UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ü] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2005
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 ü No
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ü No __
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 May 3, 2005
Common Stock, $5.00 Par Value		77,109,918

1

AGL RESOURCES INC.

Form 10-Q

For the Quarterly Period Ended March 31, 2005

TABLE OF CONTENTS

Item Number		Page(s)
	PART I - FINANCIAL INFORMATION	3-42
1	Condensed Consolidated Financial Statements (Unaudited)	3-20
	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	7-20
	Note 1 - Accounting Policies and Methods of Application	7-8
	Note 2 - Acquisition Update	8
	Note 3 - Recent Accounting Pronouncements	8
	Note 4 - Risk Management	9-11
	Note 5 - Regulatory Assets and Liabilities	12-14
	Note 6 - Pension and Other Postretirement Benefits	14
	Note 7 - Compensation Plans	14-15
	Note 8 - Financing	15
	Note 9 - Commitments and Contingencies	16
	Note 10 - Segment Information	17-19
	Note 11 - Subsequent Events	20
2	Management's Discussion and Analysis of Financial Condition and Results of Operations	21-39
	Cautionary Statement Regarding Forward-Looking Statements	21
	Overview	21-23
	Results of Operations	23-35
	AGL Resources	23-25
	Distribution Operations	25-28
	Retail Energy Operations	29
	Wholesale Services	29-33
	Energy Investments	33-34
	Corporate	34-35
	Liquidity and Capital Resources	35-39
	Critical Accounting Policies and Estimates	39
	Accounting Developments	39
3	Quantitative and Qualitative Disclosures About Market Risk	40-42
4	Controls and Procedures	43
	PART II - OTHER INFORMATION	43
1	Legal Proceedings	43
6	Exhibits	43
	SIGNATURE	44

2

PART I - Financial Information

Item 1. Financial Statements

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
In millions, except share data	March 31, 2005		December 31, 2004		March 31, 2004
Current assets
Cash and cash equivalents	$	24	$	49	$	51
Receivables (less allowance for uncollectible accounts of $18 million at March 31, 2005, $15 million at Dec.31, 2004 and $17 million at March 31, 2004)		663		737		420
Unbilled revenues		130		152		76
Inventories		202		332		128
Unrecovered environmental remediation costs - current		24		27		25
Unrecovered pipeline replacement program costs - current		28		24		23
Energy marketing and risk management assets		62		38		33
Other		46		98		8
Total current assets		1,179		1,457		764
Property, plant and equipment
Property, plant and equipment		4,681		4,615		3,428
Less accumulated depreciation		1,457		1,437		1,052
Property, plant and equipment-net		3,224		3,178		2,376
Deferred debits and other assets
Goodwill		381		354		177
Unrecovered pipeline replacement program costs		353		337		402
Unrecovered environmental remediation costs		166		173		155
Other		135		141		52
Total deferred debits and other assets		1,035		1,005		786
Total assets	$	5,438	$	5,640	$	3,926
Current liabilities
Payables	$	648	$	728	$	448
Accrued expenses		139		65		69
Accrued pipeline replacement program costs - current		97		85		93
Energy marketing and risk management liabilities		55		15		21
Short-term debt		38		334		133
Accrued environmental remediation costs - current		12		27		51
Other		225		223		111
Total current liabilities		1,214		1,477		926
Accumulated deferred income taxes		423		437		393
Long-term liabilities
Accrued pipeline replacement program costs		249		242		304
Accumulated removal costs		93		94		104
Accrued pension obligations		86		84		39
Accrued environmental remediation costs		62		63		29
Accrued postretirement benefit costs		60		58		51
Other		46		68		10
Total long-term liabilities		596		609		537
Deferred credits		111		73		71
Commitments and contingencies (Note 9)
Minority interest		30		36		27
Capitalization
Long-term debt		1,618		1,623		970
Common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,446		1,385		1,002
Total capitalization		3,064		3,008		1,972
Total liabilities and capitalization	$	5,438	$	5,640	$	3,926

See Notes to Condensed Consolidated Financial Statements (Unaudited).

3

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
	Three months ended
	March 31,
In millions, except per share amounts	2005			2004
Operating revenues	$	912		$	651
Operating expenses
Cost of gas		572			393
Operation and maintenance expenses		115			93
Depreciation and amortization		33			24
Taxes other than income		11			8
Total operating expenses		731			518
Operating income		181			133
Other income		1			1
Interest expense		(26	)		(16	)
Minority interest		(13	)		(11	)
Earnings before income taxes		143			107
Income taxes		55			41
Net income	$	88		$	66
Basic earnings per common share	$	1.15		$	1.02
Fully diluted earnings per common share	$	1.14		$	1.00
Weighted-average number of common shares outstanding
Basic		76.9			64.6
Fully diluted		77.6			65.4

See Notes to Condensed Consolidated Financial Statements (Unaudited).

4

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(UNAUDITED)
					Premium on						Other
	Common Stock				common			Earnings			comprehensive
In millions, except per share amount	Shares		Amount		shares			reinvested			income			Total
Balance as of December 31, 2004		76.7	$	384	$	632		$	415			($46	)	$	1,385
Comprehensive income:
Net income		-		-		-			88			-			88
Unrealized loss from hedging activities (net of taxes)		-		-		-			-			(3	)		(3	)
Total comprehensive income															85
Dividends on common shares ($0.31 per share)		-		-		-			(24	)		-			(24	)
Benefit, stock compensation, dividend reinvestment and share purchase plans		0.4		1		(1	)		-			-			-
Balance as of March 31, 2005		77.1	$	385	$	631		$	479			($49	)	$	1,446

See Notes to Condensed Consolidated Financial Statements (Unaudited).

5

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
	Three months ended
	March 31,
In millions	2005			2004
Cash flows from operating activities
Net income	$	88		$	66
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		33			24
Deferred income taxes		(14	)		16
Change in risk management assets and liabilities		17			(15	)
Changes in certain assets and liabilities
Receivables		96			70
Payables		(80	)		(13	)
Inventories		129			111
Other		122			76
Net cash flow provided by operating activities		391			335
Cash flows from investing activities
Property, plant and equipment expenditures		(81	)		(45	)
Sale of ownership interest in US Propane		-			29
Other		3			-
Net cash flow used in investing activities		(78	)		(16	)
Cash flows from financing activities
Payments and borrowings of short-term debt, net		(295	)		(212	)
Payments of Medium-Term notes		-			(48	)
Dividends paid on common shares		(24	)		(19	)
Distribution to minority interest		(19	)		(14	)
Other		-			8
Net cash flow used in financing activities		(338	)		(285	)
Net (decrease) increase in cash and cash equivalents		(25	)		34
Cash and cash equivalents at beginning of period		49			17
Cash and cash equivalents at end of period	$	24		$	51
Cash paid during the period for
Interest (net of allowance for funds used during construction)	$	13		$	11
Income taxes	$	1		$	9

See Notes to Condensed Consolidated Financial Statements (Unaudited).

6

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 of its operations through its subsidiaries. Unless the context requires otherwise, references to “we”, “us”, “our” or the “company” are intended to mean consolidated AGL Resources Inc. and its subsidiaries (AGL Resources).

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 accounting principles generally accepted in the United States of America (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, 2004, filed with the SEC on February 15, 2005.

Due to the seasonal nature of our business, our results of operations for the three months ended March 31, 2005 and 2004 and our financial position as of December 31, 2004 and March 31, 2005 and 2004 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 as of and for the period ended March 31, 2005 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. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior periods have been reclassified to conform to the current period presentation. The December 31, 2004 balance sheet amounts are derived from our audited balance sheet as of December 31, 2004.

We utilize the equity method to account for and report our 50% interest in Saltville Gas Storage Company, LLC where we exercise significant influence but do not control and where we are not the primary beneficiary as defined by Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46).

In accordance with FIN 46 as revised in December 2003 (FIN 46R), as of January 1, 2004 we consolidated all of the accounts of SouthStar Energy Services LLC (SouthStar), a variable interest entity of which we currently own a noncontrolling 70% financial interest, have a 75% interest in the earnings and have a 50% voting interest, with our subsidiaries’ accounts and eliminated any intercompany balances between segments. We recorded the portion of SouthStar’s earnings that are recognized by our joint venture partner, Piedmont Natural Gas Company, Inc. (Piedmont), as a minority interest in our consolidated statements of income, and we recorded Piedmont’s portion of SouthStar’s capital as a minority interest in our consolidated balance sheet. We determined that SouthStar is a variable interest entity as defined in FIN 46R 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.

·   SouthStar obtains substantially all of its transportation capacity for delivery of natural gas through our wholly owned subsidiary, Atlanta Gas Light Company (Atlanta Gas Light).

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 and minimum pension liability adjustments.

For the three months ended March 31, 2005, our OCI decreased by $3 million, reflecting our 75% ownership interest in SouthStar’s unrealized loss associated with its cash flow hedges. For the three months ended March 31, 2004, our OCI increased by $1 million as a result of our investment in marketable equity securities that we retained after the sale of US Propane LP in January 2004.

7

Stock-based Compensation

We have several stock-based employee compensation plans and we account for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25) and Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation” (SFAS 123). For our stock option plans, we generally do not reflect stock-based employee compensation cost in net income, as options granted under those plans have an exercise price equal to the market value of the underlying common stock on the date of grant. For our stock appreciation rights, we reflect stock-based employee compensation cost based on the fair value of our common stock at the balance sheet date, since these awards constitute a variable plan under APB 25. The following table illustrates the effect on our net income and earnings per share as if we had applied the optional fair value recognition provisions of SFAS 123:

	Three months ended March 31,
In millions, except per share amounts	2005			2004
Net income, as reported	$	88		$	66
Deduct: Total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effect		(1	)		(1	)
Pro-forma net income	$	87		$	65
Earnings per share:
Basic - as reported	$	1.15		$	1.02
Basic - pro-forma	$	1.14		$	1.01
Fully diluted - as reported	$	1.14		$	1.00
Fully diluted - pro-forma	$	1.13		$	1.00

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 share units and stock options. The future issuance of shares underlying the 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, assumingrestricted stock units currently earned under the plan ultimately vest and stock options currently exercisable at prices below the average market prices are exercised. Our weighted average shares outstanding increased by 12.3 million during the first quarter of 2005, primarily as a result of our 11 million share equity offering completed in November 2004.

	Three months ended March 31,
In millions	2005		2004
Denominator for basic earnings per share (1)		76.9		64.6
Assumed exercise of restricted stock units and stock options		0.7		0.8
Denominator for diluted earnings per share		77.6		65.4

(1)   Daily weighted-average shares outstanding

8

Note 2

Acquisition Update

On November 30, 2004 we acquired NUI Corporation (NUI) for approximately $825 million, including the assumption of $709 million in debt. During the first quarter of 2005, we continued to adjust our purchase price allocation for additional known items. This resulted in an increase in goodwill of $27 million principally related to pension, severance and lease adjustments. As of March 31, 2005, the remaining significant open items are certain environmental matters, valuation adjustments for the sales of certain assets acquired, lease adjustments related to NUI’s corporate offices and certain tax items. We anticipate finishing our allocation within a year of the acquisition, with the majority of the remaining significant adjustments to our balance sheet occurring during the second quarter of 2005.

Note 3

Recent Accounting Pronouncements

Issued but not yet adopted In December 2004, the FASB issued SFAS No 123(R), “Accounting for Stock Based Compensation” (SFAS 123R).  SFAS 123R revises the guidance in SFAS No. 123 and supersedes APB 25 and its related implementation guidance. SFAS 123R focuses primarily on the accounting for share-based payments to employees in exchange for services, and it requires a public entity to measure and recognize compensation cost for these payments. Our share-based payments are typically in the form of stock option and restricted share unit awards. The primary change in accounting is related to the requirement to recognize compensation cost for stock option awards that was not recognized under APB 25. Compensation cost will be measured based on the fair value of the equity or liability instruments issued.  For stock option awards, fair value would be estimated using an option pricing model such as the Black-Scholes model. In April 2005, the SEC voted to delay the effective date of SFAS 123R from June 30, 2005 to January 1, 2006.

Note 4

Risk Management

Our enterprise risk management activities are monitored by our Risk Management Committee (RMC). The RMC is, among other things, charged with the review and enforcement of risk management policies which place limitation on the use of derivative financial instruments and physical transactions. We use the following derivative financial instruments and physical transactions to manage commodity price risks:

·   Forward contracts

·   Futures contracts

·   Options contracts

·   Financial swaps

·   Storage and transportation capacity transactions

Interest Rate Swaps

To maintain an effective capital structure, it is our policy to borrow funds using a mix of fixed-rate and variable-rate debt. We have entered into interest rate swap agreements through our wholly owned subsidiary, AGL Capital Corporation (AGL Capital), for the purpose of hedging the interest rate risk associated with our fixed-rate and variable-rate debt obligations. We designated these interest rate swaps as fair value hedges and accounted for them using the “shortcut” method prescribed by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), which allows us to designate derivatives that hedge exposure to changes in the fair value of a recognized asset or liability. We record the gain or loss on fair value hedges in earnings in the period of change, together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The effect of this accounting is to reflect in earnings only that portion of the hedge that is ineffective in achieving offsetting changes in fair value.

In addition, we use interest rate swaps to manage interest rate risks. We adjust the carrying value of each interest rate swap to its fair value at the end of each period, with an offsetting and equal adjustment to the carrying value of the debt securities whose fair value is being hedged. Consequently, our earnings are not affected negatively or positively with changes in fair value of the interest swaps each quarter. As of March 31, 2005, a notional principal amount of $175 million of these interest rate swap agreements effectively converted the interest expense associated with a portion of our senior notes and notes payable to the Trusts from fixed rates to variable rates based on an interest rate equal to the London Interbank Offered Rate (LIBOR), plus a spread determined at the swap date.

9

Commodity-Related Derivative Instruments

Elizabethtown Gas Company (Elizabethtown Gas) A program approved by the New Jersey Board of Public Utilities requires Elizabethtown Gas to utilize certain derivatives to hedge the impact of market fluctuations of natural gas prices primarily associated with natural gas supply and inventory purchases.  Pursuant to SFAS 133, such derivative products are marked-to-market each reporting period.  Pursuant to regulatory requirements, realized gains and losses related to such derivatives are reflected in purchased gas costs and included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset (loss) or liability (gain), as appropriate, on our consolidated balance sheet.  As of March 31, 2005, Elizabethtown Gas had entered into New York Mercantile Exchange (NYMEX) futures contracts to purchase 9.2 billion cubic feet (Bcf) of natural gas at prices ranging from $3.64 to $8.83 per thousand cubic feet.  Approximately 85% of these contracts have a duration of one year or less, and none of these contracts extends beyond October 2006.

Sequent We are exposed to risks associated with changes in the market price of natural gas. Our wholly owned energy trading and marketing subsidiary, Sequent Energy Management, L.P. (Sequent), uses derivative financial instruments to reduce our exposure to the risk of changes in the prices of natural gas. The fair value of these derivative financial instruments reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of the financial instruments we utilize.

We mitigate substantially all of the commodity price risk associated with Sequent’s natural gas portfolio by locking in the economic margin at the time we enter into natural gas purchase transactions for our stored natural gas. We purchase natural gas for storage when the difference in the current market price we pay to buy natural gas plus the cost to store the natural gas is less than the market price we can receive in the future, resulting in a positive net profit margin. We use NYMEX futures contracts and other over the counter derivatives to sell natural gas at that future price to substantially lock in the profit margin we will ultimately realize when the stored gas is actually sold. These futures contracts meet the definition of a derivative under SFAS 133 and are recorded at fair value and marked-to-market in our condensed consolidated balance sheet, with changes in fair value recorded in earnings in the period of change. The purchase, storage and sale of natural gas are accounted for on an accrual basis rather than on the mark-to-market basis we utilize for the derivatives used to mitigate the commodity price risk associated with our storage portfolio. This difference in accounting can result in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.

At March 31, 2005, our commodity-related derivative financial instruments, which exclude interest rate swaps, represented purchases (long) of 600 Bcf with maximum maturities less than 2 years. In addition, our financial instruments included sales (short) of 581 Bcf with approximately 93% of these scheduled to mature in less than 2 years and the remaining 7% in 3-9 years. For the three months ended March 31, our unrealized losses were $6 million in 2005 and our unrealized gains were $14 million in 2004.

SouthStar The commodity-related derivative financial instruments (futures, options and swaps) used by SouthStar manage exposures arising from changing commodity prices. SouthStar’s objective for holding these derivatives is to utilize the most effective method to reduce or eliminate the impacts of this exposure. A portion of SouthStar’s derivative transactions are designated as cash flow hedges under SFAS 133. Derivative gains or losses arising from cash flow hedges are recorded in OCI and are reclassified into earnings in the same period as the settlement of the underlying hedged item. Any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not perfectly offset the losses or gains on the hedged item, is recorded in our cost of gas on our condensed consolidated income statement in the period in which it occurs. SouthStar currently has minimal hedge ineffectiveness. The remainder of SouthStar’s derivative instruments does not meet the hedge criteria under SFAS 133. Therefore, changes in their fair value are recorded in earnings in the period of change. At March 31, 2005, the fair value of these derivatives was reflected in our condensed consolidated financial statements as an asset of $5 million and liability of $4 million. The maximum maturity of open positions is less than 1 year and represents purchases of 5 Bcf and sales of 4 Bcf.

10

Concentration of Credit Risk

Wholesale Services Sequent has a concentration of credit risk for services it provides to marketers and to utility and industrial customers. This credit risk is measured by 30-day receivable exposure plus forward exposure, which is highly concentrated in 20 of its customers. Sequent evaluates its customers using the Standard & Poor’s Rating Services (S&P) equivalent credit rating which is determined by a process of converting the lower of the S&P or Moody’s Investor Service (Moody’s) rating to an internal rating ranging from 9.00 to 1.00, with 9.00 being equivalent to AAA/Aaa by S&P and Moody’s and 1.00 being equivalent to D or Default by S&P and Moody’s. A customer that does not have an external rating is assigned an internal rating based on the strength of its financial ratios.

The weighted average credit rating is obtained by multiplying each customer’s assigned internal rating by its credit exposure and the individual results are then summed for all counterparties. That total is divided by the aggregate total exposure. This numeric value is converted to an S&P equivalent. At March 31, 2005, Sequent’s top 20 customers represented approximately 58% of the total credit exposure of $286 million, derived by adding the top 20 customers’ exposures and dividing by the total of Sequent’s exposures. Sequent’s customers or the customers’ guarantors had a weighted average S&P equivalent to a BBB+ rating at March 31, 2005.

Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. When Sequent is engaged in more than one outstanding derivative transaction with the same counterparty and it also 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 we conduct significant transactions.

11

Note 5

Regulatory Assets and Liabilities

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

In millions	March 31, 2005		Dec. 31, 2004		March 31, 2004
Regulatory assets
Unrecovered PRP costs	$	381	$	361	$	426
Unrecovered ERC		190		200		180
Unrecovered postretirement benefit costs		14		14		9
Unrecovered seasonal rates		-		11		-
Unamortized purchased gas adjustment		-		5		-
Regulatory tax asset		1		2		3
Other		5		20		6
Total regulatory assets	$	591	$	613	$	624
Regulatory liabilities
Accumulated removal costs	$	93	$	94	$	103
Unamortized investment tax credit		20		20		19
Deferred seasonal rates		22		-		21
Deferred purchased gas adjustment		60		37		43
Regulatory tax liability		11		14		15
Other		-		18		2
Total regulatory liabilities		206		183		203
Associated liabilities
PRP costs		346		327		397
ERC		74		90		80
Total associated liabilities		420		417		477
Total regulatory and associated liabilities	$	626	$	600	$	680

Our regulatory assets and liabilities are 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, 2004. The following represent significant changes to our regulatory assets and liabilities during the three months ended March 31, 2005:

Environmental Remediation Costs

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites.

Atlanta Gas LightThe presence of coal tar and certain other by-products of a natural gas manufacturing process used to produce natural gas prior to the 1950s has been identified at or near 13 former Atlanta Gas Light operating sites in Georgia and Florida. Atlanta Gas Light has active environmental remediation or monitoring programs in effect at 10 of these sites. Two sites in Florida are currently in the investigation or preliminary engineering design phase, and one Georgia site has been deemed compliant with state standards, subject to approval of a continuing action plan. The required soil remediation at our remaining Georgia sites is scheduled to be completed by June 2005. As of March 31, 2005, Atlanta Gas Light’s remediation program was approximately 82% complete.

Atlanta Gas Light has historically reported estimates of future remediation costs for these former sites based on probabilistic models of potential costs. These estimates are reported on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, Atlanta Gas Light is increasingly able to provide conventional engineering estimates of the likely costs of many elements at its former sites. These estimates contain various engineering uncertainties, and Atlanta Gas Light continuously attempts to refine and update these engineering estimates.

12

Our current engineering estimate projects costs associated with Atlanta Gas Light’s engineering estimates and in-place contracts to be $29 million. This is a reduction of $37 million from last year’s estimate of projected engineering and in-place contracts, resulting from $40 million of program expenditures incurred in the year ended December 31, 2004.

For those remaining elements of Atlanta Gas Light’s environmental remediation program where it is unable to perform engineering cost estimates at the current state of investigation, considerable variability remains in the estimates for future remediation costs. For these elements, the estimate for the remaining cost of future actions at these former operating sites is $17 million. Atlanta Gas Light estimates certain other costs related to administering the remediation program and remediation of sites currently in the investigation phase. To date, Atlanta Gas Light estimates the administrative costs to be $2 million.

For those sites currently in the investigation phase, Atlanta Gas Light’s estimate for remediation is $7 million. This estimate is based on preliminary data received during 2004 with respect to the existence of contamination at those sites.

The liability does not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, unbudgeted legal expenses or other costs for which Atlanta Gas Light may be held liable but with respect to which it cannot reasonably estimate the amount. As of March 31, 2005, the remediation expenditures expected to be incurred over the next 12 months are reflected as a current liability of $12 million.

The ERC liability is included in a corresponding regulatory asset, which is a combination of accrued ERC and unrecovered cash expenditures for investigation and cleanup costs. Atlanta Gas Light has three ways of recovering investigation and cleanup costs. First, the Georgia Public Service Commission has approved an ERC recovery rider. Because of that rider, these actual and projected future costs related to investigation and cleanup to be recovered from customers in future years are included in our regulatory assets. The ERC recovery mechanism allows for recovery of expenditures over a five-year period subsequent to the period in which the expenditures are incurred. Atlanta Gas Light expects to collect $24 million in revenues over the next 12 months under the ERC recovery rider, which is reflected as a current asset.

The second way to recover costs is by exercising the legal rights Atlanta Gas Light believes it has to recover a share of its costs from other potentially responsible parties, typically former owners or operators of these sites. There were no material recoveries from potentially responsible parties during the three months ended March 31, 2005. The third way to recover costs is from the receipt of net profits from the sale of remediated property. There were no remediated property sales during the three months ended March 31, 2005.

Elizabethtown Gas In New Jersey, Elizabethtown Gas is currently conducting remedial activities with oversight from the New Jersey Department of Environmental Protection. Although the actual total cost of future environmental investigation and remediation efforts cannot be estimated with precision the range of reasonably probable costs is from $30 million to $116 million. As of March 31, 2005, no value within this range is a better estimate than any other value, so we have recorded a liability equal to the low end of that range, or $30 million. 

Elizabethtown Gas’ prudently incurred remediation costs for the New Jersey properties have been authorized by the New Jersey Board of Public Utilities to be recoverable in rates through its Remediation Adjustment Clause. As a result, Elizabethtown Gas has recorded a regulatory asset of approximately $36 million, inclusive of interest, as of March 31, 2005, reflecting the future recovery of both incurred costs and accrued carrying charges. Elizabethtown Gas has also been successful in recovering a portion of remediation costs incurred in New Jersey from its insurance carriers and continues to pursue additional recovery. As of March 31, 2005, the variation between the amounts of the ERC liability recorded on the consolidated balance sheet and the associated regulatory asset result from expenditures for environmental investigation and remediation exceeded recoveries from ratepayers and insurance carriers.

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Other We also own a former NUI remediation site in Elizabeth City, North Carolina, which is subject to an order by the North Carolina Department of Energy and Natural Resources. We do not have precise estimates for the cost of investigating and remediating this site, although preliminary estimates for these costs range from $4 to $19 million. As of March 31, 2005, we have recorded a liability of $4 million related to this site. There is one other site in North Carolina where investigation and remediation is probable, although no regulatory order exists and we do not believe costs associated with this site can be reasonably estimated. In addition, there are as many as six other sites with which NUI had some association, although no basis for liability has been asserted, and accordingly , we have not accrued any remediation liability.

We are evaluating the estimates at Elizabethtown Gas and at NUI’s other former remediation sites. The differences between our estimates and actual costs could be significant, and any such difference could affect the amount ultimately recorded as part of our purchase price of NUI.

Note 6

Pension and Other Postretirement Benefits

Pension Benefits We sponsor two 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 cost components of our two pension plans for the periods indicated:

	Three months ended
	March 31,
In millions	2005			2004
Service cost	$	-		$	1
Interest cost		1			5
Expected return on plan assets		(1	)		(6	)
Net amortization		-			-
Recognized actuarial loss		-			1
Net annual cost	$	-		$	1

Other Postretirement Benefits 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 Plan Health Care Plan. Eligibility for these benefits is based on age and years of service. The following are the cost components of these two postretirement benefit plans for the periods indicated:

	Three months ended
	March 31,
In millions	2005		2004
Service cost	$	-	$	-
Interest cost		-		2
Expected return on plan assets		-		(1	)
Net amortization		-		-
Recognized actuarial loss		-		1
Net annual cost	$	-	$	2

Note 7

Compensation Plans

Restricted Stock Units In general, a restricted stock unit is an award that represents the opportunity to receive a specified number of shares of company common stock, subject to the achievement of certain pre-established performance criteria.

In January 2005, we granted to a select group of officers a total of 85,900 restricted stock units. The awards were made pursuant to our Amended and Restated Long-Term Incentive Plan (1999) (Incentive Plan), as amended in 2002.

The restricted stock units have a twelve-month performance measurement period. If the performance goal set forth in the restricted stock unit agreement is achieved, the performance units are converted to an equal number of shares of company common stock and, thereafter, are subject to the vesting schedule set forth in the restricted stock unit agreement. If the performance goal set forth in the agreement is not attained, the restricted units will be forfeited and returned to the company. The performance goal is related to management’s success in integrating its acquisitions and generating improvement in earnings from these acquired businesses.

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Performance Cash Units In general, a performance cash unit award is an award that represents the opportunity to receive an incentive payment, in cash, subject to the achievement of certain pre-established performance criteria.

In January 2005, we granted performance cash units to a group of 26 executives pursuant to our Incentive Plan. The performance cash units represent a maximum aggregate payout of $35 million. The performance cash units have a performance measurement period that ranges from 12 to 36 months. The performance criteria relate to our internal measure of total shareholder return.

Note 8

Financing

Our financing consists of short and long-term debt as indicated in the following table. There have been no significant changes to our financing, 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, 2004.

						Outstanding as of:
Dollars in millions	Year(s) due		Int. rate (1)			Mar. 31, 2005			Dec. 31, 2004		Mar. 31, 2004
Short-term debt
Commercial paper(2)		2005		2.9	%	$	31		$	314	$	91
Current portion of long-term debt		-		-			-			-		33
Sequent line of credit(3)		-		-			-			18		7
Current portion of capital leases		2005		4.9			1			2		-
SouthStar non-recourse debt		2005		5.8			6			-		2
Total short-term debt(4)				3.4	%	$	38		$	334	$	133
Long-term debt - net of current portion
Medium-Term notes		2012-2027		6.6 - 9.1	%	$	208		$	208	$	208
Senior notes		2011-2034		4.5 - 7.1			975			975		525
Gas facility revenue bonds, net of unamortized issuance costs		2022-2033		2.4 - 6.4			199			199		-
Notes payable to Trusts		2037-2041		8.0 - 8.2			232			232		232
Capital leases		2013		4.9			8			8		-
Interest rate swaps		2041		4.1 - 6.3			(4	)		1		5
Total long-term debt(4)				6.0	%	$	1,618		$	1,623	$	970
Total short-term and long-term debt(4)				6.0	%	$	1,656		$	1,957	$	1,103

(1)   As of March 31, 2005.

(2)   The daily weighted average rate was 2.6% for the three months ended March 31, 2005.

(3)   The daily weighted average rate was 2.9% for the three months ended March 31, 2005.

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

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Note 9

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 10 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2004.

SouthStar has natural gas purchase commitments related to the supply of minimum natural gas volumes to its customers. These commitments are priced on an index plus premium basis. At March 31, 2005, SouthStar had obligations under these arrangements for 11 Bcf through December 31, 2005. SouthStar also had capacity commitments related to the purchase of transportation rights on interstate pipelines.

We have also incurred various contingent financial commitments in the normal course of business. The following table illustrates our expected contingent financial commitments representing obligations that become payable only if certain pre-defined events occur, such as financial guarantees, reflecting the maximum potential amount of future payments that could be required of us as of March 31, 2005:

			Commitments due before December 31,
					2006 &		2008 &		2010 &
In millions	Total		2005		2007		2009		thereafter
Guarantees(1)	$	7	$	7	$	-	$	-	$	-
Standby letters of credit, performance / surety bonds		15		12		3		-		-
Total	$	22	$	19	$	3	$	-	$	-
(1) We provide guarantees on behalf of SouthStar. We guarantee 70% of SouthStar’s obligations to Southern Natural Gas Company (SNG) under certain agreements between the parties up to a maximum of $7 million if SouthStar fails to make payment to SNG.

Litigation We are involved in litigation arising in the normal course of business. There has been no significant change in the litigation which was described in Note 10 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2004. 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.

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Note 10

Segment Information

Prior to 2005 our business was organized into three operating segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environments as well as the manner in which we manage these segments and our internal management information flows.

Beginning in 2005, we added an additional segment, retail energy operations, which consists of the operations of SouthStar, our retail gas marketing subsidiary that conducts business primarily in Georgia. We added this segment due to our application of accounting guidance in SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS 131) in consideration of the impact of our acquisitions of NUI and Jefferson Island Storage & Hub, LLC (Jefferson Island). The addition of this segment also is consistent with our desire to provide transparency and visibility to SouthStar on a stand-alone basis and to provide additional visibility to the remaining businesses in the energy investments segment, principally Jefferson Island and Pivotal Propane of Virginia, Inc. (Pivotal Propane), which are more closely related in structure and operation. Additionally, we have restated the segment information for the three months ended March 31, 2004 in accordance with the guidance set forth in SFAS 131 as shown in the tables below. Our four operating segments are now as follows:

·   Distribution operations consists primarily of:

o   Atlanta Gas Light Company

o   Elizabethtown Gas Company

o   Virginia Natural Gas Company

o   Florida City Gas Company

o   Chattanooga Gas Company

o   Elkton Gas Company

·   Retail energy operations consists of SouthStar

·   Wholesale services consists primarily of Sequent.

·   Energy investments consists primarily of:

o   Pivotal Jefferson Island

o   Pivotal Propane

o   Virginia Gas Company

o   50% ownership interest in Saltville Gas Storage Company, LLC

o   AGL Networks, LLC

We treat corporate, our fifth segment, as a non-operating business segment, and it includes AGL Resources Inc., AGL Services Company, Pivotal Energy Development, nonregulated financing subsidiaries and the effect of intercompany eliminations. We eliminated intersegment sales for the three months ended March 31, 2005 and 2004 from our condensed consolidated statements of income.

We evaluate segment performance based on earnings before interest and taxes (EBIT), which includes the effects of corporate expense allocations. EBIT is a GAAP measure that includes operating income, other income, minority interest and gain on sales of assets. Items that are not included in EBIT are financing costs, including interest and debt expense, income taxes and the cumulative effect of changes in accounting principles, each of which is evaluated at the consolidated level. Management believes EBIT is useful to investors as a measurement of our operating segments’ performance because it can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

You should not consider EBIT as 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, 2005 and 2004 are presented below.

	Three months ended March 31,
In millions	2005			2004
Operating revenues	$	912		$	651
Operating expenses		731			518
Operating income		181			133
Other income		1			1
Minority interest		(13	)		(11	)
EBIT		169			123
Interest expense		26			16
Earnings before income taxes		143			107
Income taxes		55			41
Net income	$	88		$	66

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Summarized income statement information and capital expenditures as of and for the three months ended March 31, 2005 and 2004 by segment are shown in the following tables:

2005
In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intersegment eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	575	$	314		$	11	$	12	$	-		$	912
Intersegment revenues (1)		59		-			-		-		(59	)		-
Total revenues		634		314			11		12		(59	)		912
Operating expenses
Cost of gas		381		248			-		3		(60	)		572
Operation and maintenance		93		13			7		3		(1	)		115
Depreciation and amortization		28		-			-		2		3			33
Taxes other than income taxes		9		-			-		-		2			11
Total operating expenses		511		261			7		8		(56	)		731
Operating income (loss)		123		53			4		4		(3	)		181
Other income		-		-			-		1		-			1
Minority interest		-		(13	)		-		-		-			(13	)
EBIT	$	123	$	40		$	4	$	5		($3	)	$	169
Capital expenditures	$	72	$	-		$	-	$	3	$	6		$	81

2004
In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intersegment eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	323	$	307		$	20	$	1	$	-		$	651
Intersegment revenues (1)		66		-			-		-		(66	)		-
Total revenues		389		307			20		1		(66	)	$	651
Operating expenses
Cost of gas		209		250			-		-		(66	)		393
Operation and maintenance		71		13			8		1		-			93
Depreciation and amortization		21		-			-		-		3			24
Taxes other than income taxes		6		-			-		-		2			8
Total operating expenses		307		263			8		1		(61	)		518
Operating income (loss)		82		44			12		-		(5	)		133
Other income		-		-			-		1		-			1
Minority interest		-		(11	)		-		-		-			(11	)
EBIT	$	82	$	33		$	12	$	1		($5	)	$	123
Capital expenditures	$	36	$	2		$	3	$	4	$	-		$	45

(1)   Intersegment revenues - Wholesale services records its energy marketing and risk management revenue on a net basis. The following table provides detail of wholesale services’ total gross revenues and gross sales to distribution operations:

	Three months ended March 31,
In millions	2005		2004
Third-party gross revenues	$	1,283	$	1,024
Intersegment revenues		87		96
Total gross revenues	$	1,370	$	1,120

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Balance sheet information at March 31, 2005 and 2004 and December 31, 2004 by segment is shown in the following tables:

As of March 31, 2005
In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments		Corporate and intersegment eliminations (2)			Consolidated AGL Resources
Goodwill	$	367	$	-	$	-	$	14	$	-		$	381
Identifiable assets (1)	$	4,542	$	193	$	652	$	276		($239	)	$	5,424
Investment in joint ventures		42		-		-		3		(31	)		14
Total assets	$	4,584	$	193	$	652	$	279		($270	)	$	5,438

As of December 31, 2004
In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments		Corporate and intersegment eliminations (2)			Consolidated AGL Resources
Goodwill	$	340	$	-	$	-	$	14	$	-		$	354
Identifiable assets (1)	$	4,386	$	244	$	696	$	386		($86	)	$	5,626
Investment in joint ventures		-		-		-		235		(221	)		14
Total assets	$	4,386	$	244	$	696	$	621		($307	)	$	5,640

As of March 31, 2004
In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments		Corporate and intersegment eliminations (2)			Consolidated AGL Resources
Goodwill	$	177	$	-	$	-	$	-	$	-		$	177
Identifiable assets (1)	$	3,284	$	161	$	453	$	122		($96	)	$	3,924
Investment in joint ventures		-		-		-		2		-			2
Total assets	$	3,284	$	161	$	453	$	124		($96	)	$	3,926

(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.

Note 11

Subsequent Events

Sale of Saltville Gas Storage Company, LLC On April 27, 2005, we announced our agreement to sell our 50% interest in Saltville Gas Storage Company, LLC (Saltville) and our wholly-owned subsidiaries Virginia Gas Pipeline and Virginia Gas Storage to Duke Energy Corporation, the other 50% partner in Saltville. We acquired these Virginia assets in November 2004 with our purchase of NUI Corporation. We will retain Virginia Gas Distribution Company, another NUI asset, which has 270 customers and annual throughput of 240,000 dekatherms.

When completed, the sale will make Duke Energy the sole owner of Saltville, which operates a storage facility that currently has approximately 1.8 Bcf of capacity. We will receive, subject to working capital adjustments, $62 million in cash at closing and will utilize the proceeds to repay debt and for other general corporate purposes. The transaction is not expected to have a material impact on our earnings. Closing of the transaction, which is conditional upon regulatory approvals, including approval from the Virginia State Corporation Commission, is expected by the end of 2005.

Refinancing of Gas Facility Revenue Bonds On April 19, 2005, we refinanced $20 million in Gas Facility Revenue Bonds due October 1, 2024. These bonds, which had a fixed interest rate of 6.4%, were refunded with $20 million of adjustable rate Gas Facility Revenue Bonds. The maturity date of these bonds remains October 1, 2024. The bonds were issued at an initial interest rate of 2.8% and initially have a 35-day auction period where the interest rate will adjust every 35 days.

On May 5, 2005, we refinanced an additional $46 million in Gas Facility Revenue Bonds due October 1, 2022 and bearing interest at a fixed rate of 6.35%. The new bonds were issued at an initial interest rate of 2.9% and initially have a 35-day auction period where the interest rate will adjust every 35 days. The maturity date remains October 1, 2022.

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Atlanta Gas Light Rate Case On April 29, 2005, the Georgia Public Service Commission (Georgia Commission) issued an order (Order) in connection with Atlanta Gas Light’s rate case proceeding under Docket No. 18638-U, that would result in a reduction of operating revenues by up to $21.9 million annually, beginning on May 1, 2005. Also on April 29, 2005, Atlanta Gas Light filed a Motion for Stay of Order (Motion) requesting that the Georgia Commission immediately stay its Order until such time as the Georgia Commission rules on a petition for rehearing, reconsideration and oral argument that Atlanta Gas Light intends to file on or about May 9, 2005.

The Order adopted a “Comprehensive Rate Plan” (Plan) to fix base rates charged to customers at their current levels, and to levelize the rates in effect for the Pipeline Replacement Program Rider (PRP Rider). The Order accomplishes this by requiring Atlanta Gas Light to begin accruing, as of May 1, 2005, a regulatory liability equivalent to the amount of the reduction in operating revenues of $21.9 million. In October of each year, rates under the amounts charged to customers under the PRP Rider are normally adjusted upward to take into account the additional capital spent in the previous October to September fiscal year. The Order states that the PRP rates will be levelized at the current surcharge for the next three years, and that the regulatory liability account will be used to “supplement” the levelized rates. Therefore, as prescribed under the Plan, the Company is no longer permitted to make the annual adjustment in rates related to the PRP, which historically has been the recovery mechanism.

The Order also contained a specific provision that would have required Atlanta Gas Light to recapture the $21 million pre-tax gain previously recognized and associated with the sale of the real property associated with the Caroline Street campus in September 2003, resulting in recognition of a pre-tax charge of up to $21 million and an associated regulatory liability as of the quarter ended March 31, 2005. The Order made it probable that a liability had been incurred associated with a transaction occurring prior to the balance sheet date. We concluded in 2003, based on historical precedents and law, that the sale of the real property associated with the Caroline Street campus was a sale of a non-jurisdictional asset, and that any gain on the sale was not attributable to customers. The relevant provision in the Order would defer the $21 million pre-tax gain previously recorded and would amortize the gain into base rates over a 10-year period. The impact of this provision would be a $2.1 million annual reduction in rates, and this amount is included in the $21.9 million total annual reduction reflected in the Order.

On May 4, 2005, the Georgia Commission voted unanimously to stay, for up to 40 days, all provisions of the April 29, 2005 Order related to the Caroline Street sale, including the impact of the associated $2.1 million annual revenue reduction, in order to provide adequate time for Atlanta Gas Light to file for reconsideration of the Order and for the Commission to address the petition for reconsideration. Since this provision of the Order is not now in effect, management is unable to predict what the ultimate outcome will be of the Georgia Commission’s reconsideration of the Caroline Street issue and other issues associated with the Order. As a result, no expense or related regulatory liability has been recorded related to the Caroline Street gain as of March 31, 2005.

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain expectations and projections regarding our future performance referenced in this “Management’s Discussion and Analysis of Financial Condition and Results of Operation” 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 key 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, such as projections of our financial performance, management’s goals and strategies for our business and assumptions regarding the foregoing. Because these statements involve anticipated events or conditions, forward-looking statements often include words such as “anticipate,” “assume,” “believe,” “can,” “could,” “estimate,” “expect,” “forecast,” “indicate,” “intend,” “may,” “plan,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would” or similar expressions. For example, in this “Management’s Discussion and Analysis of Financial Condition and Results of Operation” section and elsewhere in this report, we have forward-looking statements regarding our expectations for various items, including

·   revenue growth

·   operating income growth

·   cash flows from operations

·   operating expense growth

·   capital expenditures

·   our business strategies and goals

·   our potential for growth and profitability

·   our ability to integrate our recent and future acquisitions

·   trends in our business and industries, and

·   developments in accounting standards

Do not unduly rely on forward-looking statements. They represent our expectations about the future and are not guarantees. Our expectations 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 the 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 results to differ significantly from our expectations. We caution readers that, in addition to the important factors described elsewhere in this report, the factors set forth in our 2004 Annual Report on Form 10-K filed with the SEC on February 15, 2005 under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Risk Factors,” among others, could cause our business, results of operations or financial condition in 2005 and thereafter to differ significantly from those expressed in any forward-looking statements. There also may be other factors not described 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 undertake any obligation to update these statements to reflect subsequent changes.

Overview

We are a Fortune 1000 energy services holding company whose principal business is the distribution of natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. Our six utilities serve more than 2.3 million end-use customers, making us the largest distributor of natural gas in the Southeast and mid-Atlantic regions of the United States based on customer count. We also are involved in various related businesses, including retail natural gas marketing to end-use customers in Georgia; natural gas asset management and related logistics activities for our own utilities as well as for other non-affiliated companies; natural gas storage arbitrage and related activities; operation of high-deliverability underground natural gas storage assets; and construction and operation of telecommunications conduit and fiber infrastructure within select metropolitan areas. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services and energy investments - and a non-operating corporate segment.

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The distribution operations segment is the largest component of our business and is comprehensively regulated by regulatory agencies in six states. These agencies approve rates designed to provide us the opportunity to generate revenues; to recover the cost of natural gas delivered to our customers and our fixed and variable costs such as depreciation, interest, maintenance and overhead costs; and to earn a reasonable return for our shareholders. With the exception of Atlanta Gas Light Company (Atlanta Gas Light), our largest utility franchise, the earnings of our regulated utilities are weather-sensitive to varying degrees. Although various regulatory mechanisms provide a reasonable opportunity to recover our fixed costs regardless of volumes sold, the effect of weather manifests itself in terms of higher earnings during periods of colder weather and lower earnings with warmer weather. Our retail energy operations segment, which consists of SouthStar Energy Services LLC (SouthStar), also is weather sensitive and uses a variety of hedging strategies to mitigate potential weather impacts. Our utilities and SouthStar face competition in the residential and commercial customer markets based on customer preferences for natural gas compared with other energy products, as well as the price of those products relative to that of natural gas.

We derived approximately 96% of our earnings before interest and taxes (EBIT) during the three months ended March 31, 2005 from our regulated natural gas distribution business and from the sale of natural gas to end-use customers in Georgia by SouthStar. This statistic is significant because it represents the portion of our earnings that results directly from the underlying business of supplying natural gas to retail customers. Although SouthStar 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. For more information regarding our measurement of EBIT and the items it excludes from operating income and net income, see “Results of Operations - AGL Resources.”

The remaining 4% of our EBIT was principally derived from businesses that are complementary to our natural gas distribution business. We engage in natural gas asset management and operation of high deliverability natural gas underground storage as subordinate activities to our utility franchises. 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 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 vitality.

Industry Dynamics and Competition The natural gas industry continues to face a number of challenges, most of which relate to the supply of, and demand for, natural gas across the United States. A confluence of factors - including higher peak demands across all customer classes, incremental demand for natural gas to fuel the production of electricity, declining continental supply, particularly in the Gulf of Mexico region, and sustained higher pricing levels relative to historical averages - have created a mismatch between increasing demand and declining supply.

These factors continue to challenge our industry to unlock new sources of natural gas supply to serve the North American market. Liquefied natural gas (LNG) continues to grow in importance as an incremental supply source to meet the expected growth in demand for natural gas. Expansion of existing LNG terminals and construction of new facilities both point toward rapid import expansions throughout the rest of this decade. In addition to expansion of LNG supplies, access to previously restricted areas for natural gas drilling will be critical in meeting future supply needs. The challenge is magnified by the time lags and capital expenditures required to bring new LNG facilities and new drilling rigs online and by the absence of a comprehensive national energy policy designed to facilitate the construction and expansion process.

The natural gas industry also continues to face significant competition from the electric utilities serving the residential and small commercial markets as the potential replacement of natural gas appliances with electric appliances becomes more prevalent. The primary competitive factors are the price of energy and the comfort of natural gas heating compared to electric heating and other energy sources. The increase in wholesale natural gas prices over the last several years has resulted in increases in the costs of natural gas billed to our customers and has affected, to some extent, our ability to retain customers, which remains one of our greater challenges in our southernmost utilities in 2005 and future years.

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Integration of NUI Corporation We have made significant progress in integrating the assets and operations of NUI Corporation (NUI), which we acquired on November 30, 2004, into our business operations. In the first quarter of 2005, we consolidated a number of NUI’s business technology platforms into our enterprise-wide systems, including the accounting, payroll, human resources and supply chain functions. We also consolidated the call center operation that previously served the NUI utilities into our centralized call center. The combination of system integrations and the application of our best-practice operational model in managing the NUI assets already has resulted in improvements in the metrics we use to measure our business results. Such metrics include the productivity of our field personnel, the speed of our response to customers, personal and system safety and system reliability.

Internal Controls Section 404 of the Sarbanes-Oxley Act of 2002 (SOX 404) and related rules of the SEC require management of public companies to assess the effectiveness of the company’s internal controls over financial reporting as of the end of each fiscal year. In our 2004 Annual Report on Form 10-K filed with the SEC on February 15, 2005 we noted that, for 2004, the scope of our assessment of our internal controls over financial reporting included all our consolidated entities except those falling under NUI, which we acquired on November 30, 2004, and Jefferson Island Storage & Hub, LLC (Jefferson Island), which we acquired on October 1, 2004. In accordance with the SEC’s published guidance, we excluded these entities from our assessment as they were acquired late in the year, and it was not possible to conduct our assessment between the date of acquisition and the end of the year. SEC rules require that we complete our assessment of the internal control over financial reporting of these entities within one year from the date of acquisition.

We have initiated our efforts to assess the systems of internal control related to NUI’s and Jefferson Island’s businesses to comply with the SEC’s requirements under both Sections 302 and 404 of the Sarbanes-Oxley Act. During the first quarter of 2005, we converted and integrated substantially all of NUI’s accounting systems and internal control processes into our corporate accounting systems and internal control processes. As part of this process, we are addressing and resolving the material deficiencies in internal controls for the NUI business identified by NUI’s external and internal auditors during audits performed in fiscal years 2003 and 2004, as more fully described in our 2004 Annual Report on Form 10-K. While the conversion of financial systems is a key step toward remediation of the control deficiencies, we still are in the process of documenting the internal control process for the NUI business, and we continue to remediate known deficiencies in the NUI internal controls.

Results of Operations

AGL Resources We acquired Jefferson Island and NUI in the fourth quarter of 2004. As a result, these acquired operations are included in our results of operations for the three months ended March 31, 2005 but are not included for the same period in 2004.

Beginning in 2005, we added an additional segment, retail energy operations, which consists of the operations of SouthStar, our retail gas marketing subsidiary that conducts business primarily in Georgia. We added this segment due to our application of accounting guidance in Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS 131) in consideration of the impact of the NUI and Jefferson Island acquisitions. The addition of this segment also is consistent with our desire to provide transparency and visibility to SouthStar on a stand-alone basis and to provide additional visibility to the remaining businesses in the energy investments segment, principally Jefferson Island and Pivotal Propane of Virginia, Inc. (Pivotal Propane), which are more closely related in structure and operation. Additionally, we have restated the segment information for the three months ended March 31, 2004 in accordance with the guidance set forth in SFAS 131.

RevenuesWe generate nearly all our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period. We record these estimated revenues as unbilled revenues on our consolidated balance sheet.

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A significant portion of our operations is subject to variability associated with changes in commodity prices and seasonal fluctuations. During the heating season, primarily from November through March, natural gas usage and operating revenues are higher since generally more customers will be connected to our distribution systems and natural gas usage is higher in periods of colder weather than in periods of warmer weather. Commodity prices tend to be higher in colder months as well. Our non-utility businesses principally use physical and financial arrangements to economically hedge the risks associated with seasonal fluctuations and changing commodity prices. Certain hedging and trading activities may require cash deposits to satisfy margin requirements. In addition, because these economic hedges do not generally qualify for hedge accounting treatment, our reported earnings for the wholesale services and retail energy operations segments reflect changes in the fair value of certain derivatives, and these values may change significantly from period to period.

Operating margin and EBITWe evaluate the performance of our operating segments using the measures of operating margin and EBIT. We believe operating margin is a better indicator than revenues for the contribution resulting from customer growth in our distribution operations and retail energy operations segments 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 wholesale services and energy investments segments since it is a direct measure of gross profit before overhead costs. Management believes EBIT is useful to investors as a measurement of our operating segments’ performance because it 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 affects the efficiency of the underlying operations.

Our operating margin and EBIT are not measures that are considered to be calculated in accordance with 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 a similarly titled measure of another company. The following are reconciliations of our operating margin and EBIT to operating income and net income, together with other consolidated financial information for the three months ended March 31, 2005 and 2004.

	Three months ended March 31,
In millions	2005			2004			2005 vs. 2004
Operating revenues	$	912		$	651			40	%
Cost of gas		572			393			46
Operating margin		340			258			32
Operating expenses		159			125			27
Operating income		181			133			36
Other income		1			1			-
Minority interest		(13	)		(11	)		(18	)
EBIT		169			123			37
Interest expense		(26	)		(16	)		(63	)
Earnings before income taxes		143			107			34
Income taxes		(55	)		(41	)		(34	)
Net income	$	88		$	66			33	%

Basic earnings per common share	$	1.15	$	1.02	13	%
Fully diluted earnings per common share	$	1.14	$	1.00	14	%
Weighted average number of common shares outstanding
Basic		76.9		64.6	19	%
Fully diluted		77.6		65.4	19	%

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, 2005 and 2004:

2005 (in millions)	Operating revenues			Operating margin		EBIT
Distribution operations	$	634		$	253	$	123
Retail energy operations		314			66		40
Wholesale services		11			11		4
Energy investments		12			9		5
Corporate (1)		(59	)		1		(3	)
Consolidated	$	912		$	340	$	169
2004
Distribution operations	$	389		$	180	$	82
Retail energy operations		307			57		33
Wholesale services		20			20		12
Energy investments		1			1		1
Corporate (1)		(66	)		-		(5	)
Consolidated	$	651		$	258	$	123

(1)   Includes intercompany eliminations

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First quarter 2005 compared to first quarter 2004

EBIT Our EBIT increased $46 million in the first quarter of 2005 as compared to the first quarter of 2004, primarily as a result of increased margin of $82 million, partially offset by an increase in operating expenses of $34 million.

Operating Margin$73 million of the $82 million increase in operating margin resulted from distribution operations, of which approximately $70 million resulted from the acquisition of NUI. The remaining $12 million primarily reflects increased contributions from retail energy operations in the amount of $9 million, increased contributions of $8 million in the energy investments segment, and an increase of $1 million in the corporate segment, offset by a $9 million decrease in wholesale services.

Operating Expenses Operating expenses increased by $34 million, of which $32 million was from our distribution operations where $37 million was as a result of the NUI acquisition. The higher expenses from NUI were offset by $2 million of lower expenses at Virginia Natural Gas Company and $1 million of lower expenses related to favorable bad debt expense compared to last year. Wholesale services’ operating expenses were $1 million less than in 2004 because of costs related to Sequent’s Energy Trading and Risk Management system in the first quarter of 2004. Energy investments expenses increased $4 million due primarily to the Jefferson Island acquisition. Operating expenses for the retail energy operations segment were essentially flat year-over-year.

Interest Expense Interest expense increased by $10 million from last year’s first quarter, primarily as a result of NUI and Jefferson Island acquisition debt ($8 million) and higher short-term interest rates ($2 million) as shown in the following table:

	Three months ended March 31,
Dollars in millions	2005			2004			2005 vs. 2004
Average debt outstanding (1)	$	1,820		$	1,214		$	606
Average rate		5.7	%		5.3	%		0.4	%

(1)   Daily average of all outstanding debt.

If, for the three months ended March 31, 2005, market interest rates on our variable rate debt had been 100 basis points higher, representing a 6.1% interest rate rather than our actual 5.1% interest rate, our year-to-date pretax interest expense would have increased by $4 million.

Income Taxes Income taxes increased by $14 million, primarily as a result of the higher pre-tax income for the first quarter of 2005.

Shares Outstanding Weighted average shares outstanding increased 12.3 million during the first quarter 2005, primarily as a result of our 11-million share equity offering completed in November 2004.

Distribution Operations

Distribution operations includes our natural gas local distribution utility companies, which 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 Company, Inc. (Virginia Natural Gas)

·   Florida City Gas (Florida Gas)

·   Chattanooga Gas Company (Chattanooga Gas)

·   Elkton Gas

Each utility operates subject to regulations provided by 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 consists generally 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 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.

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UpdatesThe following is a summary of significant developments with regard to our distribution operations segment that have occurred since we filed our 2004 Annual Report on Form 10-K on February 15, 2005.

Atlanta Gas Light On April 29, 2005, the Georgia Public Service Commission (Georgia Commission) issued an order (Order) in connection with Atlanta Gas Light’s rate case proceeding under Docket No. 18638-U, that would result in a reduction of operating revenues by up to $21.9 million annually, beginning on May 1, 2005. Also on April 29, 2005, Atlanta Gas Light filed a Motion for Stay of Order (Motion) requesting that the Georgia Commission immediately stay its Order until such time as the Georgia Commission rules on a petition for rehearing, reconsideration and oral argument that Atlanta Gas Light intends to file on or about May 9, 2005.

The Order adopted a “Comprehensive Rate Plan” (Plan) to fix base rates charged to customers at their current levels, and to levelize the rates in effect for the Pipeline Replacement Program Rider (PRP Rider). The Order accomplishes this by requiring Atlanta Gas Light to begin accruing, as of May 1, 2005, a regulatory liability equivalent to the amount of the reduction in operating revenues of $21.9 million. In October of each year, rates under the amounts charged to customers under the PRP Rider are normally adjusted upward to take into account the additional capital spent in the previous October to September fiscal year. The Order states that the PRP rates will be levelized at the current surcharge for the next three years, and that the regulatory liability account will be used to “supplement” the levelized rates. Therefore, as prescribed under the Plan, the Company is no longer permitted to make the annual adjustment in rates related to the PRP, which historically has been the recovery mechanism.

The Order also contained a specific provision that would have required Atlanta Gas Light to recapture the $21 million pre-tax gain previously recognized and associated with the sale of the real property associated with the Caroline Street campus in September 2003, resulting in recognition of a pre-tax charge of up to $21 million and an associated regulatory liability as of the quarter ended March 31, 2005. The Order made it probable that a liability had been incurred associated with a transaction occurring prior to the balance sheet date. We concluded in 2003, based on historical precedents and law, that the sale of the real property associated with the Caroline Street campus was a sale of a non-jurisdictional asset, and that any gain on the sale was not attributable to customers. The relevant provision in the Order would defer the $21 million pre-tax gain previously recorded and would amortize the gain into base rates over a 10-year period. The impact of this provision would be a $2.1 million annual reduction in rates, and this amount is included in the $21.9 million total annual reduction reflected in the Order.

On May 4, 2005, the Georgia Commission voted unanimously to stay, for up to 40 days, all provisions of the April 29, 2005 Order related to the Caroline Street sale, including the impact of the associated $2.1 million annual revenue reduction, in order to provide adequate time for Atlanta Gas Light to file for reconsideration of the Order and for the Commission to address the petition for reconsideration. Since this provision of the Order is not now in effect, management is unable to predict what the ultimate outcome will be of the Georgia Commission’s reconsideration of the Caroline Street issue and other issues associated with the Order. As a result, no expense or related regulatory liability has been recorded related to the Caroline Street gain as of March 31, 2005.

On March 1, 2005, Atlanta Gas Light completed its acquisition of 250 miles of interstate pipeline in central Georgia from Southern Natural Gas, a subsidiary of El Paso Corporation, for $32 million. The acquisition will improve deliverable capacity and reliability of the storage capacity from our LNG facility in Macon to our markets in Atlanta.

Virginia Natural Gas In March 2005, the Virginia State Corporation Commission (Virginia Commission) staff issued a report alleging that Virginia Natural Gas’ rates were excessive and that its rates should be adjusted to produce a $15 million reduction in revenue. The staff also filed a motion requesting that Virginia Natural Gas’ rates be declared interim and subject to refund. On April 11, 2005, Virginia Natural Gas responded to the staff’s report and motion and contested the allegations in the report and objected to the motion filed by the staff. Virginia Natural Gas also notified the Virginia Commission that it would file a general rate case before December 31, 2005. On April 29, 2005, the Virginia Commission ordered the staff’s motion be held in abeyance and directed Virginia Natural Gas to file a rate case by July 1, 2005.

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Elizabethtown Gas On April 26, 2005, Elizabethtown Gas presented the New Jersey Board of Public Utilities (NJBPU) with a proposal to accelerate the replacement of approximately 88 miles of 8” to 12” elevated pressure cast iron main. Under the proposal, approximately $42 million in estimated capital costs incurred over a three year period would be recovered through a pipeline replacement rider similar to the program in effect at Atlanta Gas Light. If the program as proposed is approved, cost recovery would occur on a one-year lag basis, with collections starting on October 1, 2006 and extending through December 31, 2009, after which time the program would be rolled into base rates.

Chattanooga Gas In October 2004, the Tennessee Regulatory Authority (Tennessee Authority) denied Chattanooga Gas’ request for a $4 million rate increase, instead approving an increase of approximately $1 million based on a 10.2% return on equity. In November 2004, the Tennessee Authority granted Chattanooga Gas’ motion for reconsideration of the rate increase and in December 2004 heard oral arguments on the issues of the appropriate capital structure and the return on equity to be used in setting Chattanooga Gas’ rates. In March 2005, Chattanooga Gas filed additional testimony and supporting documentation at the request of the Tennessee Authority. The Tennessee Authority has yet to issue a final ruling on Chattanooga Gas' request for reconsideration.

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Results of Operationsfor our distribution operations segmentfor the three months ended March 31, 2005 and 2004 are as follows:

	Three months ended March 31,
In millions	2005		2004		2005 vs. 2004
Operating revenues	$	634	$	389	$	245
Cost of gas		381		209		172
Operating margin		253		180		73
Operating expenses
Operation and maintenance		93		71		22
Depreciation and amortization		28		21		7
Taxes other than income		9		6		3
Total operating expenses		130		98		32
Operating income		123		82		41
Other income		-		-		-
EBIT	$	123	$	82	$	41
Metrics(includes information only for 2005 for utilities acquired from NUI)
Average end-use customers (in thousands)		2,266		1,840		23	%
Operation and maintenance expenses per customer	$	41	$	38		8
EBIT per customer	$	54	$	45		20
Throughput (in millions of dekatherms)
Firm		106		90		18	%
Interruptible		33		28		18
Total		139		118		18	%
Heating degree days(1):						% Colder / (Warmer	)
Florida		490		-		-	%
Georgia		1,396		1,503		(7	)
Maryland		2,684		-		-
New Jersey		2,755		-		-
Tennessee		1,545		1,716		(10	)
Virginia		1,975		1,853		7

(1)   We measure the effects of weather on our businesses using “degree days.” The measure of degree days for a given day is the difference between the average daily actual temperature and the baseline temperature of 65 degrees Fahrenheit. Heating degree days result when the average daily actual temperature is less than 65-degrees. Generally, increased heating degree days result in greater demand for gas on our distribution systems.

First quarter 2005 compared to first quarter 2004

EBIT Distribution operations’ EBIT increased $41 million in the first quarter of 2005 as compared to the first quarter of 2004, primarily as a result of increased margin of $73 million, partially offset by an increase in operating expenses of $32 million. The NUI acquisition contributed approximately $34 million of the $41 million increase in EBIT.

Operating MarginThe increase in operating margin of $73 million, or 41%, was primarily a result of the addition of NUI’s operations, which contributed $70 million. The remainder of the increase was the combination of higher operating margin at Atlanta Gas Light offset by lower operating margin at Virginia Natural Gas. The increase at Atlanta Gas Light was a result of higher PRP revenues, additional revenue from gas storage carrying charges billed to marketers and increased customer usage and growth. These results were offset by a reduction in operating margins at Virginia Natural Gas resulting from lower use per heating degree day and a change in the weather normalization adjustment calculation resulting from a regulatory order.

Operating Expenses The increase in operating expenses of $32 million, or 33%, primarily was a result of the addition of NUI’s operations, which contributed $37 million. This increase was offset primarily by lower operating expenses at Virginia Natural Gas, largely due to lower bad debt and payroll expenses.

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Retail Energy Operations

Our retail energy operations segment consists of SouthStar, a joint venture formed in 1998 by our subsidiary, Georgia Natural Gas Company, Piedmont Natural Gas Company, Inc. (Piedmont) and Dynegy Inc. (Dynegy). The purpose was to market natural gas and related services to retail customers on an unregulated basis, principally in Georgia. On March 11, 2003, we purchased Dynegy’s 20% ownership interest.

We currently own a non-controlling 70% financial interest in SouthStar, and Piedmont owns the remaining 30%. The SouthStar board of directors comprises six members, with three representatives from us and three from Piedmont. Under the partnership agreement, all significant management decisions require the unanimous approval of the SouthStar board of directors; accordingly, our 70% financial interest is considered to be non-controlling. Although our ownership interest in the SouthStar partnership is 70%, SouthStar's earnings are allocated 75% to us and 25% to Piedmont, under an amended and restated partnership agreement executed in March 2004.

Results of operations for our retail energy operations segment for the three months ended March 31, 2005 and 2004 are shown in the following table.

	Three months ended March 31,
In millions	2005			2004			2005 vs. 2004
Operating revenues	$	314		$	307		$	7
Cost of sales		248			250			(2	)
Operating margin		66			57			9
Operating expenses
Operation and maintenance		13			13			-
Depreciation and amortization		-			-			-
Taxes other than income		-			-			-
Total operating expenses		13			13			-
Operating income		53			44			9
Minority interest (1)		(13	)		(11	)		(2	)
EBIT	$	40			33		$	7
Average customers (in thousands)		531			550			(4	%)
Market share in Georgia		36	%		37	%		(3	%)

(1) Minority interest adjusts our earnings to reflect our 75% share of SouthStar’s earnings.

First quarter 2005 compared to first quarter 2004

EBIT SouthStar’s EBIT contribution of $40 million in 2005 was $7 million higher than last year, reflecting higher commodity margins and favorable asset management results during the quarter.

Operating MarginThe $9 million increase in operating margin is primarily a result of the higher commodity margins in 2005, partly offset by lower sales volumes due to 7% warmer weather in 2005. The higher margins resulted from larger storage spreads and favorable asset management activities during the quarter.

Operating Expenses Operating expenses were virtually flat year-over-year. SouthStar’s bad debt expenses decreased by $2 million in 2005 primarily as a result of significantly lower write-offs. However, this was substantially offset by a one-time vendor performance credit and the timing of marketing expenses in 2005.

Wholesale Services

Wholesale services consists of Sequent, our subsidiary involved in asset optimization, transportation, storage, producer and peaking services and wholesale marketing. Our asset optimization business focuses on capturing economic value from idle or underutilized natural gas assets, which 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 its customers with natural gas from the major producing regions and market hubs primarily in the Eastern and Mid-Continental United States. Sequent also 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 end-use customers.

Updates The following is a summary of significant developments with regard to our wholesale services segment that have occurred since we filed our 2004 Annual Report on Form 10-K on February 15, 2005.

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Asset Management Transactions Our asset management customers include our own utilities, nonaffiliated utilities, municipal utilities and large industrial customers. These customers must contract for transportation and storage services to meet their demands, and they typically contract for these services on a 365-day basis even though they may only need a portion of these services to meet their peak demands for a much shorter period. We enter into agreements with these customers, either through contract assignment or agency arrangement, whereby we use their rights to transportation and storage services during periods when they do not need them. We capture margin by optimizing the purchase, transportation, storage and sale of natural gas, and we typically either share profits with customers or pay them a fee for using their assets.

On April 1, 2005, in connection with the acquisition of NUI, Sequent commenced asset management responsibilities for Elizabethtown Gas, Florida Gas and Elkton Gas. The following table summarizes Sequent’s asset management transactions with our affiliated utilities.

Dollars in millions	Duration of contract (in years)		Expiration date		Frequency of payment		Profits shared / fees paid in 2005		Profits shared / fees paid in 2004
Virginia Natural Gas		5		Oct 2005		Annually	$	-	$	3
Atlanta Gas Light		3		Feb 2006		Semi-annually		3		4
Chattanooga Gas		3		Mar 2007		Annually		2		1
Elkton Gas		2		Mar 2007		Monthly		-		-
Elizabethtown Gas		3		Mar 2008		Monthly		-		-
Florida Gas		3		Mar 2008		Quarterly		-		-

(1)   For the three months ended March 31.

(2)   For the twelve months ended December 31.

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, 2005 and 2004, and provide details of the net fair value of contracts outstanding as of March 31, 2005. Sequent’s storage positions are affected by changes in the New York Mercantile Exchange, Inc. (NYMEX) average price.

	Three months ended March 31,
In millions	2005			2004
Net fair value of contracts outstanding at beginning of period	$	17			($5	)
Contracts realized or otherwise settled during period		9			4
Change in net fair value of contracts		(15	)		10
Net fair value of contracts outstanding at end of period		11			9
Less net fair value of contracts outstanding at beginning of period		17			(5	)
Unrealized (loss) gain related to changes in the fair value of derivative instruments		($6	)	$	14

The sources of our net fair value at March 31, 2005 are as follows:

In millions	Matures through March 2006			Matures through March 2009		Matures through March 2011		Matures after March 2012		Total net fair value
Prices actively quoted (1)	$	19			1		-		-	$	20
Prices provided by other external sources (1)		(13	)		3		1		-		(9	)

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

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Mark-to-Market versus Lower of Average Cost or Market We purchase natural gas for storage when the current market price we pay plus the cost for storage is less than the market price we could receive in the future. We attempt to mitigate substantially all of our commodity price risk associated with our storage portfolio. We use derivative instruments to reduce the risk associated with future changes in the price of natural gas. We sell NYMEX futures contracts or other over-the-counter derivatives in forward months to substantially lock-in the profit margin we will ultimately realize when the stored gas is actually sold.

Natural gas stored in inventory is accounted for differently than the derivatives we use to mitigate the commodity price risk associated with our storage portfolio. The difference in accounting can result in volatility in our reported net income, even though the profit margin is essentially unchanged from the date the transactions were consummated. Natural gas that we purchase and inject into storage is accounted for at the lower of average cost or market. The derivatives we use to mitigate commodity price risk are accounted for at fair value and marked to market each period. These differences in our accounting treatment result in volatility in our reported net income.

Earnings Volatility And Price Sensitivity As discussed above, we attempt to mitigate substantially all our commodity price risk associated with our storage portfolio. As a result, over time, gains or losses on the sale of inventory that we have haedged will be offset by losses or gains on the derivatives used as hedges, resulting in the realization of the profit margin we expected when we entered into the transactions. Accounting timing differences cause Sequent’s reported earnings on its storage positions to be affected by natural gas price changes, even though the economic profits remain essentially unchanged. Based upon our storage positions at March 31, 2005, a $0.10 change in the forward NYMEX prices would result in a $0.5 million impact to Sequent’s EBIT.

Storage Inventory Outlook The NYMEX forward curve graph set forth below reflects the NYMEX natural gas prices as of December 31, 2004 and March 31, 2005 for the period of April 2005 through March 2006, and reflects the prices at which we could buy natural gas at the Henry Hub for delivery in the same time period. April 2005 futures expired on March 29, 2005; however they are included in the table below as they coincide with the April storage withdrawals. 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.

The NYMEX forward curve graph also displays the significant increase in NYMEX prices experienced during the first quarter of 2005. As shown in the table following the graph, a significant portion of our inventory in storage as of March 31, 2005 is scheduled for withdrawal in July and August. Since we have these NYMEX contracts in place, our original economic profit margin is unaffected. However, the increase in NYMEX prices during the first quarter of 2005 resulted in unrealized losses associated with our NYMEX contracts. During the first quarter of 2004, we experienced the same phenomenon, although to a lesser degree. See further discussions in “Results of Operations” below.

As shown in the table, “Open Futures NYMEX Contracts” represents the volume in contract equivalents of the transactions we executed to lock in our storage inventory margin. Each contract equivalent represents 10,000 million British thermal units (MMBtu’s). As of March 31, 2005, the expected withdrawal schedule of this inventory is reflected in items (B) and (C) of the table to the graph. At March 31, 2005, the weighted average cost of gas (WACOG) in salt dome storage was $6.74, and the WACOG for gas in reservoir storage was $6.33.

The table also reflects that our storage inventory is fully hedged with futures as evidenced by the NYMEX short positions (A) being equal to the physical long positions (B and C), which results in an overall locked-in margin, timing notwithstanding. Expected gross margin after regulatory sharing reflects the gross margin we would generate in future periods based on the forward curve and inventory withdrawal schedule at March 31, 2005. Our current inventory level and pricing should result in gross margin of approximately $7 million through March 2006. This gross margin will likely change as we adjust our daily injection and withdrawal plans in response to changes in market conditions in future months.

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													Total
(A)	(114)	(89)	(66)	(165)	(225)	(21)	(68)	-	-	-	(41)	(46)	(835)
(B)	80	64	-	-	-	-	-	-	-	-	-	-	144
(C)	34	25	66	165	225	21	68	-	-	-	41	46	691
	114	89	66	165	225	21	68	-	-	-	41	46	835
(D)	$0.8	$0.7	$0.4	$1.1	$2.0	$0.3	$0.7	-	-	-	$0.6	$0.6	$7.2

(A) Open futures NYMEX contracts (short) long (in MMBtu)

(B) Physical salt dome withdrawal schedule (in MMBtu)

(C) Physical reservoir withdrawal schedule (in MMBtu)

(D) Expected gross margin, in millions, after regulatory sharing for withdrawal activity

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Credit Rating Sequent has certain trade and credit contracts that have explicit credit 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, we would need to post collateral to continue transacting business with some of our counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If at March 31, 2005, our credit ratings had been downgraded to non-investment grade, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $15 million.

Results of Operations for our wholesale services segmentfor the three months ended March 31, 2005 and 2004 are as follows:

	Three months ended March 31,
In millions	2005		2004		2005 vs. 2004
Operating revenues	$	11	$	20		($9	)
Cost of sales		-		-
Operating margin		11		20		(9	)
Operating expenses
Operation and maintenance		7		8		(1	)
Depreciation and amortization		-		-		-
Taxes other than income		-		-		-
Total operating expenses		7		8		(1	)
Operating income		4		12		(8	)
Other income		-		-
EBIT	$	4	$	12		($8	)
Metrics
Physical sales volumes (Bcf/day)		2.3		2.1		10	%

First quarter 2005 compared to first quarter 2004

EBIT The decrease in EBIT of $8 million in 2005 as compared to 2004 was due to a decrease in operating margin of $9 million, partially offset by a decrease in operating expenses of $1 million.

Operating MarginThe $9 million reduction in operating margin reflects the negative impact of changes in forward NYMEX prices during late 2004 and early 2005, partially offset by improved origination operations during the 2005 period. During December 2004, there was a significant decline in forward NYMEX prices which resulted in the recognition of gains associated with the financial instruments used to hedge Sequent’s inventory held in storage. The majority of this inventory was scheduled for withdrawal during the first quarter of 2005 and, as a result, $5 million of margin that was originally anticipated to be recognized during the first quarter of 2005 was recognized in 2004. The results for the first quarter of 2004 did not experience a similar impact. Also, as a result of an increase in forward NYMEX prices during the first quarter of 2005, the results for this period reflect the recognition of $8 million of losses associated with our inventory hedges. The results for the first quarter of 2004 were similarly affected; however, the earnings impact was less than $1 million. Partially offsetting the negative impacts of forward NYMEX price changes was a $5 million increase in origination results in the Northeast market due to higher transportation spreads.

Operating ExpensesOperating expenses decreased $1 million as a result of lower outside services costs associated with the prior year implementation of our ETRM system and certain one-time SOX compliance costs incurred in 2004. The reduced expenses were partially offset by higher payroll costs related to increased headcount.

Energy Investments

Our energy investments segment includes:

·   Jefferson Island

·   Pivotal Propane of Virginia

·   Virginia Gas Company

·   50% ownership interest in Saltville Gas Storage Company, LLC (Saltville)

·   AGL Networks, LLC

On April 27, 2005, we announced our agreement to sell our 50% interest in Saltville and our wholly-owned subsidiaries Virginia Gas Pipeline and Virginia Gas Storage to Duke Energy Corporation, the other 50% partner in Saltville. We acquired these Virginia assets in November 2004 with our purchase of NUI. We will retain Virginia Gas Distribution Company, another NUI asset, which has 270 customers and annual throughput of 240,000 dekatherms.

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When completed, the sale will make Duke Energy the sole owner of Saltville, which operates a storage facility that currently has approximately 2.0 billion cubic feet of capacity. We will receive, subject to working capital adjustments, $62 million in cash at closing and will utilize the proceeds to repay debt and for other general corporate purposes. The transaction is not expected to have a material impact on our earnings. Closing of the transaction, which is conditional upon regulatory approvals, including approval from the Virginia State Corporation Commission, is expected in the third quarter of 2005.

Results of operations for our energy investments segment for the three months ended March 31, 2005 and 2004 are shown in the following table.

	Three months ended March 31,
In millions	2005		2004		2005 vs. 2004
Operating revenues	$	12	$	1	$	11
Cost of sales		3		-		3
Operating margin		9		1		8
Operating expenses
Operation and maintenance		3		1		2
Depreciation and amortization		2		-		2
Taxes other than income		-		-		-
Total operating expenses		5		1		4
Operating income		4		-		4
Other income		1		1		-
EBIT	$	5	$	1	$	4

First quarter 2005 compared to first quarter 2004

EBIT The $4 million EBIT growth year-over-year is from the addition of Jefferson Island.

Operating MarginOperating margin in the energy investments segment increased $8 million, primarily as a result of the addition of Jefferson Island (which contributed $4 million of the increase), the addition of Virginia Gas Company and Saltville obtained with the NUI acquisition (which contributed $2 million of the increase) and improved margins at AGL Networks (which contributed approximately $1 million of the increase) during the quarter.

Operating Expenses Operating expenses in the Energy Investments segment increased $4 million, primarily driven by the addition of Pivotal Jefferson Island, Virginia Gas Company and Saltville and additional expenses at AGL Networks associated with projects in Phoenix and Atlanta.

Corporate

Our corporate segment includes our nonoperating business units, including AGL Services Company (AGSC), AGL Capital Corporation (AGL Capital) and Pivotal Energy Development (Pivotal). AGSC is a service company established in accordance with the Public Utility Holding Company Act of 1935, as amended (PUHCA). AGL Capital provides for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities, and other financing arrangements.

Pivotal coordinates, among our related operating segments, the development, construction or acquisition of assets in the Southeast and Mid-Atlantic regions in order to extend our natural gas capabilities and improve system reliability while enhancing service to our customers in those areas. The focus of Pivotal’s commercial activities is to improve the economics of system reliability and natural gas deliverability in these targeted regions.

We allocate substantially all of AGSC’s and AGL Capital’s operating expenses and interest costs to our operating segments in accordance with PUHCA and 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.  The acquisition of additional assets, such as NUI and Jefferson Island, typically will enable us to allocate corporate costs across a larger number of businesses and, as a result, lower the relative allocations charged to those business units we owned prior to the acquisition of the new businesses.

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Results of operations for our corporate segmentfor the three months ended March 31, 2005 and 2004 are as follows:

	Three months ended March 31,
In millions	2005			2004			2005 vs. 2004
Payroll	$	13		$	11		$	2
Benefits and incentives		8			10			(2	)
Outside services		8			6			2
Depreciation and amortization		3			3			-
Taxes other than income		2			2			-
Other		11			11			-
Total operating expenses before allocations		45			43			2
Allocation to operating segments		(42	)		(38	)		(4	)
Total operating expenses		3			5			(2	)
Other losses		-			-			-
EBIT		($3	)		($5	)	$	2

First quarter 2005 compared to first quarter 2004

EBIT The corporate segment had a $2 million positive EBIT variance in the first quarter of 2005 relative to the same period last year. The key drivers of corporate operating expense are detailed in the above table and summarized below.

Payroll Expense Corporate payroll expenses were $2 million higher than last year. Approximately $1 million of the increase related to the acquisition of NUI. The remaining $1 million is the result of increased headcount.

Benefits and Incentives A $2 million reduction in benefits and incentive expenses was primarily the result of $1 million lower incentive pay and $1 million lower group insurance expense charged to AGSC.

Outside Services A $2 million increase in outside services resulted primarily from additional spending in the information technology area, including $2 million in projects related to NUI integration and $1 million related to customer solution projects.

Other Our corporate segment recorded a $2 million loss on the retirement of some information technology assets in the first quarter of 2004 that was absent from this year’s results.

Liquidity and Capital Resources

We rely on operating cash flow; short-term borrowings under our commercial paper program, which is backed by our supporting credit agreement (Credit Facility); and borrowings or stock issuances in the long-term capital markets to meet our capital and liquidity requirements. 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 and the SEC. 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 and unused availability under our Credit Facility is limited and subject to conditions specified within the Credit Facility, which we currently meet. These conditions specified within the Credit Facility include:

·   compliance with certain financial covenants

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

·   our total debt-to-capital ratio

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

In millions	March 31, 2005		Dec. 31, 2004
Unused availability under the Credit Facility	$	750	$	750
Cash and cash equivalents		24		49
Total cash and available liquidity under the Credit Facility	$	774	$	799

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We believe these sources will be sufficient for our working capital needs, debt service obligations and scheduled capital expenditures for the foreseeable future. The relatively stable operating cash flows of our distribution operations businesses currently contribute most of our cash flow from operations, and we anticipate this to continue in the future. However, we have historically had a working capital deficit, primarily as a result of our use of short-term debt to finance the purchase of long-term assets, principally property, plant and equipment. We will continue to evaluate our need to increase our available liquidity based upon our view of 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 impact of the integration of NUI

·   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 rate-making 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

Regulatory changes that could have a significant long-term impact on our liquidity and capital resource requirements include, but are not limited to, the ultimate impact of the Georgia Commission’s recent Order affecting Atlanta Gas Light. An unfavorable ruling by the Georgia Commission could negatively impact our future cash flow available to pay dividends or to repay debt obligations. At this time, we are unable to neither quantify nor identify the timing of such an impact, as it is dependent on future spending and the timing of capital expenditures.

Seasonality The seasonal nature of our sales affects the comparison of certain balance sheet items at March 31, 2005 and December 31, 2004, such as receivables, unbilled revenue, inventories and short-term debt. We have presented the condensed consolidated balance sheet as of March 31, 2004 to provide comparisons of these items with the corresponding period of the preceding year.

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. We calculate any pension contribution expense using an actuarial method called the projected unit credit cost method, and as a result of our calculations, we do not expect to make a pension contribution in 2005. The following table illustrates our expected future contractual obligations:

			Payments due before December 31,
					2006		2008		2010
					&		&		&
In millions	Total		2005		2007		2009		Thereafter
Pipeline charges, storage capacity and gas supply(1)	$	1,756	$	208	$	502	$	423	$	623
Long-term debt(2) (3)		1,618		-		2		2		1,614
Pipeline replacement program costs(4)		346		76		178		92		-
Operating leases (5)		146		14		32		28		72
Commodity and transportation charges		129		20		23		14		72
ERC(4)		74		12		14		11		37
Short-term debt (3)		38		38		-		-		-
Communication/network service and maintenance		12		5		7		-		-
Total	$	4,119	$	373	$	758	$	570	$	2,418
(1) Charges recoverable through a purchased gas adjustment mechanism or alternatively billed to Marketers. Also includes demand charges associated with Sequent. (2) Includes $232 million of Notes Payable to Trusts, callable in 2006 or 2007. (3) Does not include the interest expense associated with long-term and short-term debt. (4) Charges recoverable through rate rider mechanisms. (5) We have certain operating leases with provisions for step rent or escalation payments, or 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.

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SouthStar has natural gas purchase commitments related to the supply of minimum natural gas volumes to its customers. These commitments are priced on an index plus premium basis. At March 31, 2005, SouthStar had obligations under these arrangements for 11 Bcf through December 31, 2005.

We have also incurred various contingent financial commitments in the normal course of business. The following table illustrates our expected contingent financial commitments representing obligations that become payable only if certain pre-defined events occur, such as financial guarantees, reflecting the maximum potential amount of future payments that could be required of us as of March 31, 2005:

			Commitments due before December 31,
					2006		2008		2010
					&		&		&
In millions	Total		2005		2007		2009		Thereafter
Guarantees (1)	$	7	$	7	$	-	$	-	$	-
Standby letters of credit, performance/ surety bonds		15		12		3		-		-
Total	$	22	$	19	$	3	$	-	$	-
(1) We provide guarantees on behalf of SouthStar. We guarantee 70% of SouthStar’s obligations to SNG under certain agreements between the parties up to a maximum of $7 million if SouthStar fails to make payment to SNG.

Cash flow provided from operating activities Our condensed consolidated statements of cash flows are prepared using the indirect method. Under this method, net income is reconciled to cash flows from operating activities by adjusting net income for those items that impact net income but do not result in actual cash receipts or payments during the period. These reconciling items include depreciation, changes in deferred income taxes and changes in the balance sheet for working capital from the beginning to the end of the period.

Year-over-year changes in our operating cash flows are attributable primarily to working capital changes within our distribution operations and retail energy operations segments resulting from the impact of weather, the price of natural gas, the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries. In the first quarter of 2005, our net cash flow provided from operating activities was $391 million an increase of $56 million from the same period last year.

The increase was primarily a result of an increase in net income of $22 million and working capital contributions of approximately $34 million. The increase in net income was principally from the inclusion of the acquired NUI utilities in our operations and improved results at our retail energy operations segment.

The working capital contributions primarily include decreased payments for accrued taxes of $51 million, increased cash from the collection of our receivables of $26 million and increased cash of $18 million from the draw down of our natural gas inventories used to satisfy the winter sales demand. These working capital contributions were offset by increased cash payments for our payables of approximately $67 million, primarily from our energy marketing payables due to increased NYMEX prices.

Cash flow used in investing activities Our cash used in investing activities consists primarily of property, plant and equipment expenditures. As shown in the following table, we made investments of $81 million in the three months ended March 31, 2005 and $45 million in the same period in 2004.

	Three months ended
	March 31,
In millions	2005		2004
Distribution operations	$	72	$	36
Retail energy operations		-		2
Wholesale services		-		3
Energy investments		3		4
Corporate		6		-
Total property, plant and equipment expenditures	$	81	$	45

The increase of $36 million is primarily from higher expenditures at our distribution operations segment, including $32 million for the acquisition of a 250 mile pipeline in Georgia from SNG and approximately $7 million in expenditures at Elizabethtown Gas and Florida Gas.

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Cash flow used in financing activities Our financing activities primarily consist 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 and issuances of common stock. 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 by us of the percentage of our total debt relative to our total capitalization, as well as the term and interest rate profile of our debt securities.

We also work to maintain or improve our credit ratings on our senior notes 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 credit ratings or our stock price and have not entered into any transaction that would require us to issue equity based on credit ratings or other trigger events. As of May 2005, our senior unsecured debt ratings were BBB+ from Standard & Poor’s Rating Services (S&P), Baa1 from Moody’s Investor Service (Moody’s) and A- from Fitch Ratings.

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 maximum leverage ratio, minimum net worth, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. Our Credit Facility’s financial covenants and our (PUHCA) financing authority require us to maintain a ratio of total debt-to-total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. We are currently in compliance with all existing debt provisions and covenants.

We believe that accomplishing these 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, 2005				December 31, 2004				March 31, 2004
Short-term debt	$	38	1	%	$	334	10	%	$	100	5	%
Current portion of long-term debt		-	-			-	-			33	1
Long-term debt (1)		1,618	52			1,623	48			970	46
Total debt		1,656	53			1,957	58			1,103	52
Minority interest		30	1			36	1			27	1
Common equity		1,446	46			1,385	41			1,002	47
Total capitalization	$	3,132	100	%	$	3,378	100	%	$	2,132	100	%

(1)   Net of interest rate swaps

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Short-term debt Our short-term debt is composed of borrowings under our commercial paper program, Sequent’s line of credit, the current portion of our capital lease obligation due within the next year and SouthStar’s line of credit. The decrease in our short-term debt of $295 million is primarily a result of payments on outstanding commercial paper from:

·   cash generated from strong operating results

·   positive working capital from lower inventory and receivable requirements

Refinancing of Gas Facility Revenue BondsOn April 19, 2005, we refinanced $20 million in Gas Facility Revenue Bonds due October 1, 2024. These bonds, which had a fixed interest rate of 6.4%, were refunded with $20 million of adjustable rate Gas Facility Revenue Bonds. The maturity date of these bonds remains October 1, 2024. The bonds were issued at an initial interest rate of 2.8% and initially have a 35-day auction period, where the interest rate will adjust every 35 days.

On May 5, 2005, we refinanced an additional $46 million in Gas Facility Revenue Bonds due October 1, 2022 and bearing interest at a fixed rate of 6.35%. The new bonds were issued at an initial interest rate of 2.9% and initially have a 35-day auction period where the interest rate will adjust every 35 days. The maturity date remains October 1, 2022.

Dividends on Common StockIn February 2005, we announced a 7% increase in our common stock dividend, raising the quarterly dividend from $0.29 per share to $0.31 per share, which equates to an indicated annual dividend of $1.24 per share. The increase in our common stock dividend of $5 million for the three months ended March 31, 2005 as compared to the same period last year was a result of our increased quarterly dividend and the increase in the number of shares outstanding as a result of our November 2004 equity offering.

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 consolidated financial statements are described in our Annual Report on Form 10-K for the year ended December 31, 2004 and includes the following:

·   Regulatory Accounting

·   Pipeline Replacement Program

·   Environmental Remediation Liabilities

·   Revenue Recognition

·   Purchase Price Allocation

·   Derivatives and Hedging Activities

·   Accounting for Contingencies

·   Allowance for Doubtful Accounts

·   Accounting for Pension Benefits

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, 2004.

Accounting Developments

For information regarding accounting developments, see "Note 3 - Recent Accounting Pronouncements."

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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 Committee (RMC) is responsible for the overall establishment of risk management policies and the monitoring of compliance with and adherence to the terms within these policies, including approval and authorization levels and delegation of these levels. Our RMC consists of senior executives who monitor commodity price risk positions, corporate exposures, credit exposures and overall results of our risk management activities. The RMC is chaired by our chief risk officer, who is responsible for ensuring that appropriate reporting mechanisms exist for the RMC to perform its monitoring functions. Our risk management activities and related accounting treatment are described in further detail in Note 4 to the condensed consolidated financial statements.

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Commodity Price Risk

Wholesale Services This segment 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, option contracts and financial swap agreements. The following table includes the fair values and average values of our energy marketing and risk management assets and liabilities as of March 31, 2005, December 31, 2004 and March 31, 2004. We based the average values on monthly averages for the three months ended March 31, 2005 and the twelve months ended December 31, 2004.

Natural gas contracts	Average values				Value at:
In millions	Three months ended March 31, 2005		Twelve months ended Dec. 31, 2004		March 31, 2005		Dec. 31, 2004		March 31, 2004
Asset	$	54	$	28	$	72	$	36	$	30
Liability		38		21		61		19		21

We employ a systematic approach to the evaluation and management of the risks associated with our contracts related to wholesale marketing and risk management, including value-at-risk (VaR). VaR is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability.

We use a 1-day and a 10-day holding period and a 95% confidence interval to evaluate our VaR exposure. 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 calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price volatility, confidence interval and holding period. Our VaR may not be comparable to a similarly titled measure of another company because, although VaR is a common metric in the energy industry, there is no established industry standard for calculating VaR or for the assumptions underlying such calculations.

Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the chief risk officer. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally minimal, permitting us to operate within relatively low VaR limits. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of our open positions.

Our management actively monitors open commodity positions and the resulting VaR. We continue to maintain a relatively matched book, where our total buy volume is close to our sell volume, with minimal open commodity risk. Based on a 95% confidence interval and employing a 1-day and a 10-day holding period for all positions, our portfolio of positions for the three months ended March 31, 2005 had the following 1-day and 10-day holding period VaRs:

	Three months ended March 31, 2005
In millions	1-day		10-day
Period end (1)	$	0.0	$	0.1
Average		0.2		0.5
High		0.4		1.3
Low (1)		0.0		0.0

(1)   $0.0 values represent amounts less than $0.1 million.

Retail Energy Operations SouthStar’s use of derivatives is governed by a risk management policy which prohibits the use of derivatives for speculative purposes. This policy also establishes VaR limits of $0.5 million on a 1-day holding period and $0.7 million on a 10-day holding period. A 95% confidence interval is used to evaluate VaR exposure. The maximum VaR experienced during the three months ended March 31, 2005 was less than $0.2 million for the 1-day holding period and $0.5 million for the 10-day holding period.

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Credit Risk

Sequent may require its counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for our counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not meet the minimum ratings threshold.

Sequent evaluates its counterparties using the S&P equivalent credit rating which is determined by a process of converting the lower of the S&P or Moody’s rating to an internal rating ranging from 9.00 to 1.00, with 9.00 being equivalent to AAA/Aaa by S&P and Moody’s and 1.00 being equivalent to D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based a variety of financial metrics.

The weighted average credit rating is obtained by multiplying each counterparty’s assigned internal rating by the counterparty’s credit exposure and the individual results are then summed for all counterparties. That total is divided by the aggregate total counterparties’ exposure. This numeric value is converted to an S&P equivalent. Under the refined methodology, Sequent’s counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of BBB+ at March 31, 2005, compared with our previously reported rating of A- at December 31, 2004 and BBB+ at March 31, 2004. For more information on Sequent’s counterparties credit ratings, see the discussion in “Results of Operations - Wholesale Services.” The following tables show Sequent’s commodity receivable and payable positions as of the dates indicated:

Gross receivables
In millions	March 31, 2005		Dec. 31, 2004		March 31, 2004
Receivables with netting agreements in place:
Counterparty is investment grade	$	295	$	378	$	232
Counterparty is non-investment grade		28		36		8
Counterparty has no external rating		59		78		11
Receivables without netting agreements in place:
Counterparty is investment grade		12		16		17
Counterparty is non-investment grade		2		6		-
Counterparty has no external rating		-		-		-
Amount recorded on balance sheet	$	396	$	514	$	268

Gross payables
In millions	March 31, 2005		Dec. 31, 2004		March 31, 2004
Payables with netting agreements in place:
Counterparty is investment grade	$	215	$	291	$	189
Counterparty is non-investment grade		46		45		33
Counterparty has no external rating		141		139		50
Payables without netting agreements in place:
Counterparty is investment grade		37		40		43
Counterparty is non-investment grade		-		6		3
Counterparty has no external rating		-		-		-
Amount recorded on balance sheet	$	439	$	521	$	318

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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, 2005, the end of the period covered by this report, except, and in accordance with the Public Company Accounting Oversight Board’s Auditing Standard No. 2, An Audit of Internal Control Over Financial Reporting Performed in Conjunction With an Audit of Financial Statements, the disclosure controls and procedures of Jefferson Island and NUI were excluded from management’s evaluation, as Jefferson Island and NUI were acquired on October 1, 2004 and November 30, 2004, respectively. 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, 2005 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 identified in connection with the evaluation described in paragraph (a) above that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls 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 "Results of Operations - Distribution Operations" contained in Item 2 of Part I under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations." 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.

Item 6. Exhibits

3.1

Amended and Restated Articles of Incorporation filed January 5, 1996, with the Secretary of State of the state of Georgia (incorporated herein by reference to Exhibit B, Proxy Statement and Prospectus filed as a part of Amendment No. 1 to AGL Resources Inc. Registration Statement on Form S-4, No. 33-99826).

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).

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Rule 13a-14(a) / 15d-14(a) Certifications

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Section 1350 Certifications

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SIGNATURE

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

	AGL RESOURCES INC.
	(Registrant)
Date: May 5, 2005	/s/ Richard T. O'Brien
	Executive Vice President and Chief Financial Officer

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