AGL RESOURCES INC - 10-Q Quarterly Report

Table of Contents

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

FORM 10-Q

(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2004

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 X No

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X 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 October 21, 2004
Common Stock, $5.00 Par Value		65,363,168


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AGL RESOURCES INC.

Form 10-Q

For the Quarterly Period Ended September 30, 2004

TABLE OF CONTENTS

Item Number		Page(s)
	Glossary of key terms and referenced accounting standards	3-4

	PART I - FINANCIAL INFORMATION

1	Condensed Consolidated Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets	5-6
	Condensed Consolidated Statements of Income	7
	Condensed Consolidated Statements of Common Shareholders’ Equity	8
	Condensed Consolidated Statements of Cash Flows	9
	Notes to Condensed Consolidated Financial Statements
	Note 1 - Accounting Policies and Methods of Application	10-12
	Note 2 - NUI Corp. Acquisition	12
	Note 3 - Recent Accounting Pronouncements	13-14
	Note 4 - Risk Management	15-17
	Note 5 - Regulatory Assets and Liabilities	18-19
	Note 6 - Pension and Other Postretirement Benefits	20
	Note 7 - Financing	21-22
	Note 8 - Commitments and Contingencies	22-23
	Note 9 - Income Taxes	24
	Note 10 - Segment Information	25-27
	Note 11 - Subsequent Events	27
2	Management's Discussion and Analysis of Financial Condition and Results of Operations
	Cautionary Statement Regarding Forward-Looking Statements	28-29
	Overview	30-33
	Results of Operations
	AGL Resources	34-36
	Distribution Operations	37-40
	Wholesale Services	41-45
	Energy Investments	46-50
	Corporate	51
	Liquidity and Capital Resources	52-57
	Critical Accounting Policies and Estimates	58-59
	Accounting Developments	60
3	Quantitative and Qualitative Disclosures About Market Risk	61-63
4	Controls and Procedures	64

	PART II - OTHER INFORMATION

1	Legal Proceedings	65
2	Unregistered Sales of Equity Securities and Use of Proceeds	65
3	Defaults Upon Senior Securities	66
4	Submission of Matters to a Vote of Security Holders	66
5	Other Information	66
6	Exhibits and Reports on Form 8-K	66

	SIGNATURE	67


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GLOSSARY OF KEY TERMS

AGLC	Atlanta Gas Light Company
AGL Capital	AGL Capital Corporation
AGL Networks	AGL Networks, LLC
AGL Resources	AGL Resources Inc. and its subsidiaries
AGSC	AGL Services Company
CGC	Chattanooga Gas Company
Corporate	Nonoperating segment, which includes AGSC and AGL Capital
Credit Facility	Credit agreement supporting our commercial paper program
Distribution operations	Segment that includes AGLC, VNG and CGC
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income, other income, equity in SouthStar’s income in 2003, donations, minority interest in 2004 and gain on sales of assets. Excludes interest and tax expense; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, operating income or net income as determined in accordance with GAAP
Energy investments	Segment that consists primarily of SouthStar, AGL Networks, Pivotal Propane of Virginia Inc. and US Propane through the date of its sale in January 2004
ERC	Environmental response costs
FASB	Financial Accounting Standards Board
FIN	FASB Interpretation Number
GAAP	Accounting principles generally accepted in the United States of America
GPSC	Georgia Public Service Commission
Jefferson Island	Jefferson Island Storage & Hub, L.L.C.
LNG	Liquefied natural gas
Marketers	Georgia Public Service Commission-certificated marketers selling retail natural gas in Georgia
Medium-Term notes	Notes issued by AGLC scheduled to mature in 2004 through 2027 bearing interest rates ranging from 6.55% to 8.7%
MGP	Manufactured gas plant
NUI	NUI Corporation and its subsidiaries
NYMEX	New York Mercantile Exchange, Inc.
Operating margin	A non-GAAP measure of income, calculated as revenues minus cost of gas, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain on the sale of our Caroline Street campus; these items are included in our calculation of operating income as reflected in our statements of consolidated income; operating margin should not be considered an alternative to, or more meaningful than, operating income or net income as determined in accordance with GAAP
PGA	Purchased gas adjustment
Pivotal	Pivotal Energy Development
PRP	Pipeline replacement program
PUHCA	Public Utility Holding Company Act of 1935, as amended
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
Senior notes	Notes issued by AGL Capital scheduled to mature in 2011 through 2034 bearing interest rates ranging from 4.45% to 7.125%
SFAS	Statement of Financial Accounting Standards
SouthStar	SouthStar Energy Services LLC
Trust Preferred Securities	Trust preferred securities subject to mandatory redemption
Trusts	AGL Capital Trust I and AGL Capital Trust II
US Propane	US Propane LP
VNG	Virginia Natural Gas, Inc.
VSCC	Virginia State Corporation Commission
Wholesale services	Segment that consists primarily of Sequent
WNA	Weather normalization adjustment


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REFERENCED ACCOUNTING STANDARDS

APB 25	Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”
ARB 51	Accounting Research Bulletin No. 51, “Consolidated Financial Statements”
EITF 99-02	Emerging Issues Task Force Issue No. 99-02, “Accounting for Weather Derivatives”
EITF 02-03	Emerging Issues Task Force Issue No. 02-03, “Issues Involved in Accounting for Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’”
EITF 04-08	Emerging Issues Task Force Issue No. 04-08, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share”
FIN 46 & FIN 46R	FASB Interpretation No. 46, “Consolidation of Variable Interest Entities”
FSP 106-1	FASB Staff Position No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”
FSP 106-2	FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”
SFAS 66	SFAS No. 66, “Accounting for Sales of Real Estate”
SFAS 71	SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 123	SFAS No. 123, “Accounting for Stock-Based Compensation”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 149	SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”


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Item 1. Financial Statements

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

In millions	September 30, 2004		December 31, 2003		September 30, 2003
Current assets
Cash and cash equivalents	$	44	$	17	$	1
Receivables (less allowance for uncollectible accounts of $12 million at September 30, 2004, $2 million at December 31, 2003 and $2 million at September 30, 2003)		328		394		210
Unbilled revenues		34		40		6
Inventories		340		210		254
Unrecovered environmental response costs - current		26		24		24
Unrecovered pipeline replacement program costs - current		24		22		19
Energy marketing and risk management assets		33		13		10
Other		19		22		19
Total current assets		848		742		543
Property, plant and equipment
Property, plant and equipment		3,509		3,402		3,400
Less accumulated depreciation		1,072		1,050		1,166
Property, plant and equipment-net		2,437		2,352		2,234
Deferred debits and other assets
Unrecovered pipeline replacement program costs		358		410		426
Goodwill		177		177		177
Unrecovered environmental response costs		147		155		163
Investments in Trusts		10		-		-
Unrecovered postretirement benefit costs		9		9		11
Investments in equity interests		-		101		115
Other		48		26		19
Total deferred debits and other assets		749		878		911
Total assets	$	4,034	$	3,972	$	3,688

See Notes to Condensed Consolidated Financial Statements (Unaudited).


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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

In million, except per share amounts	September 30, 2004		December 31, 2003		September 30, 2003
Current liabilities
Payables	$	423	$	403	$	299
Short-term debt		51		306		127
Accrued pipeline replacement program costs - current		88		82		74
Accrued expenses		38		54		55
Accrued environmental response costs - current		25		40		54
Current portion of long-term debt		34		77		42
Energy marketing and risk management liabilities		26		17		8
Other		98		69		48
Total current liabilities		783		1,048		707
Accumulated deferred income taxes		433		376		360
Long-term liabilities
Accrued pipeline replacement program costs		264		323		345
Accumulated removal costs		93		102		-
Accrued postretirement benefit costs		48		51		52
Accrued pension obligations		28		39		62
Accrued environmental response costs		36		43		40
Other		10		11		10
Total long-term liabilities		479		569		509
Deferred credits		70		77		73
Commitments and contingencies (Note 8)
Minority interest		30		-		-
Capitalization
Senior and Medium-Term notes		981		731		904
Notes payable to Trusts		235		-		-
Subsidiaries’ obligated mandatorily redeemable preferred securities		-		225		227
Total long-term debt		1,216		956		1,131
Common shareholders’ equity, $5 par value; 750,000,000 shares authorized		1,023		946		908
Total capitalization		2,239		1,902		2,039
Total liabilities and capitalization	$	4,034	$	3,972	$	3,688

See Notes to Condensed Consolidated Financial Statements (Unaudited).


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

	Three months ended						Nine months ended
	September 30,						September 30,
In millions, except per share amounts	2004			2003			2004			2003
Operating revenues	$	262		$	165		$	1,206		$	704
Operating expenses
Cost of gas		105			28			626			222
Operation and maintenance expenses		83			66			257			208
Depreciation and amortization		23			23			71			68
Taxes other than income		5			6			20			21
Total operating expenses		216			123			974			519
Gain on sale of Caroline Street campus		-			16			-			16
Operating income		46			58			232			201
Equity in earnings of SouthStar		-			5			-			29
Other income		-			1			2			1
Donation to private foundation		-			(8	)		-			(8	)
Interest expense		(17	)		(19	)		(49	)		(57	)
Minority interest		-			-			(14	)		-
Earnings before income taxes		29			37			171			166
Income taxes		9			15			64			65
Income before cumulative effect of change in accounting principle		20			22			107			101
Cumulative effect of change in accounting principle, net of taxes		-			-			-			(8	)
Net income	$	20		$	22		$	107		$	93
Basic earnings per common share
Income before cumulative effect of change in accounting principle	$	0.31		$	0.35		$	1.66		$	1.61
Cumulative effect of change in accounting principle		-			-			-			(0.13	)
Basic earnings per common share	$	0.31		$	0.35		$	1.66		$	1.48
Diluted earnings per common share
Income before cumulative effect of change in accounting principle	$	0.31		$	0.34		$	1.64		$	1.59
Cumulative effect of change in accounting principle		-			-			-			(0.12	)
Diluted earnings per common share	$	0.31		$	0.34		$	1.64		$	1.47
Weighted-average number of common shares outstanding
Basic		65.1			64.0			64.8			62.6
Diluted		65.8			64.8			65.5			63.2

See Notes to Condensed Consolidated Financial Statements (Unaudited).


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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 amounts	Shares		Amount		shares		reinvested			income			Total
Balance as of December 31, 2003		64.5	$	322	$	326	$	338			($40	)	$	946
Comprehensive income:
Net income		-		-		-		107			-			107
Unrealized gain from hedging activities (net of taxes)		-		-		-		-			1			1
2003 tax adjustment in 2004 (1)		-		-		-		-			1			1
Total comprehensive income														109
Dividends on common shares ($0.86 per share)		-		-		-		(56	)		-			(56	)
Benefit, stock compensation, dividend reinvestment and share purchase plans ($29.55) weighted average price per share		0.8		5		19		-			-			24
Balance as of September 30, 2004		65.3	$	327	$	345	$	389			($38	)	$	1,023

(1) See Note 9, Income Taxes.

See Notes to Condensed Consolidated Financial Statements (Unaudited).


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

	Nine months ended
	September 30,
In millions	2004			2003
Cash flows from operating activities
Net income	$	107		$	93
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		71			68
Cumulative effect of accounting change		-			13
Gain on sale of Caroline Street campus		-			(16	)
Deferred income taxes		57			35
Equity in earnings of unconsolidated affiliates, net of distributions		-			(23	)
Minority interest		14			-
Changes in certain assets and liabilities
Receivables		200			149
Payables		(38	)		(43	)
Inventories		(102	)		(136	)
Other		(54	)		(39	)
Net cash flow provided by operating activities		255			101
Cash flows from investing activities
Property, plant and equipment expenditures		(168	)		(113	)
Purchase of Dynegy Inc.’s 20% ownership interest in SouthStar		-			(20	)
Cash received from sale of Caroline Street campus		-			23
Sale of ownership interest in US Propane		31			-
Other		13			2
Net cash flow used in investing activities		(124	)		(108	)
Cash flows from financing activities
Payments and borrowings of short-term debt, net		(261	)		(261	)
Payments of Medium-Term notes		(49	)		(72	)
Dividends paid on common shares		(56	)		(53	)
Borrowings from senior notes		250			225
Distribution to minority interest		(14	)		-
Proceeds of equity offering		-			137
Other		26			24
Net cash flow used in financing activities		(104	)		-
Net increase (decrease) in cash and cash equivalents		27			(7	)
Cash and cash equivalents at beginning of period		17			8
Cash and cash equivalents at end of period	$	44		$	1
Cash paid during the period for
Interest (net of allowance for funds used during construction)	$	36		$	43
Income taxes	$	27		$	9

See Notes to Condensed Consolidated Financial Statements (Unaudited).


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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). We believe, however, that our disclosures are adequate and the information pr esented is not misleading.

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, 2003, filed with the SEC on February 6, 2004.

Due to the seasonal nature of our business, our results of operations for the three and nine months ended September 30, 2004 and 2003 and our financial position as of December 31, 2003 and September 30, 2004 and 2003 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other interim period or as of or for the year ending December 31, 2004. For a glossary of key terms and referenced accounting standards, see pages 3 and 4 of this filing.

Basis of Presentation

Our condensed consolidated financial statements as of and for the periods ended September 30, 2004 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, 2003 balance sheet amounts are derived from our audited financial statements.

Our condensed consolidated financial statements include the accounts of SouthStar Energy Services LLC (SouthStar), a variable interest entity of which we are the primary beneficiary. Previously, we accounted for our 70% non-controlling financial ownership interest in SouthStar using the equity method of accounting. Under the equity method, our ownership interest in SouthStar was reported as an investment within our consolidated balance sheet, and our share of SouthStar’s earnings was reported in our condensed consolidated statement of income as a component of other income. We utilize the equity method to account for and report investments 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) Interpretati on No. 46, “Consolidation of Variable Interest Entities” (FIN 46). Our equity method investments generally include entities where we have a 20% to 50% voting interest. FIN 46 was revised in December 2003 (FIN 46R). For more discussion of FIN 46R and the impact of its adoption on our condensed consolidated financial statements, see Note 3, Recent Accounting Pronouncements.


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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 Standard 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 had an exercise price equal to the market value of the underlying common stock on the date of grant. For our stock appreciation righ ts, 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				Nine months ended
	September 30,				September 30,
In millions, except per share amounts	2004		2003		2004		2003
Net income, as reported	$	20	$	22	$	107	$	93
Deduct: Total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effect		-		-		1		-
Pro-forma net income	$	20	$	22	$	106	$	93

Earnings per share:
Basic-as reported	$	0.31	$	0.35	$	1.66	$	1.48
Basic-pro-forma	$	0.30	$	0.34	$	1.64	$	1.48

Diluted-as reported	$	0.31	$	0.34	$	1.64	$	1.47
Diluted-pro-forma	$	0.30	$	0.34	$	1.63	$	1.46

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 and nine months ended September 30, 2004, our OCI increased $2 million as a result of the fair value of derivatives at SouthStar in the amount of $1 million and a $1 million related to the 2003 income tax adjustments recorded in 2004, as discussed in Note 9, Income Taxes. The income tax adjustments were related to the deferred taxes associated with our 2003 pension additional minimum liability.

For the three and nine months ended September 30, 2003, we recorded an after-tax charge to OCI of $1 million for our 70% ownership interest in SouthStar’s unrealized loss associated with its cash flow hedges.


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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 performance units and stock options. The future issuance of shares underlying the performance 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. There were no anti-dilutive items for the respective periods. The following table shows the calculation of our diluted shares, assuming performance units currently earned under the plan ultimately vest and stock options currently exercisable at prices below the average market prices are exercised:

	Three months ended				Nine months ended
	September 30,				September 30,
In millions	2004		2003		2004		2003
Denominator for basic earnings per share (1)		65.1		64.0		64.8		62.6
Assumed exercise of performance units and stock options		0.7		0.8		0.7		0.6
Denominator for diluted earnings per share		65.8		64.8		65.5		63.2

(1)	Daily weighted-average shares outstanding

Note 2
NUI Corporation Acquisition

On July 15, 2004, we announced that our board of directors approved a definitive merger agreement under which we will acquire all of the outstanding shares of NUI Corporation (NUI) for $13.70 per share in cash, or $220 million in the aggregate based on approximately 16 million shares outstanding, and the assumption of NUI’s outstanding debt at closing. At June 30, 2004, NUI had approximately $606 million in debt and $111 million of cash on its balance sheet, bringing the estimated net value of the acquisition to $715 million.

On October 21, 2004, NUI’s shareholders approved the transaction. The sale remains subject to regulatory approvals by the SEC and state regulatory agencies of New Jersey, Maryland and Virginia as well as various other closing conditions unrelated to regulatory approvals. We have asked for expedited treatment from the SEC and various state regulatory agencies. The merger agreement provides that the closing must occur on or prior to April 11, 2005, but the closing may be extended for an additional 90 days until July 11, 2005, in the event the parties have not obtained the required consents for the acquisition.


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Note 3

Recent Accounting Pronouncements

FIN 46

FIN 46 requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities.

In December 2003, the FASB revised FIN 46, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance. For potential variable interest entities other than any special purpose entities, FIN 46R was required to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004.

FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities. Effective January 1, 2004 we adopted FIN 46R resulting in the consolidation of SouthStar’s accounts in our condensed consolidated financial statements and the deconsolidation of the accounts related to our trust preferred securities.

Notes Payable to Trusts and Trust Preferred Securities In June 1997 and March 2001, we established AGL Capital Trust I and AGL Capital Trust II (Trusts) to issue our Trust Preferred Securities. The Trusts are considered to be special purpose entities under FIN 46 and FIN 46R since our equity in the Trusts is not considered to be sufficient to allow the Trusts to finance their own activities and our equity investment is not considered to be at risk since the equity amounts were financed by the Trusts.

Under FIN 46 (prior to the revision in FIN 46R), we concluded that we were the primary beneficiary of the Trusts because the Trust Preferred Securities are publicly traded, widely held, and no one party would absorb a majority of any expected losses of the Trusts. In addition, our loan agreements with the Trusts include call options allowing us to capture the benefits of declining interest rates since the options enable us to call the preferred securities at par, giving us the ability to capture the majority of the residual returns in the Trusts. Accordingly, at December 31, 2003, the accounts of the Trusts were included in our consolidated financial statements.

The revisions in FIN 46R included specific guidance that instruments such as the call options included in our loan agreements with the Trusts do not constitute variable interests and should not be considered in the determination of the primary beneficiary. As a result, as of January 1, 2004 we were required to exclude the accounts of the Trusts from our consolidated financial statements upon our adoption of FIN 46R and to classify amounts payable to the Trusts as “Notes payable to Trusts” within Capitalization in our condensed consolidated balance sheets as of September 30, 2004.

The impact of deconsolidation of the Trusts is that we have included in our condensed consolidated balance sheets at September 30, 2004, an asset of approximately $10 million representing our investment in the Trusts and a note payable to the Trusts totaling approximately $235 million, which is net of an interest rate swap of $3 million, and removed $222 million related to the Trust Preferred Securities issued by the Trusts. The notes payable represent the loan payable to fund our investments in the Trusts of $10 million and the amounts due to the Trusts from the proceeds received from their issuances of Trust Preferred Securities of $222 million.

SouthStar is a joint venture formed in 1998 by our subsidiary, Georgia Natural Gas Company, Piedmont Natural Gas Company, Inc. (Piedmont) and Dynegy Inc. (Dynegy) to market natural gas and related services to retail customers, principally in Georgia. On March 11, 2003, we purchased Dynegy’s 20% ownership interest in a transaction that for accounting purposes had an effective date of February 18, 2003. We currently own a non-controlling 70% financial interest in SouthStar and Piedmont owns the remaining 30%. Our 70% interest is non-controlling because all significant management decisions require approval by both owners.


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On March 29, 2004 we executed an amended and restated partnership agreement with Piedmont. This amended and restated partnership agreement calls for SouthStar’s future earnings starting in 2004 to be allocated 75% to our subsidiary and 25% to Piedmont. For all periods prior to February 18, 2003, SouthStar’s earnings have been allocated to us based upon our ownership interests in those periods of 50%. SouthStar, which operates under the trade name Georgia Natural Gas, competes with other energy marketers, including Marketers in Georgia, to provide natural gas and related services to customers in Georgia and the Southeast.

As of December 31, 2003, we did not consolidate SouthStar in our financial statements because it did not meet the definition of a variable interest entity under FIN 46. FIN 46R added the following conditions for determining whether an entity was a variable interest entity:

·	the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both, and

·	substantially all of the entity’s activities (for example purchasing products and additional capital) either involve or are conducted on behalf of an investor that has disproportionately fewer voting rights.

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, and

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

Consequently, as of January 1, 2004, we consolidated all of SouthStar’s accounts with our subsidiaries’ accounts and eliminated any intercompany balances between segments. We recorded Piedmont’s portion of SouthStar’s earnings as a minority interest in our condensed consolidated statements of income, and we recorded Piedmont’s portion of SouthStar’s capital as a minority interest on our condensed consolidated balance sheet.


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Note 4
Risk Management

Our risk management activities are monitored by our Risk Management Committee (RMC). The RMC is charged with the review and enforcement of our risk management policies. Our risk management policies limit the use of derivative financial instruments and physical transactions within pre-defined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following derivative financial instruments and physical 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 Statement of Financial Accounting Standards (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.

Accordingly, 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.

In March 2004 we adjusted our fixed to variable-rate debt obligations and terminated an interest rate swap on $100 million of the principal amount of our 4.45% Senior Notes due 2013. Additionally, as of March 31, 2004 and in connection with the deconsolidation of the Trusts, we re-designated the interest rate swaps on the Trust Preferred Securities as a fair value hedge of our notes payable to the Trusts.

As of September 30, 2004, 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. The aggregate fair value of these interest rate swaps was recorded as an asset of $1 million at September 30, 2004, as a liability of $4 million at December 31, 2003 and as an asset of $1 million at September 30, 2003. Our interest rate swaps consist of the following:

$100 million principal amount of 7.125% Senior Notes due 2011. We pay floating interest each January 14 and July 14 at six-month LIBOR plus 3.4%. The effective variable interest rate at September 30, 2004 was 5.2%, an increase of 0.7% from December 31, 2003. These interest rate swaps expire January 14, 2011, unless terminated earlier.

$75 million principal amount of 8.0% notes payable to Trusts due 2041. We pay floating interest rates each February 15, May 15, August 15 and November 15 at three-month LIBOR plus 1.315%. The effective interest rate at September 30, 2004 was 3.0%, an increase of 0.5% from December 31, 2003. These interest rate swaps expire May 15, 2041, unless terminated earlier.


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In the third quarter 2004, in anticipation of our $250 million senior note offering, we executed two treasury lock derivative instruments totaling $200 million to hedge our exposure to the potential increase in interest rates. These derivative instruments locked in a 10 year U.S. treasury rate of 4.45%. The rate on the 10-year treasury notes declined subsequently to the execution of these instruments and the pricing of our senior notes was set on a U.S. treasury rate of 4.81%. As a result, we terminated these derivative instruments and made an $8 million settlement payment to our counterparties, which will be amortized over the next 10 years through interest expense. The termination added approximately 30 basis points to the interest rate of our 6% senior notes.

Commodity-Related Derivative Instruments

Sequent We are exposed to risks associated with changes in the market price of natural gas. 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 the financial instruments we utilize.

We attempt to mitigate substantially all the commodity price risk associated with Sequent’s natural gas portfolio to lock 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 New York Mercantile Exchange (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 rec orded at fair value 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.

Our commodity-related derivative financial instruments, which exclude interest rate swaps, had a weighted average maturity of 9 months based on volumes. At September 30, 2004, our commodity-related derivative financial instruments represented purchases (long) of 415 billion cubic feet (Bcf) with approximately 99% of these scheduled to mature in less than 2 years. In addition, our financial instruments included sales (short) of 455 Bcf with approximately 92% of these scheduled to mature in less than 2 years and the remaining 8% in 3-9 years. For the nine months ended September 30, excluding the cumulative effect of a change in an accounting principle in 2003 for the adoption of Emerging Issues Task Force Issue No. 02-03, “Issues Involved in Accounting for Contracts under EITF Issue No. 98-10, ‘Accounting f or Contracts Involved in Energy Trading and Risk Management Activities’”, our unrealized gains were $5 million in 2004 and $8 million in 2003.

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 minimize this risk using the most effective methods to reduce or eliminate the impacts of these exposures. A significant 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 inst rument 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 no hedge ineffectiveness. The remainder of SouthStar’s derivative instruments do not meet the hedge criteria under SFAS 133. Therefore, changes in their fair value are recorded in earnings in the period of change. At September 30, 2004, the fair value of these derivatives was reflected in our condensed consolidated financial statements as an asset of $14 million and liability of $6 million. The maximum maturity of open positions is less than 1 year and represents purchases of 18 Bcf and sales of 4 Bcf.


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Weather Derivative Contracts

SouthStar routinely enters into weather derivative contracts for hedging purposes in order to preserve margins in the event of warmer-than-normal weather in the winter months. SouthStar accounts for these contracts using the intrinsic value method under the guidelines of EITF 99-02, “Accounting for Weather Derivatives”. There were no weather derivative contracts outstanding as of September 30, 2004 and 2003.

Concentration of Credit Risk

Distribution Operations AGLC has a concentration of credit risk for amounts billed for services and other costs to its customers, ten Marketers and poolers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. These retail functions include customer service, billing, collections, and the purchase and sale of natural gas. The provisions of AGLC’s tariff allow AGLC to obtain security support in an amount equal to a minimum of two times a Marketer’s highest monthly bill.

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 counterparties. Sequent evaluates its counterparties using the S&P equivalent credit rating which is determined by a process of converting the lower of the Standard & Poor’s Rating Services (S&P) or Moody’s Investor Service (Moody’s) 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 coun terparty 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 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. At September 30, 2004, Sequent’s top 20 counterparties represented approximately 56% of the total counterparty credit exposure of $297 million, derived by adding the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures. Sequent’s counterparties or the counterparties’ guarantors had a weighted average Standard & Poor’s Ratings Services equivalent of an A rating at September 30, 2004.

Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. When we are engaged in more than one outstanding derivative transaction with the same counterparty and we also have a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of our credit risk. Sequent also uses other netting agreements with certain counterparties with whom we conduct significant transactions.


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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 response costs (ERC), are summarized in the table below:

In millions	Sept. 30, 2004		Dec. 31, 2003		Sept. 30, 2003
Regulatory assets
Unrecovered PRP costs	$	382	$	432	$	445
Unrecovered ERC		173		179		187
Unrecovered postretirement benefit costs		9		9		11
Unrecovered seasonal rates (1)		10		11		10
Unamortized call premium (2)		6		4		3
Regulatory tax asset (2)		3		3		2
Other (3)		-		1		-
Total regulatory assets	$	583	$	639	$	658
Regulatory liabilities
Accumulated removal costs	$	93	$	102	$	-
Unamortized investment tax credit (5)		18		19		19
Deferred PGA (4)		34		30		13
Regulatory tax liability (5)		14		15		15
Other (3)		2		3		1
Total regulatory liabilities		161		169		48
Associated liabilities
PRP costs		352		405		419
ERC		61		83		94
Total associated liabilities		413		488		513
Total regulatory and associated liabilities	$	574	$	657	$	561

(1) Presented in other current assets in our condensed consolidated balance sheets.

(2) Presented in other deferred debits and other assets in our condensed consolidated balance sheets.

(3) Presented in other deferred debits and other assets, other current liabilities and accrued postretirement benefit costs in our condensed consolidated balance sheets.

(4) Presented in other current liabilities in our condensed consolidated balance sheets.

(5) Presented in deferred credits in our condensed consolidated balance sheets.

Our regulatory assets and liabilities are described in our Annual Report on Form 10-K for the year ended December 31, 2003. The following represent significant changes to our regulatory assets and liabilities during the nine months ended September 30, 2004:

Environmental Response Costs

Our latest engineering estimate for the remaining costs to remediate certain former manufactured gas plant (MGP) sites was $51 million, a reduction of $16 million from the estimate as of December 31, 2003. The decrease was primarily a result of actual expenditures in 2004, partially offset by increases in certain future engineering cost estimates. For those remaining elements of the MGP program where AGLC 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 MGP sites is $13 million, a reduction of $2 million from the estimate as of December 31, 2003. AGLC estimates certain other costs related to administering the MGP program an d remediation of sites currently in the investigation phase. Through January 2005, AGLC estimates the administrative costs to be $3 million.


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For those sites currently in the investigation phase, our estimate is $9 million. This estimate is based upon preliminary data received during 2003 with respect to the existence of contamination at those sites. Our range of estimates for these sites is from $9 million to $15 million. We have accrued the low end of our range, or $9 million, as this is our best estimate at this phase of the remediation process. AGLC’s ERC liability is composed of the elements in the following table:

In millions	Sept. 30, 2004			Dec. 31, 2003			Sept. 30, 2003
Projected engineering estimates and in-place contracts (1)	$	51		$	67		$	72
Estimated future remediation costs (1)		13			15			15
Administrative expenses		3			3			3
Other expenses		9			9			9
Cash payments for cleanup expenditures (2)		(15	)		(11	)		(5	)
Accrued ERC	$	61		$	83		$	94

(1) As of June 30, 2004, September 30, 2003 and June 30, 2003.

(2) Expenditures during the three months ended September 30, 2004, December 31, 2003 and September 30, 2003.

The ERC liability is included in a corresponding regulatory asset. As of September 30, 2004, the regulatory asset was $173 million, which is a combination of accrued ERC and unrecovered cash expenditures. 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 AGLC may be held liable but with respect to which we cannot reasonably estimate an amount.

AGLC has three ways of recovering investigation and cleanup costs. First, the Georgia Public Service Commission has approved an ERC recovery rider. It allows recovery of the costs of investigation, testing, cleanup and litigation. Because of this 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. AGLC recovered $18 million during the nine months ended September 30, 2004, through its ERC recovery rider.

The second way AGLC can recover costs is by exercising the legal rights AGLC believes it has to recover a share of its costs from other potentially responsible parties, typically former owners or operators of the MGP sites. There were no material recoveries from potentially responsible parties during the nine months ended September 30, 2004.

The third way AGLC can recover costs is from the receipt of net profits from the sale of remediated property. On June 30, 2004, a residential and retail development located in Savannah, Georgia and adjacent to a former MGP site was sold, resulting in a gain of $6 million. All gains on sales of MGP property are required by the ERC recovery rider to be shared 70% with ratepayers. As a result, approximately $4 million was credited to the MGP program as a reduction to the regulatory asset.

The ERC recovery mechanism allows for recovery of expenditures over a five-year period subsequent to the period in which the expenditures are incurred. As of September 30, 2004, the MGP expenditures expected to be incurred over the next 12 months are reflected as a current liability of $25 million. In addition, AGLC expects to collect $26 million in revenues over the next 12 months under the ERC recovery rider, which is reflected as a current asset.


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Note 6

Pension and Other Postretirement Benefits

The measurement date for our pension and other postretirement benefit plans is December 31. In April 2004, we made a $13 million contribution to our pension plan, and we do not anticipate making any additional contributions in 2004. The following are the costs components of our pension plan for the periods indicated:

Pension Benefits	Three months ended						Nine months ended
	September 30,						September 30,
In millions	2004			2003			2004			2003
Service cost	$	1		$	1		$	4		$	3
Interest cost		5			4			14			14
Expected return on plan assets		(6	)		(6	)		(17	)		(17	)
Net amortization		-			-			(1	)		(1	)
Recognized actuarial loss		2			1			3			2
Net annual cost	$	2		$	-		$	3		$	1

The following are the cost components of our other postretirement benefit plan for the periods indicated:

Other Benefits	Three months ended					Nine months ended
	September 30,					September 30,
In millions	2004			2003		2004			2003
Service cost	$	-		$	-	$	1		$	1
Interest cost		1			2		5			6
Expected return on plan assets		-			-		(2	)		(2	)
Net amortization		(1	)		-		(1	)		1
Recognized actuarial loss		-			-		1			-
Net annual cost	$	-		$	2	$	4		$	6

We amended our Defined Benefit Postretirement Health Care and Life Insurance Plan to discontinue prescription drug benefits to retirees age 65 and older after January 1, 2006. The amendment reduced our accumulated postretirement benefit obligation by $24 million and our net annual cost by $2 million for 2004.


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Note 7

Financing

						Outstanding as of:
Dollars in millions	Year Due		Int. rate (3)			Sept. 30, 2004			Dec. 31, 2003			Sept. 30, 2003
Short-term debt
Commercial paper (1)		2004		1.9	%	$	51		$	303		$	121
Current portion of long-term debt		2004		7.6 - 7.8			34			77			42
Sequent line of credit (2)		-		-			-			3			6
Total short-term debt (3)				4.2	%	$	85		$	383		$	169
Long-term debt - net of current portion
Medium-Term notes
Series A		2021		9.1	%	$	30		$	30		$	30
Series B		2012-2022		8.3 - 8.7			61			61			95
Series C		2015-2027		6.6 - 7.3			117			122			258
Senior notes		2011-2034		4.5 - 7.1			775			525			525
AGL Capital interest rate swaps		2011		5.2			(2	)		(7	)		(4	)
Total Medium-Term and Senior notes						$	981		$	731		$	904
Notes payable to Trusts		2037-2041		8.0 - 8.2	%	$	232		$	-		$	-
Trust Preferred Securities
AGL Capital Trust I		2037		-			-			74			74
AGL Capital Trust II		2041		-			-			148			148
AGL Capital interest rate swaps		2041		3.0			3			3			5
Total notes payable to Trusts							235			-			-
Total Trust Preferred Securities							-			225			227
Total long-term debt (3)				6.2	%	$	1,216		$	956		$	1,131

Total short-term and long-term debt (3)				6.1	%	$	1,301		$	1,339		$	1,300

(1)	The daily weighted average rate was 1.3% for the nine months ended September 30, 2004.

(2)	The daily weighted average rate was 1.7% for the nine months ended September 30, 2004.

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

Short-term Debt

Our short-term debt is composed of borrowings under our commercial paper program which consists of short-term unsecured promissory notes with maturities ranging from 4 to 12 days, maturities within one year of AGLC’s Medium-Term notes, Sequent’s line of credit and SouthStar’s line of credit. The commercial paper program is supported by our Credit Facility.

On April 19, 2004, SouthStar amended its $75 million revolving line of credit, which is used to meet seasonal working capital needs. SouthStar’s line of credit is scheduled to expire on April 19, 2007 and is not guaranteed by us. Any amounts outstanding under SouthStar’s line of credit would be included on our balance sheet. At September 30, 2004 there were no outstanding borrowings. Sequent also has a $25 million line of credit, which is used solely for the posting of exchange deposits and is unconditionally guaranteed by us. On June 14, 2004, Sequent extended this line of credit until July 1, 2005.

On September 30, 2004, we amended our credit facility that supports our commercial paper program (Credit Facility). Under the terms of the amendment, the credit agreement has been extended from May 26, 2007 to September 30, 2009. The aggregate principal amount available under the amended credit agreement has been increased from $500 million to $750 million, the cost of borrowing has been decreased and our option to increase the aggregate cumulative principal amount available for borrowing on not more than one occasion during each calendar year during the term of the amended credit agreement has been increased from $200 million to $250 million.


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Long-term Debt

On September 27, 2004, AGL Capital issued $250 million of senior notes with a maturity date of October 1, 2034. These senior notes have an interest rate of 6.0% payable on April 1 and October 1, beginning April 1, 2005. We fully and unconditionally guarantee the senior notes. The proceeds from the issuance were used to refinance a portion of the short-term debt under our commercial paper program and for general corporate purposes.

Note 8

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 have not been any significant changes to our contractual obligations which were described in our Annual Report on Form 10-K for the year ended December 31, 2003.

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 September 30, 2004, SouthStar had obligations under these arrangements for 1.8 Bcf through December 31, 2004, and 2.8 Bcf for the year ending December 31, 2005. SouthStar also had capacity commitments related to the purchase of transportation rights on interstate pipelines.

We also have incurred various contingent financial commitments in the normal course of business. Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our expected contingent financial commitments as of September 30, 2004:

			Commitments Due before December 31,
					2005 &		2007 &		2009 &
In millions	Total		2004		2006		2008		Thereafter
Guarantees (1) (2)	$	251	$	251	$	-	$	-	$	-
Standby letters of credit, performance/ surety bonds		12		8		4		-		-
Total other commercial commitments	$	263	$	259	$	4	$	-	$	-

(1)

$180 million of these guarantees support credit exposures in Sequent’s energy marketing and risk management business related to Sequent’s gas purchases. In the event that Sequent defaults on any commitments under these guarantees, these amounts would become payable by us as guarantor. These amounts are included in ‘payables’ on our condensed consolidated balance sheet and do not represent additional amounts due.

(2)

We provide gurantees on behalf of our subsidiary, SouthStar. We guarantee 70% of SouthStar's obligations to SNG under certain agreements between the parties up to a maximum of $7 million of SouthStar fails to make payments to SNG. Under a second such guarantee, we guarantee SouthStar's obligations to AGLC under certain agreements between the parties up to a maximum of $64 million. We have an agreement with our partner in SouthStar to indemnify us for their 30% obligation under this guarantee.


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Litigation We are involved in litigation arising in the normal course of business. We believe the ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Changes to the status of previously disclosed litigation are as follows:

City of Augusta In the first quarter of 2004, we settled a lawsuit with the city of Augusta, Georgia which had served AGLC with a complaint that was filed in the Superior Court of Richmond County, Georgia on July 1, 2003. The City of Augusta’s allegations included fraud and deceit and damages to realty. The allegations arose from negotiations between the city and AGLC regarding the environmental cleanup obligations connected with AGLC’s former MGP operations in Augusta. The settlement had no material impact to our condensed consolidated financial statements.

NUI shareholder complaint In September 2004, a shareholder class action complaint (Complaint) was filed in a civil action captioned Green Meadows Partners, LLP on behalf of itself and all others similarly situated v. Robert P. Kenney, Bernard S. Lee, Craig G. Mathews, Dr. Vera King Farris, James J. Forese, J. Russell Hawkins, R. Van Whisnand, John Kean, NUI and the Company, pending in the Superior Court of the S tate of New Jersey, County of Somerset, Law Division. The Complaint, brought on behalf of a potential class of the stockholders of NUI, names as defendants all of the directors of NUI (Individual Defendants), NUI and the Company. We first became aware of the Complaint when NUI notified us that it had been formally served on September 9, 2004 and forwarded us a copy of the Complaint for our review. We were formally served with the Complaint on September 14, 2004.

The Complaint alleges that purported financial incentives in the form of change of control payments and indemnification rights created a conflict of interest on the part of certain of the Individual Defendants in evaluating a possible sale of NUI. NUI has communicated that it believes the change in control payments include a retirement plan for directors, last amended as of January 24, 1995, that provides for a lump sum payment of the retirement benefits that would be paid to such directors on retirement, discounted for present value, in the event of a change of control.

The Complaint further alleges that the Individual Defendants, aided and abetted by the Company, breached fiduciary duties owed to the plaintiff and the potential class by (i) deciding to sell NUI to the Company without making the requisite effort to obtain the best share price, (ii) agreeing to an unfair and inadequate cash sale price of $13.70 per share, (iii) entering into a merger agreement with the Company that provided for a $7.5 million break-up fee, and (iv) failing to disclose material information in NUI’s preliminary proxy statement filed on August 13, 2004, including, among other things, (a) the precise amount of consideration received by each director in connection with the sale of NUI, (b) strategic alternatives considered by NUI and its financial advisors, (c) additional details of the sale proces s, and (d) prior relationships, if any, between NUI, the Company and/or NUI’s financial advisors.

The Complaint demands judgment (i) determining that the action is properly maintainable as a class action, (ii) declaring that the Individual Defendants breached fiduciary duties owed to the plaintiff and the potential class, aided and abetted by the Company, (iii) enjoining the sale of NUI, or if consummated, rescinding the sale, (iv) eliminating the $7.5 million break-up fee with the Company, (v) awarding the plaintiff and the potential class compensatory and/or rescissory damages, (vi) awarding interest, attorney’s fees, expert fees and other costs, and (vii) granting such other relief as the Court may find just and proper.

On October 12, 2004, we reached an agreement in principle with Green Meadows Partners, LLP to settle this litigation. Although we believe that the Complaint is without merit, we also believe that litigation could delay and create uncertainty as to our ability to consummate the acquisition of NUI and that such delay and uncertainty are not in the Company’s or our shareholders’ best interests.

The settlement calls for NUI to provide certain additional information and disclosures to its shareholders, as reflected in the “Additional Disclosure” section of NUI’s proxy statement supplement, filed on October 12, 2004 with the SEC. In addition, as part of the settlement, NUI and the Company will consent to a settlement class that consists of persons holding shares of NUI common stock at any time from July 15, 2004 until the date on which the acquisition is consummated, and we will pay plaintiff’s attorney’s fees and costs in the amount of $285,000. No part of these attorney’s fees or costs will be paid out of funds that would otherwise have been paid to NUI’s shareholders.


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Note 9

Income Taxes

Reconciliations between the statutory federal and state income tax rate and our actual effective rate for the three and nine months ended September 30, 2004 and 2003 are as follows:

	Three months ended September 30,												Nine months ended September 30,
	2004						2003						2004						2003
Dollars in millions	Amount			% of Pretax Income			Amount			% of Pretax Income			Amount			% of Pretax Income			Amount			% of Pretax Income
Computed tax expense	$	10			35.0	%	$	13			35.0	%	$	60			35.0	%	$	58			35.0	%
State income tax, net of federal income tax benefit		2			6.9			2			5.0			7			4.1			7			4.0
Amortization of investment tax credits		-			-			-			-			-			-			-			-
Flexible dividend deduction		-			-			(1	)		(1.0	)		(1	)		(0.5	)		(1	)		(0.6	)
Tax accrual adjustment (1)		(3	)		(10.3	)		-			-			(3	)		(1.7	)		-			-
Other-net		-			-			-			-			1			0.5			1			0.6
Total income tax expense	$	9			31.0	%	$	15			39.0	%	$	64			37.4	%	$	65			39.0	%

(1)

In the third quarter of 2004, we made adjustments of approximately $3 million to reduce our income tax expense for the three and nine months ended September 30, 2004 resulting from a reconciliation of our income tax accruals as compared to our income tax returns for 2003 that we filed in September 2004. The adjustments related to differences in amounts estimated as of December 31, 2003 and the actual amounts reflected in our tax returns as well as additional deductions for state income taxes reflected in our federal income tax return.


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Note 10

Segment Information

Our business is organized into three operating segments:

·	Distribution operations consists of AGLC, Virginia Natural Gas (VNG) and Chattanooga Gas Company (CGC).

·	Wholesale services consists primarily of Sequent.

·	Energy investments consists primarily of SouthStar, AGL Networks, LLC, Pivotal Propane of Virginia Inc. and US Propane LP through the date of its sale in January 2004.

We treat corporate, our fourth 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 and nine months ended September 30, 2004 and 2003 from our condensed statements of consolidated income.

We evaluate segment performance based on the non-GAAP measure of earnings before interest and taxes (EBIT), which includes the effects of corporate expense allocations. EBIT is a non-GAAP measure that includes operating income, other income, equity in SouthStar’s income in 2003, donations, minority interest in 2004 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. We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance tho se activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

You should not consider EBIT an alternative to, or a more meaningful indicator of our operating performance than, operating income or net income as determined in accordance 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 and nine months ended September, 2004 and 2003 are presented below.

	Three months ended Sept. 30,					Nine months ended Sept. 30,
In millions	2004		2003			2004			2003
Operating revenues	$	262	$	165		$	1,206		$	704
Operating expenses		216		123			974			519
Gain on sale of Caroline Street campus		-		16			-			16
Operating income		46		58			232			201
Other income		-		(2	)		2			22
Minority interest		-		-			(14	)		-
EBIT		46		56			220			223
Interest expense		17		19			49			57
Earnings before income taxes		29		37			171			166
Income taxes		9		15			64			65
Income before cumulative effect of change in accounting principle		20		22			107			101
Cumulative effect of change in accounting principle		-		-			-			(8	)
Net income	$	20	$	22		$	107		$	93


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Summarized income statement information and capital expenditures as of and for the three and nine months ended September 30, 2004 and 2003 by segment are shown in the following tables:

	Three months ended September 30,
	Distribution Operations					Wholesale Services					Energy Investments					Corporate and Intersegment Eliminations						Consolidated AGL Resources

In millions	2004		2003			2004			2003		2004		2003			2004			2003			2004		2003
Operating revenues from external parties	$	129	$	160		$	3		$	4	$	130	$	1		$	-		$	-		$	262	$	165
Intersegment revenues (1)		37		-			-			-		-		-			(37	)		-			-		-
Total revenues		166		160			3			4		130		1			(37	)		-			262		165
Operating expenses
Cost of gas		31		28			-			-		111		-			(37	)		-			105		28
Operation and maintenance		63		62			4			3		17		2			(1	)		(1	)		83		66
Depreciation and amortization		20		21			-			-		1		-			2			2			23		23
Taxes other than income taxes		4		6			-			-		-		-			1			-			5		6
Total operating expenses		118		117			4			3		129		2			(35	)		1			216		123
Gain (loss) on sale of Caroline Street campus (2)		-		21			-			-		-		-			-			(5	)		-		16
Operating income (loss)		48		64			(1	)		1		1		(1	)		(2	)		(6	)		46		58
Equity in earnings of SouthStar		-		-			-			-		-		5			-			-			-		5
Other income		-		1			-			-		-		-			-			-			-		1
Donation to private foundation		-		(8	)		-			-		-		-			-			-			-		(8	)
Minority interest		-		-			-			-		-		-			-			-			-		-
EBIT	$	48	$	57			($1	)	$	1	$	1	$	4			($2	)		($6	)	$	46	$	56

Capital expenditures	$	49	$	32		$	2		$	-	$	8	$	-		$	5		$	3		$	64	$	35

	Nine months ended September 30,
	Distribution Operations					Wholesale Services				Energy Investments						Corporate and Intersegment Eliminations						Consolidated AGL Resources

In millions	2004		2003			2004		2003		2004			2003			2004			2003			2004			2003
Operating revenues from external parties	$	595	$	662		$	23	$	37	$	588		$	5		$	-		$	-		$	1,206		$	704
Intersegment revenues (1)		144		-			-		-		-			-			(144	)		-			-			-
Total revenues		739		662			23		37		588			5			(144	)		-			1,206			704
Operating expenses
Cost of gas		284		221			-		-		486			1			(144	)		-			626			222
Operation and maintenance		199		193			17		15		45			7			(4	)		(7	)		257			208
Depreciation and amortization		62		61			-		-		2			-			7			7			71			68
Taxes other than income taxes		16		19			-		-		1			-			3			2			20			21
Total operating expenses		561		494			17		15		534			8			(138	)		2			974			519
Gain (loss) on sale of Caroline Street campus (2)		-		21			-		-		-			-			-			(5	)		-			16
Operating income (loss)		178		189			6		22		54			(3	)		(6	)		(7	)		232			201
Equity in earnings of SouthStar		-		-			-		-		-			29			-			-			-			29
Donation to private foundation		-		(8	)		-		-		-			-			-			-			-			(8	)
Other income (loss)		1		1			-		-		2			1			(1	)		(1	)		2			1
Minority interest		-		-			-		-		(14	)		-			-			-			(14	)		-
EBIT	$	179	$	182		$	6	$	22	$	42		$	27			($7	)		($8	)	$	220		$	223

Capital expenditures	$	134	$	88		$	7	$	1	$	21		$	5		$	6		$	19		$	168		$	113

(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 Sept. 30,				Nine months ended Sept. 30,
In millions	2004		2003		2004		2003
Third-party gross revenues	$	1,007	$	645	$	3,069	$	2,520
Intersegment revenues		88		84		279		291
Total gross revenues	$	1,095	$	729	$	3,348	$	2,811

(2)

The gain before income taxes of $16 million on the sale of our Caroline Street campus was recorded as operating income (loss) in two of our segments. A gain of $21 million on the sale of the land was recorded in our distribution operations segment, and a write-off of ($5) million on the buildings and their contents was recorded in our corporate segment.


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Balance sheet information at September 30, 2004 and 2003 and December 31, 2003 by segment is shown in the following tables:

	As of September 30,
	Distribution Operations				Wholesale Services				Energy Investments				Corporate and Intersegment Eliminations (2)						Consolidated AGL Resources

In millions	2004		2003		2004		2003		2004		2003		2004			2003			2004		2003
Identifiable assets (1)	$	3,360	$	3,175	$	458	$	347	$	297	$	88		($81	)		($37	)	$	4,034	$	3,573
Investment in joint ventures		-		-		-		-		-		115		-			-			-		115
Total assets	$	3,360	$	3,175	$	458	$	347	$	297	$	203		($81	)		($37	)	$	4,034	$	3,688

	As of December 31, 2003
In millions	Distribution Operations		Wholesale Services		Energy Investments		Corporate and Intersegment Eliminations (2)		Consolidated AGL Resources
Identifiable assets (1)	$	3,325	$	454	$	90	$	2	$	3,871
Investment in joint ventures		-		-		101		-		101
Total assets	$	3,325	$	454	$	191	$	2	$	3,972

(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

Jefferson Island Acquisition On October 1, 2004 we completed our acquisition of Jefferson Island Storage & Hub, LLC (Jefferson Island) from an American Electric Power subsidiary. We purchased the assets for an adjusted price of $90 million, which included approximately $9 million of working gas inventory. Jefferson Island will provide us with additional access to natural gas storage services through its direct connection to the Henry Hub via the Sabine Pipeline.

Bridge credit agreement On October 22, 2004, we signed a $700 million bridge credit agreement. The bridge facility is intended only to provide us with short-term financing for our purchase of NUI. Any amount borrowed under the facility must be repaid prior to its September 30, 2005 expiration date. We may draw on the commitments under the bridge facility on the closing date of the acquisition of NUI to pay obligations related to the purchase, including the payment of related acquisition fees and expenses, certain of NUI’s regulatory obligations and certain existing indebtedness of NUI that matures at closing. The capacity under the bridge credit agreement will be reduced by the amount of the proceeds of any financing we complete prior to closing the NUI acquisition (with the exception of our commercial paper program). The bridge credit agreement has representations, covenants and borrowing costs that are similar to those in our existing Credit Facility.

Shelf registration On October 22, 2004, we filed a shelf registration statement with the SEC for authority to increase our capacity from $750 million to $1.5 billion of various capital securities to assure adequate capacity for the NUI acquisition and other financing requirements.


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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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). Our reports, filings and other public announcements often include statements reflecting assumptions, expectations, projections, intentions or beliefs about future events. These statements, which may relate to such matters as future earnings, growth, supply and demand, costs, subsidiary performance, new technologies and strategic initiatives, are “forward-looking statements” within the meaning of the federal securities laws. These statements do not relate strictly to historical or current facts, and you can identify certain of these statements, but not necessarily all, by the use of the word s “anticipate,” “assume,” “indicate,” “estimate,” “believe,” “predict,” “forecast,” “rely,” “expect,” “continue,” “grow” and other words of similar meaning.

Although we believe that the expectations and assumptions reflected in these statements are reasonable in view of the information currently available, there can be no assurance that these expectations will prove to be correct. These forward-looking statements involve a number of risks and uncertainties, including those set forth below and in our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC) on February 6, 2004 under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Risk Factors.” Actual results may differ materially from the results discussed in the forward-looking statements. In addition to the specific factors discussed in our 2003 Form 10-K, the following are among the important fac tors that could cause actual results to differ materially from the forward-looking statements:

·	changes in industrial, commercial and residential growth in our service territories

·	changes in price, supply and demand for natural gas and related products

·	impact of changes in state and federal legislation and regulation, including orders of various state public service commissions and of the Federal Energy Regulatory Commission on the gas and electric industries and on us

·	actions taken by government agencies, including decisions on base rate increase requests by state regulators

·	the ultimate impact of the Sarbanes-Oxley Act of 2002 and any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically

·	the enactment of new accounting standards, or interpretations of existing accounting standards, by the Financial Accounting Standards Board (FASB), or the SEC that could impact the way we record revenues, assets and liabilities, which in turn could affect our reported results of operations

·	the enactment of new auditing standards, or interpretations of existing auditing standards, by the Public Company Accounting Oversight Board (PCAOB) which could adversely affect our ability to comply with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 (SOX 404)

effects and uncertainties of deregulation and competition, particularly in markets where prices and providers historically have been regulated, and unknown issues following deregulation such as the stability of the Georgia retail gas market, including risks related to energy marketing and risk management

·	concentration of credit risk in Marketers - that is, marketers who are certificated by the Georgia Public Service Commission (GPSC) to sell retail natural gas in Georgia - as well as concentration of credit risk in customers of our wholesale services segment

·	excess high-speed network capacity and demand for dark fiber in metropolitan network areas

·	market acceptance of new technologies and products, as well as the adoption of new networking standards

·	the ability to negotiate new fiber optic contracts with telecommunications providers for the provision of dark fiber services

·	utility and energy industry consolidation

·	performance of equity and bond markets and the impact on pension and post retirement funding costs


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS - continued

·	impact of acquisitions and divestitures, including:

·	the risk that the businesses of NUI Corporation (NUI) and/or Jefferson Island Storage & Hub, L.L.C. (Jefferson Island) will not be integrated successfully with us or that such integrations may be more difficult, time-consuming or costly than expected

·	revenues following the acquisitions may be lower than expected

·	expected revenue synergies and cost savings from these two acquisitions may not be fully realized or realized within the expected time frame

·	the ability to obtain governmental approvals of the NUI acquisition on the proposed terms and schedule

·	the risk that we may be unable to obtain financing necessary to consummate the acquisition of NUI or that the terms of such financing may be onerous

·	the risk that any financing plan may have the effect of diluting our shareholder value in the near term

·	direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit rating or the credit ratings of our counterparties or competitors

·	interest rate fluctuations, financial market conditions and general economic conditions

·	uncertainties about environmental issues and the related impact of such issues

·	impact of changes in weather upon the temperature-sensitive portions of our business

·	impact of litigation

·	impact of changes in prices on the margins achievable in the unregulated retail gas marketing business

Any forward-looking statements should be considered in light of such important factors.

New factors that could cause actual results to differ materially from those described above emerge from time to time, and it is not possible to predict all of such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update the information contained in such statement to reflect subsequent developments or information except as required by law.


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Overview

We are an energy services holding company, headquartered in Atlanta, Georgia, whose principal business is the distribution of natural gas in Georgia, Tennessee and Virginia. We operate three utilities which, combined, serve more than 1.8 million end-use customers. We are also involved in various non-utility businesses, including natural gas asset management and optimization, producer services and wholesale marketing, risk management activities, retail natural gas marketing, natural gas storage services and operating telecommunications conduit and fiber infrastructure within select metropolitan areas.

Our overall business strategy is to operate and grow our gas distribution business efficiently and effectively, optimize returns on our assets and selectively grow our portfolio of closely related businesses while retaining our solid investment grade ratings and remaining focused on risk management and earnings visibility. We manage our business in three operating segments and one non-operating segment. The following chart shows our business segments and principal subsidiaries.

Regulatory Environment We are subject to the rate regulation and accounting requirements of the various state and federal regulatory agencies in the jurisdictions in which we do business. With respect to ongoing activities, we currently are in utility regulatory proceedings in Georgia, Tennessee and Virginia. We also are involved in regulatory proceedings in New Jersey, Maryland and Virginia as part of the required approval process for our proposed acquisition of New Jersey-based NUI. We are committed to working cooperatively and constructively with these state and federal regulatory agencies in a way that benefits our customers, shareholders and other stakeholders. We believe the dyna mic energy environment in which we operate demands that we maintain an open, respectful and ongoing dialogue with these agencies as the best way to ensure we are working toward common solutions to the many issues our industry faces. In each of the jurisdictions we serve, our goal is to continue to examine and refine, in conjunction with our regulators, our regulatory strategy to better serve our customers, shareholders and other stakeholders. For more information regarding pending federal and state regulatory matters, see "Results of Operation - Distribution Operations" and “Results of Operations - Wholesale Services”.


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Competition The principal competition for our distribution operations businesses and SouthStar Energy Services, LLC (SouthStar) are the electric utilities serving the residential and small commercial markets throughout our service areas and the potential displacement or replacement of natural gas appliances with electric appliances. 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 o ne of our greater challenges in 2004 and beyond.

Our customers’ demand for natural gas and the level of business of our natural gas assets could be affected by numerous factors, including:

·	changes in the availability or price of natural gas and other forms of energy

·	general economic conditions

·	energy conservation

·	legislation and regulations

·	the capability to convert from natural gas to alternative fuels and

weather

Sequent Energy Management, LP (Sequent) competes for asset management business with other energy wholesalers, often through a competitive bidding process. Sequent has historically been successful in obtaining new asset management business by placing bids that were based primarily on the intrinsic value of the transaction, which is the difference in commodity prices between time periods or locations at the inception of the transaction.

In recent months, energy wholesalers have become increasingly willing to place bids for asset management transactions that are priced to include extrinsic value, which is the additional value for the margins the wholesaler may be able to capture over the term of the asset management deal. We expect this trend to continue in the near term, and the increasing competition for asset management deals could result in downward pressure on the volume of transactions and the related margins available in this portion of Sequent’s business.

Technology Initiatives We continue to make progress with regard to several of our large-scale technology initiatives. During the third quarter, we implemented new technology that enables Marketers in Georgia to create and input service orders directly into our systems, eliminating the need for duplicate or three-way calls between the customer, Georgia Marketers and customer call center. This system has allowed for a reduction in the number of customer service representatives servicing Marketers in our call center. In addition, we made progress on the implementation of our new energy trading and risk management (ETRM) system at Sequent. The ETRM system is designed to enhance internal controls and provide addit ional transparency into the activities of Sequent’s business. We also anticipate that the system will enable Sequent to grow its commercial business without significant growth in the support staff.

Proposed acquisition of NUI On July 15, 2004, we announced that our board of directors approved a definitive merger agreement under which we will acquire all the outstanding shares of NUI for $13.70 per share in cash, or approximately $220 million in the aggregate and the assumption of NUI’s outstanding debt. NUI is a diversified energy company that operates natural gas utilities and natural gas storage and pipeline businesses. NUI provides natural gas to approximately 367,000 residential, commercial and industrial customers in New Jersey, Virginia, Florida and Maryland. This transaction will increase our customer base by 20% to approximately 2.2 million end-use customers. For more information on our exp ected financing of the NUI acquisition, see “Liquidity and Capital Resources - Cash flow used in financing activities”.


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The sale is subject to regulatory approvals by the SEC, state regulatory agencies of New Jersey, Maryland and Virginia and there are other closing conditions unrelated to regulatory approvals. We have asked for expedited treatment from the SEC and various state regulatory agencies. In September 2004, we testified in evidentiary hearings before the New Jersey Board of Public Utilities (NJBPU) and in October 2004 we entered into settlement discussions with the NJBPU related to the terms of approval of the transaction. State regulatory reviews are expected to be completed by mid-November and will be followed by the SEC review under the Public Utility Holding Company Act. On October 21, 2004 NUI’s shareholders approved the transaction. The merger agreement provides that the closing must occur on or prior to April 11, 2005, but the closing may be extended for an additional 90 days until July 11, 2005, in the event the parties have not obtained the required consents for the acquisition.

Acquisition of Jefferson Island On October 1, 2004, we completed the acquisition of Jefferson Island from a subsidiary of American Electric Power. We completed the acquisition by purchasing the assets for an adjusted price of $90 million, which included approximately $9 million of working gas inventory. For more information on Jefferson Island, see the discussion of Energy Investments’ results of operations below.

Income tax adjustment In the third quarter of 2004, we made adjustments of approximately $3 million to reduce our income tax expense for the three and nine months ended September 30, 2004 resulting from a reconciliation of our income tax accruals as compared to our income tax returns for 2003 that we filed in September 2004. The adjustments related to differences in amounts estimated as of December 31, 2003 and the actual amounts reflected in our tax returns as well as additional deductions for state income taxes reflected in our federal income tax return. For a reconciliation of our statutory and effective income tax rates, see Note 9, Income Taxes.

Sarbanes-Oxley Act Section 404 SOX 404 and related rules of the SEC require management of public companies to report on the effectiveness of the company’s internal control over financial reporting as of the end of each fiscal year, including disclosure of any material weaknesses in the company’s internal control over financial reporting that have been identified by management. In addition, SOX 404 requires the company’s independent accountants to attest to and report on management’s annual assessment of the company’s internal control over financial reporting. We are in the process of documenting, testing and assessing our systems of internal control over financial reporting, as requir ed under SOX 404 and PCAOB Standard No. 2, “An Audit of Internal Control Over Financial Reporting Performed in Conjunction With An Audit of Financial Statements” (Standard No. 2), which was adopted in June 2004 to provide the basis for management’s report on the effectiveness of our internal controls over financial reporting as of December 31, 2004.

During our assessment phase which will be ongoing through December 31, 2004, we could identify deficiencies in our internal controls over financial reporting that would fall into one of three categories:

·	an internal control deficiency exists when the design or the operation of a control does not allow management or employees, in the normal course of performing their functions, to prevent or detect misstatements on a timely basis;

a significant deficiency exists when an internal controls deficiency or a combination of internal control deficiencies adversely affects our ability to initiate, authorize, record, process or report financial data in accordance with GAAP such that there is a more than remote likelihood that a misstatement of the annual or interim financial statements that is more than inconsequential will not be prevented or detected;

·	a material weakness exists when a significant deficiency or a combination of significant deficiencies results in a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

As a result, our assessment could result in two possible outcomes at our reporting date:

·	we could conclude that our internal controls over financial reporting were designed and operating effectively, or

·	we could conclude that our internal controls over financial reporting were not properly designed or did not operate effectively.


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A material weakness that exists at the reporting date would require our assessment to be that our internal controls over financial reporting are not effective. Our independent auditor is now required to issue three opinions annually, beginning with our 2004 consolidated financial statements. First, the auditor must evaluate and opine regarding the process by which we assessed the effectiveness of our internal controls over financial reporting. A second opinion must be issued as to the effectiveness of our internal controls over financial reporting. Finally, they must issue an opinion, as they normally do, as to whether our consolidated financial statements are fairly presented, in all material respects. Our independent auditor could conclude it has a scope limitation as to the effectiveness of our internal controls over financial reporting. A scope limitation could occur if the auditor was unable to apply all of the procedures necessary in order to form an opinion.

At this stage, we have not identified any areas or systems where we believe there will be pervasive control deficiencies or deficiencies which cannot be timely remediated. Nevertheless, as discussed earlier in “Technology Initiatives”, in October 2004, Sequent began using its ETRM system and discontinued use of its legacy trading and control systems. The design and implementation phase of the ETRM project began in November 2003, well before the requirements of SOX 404 were finalized. We believe that the ETRM system has enhanced our internal controls. However, due to the timing of this implementation, it is possible that we may not be able to gather sufficient evidence, as required by Standard No. 2, to conclude that our internal controls over financial reporting relating to this system were designed and operating effectively as of December 31, 2004. Consequently, it is possible that our independent auditors may have a scope limitation with respect to the internal control structure at Sequent.

Consistent with our culture that emphasizes integrity, honesty and accurate financial reporting, we are working diligently to complete the documentation, testing and assessment of our internal controls over financial reporting by the December 31, 2004 compliance date. However, because this is the first year of the new SOX 404 requirements there is a risk that unexpected delays and obstacles could arise which would prevent the completion of all aspects of this project on a timely basis.


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Results of Operations

AGL Resources

Revenues We generate nearly all of our operating revenues through the sale, distribution and storage of natural gas. Distribution operations and energy investments comprised a significant portion of our consolidated revenues for the three and nine months ended September 30, 2004 and 2003.

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 condensed consolidated balance sheet.

A significant portion of our operations is subject to variability associated with changes in commodity prices and seasonal fluctuations. During the heating season, which is primarily from November through March, net revenues are higher since generally more customers will be connected and with higher usage in periods of colder weather than in periods of warmer weather and commodity prices tend to be higher in colder months. Our non-utility businesses principally use physical and financial arrangements to 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, reported earnings for the wholesale services and energy investment segments reflect changes in the fair value of certain d erivatives; these values may change significantly from period to period.

Operating Margin and EBIT We evaluate the performance of our operating segments using the measures of operating margin and earnings before interest and taxes (EBIT). We believe operating margin is a better indicator than revenues of the top line contribution resulting from customer growth in our distribution operations segment since the cost of gas 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. We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

Our operating margin and EBIT are not measures that are considered to be calculated in accordance with accounting principles generally accepted in the United States of America (GAAP). You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of our operating performance than, operating income or net income as determined in accordance GAAP. In addition, our operating margin or EBIT 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 for the three and nine months ended September 30, 2004 and 2003.

	Three months ended Sept. 30,					Nine months ended Sept. 30,
In millions	2004		2003			2004			2003
Operating revenues	$	262	$	165		$	1,206		$	704
Cost of gas		105		28			626			222
Operating margin		157		137			580			482
Operating expenses		111		95			348			297
Gain on sale of Caroline Street campus		-		16			-			16
Operating income		46		58			232			201
Other income		-		(2	)		2			22
Minority interest		-		-			(14	)		-
EBIT		46		56			220			223
Interest expense		17		19			49			57
Earnings before income taxes		29		37			171			166
Income taxes		9		15			64			65
Income before cumulative effect of change in accounting principle		20		22			107			101
Cumulative effect of change in accounting principle		-		-			-			(8	)
Net income	$	20	$	22		$	107		$	93


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Results of Operations for AGL Resources by segment and other consolidated financial information for the three and nine months ended September 30, 2004 and 2003 are as follows:

	Three months ended Sept. 30,									Nine months ended Sept. 30,
In millions, except per share amounts	2004			2003			2004 vs. 2003			2004			2003			2004 vs. 2003
EBIT by segment
Distribution operations	$	48		$	57			($9	)	$	179		$	182			($3	)
Wholesale services		(1	)		1			(2	)		6			22			(16	)
Energy investments		1			4			(3	)		42			27			15
Corporate		(2	)		(6	)		4			(7	)		(8	)		1
Consolidated EBIT		46			56			(10	)		220			223			(3	)
Interest expense		17			19			(2	)		49			57			(8	)
Earnings before income taxes		29			37			(8	)		171			166			5
Income taxes		9			15			(6	)		64			65			(1	)
Income before cumulative effect of change in accounting principle		20			22			(2	)		107			101			6
Cumulative effect of change in accounting principle		-			-			-			-			(8	)		8
Net income	$	20		$	22			($2	)	$	107		$	93		$	14
Basic earnings per common share
Income before cumulative effect of change in accounting principle	$	0.31		$	0.35			($0.04	)	$	1.66		$	1.61		$	0.05
Cumulative effect of change in accounting principle		-			-			-			-			(0.13	)		0.13
Basic earnings per common share	$	0.31		$	0.35			($0.04	)	$	1.66		$	1.48		$	0.18
Diluted earnings per common share
Income before cumulative effect of change in accounting principle	$	0.31		$	0.34			($0.03	)	$	1.64		$	1.59		$	0.05
Cumulative effect of change in accounting principle		-			-			-			-			(0.12	)		0.12
Diluted earnings per common share	$	0.31		$	0.34			($0.03	)	$	1.64		$	1.47		$	0.17
Weighted average number of common shares outstanding
Basic		65.1			64.0			1.1			64.8			62.6			2.2
Diluted		65.8			64.8			1.0			65.5			63.2			2.3

Third quarter 2004 compared to third quarter 2003 The lower net income for the third quarter reflects after-tax gain on the sale of our Caroline Street campus, net of the donation to the private foundation of $5 million or $0.08 per basic share in the third quarter of 2003. After deducting this gain, earnings for the third quarter of 2003 were $17 million or $0.27 per basic share. These results reflect improved earnings in the distribution operations segment and lower earnings in the wholesale services and energ y investments segments during the quarter.

The decrease in interest expense for the three months ended September 30, 2004 as compared to the same period in 2003 was a result of lower interest rates on commercial paper borrowings, the repayment of Medium-Term notes in 2003, interest rate swap transactions and, as shown in the following table, lower average debt balances:

	Three months ended September 30,
Dollars in millions	2004			2003			2004 vs. 2003
Average debt outstanding (1)	$	1,219		$	1,250			($31	)
Average rate		5.6	%		6.1	%		(0.5	%)

(1)	Daily average of all outstanding debt including our note payable to Trusts in 2004 and Trust Preferred Securities in 2003.


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The decrease in income tax expense was primarily due to the decrease in earnings before income taxes and adjustments resulting from a comparison of our tax returns filed in September 2004 to our income tax accruals for 2003. Adjustments from this comparison totaling approximately $3 million were recorded in the third quarter. For a reconciliation of our statutory and effective income tax rates, see Note 9, Income Taxes. The decrease in the effective tax rate from last year was primarily due to the above referenced adjustments.

Nine months 2004 compared to nine months 2003 For the nine months ended September 30, 2004, net income was $107 million, or $1.66 per basic share, compared with $93 million, or $1.48 per basic share. After deducting the previously mentioned after-tax gain of $5 million, or $0.08 per share, the sale of company property and related donation to a private foundation in the 2003 period, earnings for the nine months ended September 30, 2003 were $88 million, or $1.41 per basic share. The improvement in our operating results for the nine months ended September 30, 2004 reflects improved earnings at our distribution operation s and energy investments segments and lower corporate interest expense, which offset lower earnings in the wholesale services segment.

The decrease in interest expense for the nine months ended September 30, 2004 as compared to the same period in 2003 was a result of lower interest rates on commercial paper borrowings, lower average debt balances, the repayment of Medium-Term notes in 2003 and interest rate swap transactions. As shown in the following table, our average debt balances were lower as compared to last year due to approximately $73 million of cash distributions from SouthStar from December 2003 through September 2004 and lower working capital needs.

	Nine months ended September 30,
Dollars in millions	2004			2003			2004 vs. 2003
Average debt outstanding (1)	$	1,187		$	1,220			($33	)
Average rate		5.5	%		6.3	%		(0.8	%)

(1)	Daily average of all outstanding debt including our note payable to Trusts in 2004 and Trust Preferred Securities in 2003.

As of September 30, 2004, $34 million of long-term fixed-rate obligations are scheduled to mature within the next 12 months. Any new debt obtained to refinance this obligation will be exposed to changes in interest rates. If, for the nine months ended September 30, 2004, market interest rates had been 100 basis points higher, representing a 4.8% interest rate on our variable rate debt versus our actual 3.8% interest rate, our year-to-date pretax interest expense would have increased by $2 million.

We anticipate our interest expense in the twelve months ending December 31, 2005 will be higher than in the same period in 2004 due to the following:

·	higher projected short-term interest rates based upon higher 2005 LIBOR rates

·	higher interest rate on our 6% $250 million senior note offering compared to borrowing $250 million at the commercial paper interest rate of 1.9% at September 30, 2004

·	higher debt balances from 2004 and 2005 capital expenditures, the acquisition of Jefferson Island and the pending acquisition of NUI

The increase in income tax expense for the nine months ended September 30, 2004 was primarily due to the increase in earnings before income taxes and additional tax expense due to recognition of a tax gain from our sale of our general and limited partnership interests in US Propane. This was offset by the income tax accrual adjustments discussed above and a decrease in state taxes. We estimate our effective tax rate for the twelve months ended December 31, 2004 to be approximately 38%.


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Distribution Operations

Distribution operations include our three natural gas local distribution utility companies: Atlanta Gas Light Company (AGLC), Virginia Natural Gas (VNG) and Chattanooga Gas Company (CGC). These utilities construct, manage and maintain gas pipeline in Georgia, Tennessee and Virginia and serve more than 1.8 million end-use customers. Approximately 83% of our customers are located in Georgia, 14% are located in Virginia and 3% are located in Tennessee.

Each utility operates subject to regulations provided by the state regulatory agencies in its service territories. The Georgia Public Service Commission (GPSC) regulates AGLC; the Virginia State Corporation Commission (VSCC) regulates VNG; and the Tennessee Regulatory Authority (TRA) regulates CGC 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 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 by making a rate case filing.

AGLC is a natural gas local distribution utility with distribution systems and related facilities throughout Georgia. AGLC has approximately six Bcf of LNG storage capacity in three LNG plants to supplement the supply of natural gas during peak usage periods. Pursuant to the Georgia Natural Gas Competition and Deregulation Act, AGLC is designated as an “electing distribution company,” which means that AGLC is required to offer LNG peaking services to Marketers — that is, marketers who are certificated by the GPSC to sell retail natural gas in Georgia - at rates and on terms approved by the GPSC.

In October 2004 AGLC filed with the GPSC a general rate case request for a $25 million rate increase. The request would continue the performance-based rate plan, and include a return on equity band of 10.2% to 12.2%. If approved, the new rates would go into effect May 1, 2005 and be comprised of increases related to depreciation expense, capital expenditures and various other operating expenses such as pipeline integrity costs mandated by federal regulations and changes in the property tax valuation method.

As part of this rate case the GPSC requested testimony on whether the Pipeline Replacement Program (PRP) should be included in AGLC's base rates or whether the rider currently used for recovery of PRP expenses should be otherwise modified or discontinued. AGLC has filed testimony in support of continuing the current PRP rider agreement. Including PRP capital cost in base rates before the end of the program would result in a regulatory delay in recovery of the expected $80 million annual investment. This delay could require more frequent general rate cases to fund the annual cost of PRP capital expenditures and resulting depreciation.

AGLC has executed an agreement with Southern Natural Gas (SNG), a subsidiary of El Paso Corporation, to acquire a portion of SNG’s interstate pipeline that runs from Macon, Georgia to Atlanta, Georgia. The transaction is valued at approximately $32 million. As part of the agreement, AGLC will extend the existing SNG transportation and storage contracts to ensure reliable delivery of natural gas into Georgia in return for the right to expand AGLC’s system off of the purchased facilities. We expect the SNG transaction to close by April 30, 2005, subject to securing regulatory approvals.


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In May 2004, AGLC and 8 of the 10 Marketers entered into a settlement that resolved matters related to a capacity supply plan that was required to be filed by AGLC in July 2004. As a result of the settlement, the parties filed with the GPSC a three year capacity supply plan for the Georgia market. In October 2004 we received reconsideration and approval by the GPSC of the capacity supply plan, which includes, among other things:

·	calculation of the design (peak) day requirements for the next three years;

·	purchase by AGLC of certain SNG facilities and the recovery of those costs through a rate case;

·	construction of a line from the Macon LNG facility to those SNG facilities;

·	extension of the Sequent peaking contract to March 2005

·	approval of Sequent’s current asset management contract for retained assets through March 1, 2006; and

·	other tariff provisions.

VNG is a natural gas local distribution utility with distribution systems and related facilities serving southeastern Virginia. VNG owns and operates approximately 155 miles of a separate high-pressure pipeline that provides delivery of gas to customers under firm transportation agreements within the state of Virginia. VNG also has approximately five million gallons of propane storage capacity in its two propane facilities to supplement the supply of natural gas during peak usage periods.

In early 2005, Pivotal Propane of Virginia, Inc., our wholly owned subsidiary, intends to complete the construction of a propane air facility in the VNG service area to provide VNG with 28,800 dekatherms of propane air per day on a 10-day-per-year basis to serve VNG’s peaking needs. VNG has received approval from the VSCC for the $27 million propane air plant to improve the reliability of its system in Virginia. The cold storage tank foundation is complete and construction of the process facility is underway. We expect the plant to begin filling operations in December, and the facility to be available for vaporization in January 2005.

In June 2004, the VSCC issued its final order authorizing the recovery of all charges for the services of the propane facility through VNG’s gas cost recovery mechanism. The approval is for an initial 10-year term, with the possibility of renewal thereafter for terms of two years subject to VSCC approval. VNG has the right to purchase the facility at the end of the initial term or any renewal term.

In September 2004, we received approval from the VSCC to extend VNG’s weather normalization adjustment program for an additional two years. In addition, the VSCC staff is currently conducting a review of VNG’s annual informational filing.

CGC is a natural gas local distribution utility with distribution systems and related facilities serving the Chattanooga and Cleveland areas of Tennessee. CGC has approximately 1.2 Bcf of LNG storage capacity in its LNG plant. Included in the rates charged by CGC is a WNA factor, which offsets the impact of unusually cold or warm weather on operating margin.

In January 2004, CGC filed a rate plan request with the TRA for a total rate increase of $4.6 million annually. The rate plan was filed to cover CGC’s rising cost of providing natural gas to its customers. In May 2004, the TRA suspended the increase until July 28, 2004 and subsequently deferred the decision to August 30, 2004. Since its initial filing, CGC reduced its rate plan increase to $3.7 million, primarily as a result of the February 2004 TRA ruling discussed below. A written order was not received on August 30, but on October 1, 2004, CGC put the new rates into effect which raised rates by approximately $0.6 million annually. A written order from the TRA was received on October 20, 2004. The new rates are based on a 7.43% return on rate base. CGC has until November 4, 2004 to request reconsideration a nd the TRA has 20 days to act upon this request. .

In March 2003, CGC filed a joint petition with other Tennessee distribution companies requesting the TRA to issue a declaratory ruling that the portion of uncollectible accounts directly related to the cost of its natural gas is recoverable through a Purchased Gas Adjustment (PGA) mechanism. The PGA mechanism allows the local distribution companies to automatically adjust their rates to reflect changes in the wholesale cost of natural gas and to insure the utilities recover 100% of the cost incurred in purchasing gas for their customers. On February 9, 2004, the TRA ruled that the gas portion of accounts written-off as uncollectible after March 10, 2004 could be recovered through the PGA.


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Results of Operations for our distribution operations segment for the three and nine months ended September 30, 2004 and 2003 are as follows:

	Three months ended September 30,								Nine months ended September 30,
In millions	2004		2003			2004 vs. 2003			2004		2003			2004 vs. 2003
Operating revenues	$	166	$	160		$	6		$	739	$	662		$	77
Cost of gas		31		28			3			284		221			63
Operating margin		135		132			3			455		441			14
Operating expenses
Operation and maintenance		63		62			1			199		193			6
Depreciation and amortization		20		21			(1	)		62		61			1
Taxes other than income		4		6			(2	)		16		19			(3	)
Total operating expenses		87		89			(2	)		277		273			4
Gain on sale of Caroline Street campus		-		21			(21	)		-		21			(21	)
Operating income		48		64			(16	)		178		189			(11	)
Other income		-		(7	)		7			1		(7	)		8
EBIT	$	48	$	57			($9	)	$	179	$	182			($3	)

Metrics
Average end-use customers (in thousands)		1,824		1,815			1	%		1,853		1,843			1	%
Operation and maintenance expenses per customer	$	35	$	34			3	%	$	107	$	105			2	%
EBIT per customer (less gain on sale of Caroline Street campus and donation to private foundation in 2003)	$	26	$	24			8	%	$	97	$	91			7	%
Customers per employee		1,030		969			6	%		1,036		977			6	%
Throughput (in millions of dekatherms)
Firm		16		16			-	%		129		129			-	%
Interruptible		25		27			(7	%)		77		81			(5	%)
Total		41		43			(5	%)		206		210			(2	%)
Heating degree days (1):							% Colder / (Warmer	)							% Colder / (Warmer	)
Georgia		1		14			(93	%)		1,661		1,699			(2	%)
Virginia		2		5			(60	%)		2,078		2,274			(9	%)
Tennessee		2		21			(90	%)		1,932		1,963			(2	%)

(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.

Third quarter 2004 compared to third quarter 2003 Our distribution operation segment’s EBIT was $48 million for the 2004 quarter compared to $57 million for the same period last year. The decrease in EBIT of $9 million in the 2004 quarter was primarily the result of the gain of $21 million on the sale of the Caroline Street campus, offset by the $8 million donation to a private foundation in 2003. Exclusive of the gain and contribution from the sale EBIT was $48 million for the 2004 quarter compared to $44 million for the same period last year.

Operating margin for the quarter was $135 million, an increase of $3 million from the same period last year. The increase was due primarily from increases in the pipeline replacement program revenue as a result of continued PRP capital spending, higher customer growth and usage and increases in additional carrying charges from gas stored for Marketers due to higher storage volumes combined with higher average cost of gas.


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Operating expenses for the quarter were $87 million, a decrease of $2 million from the same period last year. The decrease was due primarily to:

·	$4 million decrease in benefit expenses due primarily to a reduction in long term compensation expenses and a decrease in post retirement benefits as a result of a change in the post-retirement plan related to prescription drug benefits, partly offset by increases in pension expense.

·	$2 million decrease in AGLC property taxes due to settlement of 2003 and 2004 tax liabilities.

$4 million increase in outside services due primarily to increased information services expenses related to our implementation of the work management system, higher legal services due to increased regulatory activity, increased costs related to our implementation of SOX 404, increased volume of requests for locating gas infrastructure, and additional facility maintenance programs.

Nine months 2004 compared to nine months 2003 The decrease in EBIT of $3 million in the 2004 period was primarily the result of the net gain on the sale of the Caroline Street campus in 2003. Exclusive of the gain, our distribution operation segment’s EBIT was $179 million for the current nine month period compared to $169 million for the same period last year.

Operating margin for the nine months ended September 30, 2004 was $455 million, an increase of $14 million from the same period last year. The increase was due primarily to:

$12 million increase in AGLC operating margin as a result of a $4 million increase in pipeline replacement program revenue as a result of continued PRP capital spending, an increase of $4 million in customer growth and higher customer usage, an increase of $3 million in additional carrying charges from gas stored for Marketers due to a higher average cost of gas, and an additional $1 million from other service fees.

·	$2 million increase in VNG margin primarily from customer growth.

Operating expenses for the nine months ended September 30, 2004 were $277 million, up from $273 million in the same period last year. The increase of $4 million was due primarily to:

$7 million increase in outside services due primarily to increased information services expenses as a result of our implementation of a work management system, increased legal services due to increased regulatory activity, increased costs related to our implementation of SOX 404, increased volume of requests for locating gas infrastructure, and additional facility maintenance programs.

·	$1 million increase in depreciation expense primarily from new depreciation rates at VNG and increased assets at each utility.

·	$3 million decrease in AGLC property taxes primarily due to settlement of 2003 and 2004 tax liabilities.

·	$1 million reduction in bad debt primarily due to a TRA ruling that allows for recovery of the gas portion of accounts written off as uncollectible at CGC and improved collection results at VNG.


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Wholesale Services

Wholesale services consist of Sequent, our subsidiary involved in asset optimization, producer services, wholesale marketing and risk management activities. 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 the other alternatives available to its end-use customers.

Regulatory Agreements We have reached the following agreements with state regulatory commissions related to Sequent’s role as asset manager for our regulated utilities. Failure to renew these agreements would have a significant impact on Sequent’s EBIT.

Various Georgia statutes require Sequent, as asset manager for AGLC, to share 90% of its earnings from capacity release transactions with Georgia’s Universal Service Fund (USF). A December 2002 GPSC order requires net margin earned by Sequent, for transactions involving AGLC assets other than capacity release, to be shared equally with the USF. In 2004, we contributed approximately $4 million to the USF based upon profits earned in the last six months of 2003 and for the first six months of 2004.

In November 2000, the VSCC approved an asset management agreement that provides for a sharing of profits between Sequent and VNG’s customers. This agreement expires in October 2005, unless Sequent, VNG and the VSCC agree to extend the contract. In December 2003, we contributed $5 million to VNG’s customers for the contract year November 2002 through October 2003. This contribution is being reflected as a reduction to customer gas cost in 2004. We will contribute profits earned in the contract year November 2003 through October 2004 in December 2004.

In June 2003, CGC’s tariff was amended effective January 1, 2003 to require net margin earned by Sequent for transactions involving CGC assets to be shared equally with CGC ratepayers. This agreement expires in April 2006 and is subject to automatic extensions unless specifically terminated by either party. In 2004, Sequent contributed $1 million to CGC based upon profits earned during 2003. This contribution is being reflected as a reduction to customer gas cost in 2004.

Peaking Services Wholesale services generates operating margin through, among other things, the sale of peaking services, which includes receiving a fee from customers that guarantees that they will receive gas under peak conditions. Sequent recorded gross revenues of $7 million in the nine months ended September 30, 2004 under these peaking services and $6 million during the same period in 2003. Wholesale services incurs costs to support its obligations under these agreements, which will be reduced in whole or in part as the matching obligations expire.

Wholesale services’ affiliated peaking arrangement with AGLC expired March 31, 2004. In October 2004, the peaking agreement was renewed and extended as a result of the GPSC approval of AGLC’s capacity supply plan. The extended agreement expires in March 2005. In addition, we renewed and extended for 5 years a separate non-affiliated peaking service agreement that begins in November 2004 and ends in March 2009. We will continue to seek new peaking transactions as well as work toward extending those that are set or have expired.


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Energy Marketing and Risk Management Activities For the three months ended September 30 in each year, Sequent recorded unrealized losses of $10 million in 2004 and unrealized gains of $2 million in 2003 related to changes in the fair value of derivative instruments utilized in its energy marketing and risk management activities. For the nine months ended September 30 in each year, Sequent recorded unrealized gains of $5 million in 2004 and $8 million in 2003, excluding the cumulative effect of a change in accounting principle.

The tables below illustrate the change in the net fair value of the derivative instruments and energy-trading contracts during the three and nine months ended September 30, 2004 and 2003 and provide details of the net fair value of contracts outstanding as of September 30, 2004. Sequent’s storage positions are affected by price sensitivity in the New York Mercantile Exchange, Inc. (NYMEX) average price.

	Three months ended September 30,						Nine months ended September 30,
In millions	2004			2003			2004			2003
Net fair value of contracts outstanding at beginning of period	$	10		$	-			($5	)	$	7
Cumulative effect of change in accounting principle		-						-			(13	)
Net fair value of contracts outstanding at beginning of period, as adjusted		10			-			(5	)		(6	)
Contracts realized or otherwise settled during period		9			(2	)		16			(6	)
Change in net fair value of contracts		(19	)		4			(11	)		14
Net fair value of contracts outstanding at end of period	$	-		$	2		$	-		$	2

The sources of our net fair value at September 30, 2004 are as follows:

In millions	Matures through Sept. 2005			Matures through Sept. 2008		Matures through Sept 2010		Matures after Sept. 2010		Total Net Fair Value
Prices actively quoted (1)	$	9		$	2	$	-	$	-	$	11
Prices provided by other external sources (1)		($11	)	$	-	$	-	$	-		($11	)

(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.

Mark-to-Market versus Accrual Accounting for Gas Stored in Inventory We purchase gas for storage when the current market price we pay for gas plus the cost to store the gas 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 gas portfolio. We use derivative instruments to reduce the risk associated with future changes in the price of natural gas. We sell NYMEX futures contracts in forward months to substantially lock-in the profit margin we will ultimately realize when the stored gas is actually sold.

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. Gas that we purchase and inject into storage is accounted for on an accrual basis, 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. This difference in accounting, the accrual basis for our gas storage inventory versus mark-to-market accounting for the derivatives used to mitigate commodity price risk, can result in volatility in our reported net income. Based upon our storage positions at September 30, 2004, a $0.10 forward NYMEX change would result in a $0.6 million impact to Sequent’s EBIT.

Over time, gains or losses on the sale of gas storage inventory will be offset by losses or gains on the derivatives, resulting in the realization of the profit margin we expected when we entered into the transactions. This accounting difference causes Sequent’s earnings on its storage gas positions to be affected by natural gas price changes, even though the economic profits remain essentially unchanged.


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Storage Inventory Outlook The NYMEX forward curve graph set forth below reflects the NYMEX natural gas prices as of September 30, 2004 through October 2005, and reflects the prices we could buy natural gas at the Henry Hub for delivery in the same time period. October 2004 futures expired on September 30, 2004, however they are included as they coincide with the October 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.

As shown in the following table, “Open futures NYMEX contracts” represents the volume in contract equivalents of the transactions we executed to hedge our storage inventory. Each contract equivalent represents 10,000 million British thermal units (MMBtu’s). As of September 30, 2004, the expected withdrawal schedule of this inventory and its weighted average costs are reflected in the category “Physical withdrawal schedule as of September 30, 2004 (NYMEX contract equivalents).”

The table also reflects that our storage inventory is fully hedged with futures, 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 September 30, 2004 which would result in gross margin of $2 million during the fourth quarter of 2004 and $5 million during the first quarter of 2005. This gross margin could change in the future as we adjust our daily injection and withdrawal plans due to changes in market conditions.


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	Oct. 2004			Nov. 2004		Dec. 2004		Jan. 2005		Feb. 2005		Mar. 2005		Total
Open futures NYMEX contracts - (short) long (1)	(169)			-		(149)		(25)		(61)		(249)		(653)

Physical withdrawal schedule as of September 30, 2004 (NYMEX contract equivalents)
Salt dome (WACOG (2) = $5.35)	-			-		75		-		-		-		75
Reservoir (WACOG (2) = $5.78)	169			-		74		25		61		249		578
Total	169			-		149		25		61		249		653

Expected gross margin, after regulatory sharing (In millions)
Salt dome	$	-		$	-	$	1.7	$	-	$	-	$	-	$	1.7
Reservoir		($0.5	)	$	-	$	1.1	$	0.7	$	0.8	$	3.4	$	5.5

(1)	October futures expired on September 30, 2004; however, they are included herein as they coincide with the October storage withdrawals.

(2)	WACOG = Weighted average cost of gas

Park and Loan Outlook Additionally, we have entered into park and loan transactions with various pipelines. A park and loan transaction is a tariff transaction offered by pipelines, where the pipeline allows the customer to park natural gas on or borrow natural gas from the pipeline in one period and reclaim natural gas from or repay natural gas to the pipeline in a subsequent period. The economics of these transactions are evaluated and managed similar to the way traditional reservoir and salt dome storage transactions are evaluated. However, these transactions have elements that qualify as derivatives in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivat ive Instruments and Hedging Activities” (SFAS 133).

Under SFAS 133, the transactions are considered financing arrangements when the contracts contain fixed volumes that are payable or repaid at determinable dates and at a specific point in time to third parties. Because these park and loan transactions have fixed volumes, they contain price risk for the change in market prices from the date the transaction is initiated to the time the natural gas is repaid. As a result, these transactions qualify as derivatives under SFAS 133 and must be recorded at their fair value. Certain park and loan transactions that we execute meet this definition.

As such, we account for these transactions at fair value once the transaction has started (either the natural gas is originally parked on or borrowed from the pipeline). “Park and (loan) volumes” represents the contract equivalent for the volumes of our park and loan transactions as of September 30, 2004 that is not already accounted for at fair value. “Expected gross margin from park and loans” represents the gross margin from those transactions expected to be recognized in future periods based on the NYMEX forward curves at September 30, 2004.

	Oct. 2004			Nov. 2004			May 2005		June 2005		Total
Park and (loan) volumes		(41	)		(80	)		30		91		-

Expected gross margin from park and (loans) (in millions)		($0.7	)		($0.2	)	$	-	$	-		($0.9	)

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 September 30, 2004, our credit ratings had been downgraded to non-investment grade, th e required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $15 million.


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Results of Operations for our wholesale services segment for the three and nine months ended September 30, 2004 and 2003 are as follows:

	Three months ended September 30,								Nine months ended September 30,
In millions	2004			2003		2004 vs. 2003			2004		2003		2004 vs. 2003
Operating revenues	$	3		$	4		($1	)	$	23	$	37		($14	)
Cost of sales		-			-		-			-		-		-
Operating margin		3			4		(1	)		23		37		(14	)
Operating expenses
Operation and maintenance		4			3		1			17		15		2
Depreciation and amortization		-			-		-			-		-		-
Taxes other than income		-			-		-			-		-		-
Total operating expenses		4			3		1			17		15		2
Operating income		(1	)		1		(2	)		6		22		(16	)
Other income		-			-		-			-		-		-
EBIT		($1	)	$	1		($2	)	$	6	$	22		($16	)

Metrics
Physical sales volumes (Bcf/day)		2.08			1.49		40	%		2.06		1.71		20	%

Third quarter 2004 compared to third quarter 2003 The $2 million decline in EBIT in the third quarter of 2004 was a result of decreased operating margin and increased operating expenses. The $1 million decrease in operating margin was primarily due to temporary changes in the fair value of derivative contracts that we use to economically hedge our storage positions. The changes in fair value were caused by increases in the market price of natural gas and they are reflected in our unrealized losses of $10 million during the third quarter of 2004. During the third quarter of 2003 our results reflected unrealized gains o f $2 million. This unfavorable variance was partially offset by an increase in our realized margins period over period.

The $1 million increase in operating expenses was due to additional salary expenses as a result of an increase in the number of employees and additional costs for outside services related to the development of Sequent’s ETRM system and the implementation of SOX 404.

Nine months 2004 compared to nine months 2003 EBIT for the nine months of 2004 was $6 million, down from $22 million in the same period last year. The decrease of $16 million was due to a decrease in operating margin of $14 million and an increase in operating expenses of $2 million.

Operating margin for the nine months ended September 30, 2004 was $23 million, down from $37 million in the same period last year. The decrease of $14 million was primarily due to lower volatility during the first and second quarter of 2004 compared to the same period in 2003 which compressed Sequent's trading and marketing activities and the related margins within its transportation portfolio. In addition, Sequent's weighted average cost of natural gas sold from inventory was $5.06 per MMBtu during the first quarter of 2004 compared to $2.20 per MMBtu during the same period in 2003. This significant difference in cost resulted in reduced operating margins from storage inventory sold in the first quarter of 2004 compared to 2003.

Operating expenses for the nine months ended September 30, 2004 were $17 million, up from $15 million in the same period last year. The increase of $2 million was due primarily to additional salary expenses as a result of an increase in the number of employees and additional costs for outside services related to the development of Sequent’s ETRM system and the implementation of SOX 404.


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Energy Investments

Our energy investments segment includes SouthStar, AGL Networks, LLC (AGL Networks), Pivotal Propane of Virginia Inc. and US Propane LP (US Propane) through the date of its sale in January 2004. Upon closing of the sale of US Propane, we received $29 million for the sale of our general and limited partnership interests and recognized a gain of $1 million, which we recorded in other income. Jefferson Island, which we acquired effective October 1, 2004, is also included in our energy investments segment.

SouthStar is a joint venture formed in 1998 by our subsidiary, Georgia Natural Gas Company, Piedmont and Dynegy Inc. (Dynegy) to market natural gas and related services to retail customers, principally in Georgia. On March 11, 2003, we purchased Dynegy’s 20% ownership interest in a transaction that for accounting purposes had an effective date of February 18, 2003.

We currently own a non-controlling 70% financial interest in SouthStar and Piedmont owns the remaining 30%. Our 70% interest is non-controlling because all significant management decisions require approval by both owners. On March 29, 2004, we executed an amended and restated partnership agreement with Piedmont. This amended and restated partnership agreement calls for SouthStar’s future earnings starting in 2004 to be allocated 75% to our subsidiary and 25% to Piedmont. In addition, we executed a services agreement, which provided that AGL Services Company will provide and administer accounting, treasury, internal audit, human resources and information technology functions.

AGL Networks, our wholly owned subsidiary, is a provider of telecommunications conduit and un-used fiber optic cable or dark fiber. AGL Networks leases and sells its fiber to a variety of customers in the Atlanta, Georgia and Phoenix, Arizona metropolitan areas, with a small presence in other cities in the United States. Its customers include local, regional and national telecommunications companies, internet service providers, educational institutions and other commercial entities.

AGL Networks typically provides underground conduit and dark fiber to its customers under leasing arrangements with terms that vary from 1 to 20 years. In addition, AGL Networks offers telecommunications construction services to companies. Our primary goals for this business in the next 12 to 15 months are to:

·	increase revenues through our sales efforts,

·	maintain control of capital costs for connecting customers to the network,

·	and maintain control of sales and operating expenses.

·	Pivotal Propane, our wholly owned subsidiary, intends to complete the construction of a propane air facility in the VNG service area to provide VNG with 28,800 dekatherms of propane air per day on a 10-day-per-year basis to serve its peaking needs.

Jefferson Island is in Erath, Vermilion Parish, Louisiana, approximately eight miles from the Henry Hub and is an intrastate storage facility regulated by the state of Louisiana. The storage and transportation services also are regulated by the Federal Energy Regulatory Commission. The facility consists of two salt dome gas storage caverns with 9.4 million Dekatherms (Dth) of total capacity and about 6.9 million Dth of working gas capacity. The facility has approximately 720,000 Dth/day withdrawal capacity and 240,000 Dth/day injection capacity. Our acquisition of Jefferson Island included approximately $9 million of working gas inventory which will be used for resale. Jefferson Island provides for storage and hub services through its direct connection to the Henry Hub via the Sabine Pipeline and its interconnection with other pipelines in the area. Our wholly owned subsidiary, Pivotal Energy Development (Pivotal), will be responsible for the day-to-day operation of the facility.


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Results of operations for our energy investments segment for the three and nine months ended September 30, 2004 and 2003 are shown in the following tables. We have also included pro-forma results as if SouthStar’s accounts were consolidated with our subsidiaries’ accounts for the three and nine months ended September 30, 2003. These unaudited pro-forma results are presented for comparative purposes only.

	Three months ended September 30,
In millions	2004 (1)		2003			Pro-forma 2003 (1)			2004 vs. 2003			2004 vs. Pro-forma 2003
Operating revenues	$	130	$	1		$	111		$	129		$	19
Cost of sales		111		-			88			111			23
Operating margin		19		1			23			18			(4	)
Operating expenses
Operation and maintenance		17		2			17			15			-
Depreciation and amortization		1		-			-			1			1
Taxes other than income		-		-			-			-			-
Total operating expenses		18		2			17			16			1
Operating income (loss)		1		(1	)		6			2			(5	)
Equity earnings from SouthStar		-		5			-			(5	)		-
Other income		-		-			-			-			-
Minority interest (2)		-		-			(2	)		-			2
EBIT	$	1	$	4		$	4			($3	)		($3	)

	Nine months ended September 30,
In millions	2004 (1)			2003			Pro-forma 2003 (1)			2004 vs. 2003			2004 vs. Pro-forma 2003
Operating revenues	$	588		$	5		$	543		$	583		$	45
Cost of sales		486			1			444			485			42
Operating margin		102			4			99			98			3
Operating expenses
Operation and maintenance		45			7			53			38			(8	)
Depreciation and amortization		2			-			1			2			1
Taxes other than income		1			-			-			1			1
Total operating expenses		48			7			54			41			(6	)
Operating income (loss)		54			(3	)		45			57			9
Equity earnings from SouthStar		-			29			-			(29	)		-
Other income		2			1			1			1			1
Minority interest (2)		(14	)		-			(19	)		(14	)		5
EBIT	$	42		$	27		$	27		$	15		$	15

Metrics
SouthStar
Average customers (in thousands) (3)		537			561			n/a			(4	%)		n/a
Market share in Georgia (3)		36.0	%		37.7	%		n/a			(5	%)		n/a

(1)	Includes 100% of SouthStar’s revenues and expenses adjusted for SouthStar’s consolidation in 2004.

(2)	Minority interest adjusts our earnings to reflect our 75% share of SouthStar’s earnings in 2004 and our 70% share in 2003 (less Dynegy Inc.’s 20% share of SouthStar’s income prior to February 18, 2003).

(3)	12 month average ended September 30.


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As a result of our consolidation of SouthStar in 2004, we discuss changes in energy investments’ operating margin, operating expenses and EBIT for the three and nine months ended September 30, 2004 on a pro-forma basis as if SouthStar’s accounts were consolidated with our subsidiaries’ accounts in both 2004 and 2003.

Third quarter 2004 compared to third quarter 2003 The decrease in EBIT of $3 million for the quarter ended September 30, 2004 compared to the same period in 2003 is primarily due to lower results from SouthStar. On a pro-forma basis, operating margin for the quarter ended September 30, 2004 decreased $4 million as a result of a $2 million decrease in commodity margins in 2004 as compared to the same period last year and a $2 million positive out of period adjustment in 2003 to remove excess accrual for cost of gas.

Operating expenses for the three months ended September 30, 2004 increased $1 million. This was due to increased marketing activities in 2004 and an increase in outside services, including services for SouthStar’s SOX 404 compliance efforts. There was also a $2 million decrease in minority interest primarily as a result of lower SouthStar earnings in 2004 as compared to 2003.

Nine months 2004 compared to nine months 2003 The increase in EBIT of $15 million for the nine months ended September 30, 2004 compared to the same period in 2003 is primarily due to improved results from SouthStar. On a pro-forma basis, operating margin for the nine months ended September 30, 2004 increased $3 million. This was due to:

·	$6 million increase due to lower hedging costs in 2004 as compared to 2003.

·	$3 million increase due to higher customer service charges in 2004 as compared to 2003.

·	$4 million decrease due to lower commodity margins in 2004.

·	$2 million decrease related to a one-time sale of storage assets in 2003.

Operating expenses decreased by $6 million primarily due to lower bad debt expense as a result of SouthStar’s ongoing active customer collection process improvements and the increased credit quality of the customer base. There was also a $5 million decrease in minority interest primarily due to an increase in our ownership percentage in SouthStar.


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Consolidation of SouthStar Pursuant to our adoption of FIN 46R, we consolidated all of SouthStar’s accounts with our subsidiaries’ accounts as of January 1, 2004. We recorded Piedmont’s portion of SouthStar’s earnings as a minority interest in our condensed consolidated statements of income and Piedmont’s portion of SouthStar’s contributed capital as a minority interest on our condensed consolidated balance sheet. We eliminated any intercompany profits between segments. Below are our unaudited pro-forma condensed consolidated balance sheet and statement of income, presented as if SouthStar’s balances were consolidated with our subsidiaries’ accounts as of December 31, 2 003. This pro-forma presentation is a non-GAAP presentation; however, we believe this pro-forma presentation is useful to users of our financial statements since it presents prior year revenues and expenses on the same basis as 2004 following our consolidation of SouthStar pursuant to our adoption of FIN 46R. These unaudited pro-forma amounts are only presented for comparative purposes.

AGL Resources Inc. and Subsidiaries
Pro-forma condensed consolidated balance sheet
December 31, 2003
(unaudited)

In millions	As reported		SouthStar		Eliminations (3)			Pro-forma
Current assets	$	742	$	174		($11	)	$	905
Property, plant and equipment		2,352		2		-			2,354
Deferred debits and other assets (1)		878		-		(71	)		807
Total assets	$	3,972	$	176		($82	)	$	4,066

Current liabilities	$	1,048	$	75	($11	)	$	1,112
Accumulated deferred income taxes		376		-	-			376
Long-term liabilities		569		-	-			569
Deferred credits		77		-	-			77
Minority interest (2)		-		-	30			30
Capitalization		1,902		101	(101	)		1,902
Total liabilities and capitalization	$	3,972	$	176	($82	)	$	4,066

(1)	Our investment in SouthStar was $71 million.

(2)	Minority interest adjusts our balance sheet to reflect Piedmont’s portion of SouthStar’s contributed capital

(3)	Includes the intercompany eliminations, our investment in SouthStar and SouthStar’s capitalization.

AGL Resources Inc. and Subsidiaries
Pro-forma condensed consolidated statement of income
for the three months ended September 30, 2003
(unaudited)

In millions	As reported			SouthStar (1)		Eliminations (3)			Pro-forma
Operating revenues	$	165		$	110		($39	)	$	236
Operating expenses
Cost of gas		28			88		(39	)		77
Operation and maintenance expenses		66			14		-			80
Depreciation and amortization		23			-		-			23
Taxes other than income		6			-		-			6
Total operating expenses		123			102		(39	)		186
Gain on sale of Caroline Street campus		16			-		-			16
Operating income		58			8		-			66
Equity earnings from SouthStar		5			-		(5	)		-
Donation to private foundation		(8	)		-		-			(8	)
Other income		1			-		-			1
Interest expense		(19	)		-		-			(19	)
Minority interest in income of consolidated subsidiary (2)		-			-		(3	)		(3	)
Earnings before income taxes		37			8		(8	)		37
Income taxes		15			-		-			15
Income before cumulative effect of change in accounting principle	$	22		$	8		($8	)	$	22

(1)	Includes 100% of SouthStar’s revenues and expenses for comparisons among 2003 and 2004 quarters adjusted for SouthStar’s consolidation in 2004.

(2)	Minority interest adjusts our earnings to reflect our 70% share of SouthStar’s earnings (less Dynegy Inc.’s 20% share of SouthStar’s income prior to February 18, 2003).

(3)	Includes intercompany eliminations and our equity in earnings from SouthStar


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AGL Resources Inc. and Subsidiaries
Pro-forma condensed consolidated statement of income
for the nine months ended September 30, 2003
(unaudited)

In millions	As reported			SouthStar (1)		Eliminations			Pro-forma
Operating revenues	$	704		$	538		($149	)	$	1,093
Operating expenses
Cost of gas		222			443		(149	)		516
Operation and maintenance expenses		208			46		-			254
Depreciation and amortization		68			1		-			69
Taxes other than income		21			-		-			21
Total operating expenses		519			490		(149	)		860
Gain on sale of Caroline Street campus		16			-		-			16
Operating income		201			48		-			249
Equity earnings from SouthStar		29			-		(29	)		-
Donation to private foundation		(8	)		-		-			(8	)
Other income		1			-		-			1
Interest expense		(57	)		-		-			(57	)
Minority interest in income of consolidated subsidiary (2)		-			-		(19	)		(19	)
Earnings before income taxes		166			48		(48	)		166
Income taxes		65			-		-			65
Income before cumulative effect of change in accounting principle	$	101		$	48		($48	)	$	101

(1)	Includes 100% of SouthStar’s revenues and expenses for comparisons among 2003 and 2004 quarters adjusted for SouthStar’s consolidation in 2004.

(2)	Minority interest adjusts our earnings to reflect our 70% share of SouthStar’s earnings (less Dynegy Inc.’s 20% share of SouthStar’s income prior to February 18, 2003).

(3)	Includes intercompany eliminations and our equity in earnings from SouthStar


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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.

In August 2003, we formed Pivotal within AGSC. 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.

Results of operations for our corporate segment for the three and nine months ended September 30, 2004 and 2003 are as follows:

	Three months ended September 30,								Nine months ended September 30,
In millions	2004			2003			2004 vs. 2003		2004			2003			2004 vs. 2003
Operation and maintenance (1)		($1	)		($1	)		-		($4	)		($7	)	$	3
Depreciation and amortization		2			2			-		7			7			-
Taxes other than income		1			-			1		3			2			1
Total operating expenses		2			1			1		6			2			4
Asset disposal on sale of Caroline Street campus		-			(5	)		5		-			(5	)		5
Operating (loss) income		(2	)		(6	)		4		(6	)		(7	)		1
Other loss		-			-			-		(1	)		(1	)		-
EBIT		($2	)		($6	)	$	4		($7	)		($8	)	$	1

(1)	Includes the allocation of operating expenses to our operating segments.

Third quarter 2004 compared to third quarter 2003 EBIT for the quarter ended September 30, 2004 increased $4 million as compared to the same period last year, primarily due to the prior year’s $5 million loss on the disposal of the Caroline Street assets, offset by an increase in operating expenses of $1 million in 2004. Excluding corporate allocations, the increase in operating expenses was due to increased costs associated with the Company’s ongoing SOX 404 compliance efforts and implementation of our work management system project offset by lower 2004 benefit expenses associated with long-term incentives compensation.

Nine months 2004 compared to nine months 2003 EBIT for the nine months ended September 30, 2004 increased $1 million as compared to the same period last year primarily due to the prior year’s $5 million loss on the disposal of the Caroline Street assets. This was offset by an increase in corporate costs, net of corporate allocations, of $4 million resulting from increased operating expenses. Excluding corporate allocations, operating expenses increased due primarily to costs associated with software maintenance, licensing and implementation of our work management system project, a los s on the retirement of information services and facilities assets, higher costs due to our SOX 404 compliance efforts, merger and acquisition related expenses and expenses related to Pivotal’s activities in 2004.


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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. On April 1, 2004 we received approval from the SEC under the PUHCA for the renewal of our financing authority to issue securities through April 2007.

On September 30, 2004 we amended our Credit Facility. Under the terms of the amendment, the initial term of the credit agreement has been extended from May 26, 2007 to September 30, 2009. The aggregate principal amount available under the amended credit agreement has been increased from $500 million to $750 million, and our option to increase the aggregate cumulative principal amount available for borrowing on not more than one occasion during each calendar year during the term of the amended credit agreement has been increased from $200 million to $250 million. The availability of borrowings and unused availability under our Credit Facility is limited and subject to conditions specified within the Credit Facility, which we c urrently 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 at September 30, 2004, December 31, 2003 and September 30, 2003 is represented in the table below.

In millions	Sept. 30, 2004		Dec. 31, 2003		Sept. 30, 2003
Unused availability under the Credit Facility	$	750	$	500	$	500
Cash and cash equivalents		44		17		1
Total cash and available liquidity under the Credit Facility	$	794	$	517	$	501

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 a most of our cash flow from operations, and we anticipate this to continue in the future. However, our liquidity and capital resource requirements may change in the future due to a number of factors, some of which we cannot control. These factors include:

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

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

·	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

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

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

·	operational risks

·	risks related to the anticipated debt and equity financings associated with our NUI acquisition


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Seasonality The seasonal nature of our sales affects the comparison of certain balance sheet items at September 30, 2004 and December 31, 2003, such as receivables, unbilled revenue, inventories and short-term debt. We have presented the condensed consolidated balance sheet as of September 30, 2003 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. The following table illustrates our expected future contractual obligations:

			Payments Due before December 31,
					2005		2007		2009
					&		&		&
In millions	Total		2004		2006		2008		Thereafter
Long-term debt (1)	$	1,216	$	-	$	-	$	-	$	1,216
Short-term debt		85		85		-		-		-
Pipeline charges, storage capacity and gas supply (2)		705		63		279		125		238
Commodity and transportation charges		32		29		3		-		-
Pipeline replacement program costs (3)		352		25		166		161		-
ERC (3)		61		6		28		3		24
Operating leases (4)		77		3		23		17		34
Communication/network service and maintenance		18		2		12		4		-
Total	$	2,546	$	213	$	511	$	310	$	1,512

(1)	Includes $235 million of Notes Payable to Trusts, callable in 2006 and 2007.

(2)	Charges recoverable through a PGA mechanism or alternatively billed to Marketers. Also includes demand changes associated with Sequent.

(3)	Charges recoverable through rate rider mechanisms.

(4)

We have certain operating leases with provisions for step rent or esclation payments, or certain lease concessions. We account for these leases by recongnizing 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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			Commitments Due before December 31,
					2005		2007		2009
					&		&		&
In millions	Total		2004		2006		2008		Thereafter
Guarantees (1) (2)	$	251	$	251	$	-	$	-	$	-
Standby letters of credit, performance/ surety bonds		12		8		4		-		-
Total other commercial commitments	$	263	$	259	$	4	$	-	$	-

(1)

(2)

We provide gurantees on behalf of our subsidiary, SouthStar. We guarantee 70% of SouthStar's obligations to SNG under certain agreements between the parties up to a maximum of $7 million of SouthStar fails to make payments to SNG. Under a second such guarantee, we guarantee SouthStar's obligations to AGLC under certain agreements between the parties up to a maximum of $64 million. We have an agreement with our partner in SouthStar for our partners to indemnify us for their 30% obligation under this guarantee.

Cash flow provided from operating activities Our statement of cash flows is 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, undistributed earnings from equity investments, changes in deferred income taxes, gains or losses on the sale of assets and changes in the balance sheet for working capital from the beginning to the end of the period.

Our operating cash flows for the nine months ended September 30, 2004 include SouthStar’s operating cash flows of approximately $82 million as a result of our consolidation of SouthStar effective January 1, 2004. In 2003, our operating cash flow only included amounts for cash distributions and our equity in earnings from SouthStar, consistent with the equity method of accounting. Excluding SouthStar, our cash flow from operations for the nine months ended September 30, 2004 was $173 million, an increase of $72 million from the same period in 2003. Year-to-year changes in our operating cash flows, excluding SouthStar, were primarily the result of the following:

·	decreased cash payments for inventory purchases of $53 million. These decreases were a result of lower payments for seasonal injections of $36 million and the purchase in 2003 of Marketers’ gas inventory of $12 million

·	decreased cash payments of approximately $30 million for our energy marketing payables due to lower NYMEX prices of $0.38 per dekatherm and decreases in purchased volumes of 2 billion cubic feet

·	increased earnings of $14 million.

·	these increases were mostly offset by increased cash payments for environmental response costs of $13 million and the $8 million payment for the termination of our treasury lock instruments. For more information on the treasury lock termination, see Note 4, Risk Management

We generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters due to significant volumes of natural gas that are delivered by distribution operations and SouthStar to our customers during the November-to-March heating season. In addition, during this period our accounts payable increases to reflect payments due to providers of the natural gas commodity and pipeline capacity. The value of the natural gas commodity can vary significantly from one period to the next as a result of the volatility in the price of natural gas.

Our natural gas costs and deferred purchased natural gas costs due from or to our customers represent the difference between natural gas costs that have been paid to suppliers in the past and what has been collected from customers. These natural gas costs can cause significant variations in cash flows from period to period. Finally, our natural gas inventories, which usually peak on November 1, are largely drawn down in the heating season and provide a source of cash as this asset is used to satisfy winter sales demand.


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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 $168 million in the nine months ended September 30, 2004 and $113 million in the same period in 2003.

	Nine months ended
	September 30,
In millions	2004		2003		2004 vs. 2003
Construction of distribution facilities	$	42	$	39	$	3
Pipeline replacement program (1)		67		36		31
Pivotal propane plant		16		-		16
Other		43		38		5
Total property, plant and equipment expenditures		168		113		55
Environmental response costs (2)		36		22		14
Total capital requirements	$	204	$	135	$	69

(1)	These expenditures include removal costs. Capital expenditures under this program are expected to end June 30, 2008, unless the program is extended by the GPSC.

(2)	These costs are not included in our cash flows used in investing activities as they are not considered property, plant and equipment expenditures. They are considered a component of our capital requirements as we estimate our cash requirements for future years.

The increase of $55 million is primarily from higher expenditures at our distribution operations segment, including higher expenditures at AGLC. This includes a $31 million increase in the PRP as a result of larger diameter and more expensive replacement pipe that has been installed this year. In addition, the increase at Pivotal Propane of $16 million relates to expenditures for the construction of a propane plant in the VNG service area.

These increases were offset by decreased telecommunications expenditures at AGL Networks of $5 million as a result of the completion of our initial Atlanta and Phoenix networks in 2003. In 2004, our investing activities also included $31 million in cash receipts for the sale of our interests in US Propane. In 2003, we paid $20 million for the purchase of Dynegy’s 20% interest in SouthStar.

Cash flow used in financing activities 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 total debt relative to our total capitalization, as well as the term and interest rate profile of our debt securities. We work to maintain or improve our capitalization by effectively managing the credit ratings of our senior notes. As of October 2004, those ratings were BBB+ from Standard & Poor’s Ratings Services (S&P), Baa1 from Moody’s Investor Service (Moody’s) and BBB+ from Fitch Ratings (Fitch).

As a result of our definitive agreement to acquire NUI, which includes the assumption of approximately $606 million of NUI’s debt, the outlooks on our credit ratings have changed. Moody’s recently affirmed our ratings but changed its rating outlook to negative from stable. Both S&P and Fitch placed our credit ratings on watch status with negative outlooks.

These rating agencies have indicated their actions are the result of the execution risks in consummating, financing and integrating the NUI acquisition and certain closing conditions that must be met by NUI. The execution risks include obtaining regulatory approvals and the capital market risks related to the successful completion of equity and debt financing related to the acquisition closing, mitigating our increased leverage. The closing conditions include NUI’s obtaining additional liquidity lines, obtaining a favorable rate order from the NJBPU and assurances that issues raised in an audit of NUI by the NJBPU and ongoing investigations are resolved.


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Our capitalization strategy also includes expected equity proceeds and debt borrowings related to the acquisition of NUI. We will acquire all of the outstanding shares of NUI for $13.70 per share in cash, or $220 million in the aggregate based on approximately 16 million shares outstanding. We expect to fund the purchase of these shares primarily through the issuance of common stock with proceeds of at least $2 75 million. The total value of the acquisition is estimated at $715 million, which includes the assumption of approximately $606 million of NUI’s debt and $111 million of cash on its June 30, 2004 balance sheet. We expect to refinance a portion of NUI’s outstanding debt through the issuance of our debt securities.

On October 22, 2004, we signed a $700 million bridge credit agreement. The bridge facility is intended only to provide us with short-term financing for our purchase of NUI. Any amount borrowed under the facility must be repaid prior to its September 30, 2005 expiration date. We may draw on the commitments under the bridge facility on the closing date of the acquisition of NUI to pay obligations related to the purchase, including the payment of related acquisition fees and expenses, certain of NUI’s regulatory obligations and certain existing indebtedness of NUI that matures at closing. The capacity under the bridge credit agreement will be reduced by the amount of the proceeds of any financing we complete prior to closing the NUI acquisition (with the exception of our commercial paper program). The bridge cred it agreement has representations, covenants and costs that are similar to those in our existing Credit Facility.

In the nine months ended September 30, 2004 and 2003, our cash used in financing activities consists primarily of borrowings and payments of short-term debt, borrowings of senior notes, payments of Medium-Term notes, cash dividends on our common stock and the issuance of common stock. Our Credit Facility financial covenants and the PUHCA’s order require us to maintain a ratio of total debt-to-total capitalization of no greater than 70.0%, and our goal is to maintain our common equity ratio in the 40 - 50 % range of total capitalization. As of September 30, 2004, we were in compliance with this leverage ratio requirement.

Our short-term debt financing generally increases between September 30 and December 31 because our payments for natural gas and pipeline capacity are generally made to suppliers prior to the collection of accounts receivable from our customers. In addition, we typically reduce short-term debt balances in the spring because a significant portion of our current assets are converted into cash at the end of the winter heating season.

We believe that accomplishing these capital structure objectives and maintaining sufficient cash flow are necessary to maintain our current credit ratings and to allow our 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	September 30, 2004				December 31, 2003				September 30, 2003
Short-term debt	$	51	2	%	$	306	13	%	$	127	6	%
Current portion of long-term debt		34	1			77	3			42	2
Senior and Medium-Term notes (1)		981	42			731	32			904	41
Note payable to capital trust (1)		235	10			-	-			-	-
Trust Preferred Securities (1)		-	-			225	10			227	10
Total debt		1,301	55			1,339	58			1,300	59

Minority interest		30	1			-	-			-	-
Common equity		1,023	44			946	42			908	41
Total capitalization	$	2,354	100	%	$	2,285	100	%	$	2,208	100	%

(1)	Net of interest rate swaps

Short-term debt Our short-term debt is composed of borrowings under our commercial paper program, Sequent’s line of credit and SouthStar’s line of credit. The decrease in our short-term debt of $255 million is primarily a result of payments on outstanding commercial paper from:

·	cash generated from strong operating results

·	proceeds from the issuance of our 6.0% senior notes due in 2034

·	positive working capital from lower receivable requirements

·	proceeds from the sale of our ownership interest in US Propane

·	receipt of cash from SouthStar between December 2003 and September 2004


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Long-term Debt On September 27, 2004, AGL Capital issued $250 million of senior notes with a maturity date of October 1, 2034. These senior notes have an interest rate of 6.0% payable on April 1 and October 1, beginning April 1, 2005. We fully and unconditionally guarantee the senior notes. The proceeds from the issuance were used for to refinance a portion of the existing short-term debt under our commercial paper program and for general corporate purposes.

In the nine months ended September 30, 2004, we made $49 million in Medium-Term note payments, as follows:

·	In January, 2004, we exercised our option to redeem $44 million at a call premium. These notes were scheduled to mature in 2019 with interest rates ranging from 7.0% to 7.1%

·	In February 2004, we exercised our option to redeem $5 million at a call premium. This note was scheduled to mature in 2014 with a interest rate of 7.0%

Minority interest SouthStar’s accounts have been combined with our subsidiaries’ accounts as of and for the nine months ended September 30, 2004. As a result, we recorded Piedmont’s portion of SouthStar’s contributed capital as minority interest on our condensed consolidated balance sheet and included it as a component of our capitalization. In addition, we recorded a cash disbursement of $14 million in our cash flows from financing activities for SouthStar’s dividend distribution to Piedmont.

Interest Rate Swaps To maintain an effective capital structure, it is our policy to borrow funds using a mix of fixed-rate debt and variable-rate debt. We have entered into interest rate swap agreements, for the purpose of hedging the interest rate risk associated with our fixed-rate and variable-rate debt obligations. Including the effects of our interest rate swaps, 83% of our total short-term and long-term debt was fixed. For more discussion of our interest rate swaps, see Note 4, Risk Management.

Dividends on Common Stock On April 28, 2004, we announced a 4% increase in our common stock dividend, raising the quarterly dividend from $0.28 per share to $0.29 per share, which equates to an indicated annual dividend of $1.16 per share. This increase in our common stock dividend resulted in an approximately $1 million increase in dividends paid on our common shares during the nine months ended September 30, 2004.

Shelf Registration We currently have a shelf registration statement for up to $1 billion of various capital securities, with remaining capacity of $750 million. On October 22, 2004, we filed a new shelf registration statement with the SEC for authority to increase our aggregate capacity to $1.5 billion of various capital securities to provide for expected financing related to NUI and other financing requirements. We may seek additional financing through debt or equity offerings in the private or public markets at any time.


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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 based 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, 2003 and includes the following:

·	Regulatory Accounting

·	Pipeline Replacement Program

·	Environmental Response Costs

·	Revenue Recognition

·	Accounting for Contingencies

·	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. The following presents additional information on our more important critical accounting policies:

Derivatives and Hedging Activities

SFAS 133, as updated by SFAS 149, established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. However, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting treatment of SFAS 133, as updated by SFAS 149, and is accounted for using traditional accrual accounting.

SFAS 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, SFAS 133 allows a derivative’s gains and losses to offset related results on the hedged item in the income statement in the case of a fair value hedge, or to record the gains and losses in other comprehensive income until maturity in the case of a cash flow hedge. Additionally, SFAS 133 requires that a company formally designate a derivative as a hedge as well as document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting treatment. Two areas where SFAS 133 applies are interest rate swaps and gas commodity contracts at both Sequent and SouthStar. Our derivative and hed ging activities are described in further detail in Note 3 to the condensed consolidated financial statements.

Interest rate swaps We designate our interest rate swaps as fair value hedges as defined by 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 not effective in achieving offsetting changes in fair value.

Commodity-related derivative instruments We are exposed to risks associated with changes in the market of natural gas. Through Sequent and SouthStar, we use derivative instruments to reduce our exposure to the risk of changes in the prices of natural gas. When the market value of the portfolio changes, primarily due to newly originated transactions and the effect of price changes, Sequent recognizes the change in value of derivative instruments as an unrealized gain or loss in revenues in the period of change. Sequent recognizes cash inflows and outflows associated with the settlement of these risk management activities in operating cash flows, and Sequent reports these settlements as receivables and payables separately from risk management activities in the balance sheet as energy marketing receivables and trade payables.


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Under our risk management policy, we attempt to mitigate substantially all of our commodity price risk associated with Sequent’s storage gas portfolio and lock in the economic margin at the time we enter into gas purchase transactions for our stored gas. We purchase gas for storage when the current market price we pay for gas plus the cost to store the gas is less than the market price we could receive in the future by selling NYMEX futures contracts, or other over-the-counter derivatives, in the forward months, resulting in a positive net profit margin. We use contracts to sell gas at that future price to substantially lock in the profit margin we will ultimately realize when the stored gas is actually sold. These contracts meet the definition of a derivative under SFAS 133.

The purchase, storage and sale of natural gas 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 economic margin is essentially unchanged from the date the transactions were consummated. We do not currently use hedge accounting under SFAS 133 to account for this activity.

Gas that we purchase and inject into storage is accounted for on an accrual basis, at the lower of average cost or market, as inventory in our consolidated balance sheets and is no longer marked to market following our implementation of the accounting guidance in EITF 02-03. Under current accounting guidance, we would recognize a loss in any period when the market price for gas is lower than the carrying amount for our purchased gas inventory. Costs to store the gas are recognized in the period the costs are incurred. We recognize revenues and cost of gas sold in our statement of consolidated income in the period we sell gas and it is delivered out of the storage facility.

The derivatives we use to mitigate commodity price risk and substantially lock in the margin upon the sale of stored gas are accounted for at fair value and marked to market each period, with changes in fair value recognized as unrealized gains or losses in the period of change. This difference in accounting, the accrual basis for our gas storage inventory versus mark-to-market accounting for the derivatives used to mitigate commodity price risk, can result in volatility in our reported net income. Based upon Sequent’s storage positions at September 30, 2004, a $0.10 forward NYMEX change would result in $0.6 million impact to Sequent’s EBIT.

Over time, gains or losses on the sale of gas storage inventory will be offset by losses or gains on the derivatives, resulting in realization of the economic profit margin we expected when we entered into the transactions. This accounting difference causes Sequent’s earnings on its storage gas positions to be affected by natural gas price changes, even though the economic profits remain essentially unchanged. Sequent manages underground storage for our utilities and holds certain capacity rights on its own behalf. The underground storage is of two types:

·	reservoir storage, where supplies are generally injected and withdrawn on a seasonal basis

·	salt dome high-deliverability storage, where supplies may be periodically injected and withdrawn on relatively short notice

SouthStar also uses derivative instruments to manage exposures arising from changing commodity prices. SouthStar’s objective for holding these derivatives is to minimize this risk using the most effective methods to reduce or eliminate the impacts of these exposures. A significant 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 other comprehensive income (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 into earnings in the period in which it occurs. SouthStar curr ently has no 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.

Weather derivative contracts SouthStar routinely enters into weather derivative contracts for hedging purposes in order to preserve margins in the event of warmer-than-normal weather in the winter months. SouthStar accounts for these contracts using the intrinsic value method under the guidelines of EITF 99-02, “Accounting for Weather Derivatives”. There were no weather derivative contracts outstanding as of September 30, 2004 and 2003.


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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 AGLC 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, and 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.

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 September 30, 2004, December 31, 2003 and September 30, 2003. We base the average values on monthly averages for the nine months ended September 30, 2004 and 12 months ended December 31, 2003.

Asset	Average Values				Value at:
*In millions*	Nine months ended Sept.30, 2004		Twelve months ended Dec. 31, 2003		Sept. 30, 2004		Dec. 31, 2003		Sept. 30, 2003
Natural gas contracts	$	12	$	14	$	28	$	13	$	10

Liability	Average Values				Value at:
*In millions*	Nine months ended Sept. 30, 2004		Twelve months ended Dec. 31, 2003		Sept. 30, 2004		Dec. 31, 2003		Sept. 30, 2003
Natural gas contracts	$	7	$	14	$	28	$	18	$	8

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.


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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 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 nine months ended September 30, 2004 and twelve months ended December 31, 2003 had the following 1-day and 10-day holding period VaRs:

	Nine months ended September 30, 2004				Twelve months ended December 31, 2003
In millions	1-day		10-day		1-day		10-day
Period end (1)	$	0.1	$	0.4	$	0.3	$	1.0
Average		0.1		0.3		0.1		0.3
High		0.4		1.2		2.5		4.7
Low (1)		0.0		0.0		0.0		0.0

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

Energy Investments 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. In June 2004, the SouthStar risk management committee approved replacing the 20-day VaR limit with a 10-day VaR limit. The 10-day VaR limit was determined to be a more appropriate industry standard, and thus adopted by SouthStar. A 95% confidence interval is used to evaluate VaR exposure. The maximum VaR experienced during the nine months ended September 30, 2004 was less than $0.1 million for the 1-day holding period and $0.2 million for the 10-day holding period.

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 on the strength of its financial ratios.

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 A at September 30, 2004, compared with our previously reported rating of BBB at December 31, 2003. For more information on Sequent’s counterparties credit ratings, see the discussion in “Results of Operation - Wholesale Services.”


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The following tables show Sequent’s commodity receivable and payable positions as of September 30, 2004, December 31, 2003 and September 30, 2003:

Gross receivables
In millions	Sept. 30, 2004		Dec. 31, 2003		Sept. 30, 2003
Receivables with netting agreements in place:
Counterparty is investment grade	$	213	$	282	$	169
Counterparty is non-investment grade		18		13		11
Counterparty has no external rating		37		9		3

Receivables without netting agreements in place:
Counterparty is investment grade		6		15		4
Counterparty is non-investment grade		-		-		-
Counterparty has no external rating		-		-		-
Amount recorded on balance sheet	$	274	$	319	$	187

Gross payables
In millions	Sept. 30, 2004		Dec. 31, 2003		Sept. 30, 2003
Payables with netting agreements in place:
Counterparty is investment grade	$	159	$	205	$	152
Counterparty is non-investment grade		37		31		39
Counterparty has no external rating		76		45		26

Payables without netting agreements in place:
Counterparty is investment grade		22		29		17
Counterparty is non-investment grade		2		3		-
Counterparty has no external rating		-		16		8
Amount recorded on balance sheet	$	296	$	329	$	242


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Item 4. Controls and Procedures

(a)

Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, after evaluating the effectiveness of our "disclosure controls and procedures" (as defined in SEC Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this quarterly report, have concluded that our disclosure controls and procedures were effective in ensuring that information required to be disclosed by us (including our consolidated subsidiaries) in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to our management, including our chief executive officer and our chief financial officer, or persons performing similar functions, 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 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.


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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/or litigation incidental to the business. For information regarding the NUI shareholder complaint and its resolution, see Note 8, “Commitments and Contingencies.” For information regarding pending federal and state regulatory matters, see "Results of Operations - Distribution Operations" and “Results of Operations - Wholesale Services” 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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth our common stock repurchases for the three months ended September 30, 2004. All shares were purchased in open market transactions in connection with awards payable in common stock under the AGL Resources Inc. Officer Incentive Plan (OIP).

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 1, 2004 - July 31, 2004		-		-		-		517,260
August 1, 2004 - August 31, 2004		36,142	$	30.06		36,142		481,118
September 1, 2004 - September 30, 2004		2,047	$	30.93		2,047		479,071
Total third quarter		38,189	$	30.11		38,189		479,071

(1) On June 30, 2001, we disclosed that our board of directors approved the repurchase of up to 600,000 shares of our common stock to be used for the OIP. As of September 30, 2004 a total of 120,929 shares have been repurchased, leaving a maximum of 479,071 shares that can still be repurchased for use in the OIP.


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PART II -- OTHER INFORMATION - Continued

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

10.1	Forms of AGL Resources Inc. Long-Term Incentive Plan

10.2	Credit Agreement, dated as of October 22, 2004, among AGL Resources Inc., as Guarantor, AGL Capital Corporation, as Borrower, JP Morgan Chase Bank, as administrative agent, Morgan Stanley Senior Funding, Inc. as syndication agent, and several other banks and other financial institutations named therein.

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

32	Section 1350 Certifications

(b) Reports on Form 8-K.

Date of report	Event reported
July 15, 2004	Filed under Items 5 “Other Events” and 7 “Financial Statements and Exhibits” and furnished under Item 9 “Regulation FD Disclosure” related to execution of agreement to acquire NUI

July 26, 2004	Filed under Item 5 “Other Events” related to re-appointment of Thomas D. Bell, Jr. to board of directors

July 29, 2004	Furnished under Item 12 “Results of Operations and Financial Condition” related to June 30, 2004 financial results

August 9, 2004	Furnished under Item 9 “Regulation FD Disclosure” related to acquisition of Jefferson Island

September 9, 2004	Filed under Item 8.01 “Other Events” related to NUI lawsuit

September 22, 2004	Furnished under Item 7.01 “Regulation FD Disclosure” regarding public offering of senior notes

September 22, 2004	Filed under Items 1.01 “Entry into a Material Definitive Agreement”, 8.01 “Other Events” and 9.01 “Financial Statements and Exhibits” regarding public offering of senior notes

September 30, 2004	Filed under Items 1.01 “Entry into a Material Definitive Agreement”, Item 2.03 “Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant” and Item 9.01 “Financial Statements and Exhibits” regarding amendment of our Credit Facility


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Table of Contents

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: October 27, 2004	/s/ Richard T. O'Brien
	Executive Vice President and Chief Financial Officer