 activities and related accounting treatments are described in further detail in Note 2, “Risk Management. “

Commodity Price Risk

We employ a systematic approach to evaluating and managing the risks associated with our contracts related to wholesale marketing and risk management, including Value at Risk (VaR). A 95% confidence interval is used to evaluate our exposures. A 95% confidence interval means there is a 5% probability that the actual change in portfolio value will be greater than the calculated VaR value over the holding period. We currently use a 1-day holding period to evaluate our VaR exposure, and we calculate VaR based on the variance-covariance technique. Additionally, our calculation requires us to make a number of assumptions, regarding matters such as prices, volatilities, and positions. 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 are no established industry standards for calculating VaR or for the assumptions underlying such calculations.

Retail Energy Operations SouthStar’s use of derivatives is governed by a risk management policy, created and monitored by its risk management committee, which prohibits the use of derivatives for speculative purposes. A 95% confidence interval is used to evaluate its VaR. SouthStar’s portfolio of positions for the three months ended March 31, 2007 and 2006 had a $0.1 million quarterly average 1-day holding period VaR, and its high, low and period end 1-day holding period VaR was immaterial.

SouthStar generates operating margin from the active management of storage positions through a variety of hedging transactions and derivative instruments aimed at managing exposures arising from changing commodity prices. SouthStar uses these hedging instruments to lock in economic margins (as spreads between wholesale and retail commodity prices widen between periods) and thereby minimize its exposure to declining operating margins.

Wholesale Services Sequent routinely utilizes various types of financial and other instruments to mitigate certain commodity price risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter 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 our energy marketing and risk management assets and liabilities as of March 31, 2007, December 31, 2006 and March 31, 2006. We base the average values on monthly averages for the three months ended March 31, 2007 and 2006.

	Average values at March 31,
In millions		2007		2006
Asset	$	67	$	85
Liability		23		60

	Fair Values at
In millions	March 31, 2007		Dec. 31, 2006		March 31, 2006
Asset	$	29	$	133	$	66
Liability		25		14		46

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 commodity positions and the resulting VaR. Sequent continues to maintain a relatively matched book, where its total buy volume is close to sell volume. Based on a 95% confidence interval and employing a 1-day holding period for all positions, Sequent’s portfolio of positions for the three months ended March 31, 2007 and 2006 had the following 1-day holding period VaRs.

In millions	2007		2006
Period end	$	1.4	$	0.9
Average		1.4		0.9
High		2.1		1.9
Low		0.9		0.7

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. To facilitate the achievement of desired fixed-rate to variable-rate debt ratios, AGL Capital entered into interest rate swaps whereby it agreed to exchange fixed-rate debt to floating-rate debt. The swaps exchanged, at specified intervals, the difference between fixed and variable amounts calculated by reference to agreed-on notional principal amounts. These swaps are designated to hedge the fair values of $100 million of the $300 million Senior Notes due in 2011.

Credit Risk

Wholesale Services Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. Sequent also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Sequent is engaged in more than one outstanding derivative transaction with the same counterparty and it has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Sequent’s credit risk. Sequent also uses other netting agreements with certain counterparties with whom it conducts significant transactions.

Master netting agreements enable Sequent to net certain assets and liabilities by counterparty. Sequent also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. Additionally, Sequent may require counterparties to pledge additional collateral when deemed necessary. Sequent conducts credit evaluations and obtains appropriate internal approvals for its counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, Sequent requires credit enhancements by way of guaranty, cash deposit or letter of credit for counterparties that do not meet the minimum ratings threshold.

Sequent, which provides services to Marketers and utility and industrial customers, also has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. As of March 31, 2007, Sequent’s top 20 counterparties represented approximately 56% of the total counterparty exposure of $291 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures.

To arrive at the weighted-average credit rating, each counterparty’s assigned internal rating is multiplied by the counterparty’s credit exposure and summed for all counterparties. That sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. The following tables show Sequent’s commodity receivable and payable positions as of March 31, 2007, December 31, 2006 and March 31, 2006.

	Mar. 31,		Dec. 31,		Mar. 31,
In millions	2007		2006		2006
Gross receivables
Receivables with netting agreements in place:
Counterparty is investment grade	$	295	$	359	$	283
Counterparty is non-investment grade		49		62		40
Counterparty has no external rating		85		75		71
Receivables without netting agreements in place:
Counterparty is investment grade		8		9		10
Counterparty has no external rating		-		-		1
Amount recorded on balance sheet	$	437	$	505	$	405

Gross payables
Payables with netting agreements in place:
Counterparty is investment grade	$	270	$	297	$	299
Counterparty is non-investment grade		55		52		24
Counterparty has no external rating		180		156		152
Payables without netting agreements in place:
Counterparty is investment grade		4		5		-
Counterparty has no external rating		-		-		1
Amount recorded on balance sheet	$	509	$	510	$	476

Sequent has certain trade and credit contracts that have explicit rating trigger events in case of a credit rating downgrade. These rating triggers 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. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, Sequent’s ability to continue transacting business with these counterparties would be impaired. If, at March 31, 2007, 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 $8 million.

There have been no 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, 2006.

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 March 31, 2007, 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 March 31, 2007, 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 controls 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.

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).” 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. There have been no significant changes in the litigation which was described in Note 8 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2006. We believe the ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

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

The following table sets forth information regarding purchases of our common stock by us and any affiliated purchasers during the three months ended March 31, 2007. Stock repurchases may be made in the open market or in private transactions at times and in amounts that we deem appropriate. However, there is no guarantee as to the exact number of additional shares that may be repurchased, and we may terminate or limit the stock repurchase program at any time. We will hold the repurchased shares as treasury shares.

Period	Total number of shares purchased (1) (2) (3)		Average price paid per share		Total number of shares purchased as part of publicly announced plans or programs (3)		Maximum number of shares that may yet be purchased under the publicly announced plans or programs (3)
January 2007		18,907	$	39.20		12,300		6,960,200
February 2007		65,167	$	41.71		57,500		6,902,700
March 2007		110,500	$	40.86		110,500		6,792,200
Total first quarter		194,574	$	40.99		180,300

(1)	The total number of shares purchased includes an aggregate of 6,607 shares surrendered to us to satisfy tax withholding obligations in connection with the vesting of shares of restricted stock and/or the exercise of stock options.

(2)

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 7,667 shares for such purposes in the first quarter of 2007. As of March 31, 2007, we had purchased a total 294,234 of the 600,000 shares authorized for purchase, leaving 305,766 shares authorized for purchase under this program.

(3)

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 authorized for purchase in connection with the Officer Plan as described in note (2) above, over a five-year period.

Item 6. Exhibits

3.1 Amended and Restated Articles of Incorporation filed November 2, 2005 with the Secretary of State of the state of Georgia (incorporated herein by reference to Exhibit 3.1, AGL Resources Inc. Form 8-K dated November 2, 2005).

3.2 Bylaws, as amended on October 29, 2003 (incorporated herein by reference to Exhibit 3.2 of AGL Resources Inc. Annual Report on Form 10-K for the fiscal year ended December 31, 2003).

10.1 Description of compensation arrangements for members of the board of directors (Item 1.01, AGL Resources Inc. Form 8-K, dated November 1, 2006 and Item 5.02, AGL Resources Inc. Form 8-K dated March 29, 2007.)

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

SIGNATURE

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

	AGL RESOURCES INC.
	(Registrant)

Date: May 2, 2007	/s/ Andrew W. Evans
	Executive Vice President and Chief Financial Officer