SOUTHERN Co GAS (GAS) 10-Q 2005 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ü] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2005
OR
[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-14174
AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)
Georgia	58-2210952
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Ten Peachtree Place NE, Atlanta, Georgia 30309
(Address and zip code of principal executive offices)
404-584-4000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for at least the past 90 days. Yes ü No
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes  ü No
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes    No ü
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 20, 2005
Common Stock, $5.00 Par Value		77,651,829

AGL RESOURCES INC.

Form 10-Q

For the Quarterly Period Ended September 30, 2005

TABLE OF CONTENTS

Item Number		Page(s)
	PART I - FINANCIAL INFORMATION	3-50
1	Condensed Consolidated Financial Statements (Unaudited)	3-22
	Condensed Consolidated Balance Sheets	3
	Condensed Consolidated Statements of Income	4
	Condensed Consolidated Statements of Common Shareholders’ Equity	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to Condensed Consolidated Financial Statements	7
	Note 1 - Accounting Policies and Methods of Application	7-9
	Note 2 - NUI Corporation Acquisition Update	9
	Note 3 - Recent Accounting Pronouncements	9-10
	Note 4 - Risk Management	10-12
	Note 5 - Regulatory Assets and Liabilities	13-15
	Note 6 - Pension and Other Post-retirement Benefits	15-16
	Note 7 - Compensation Plans	16
	Note 8 - Financing	17
	Note 9 - Commitments and Contingencies	18
	Note 10 - Segment Information	18-22
2	Management's Discussion and Analysis of Financial Condition and Results of Operation	23-50
	Cautionary Statement Regarding Forward-Looking Information	23
	Overview	23-27
	Results of Operations	27-43
	AGL Resources	27-30
	Distribution Operations	30-34
	Retail Energy Operations	34-35
	Wholesale Services	36-40
	Energy Investments	40-41
	Corporate	42-43
	Liquidity and Capital Resources	44-47
	Critical Accounting Policies and Estimates	47-48
	Accounting Developments	48
3	Quantitative and Qualitative Disclosures About Market Risk	48-50
4	Controls and Procedures	50
	PART II - OTHER INFORMATION	50-51
1	Legal Proceedings	50-51
2	Unregistered Sales of Equity Securities and Use of Proceeds	51
6	Exhibits	51
	SIGNATURE	52

2

PART I - Financial Information Item 1. Condensed Consolidated Financial Statements (Unaudited)
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
In millions, except shares and par value	Sept. 30, 2005		Dec. 31, 2004		Sept. 30, 2004
Current assets
Cash and cash equivalents	$	57	$	49	$	44
Receivables (less allowance for uncollectible accounts of $13 at Sept. 30, 2005, $15 at Dec. 31, 2004 and $12 at Sept. 30, 2004)		781		737		328
Inventories		518		332		340
Energy marketing and risk management assets		161		38		33
Unbilled revenues		58		152		34
Recoverable environmental remediation costs		29		27		26
Recoverable pipeline replacement program costs		24		24		24
Other		190		98		19
Total current assets		1,818		1,457		848
Property, plant and equipment
Property, plant and equipment		4,727		4,615		3,509
Less accumulated depreciation		1,487		1,437		1,072
Property, plant and equipment-net		3,240		3,178		2,437
Deferred debits and other assets
Goodwill		405		354		177
Recoverable pipeline replacement program costs		331		337		358
Recoverable environmental remediation costs		180		173		147
Other		112		141		67
Total deferred debits and other assets		1,028		1,005		749
Total assets	$	6,086	$	5,640	$	4,034
Current liabilities
Payables	$	819	$	728	$	423
Short-term debt		344		334		51
Energy marketing and risk management liabilities		278		15		26
Accrued expenses		118		65		38
Accrued pipeline replacement program costs		47		85		88
Other		152		250		157
Total current liabilities		1,758		1,477		783
Accumulated deferred income taxes		412		437		433
Long-term liabilities
Accrued pipeline replacement program costs		270		242		264
Deferred credits		168		73		70
Accumulated removal costs		92		94		93
Accrued environmental remediation costs		90		63		36
Accrued pension obligations		87		84		28
Accrued postretirement benefit costs		54		58		48
Other		57		68		10
Total long-term liabilities		818		682		549
Commitments and contingencies (Note 9)
Minority interest		31		36		30
Capitalization
Long-term debt		1,616		1,623		1,216
Shareholders’ equity (Common stock, $5 par value, 750 million shares authorized; 77.6 million shares issued and outstanding at September 30, 2005; 76.7 million shares issued and outstanding at December 31, 2004; 64.9 million shares issued and outstanding at September 30, 2004)		1,451		1,385		1,023
Total capitalization		3,067		3,008		2,239
Total liabilities and capitalization	$	6,086	$	5,640	$	4,034

See Notes to Condensed Consolidated Financial Statements (Unaudited)

3

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
	Three months ended September 30,						Nine months ended September 30,
In millions, except per share amounts	2005			2004			2005			2004
Operating revenues	$	393		$	262		$	1,736		$	1,206
Operating expenses
Cost of gas		191			105			972			626
Operation and maintenance		106			83			334			257
Depreciation and amortization		33			23			99			71
Taxes other than income		9			5			30			20
Total operating expenses		339			216			1,435			974
Operating income		54			46			301			232
Other income		-			-			2			2
Interest expense		(27	)		(17	)		(79	)		(49	)
Minority interest		(2	)		-			(18	)		(14	)
Earnings before income taxes		25			29			206			171
Income taxes		10			9			79			64
Net income	$	15		$	20		$	127		$	107
Basic earnings per common share	$	0.19		$	0.31		$	1.64		$	1.66
Diluted earnings per common share	$	0.19		$	0.31		$	1.62		$	1.64
Weighted-average number of common shares outstanding
Basic		77.5			65.1			77.2			64.8
Diluted		78.1			65.8			77.8			65.5

See Notes to Condensed Consolidated Financial Statements (Unaudited)

4

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
(UNAUDITED)
					Premium on					Other
	Common stock				common		Earnings			comprehensive
In millions, except per share amount	Shares		Amount		shares		reinvested			income			Total
Balance as of December 31, 2004		76.7	$	384	$	632	$	415		$	(46	)	$	1,385
Comprehensive income:
Net income		-		-		-		127			-			127
Net unrealized loss from hedging activities (net of taxes)		-		-		-		-			(8	)		(8	)
Total comprehensive income														119
Dividends on common shares ($0.93 per share)		-		-		-		(72	)		-			(72	)
Stock compensation, dividend reinvestment and share purchase plans		0.9		4		15		-			-			19
Balance as of September 30, 2005		77.6	$	388	$	647	$	470		$	(54	)	$	1,451

See Notes to Condensed Consolidated Financial Statements (Unaudited)

5

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
	Nine months ended
	September 30,
In millions	2005			2004
Cash flows from operating activities
Net income	$	127		$	107
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		99			71
Deferred income taxes		(25	)		57
Changes in certain assets and liabilities
Payables		93			(38	)
Receivables		43			200
Inventories		(187	)		(102	)
Other		37			(40	)
Net cash flow provided by operating activities		187			255
Cash flows from investing activities
Property, plant and equipment expenditures		(194	)		(168	)
Sale of ownership interest in Saltville Gas Storage Company, LLC		66			-
Sale of ownership interest in US Propane, LP		-			31
Other		8			13
Net cash flow used in investing activities		(120	)		(124	)
Cash flows from financing activities
Payments and borrowings of short-term debt		11			(261	)
Payments of medium-term notes		-			(49	)
Dividends paid on common shares		(72	)		(56	)
Borrowings from senior notes		-			250
Distribution to minority interest		(19	)		(14	)
Other		21			26
Net cash flow used in financing activities		(59	)		(104	)
Net increase in cash and cash equivalents		8			27
Cash and cash equivalents at beginning of period		49			17
Cash and cash equivalents at end of period	$	57		$	44
Cash paid during the period for
Interest (net of allowance for funds used during construction of $1 million for the nine months ended September 30, 2005 and $2 million for the nine months ended September 30, 2004)	$	62		$	36
Income taxes	$	48		$	27

See Notes to Condensed Consolidated Financial Statements (Unaudited)

6

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

Note 1

Accounting Policies and Methods of Application

General

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

We have prepared the accompanying unaudited condensed consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). However, the condensed consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. You should read these condensed consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on February 15, 2005, as updated in our Current Report on Form 8-K filed with the SEC on July 28, 2005. All subsequent references to our Form 8-K filed with the SEC on July 28, 2005 herein should also be considered with reference to our Form 10-K as filed on February 15, 2005.

Due to the seasonal nature of our business, our results of operations for the three and nine months ended September 30, 2005 and 2004, and our financial position as of December 31, 2004 and September 30, 2005 and 2004, are not necessarily indicative of the results of operations and financial condition to be expected for any other period or as of any other date.

Basis of Presentation

Our condensed consolidated financial statements as of and for the period ended September 30, 2005 include our accounts, the accounts of our majority-owned and controlled subsidiaries and the accounts of variable interest entities for which we are the primary beneficiary. All significant intercompany items have been eliminated in consolidation. The December 31, 2004 balance sheet amounts are derived from our audited balance sheet as of December 31, 2004.

On January 1, 2004, we adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46) as revised in December 2003 (FIN 46R). Upon adoption, we consolidated with our subsidiaries’ accounts all the accounts of SouthStar Energy Services LLC (SouthStar), a variable interest entity of which we currently own a noncontrolling 70% financial interest but have a 75% interest in the earnings and a 50% voting interest. We eliminated all intercompany balances in the consolidation. We recorded the portion of SouthStar’s earnings that are attributable to our joint venture partner, Piedmont Natural Gas Company, Inc. (Piedmont), 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 in our condensed consolidated balance sheets. 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 its transportation capacity for delivery of natural gas through our wholly-owned subsidiary, Atlanta Gas Light Company (Atlanta Gas Light).

Prior to the sale of Saltville Gas Storage Company, LLC (Saltville) in August 2005, we utilized the equity method to account for and report our 50% interest in Saltville. We utilized the equity method because we exercised significant influence over but did not control the entity and because we were not the primary beneficiary as defined by FIN 46R.

7

Comprehensive Income

Our comprehensive income includes net income plus other comprehensive income (OCI), which includes other gains and losses affecting shareholders’ equity that GAAP excludes from net income. Such items consist primarily of unrealized gains and losses on certain derivatives designated as cash flow hedges and minimum pension liability adjustments. The following table illustrates our OCI acitivity for the nine months ended September 30, 2005:

In millions
Change in cash flow hedges:
Net derivative losses arising during the period (net of $1 tax)	$	(2	)
Less reclassification adjustment of gains included in income (net of $3 in tax)		(6	)
Total	$	(8	)

Stock-based Compensation

We have several stock-based employee compensation plans, and we account for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25) and Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation” (SFAS 123). For our stock option plans, we generally do not reflect stock-based employee compensation cost in net income, as options granted under those plans have an exercise price equal to the market value of the underlying common stock on the date of grant. 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 September 30,
In millions, except per share amounts	2005		2004
Net income, as reported	$	15	$	20
Deduct stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effect		1		-
Pro-forma net income	$	14	$	20
Earnings per share:
Basic - as reported	$	0.19	$	0.31
Basic - pro-forma	$	0.18	$	0.30
Fully diluted - as reported	$	0.19	$	0.31
Fully diluted - pro-forma	$	0.18	$	0.30

	Nine months ended September 30,
In millions, except per share amounts	2005		2004
Net income, as reported	$	127	$	107
Deduct stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effect		2		1
Pro-forma net income	$	125	$	106
Earnings per share:
Basic - as reported	$	1.64	$	1.66
Basic - pro-forma	$	1.62	$	1.64
Fully diluted - as reported	$	1.63	$	1.64
Fully diluted - pro-forma	$	1.60	$	1.63

Earnings per Common Share

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

We derive our potential dilutive common shares by calculating the number of shares issuable under restricted share units and stock options. The outstanding issuance of shares underlying the restricted stock units depends on the satisfaction of certain performance criteria. The pre-established issuance of shares underlying stock options depends upon whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. The following tables show the calculation of our diluted shares, assuming that outstanding restricted stock units ultimately vest and stock options currently exercisable with exercise prices below the average market prices are exercised. Our weighted average shares outstanding increased by 12 million in the first nine months of 2005 as compared to the same period last year, primarily as a result of our 11 million share equity offering completed in November 2004.

8

	Three months ended September 30,
In millions	2005		2004
Denominator for basic earnings per share (1)		77.5		65.1
Assumed vesting of restricted stock units and exercise of stock options		0.6		0.7
Denominator for diluted earnings per share		78.1		65.8

	Nine months ended September 30,
In millions	2005		2004
Denominator for basic earnings per share (1)		77.2		64.8
Assumed vesting of restricted stock units and exercise of stock options		0.6		0.7
Denominator for diluted earnings per share		77.8		65.5

(1)   Daily weighted average shares outstanding

Note 2

NUI Corporation Acquisition Update

On November 30, 2004, we acquired NUI Corporation (NUI) for approximately $825 million, including the assumption of $709 million in debt. During the nine months ended September 30, 2005, we adjusted our purchase price allocation by $51 million for additional known items, including adjustments related to pension obligations; severance; lease obligations related to NUI’s former corporate offices; environmental remediation liabilities; and asset sales; however, there were no material adjustments for the three months ended September 30, 2005. As of September 30, 2005, goodwill related to the NUI acquisition was $209 million. We are currently evaluating other open items, including environmental remediation liabilities and tax adjustments. We will complete our allocation by November 30, 2005, but do not expect these open items to result in a material adjustment to our balance sheet during the fourth quarter of 2005.

Sale of Saltville On August 10, 2005, we completed the sale of our 50% interest in Saltville and associated subsidiaries (Virginia Gas Pipeline and Virginia Gas Storage) to a subsidiary of Duke Energy Corporation, the other 50% partner in the Saltville joint venture. We acquired these assets as part of our purchase of NUI in November 2004. We received $66 million in cash at closing, which included $4 million in working capital adjustments, and used the proceeds to repay debt and for other general corporate purposes. The transaction was reflected as a decrease of $5 million in goodwill associated with the NUI acquisition.

Sale of Other NUI Assets On September 15, 2005, we completed the sale of an appliance business in Florida for approximately $7 million, which increased goodwill associated with the NUI acquisition by approximately $3 million. We are marketing certain other NUI entities for sale, with buyers being actively solicited. The assets, liabilities, revenues and expenses of these entities are not considered to be material to our financial statements.

Note 3

Recent Accounting Pronouncements

Issued But Not Yet Adopted

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

SFAS 123R is effective for equity compensation expense in fiscal years beginning after December 15, 2005, and we will adopt it prospectively on January 1, 2006. We are currently assessing the impact it will have on our financial statements.

9

SFAS 154 In June 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” a replacement of APB Opinion No. 20 and FASB Statement No. 3.  SFAS 154 requires retrospective application to prior periods’ financial statements of a voluntary change in accounting principle, unless it is impractical.  Opinion No. 20 previously required that most voluntary changes in accounting principle be recognized by including, in net income for the period of the change, the cumulative effect of changing to the newly adopted accounting principle.  SFAS 154 also requires that a change in the method of depreciation, amortization, or depletion for long-lived, non-financial assets be accounted for as a change in accounting estimate that is effected by a change in accounting principle.  Opinion No. 20 previously required that such a change be reported as a change in accounting principle.  SFAS 154 also requires that any errors in the financial statements of a prior period shall be reported as a prior-period adjustment by restating the prior period financial statements.  SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not currently expect this statement to will have an impact on our financial statements.

FIN 47 In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (FIN 47). Asset retirement obligations (AROs) are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) the normal operation of a long-lived asset, except for certain obligations of lessees. FIN 47 clarifies that liabilities associated with asset retirement obligations whose timing or settlement method are conditional upon future events should be recorded at fair value as soon as fair value is reasonably estimable. FIN 47 also provides guidance on the information required to reasonably estimate the fair value of the liability. FIN 47 is intended to result in:

·   more consistent recognition of liabilities relating to AROs among companies;

·   more information about expected future cash outflows associated with those obligations stemming from the retirement of the asset(s); and

·   more information about investments in long-lived assets because additional asset retirement costs will be recognized by increasing the carrying amounts of the assets identified to be retired.

FIN 47 is effective for fiscal years ending after December 15, 2005. We will adopt it prospectively in the first quarter 2006, but we have not yet determined whether the interpretation will have a significant impact on our financial statements.

Note 4

Risk Management

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

·   Forward contracts

·   Futures contracts

·   Options contracts

·   Financial swaps

·   Storage and transportation capacity transactions

Interest Rate Swaps

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

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 by changes in fair value of the interest swaps each quarter. As of September 30, 2005, a notional principal amount of $100 million of these interest rate swap agreements effectively converted the interest expense associated with a portion of our senior notes 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 floating rate swap range for our interest rate swaps for the three months ended September 30, 2005 was 4.58% to 7.21% and the floating rate swap range for the nine months ended September 30, 2005 was 3.61% to 7.21%.

10

On September 7, 2005, we terminated interest rate swap agreements associated with our note payable to AGL Capital Trust II in the principal amount of $75 million. We received a payment of $1 million related to this termination, which included accrued interest and the fair value of these interest rate swap agreements at the termination date.

On September 9, 2005, we executed five treasury-lock agreements totaling $125 million to hedge the interest rate risk associated with an anticipated 2006 financing. The agreements will result in a 4.11% interest rate on the 10-year United States Treasury bond and were designated as cash flow hedges against the future interest payments on the anticipated financing. The fair value of this agreement was $3 million at September 30, 2005, with the increase in the fair value included as a credit to OCI.

Commodity-Related Derivative Instruments

Elizabethtown GasA program mandated by the New Jersey Board of Public Utilities requires Elizabethtown Gas to utilize certain derivatives to hedge the impact of market fluctuations of natural gas prices.  Pursuant to SFAS 133, such derivative products are marked-to-market each reporting period.  In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in purchased gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset (loss) or liability (gain), as appropriate, on our condensed consolidated balance sheets.  As of September 30, 2005, Elizabethtown Gas had entered into New York Mercantile Exchange (NYMEX) futures contracts to purchase approximately 8.7 billion cubic feet (Bcf) of natural gas.  Approximately 80% of these contracts have duration of one year or less, and none of these contracts extends beyond February 2007.

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

We mitigate substantially all of the commodity price risk associated with Sequent’s natural gas portfolio by locking in the economic margin at the time we enter into natural gas purchase transactions for our stored natural gas. We purchase natural gas for storage when the difference in the current market price we pay to buy and transport natural gas plus the cost to store the natural gas is less than the market price we can receive in the future, resulting in a positive net profit margin. We use NYMEX futures contracts and other over-the-counter derivatives to sell natural gas at that future price to substantially lock in the profit margin we will ultimately realize when the stored gas is actually sold. These futures contracts meet the definition of derivatives under SFAS 133 and are recorded at fair value and marked-to-market in our condensed consolidated balance sheets, with changes in fair value recorded in earnings in the period of change. The purchase, transportation, storage and sale of natural gas are accounted for on a weighted average 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.

11

At September 30, 2005, Sequent’s commodity-related derivative financial instruments, which exclude interest rate swaps, represented purchases (long) of 467 Bcf with maximum maturities less than 2 years. In addition, Sequent’s financial instruments included sales (short) of 523 Bcf with approximately 99% of these scheduled to mature in less than 2 years and the remaining 1% in 3-9 years. Sequent’s unrealized losses were $116 million for the three months ended September 30, 2005 and $10 million for the same period last year. Sequent’s unrealized losses were $125 million for the nine months ended September 30, 2005, and its unrealized gains were $5 million for the nine months ended September 30, 2004.

SouthStar The commodity-related derivative financial instruments (futures, options and swaps) used by SouthStar manage exposures arising from changing commodity prices, as such exposure would relate to the relative economics of inventory versus flowing gas supply. SouthStar’s objective for holding these derivatives is to utilize the most effective method to reduce or eliminate the impacts of this exposure. A portion of SouthStar’s derivative transactions are designated as cash flow hedges under SFAS 133. Derivative gains or losses arising from cash flow hedges are recorded in OCI and are reclassified into earnings in the same period as the settlement of the underlying hedged item. Any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not perfectly offset the losses or gains on the hedged item, is recorded in cost of gas on our condensed consolidated income statement in the period in which it occurs. SouthStar currently has minimal hedge ineffectiveness. The remainder of SouthStar’s derivative instruments is not designated as hedges under SFAS 133 and, accordingly, changes in their fair value are recorded in earnings in the period of change.

At September 30, 2005, the fair values of these SouthStar derivatives were reflected in our condensed consolidated balance sheets as an asset of $30 million and a liability of $43 million. The maximum maturity of open positions is 1 year and represents purchases of 11.4 Bcf and sales of 9.6 Bcf.

Concentration of Credit Risk

Wholesale Services Sequent has a concentration of credit risk for services it provides to marketers and to utility and industrial customers. This credit risk is measured by 30-day receivable exposure plus forward exposure, which is generally concentrated in 20 of its customers. Sequent evaluates the credit risk of its customers using a Standard & Poor’s Rating Services (S&P) equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody’s Investor Service (Moody’s) rating to an internal rating ranging from 9.00 to 1.00, with 9.00 being equivalent to AAA/Aaa by S&P and Moody’s and 1.00 being equivalent to D or Default by S&P and Moody’s. A customer that does not have an external rating is assigned an internal rating based on Sequent’s analysis of the strength of its financial ratios. At September 30, 2005, Sequent’s top 20 customers represented approximately 65% of the total credit exposure of $507 million, derived by adding the top 20 customers’ exposures and dividing by the total of Sequent’s exposures. Sequent’s customers or the customers’ guarantors had a weighted average S&P equivalent rating of A- at September 30, 2005.

The weighted average credit rating is obtained by multiplying each customer’s assigned internal rating by its credit exposure and then adding the individual results for all counterparties. That total is divided by the aggregate total exposure. This numeric value is converted to an S&P equivalent.

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

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Note 5

Regulatory Assets and Liabilities

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

In millions	Sept. 30, 2005		Dec. 31, 2004		Sept. 30, 2004
Regulatory assets
Recoverable PRP costs	$	355	$	361	$	382
Recoverable ERC		209		200		173
Unrecovered postretirement benefit costs		14		14		9
Unrecovered seasonal rates		10		11		10
Unamortized purchased gas adjustment		3		5		-
Regulatory tax asset		1		2		3
Other		8		20		6
Total regulatory assets	$	600	$	613	$	583
Regulatory liabilities
Accumulated removal costs	$	92	$	94	$	93
Unamortized investment tax credit		19		20		18
Deferred purchased gas adjustment		37		37		34
Regulatory tax liability		9		14		14
Other		1		18		2
Total regulatory liabilities		158		183		161
Associated liabilities
PRP costs		317		327		352
ERC		98		90		61
Total associated liabilities		415		417		413
Total regulatory and associated liabilities	$	573	$	600	$	574

Our regulatory assets and liabilities are described in Note 5 to our Consolidated Financial Statements in our 2004 Annual Report on Form 10-K, as updated in our Current Report on Form 8-K filed with the SEC on July 28, 2005. The following represent significant changes to our regulatory assets and liabilities during the nine months ended September 30, 2005:

Pipeline Replacement Program

The PRP, ordered by the Georgia Public Service Commission (Georgia Commission), required that Atlanta Gas Light replace all bare steel and cast iron pipe in its system within a 10-year period that began October 1, 1998. October 1, 2005 marked the beginning of the eighth year of the original 10-year PRP.

On June 10, 2005, Atlanta Gas Light and the Georgia Commission entered into a Settlement Agreement that, among other things, extends Atlanta Gas Light’s PRP by five years to require that all replacements be completed by December 2013, with the timing of such replacements to be subsequently determined through ongoing discussions with Georgia Commission staff. Under the Settlement Agreement, rates charged to customers will remain unchanged through April 30, 2010, but Atlanta Gas Light will recognize reduced base rate revenues of $5 million on an annual basis through April 30, 2010. The five-year total reduction in recognized base rate revenues of $25 million will be applied to the amount of costs incurred to replace pipe, reducing the amount recovered from customers under the PRP rider.

The Settlement Agreement also allowed Atlanta Gas Light to recover through the PRP $4 million of the $32 million capital costs associated with its purchase of 250 miles of pipeline in central Georgia from Southern Natural Gas, a subsidiary of El Paso Corporation. The remaining capital costs are included in Atlanta Gas Light’s rate base and collected through base rates.

Environmental Remediation Costs

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

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Atlanta Gas Light The presence of coal tar and certain other by-products of a natural gas manufacturing process used to produce natural gas prior to the 1950s has been identified at or near 10 former Atlanta Gas Light operating sites in Georgia and at three sites of predecessor companies in Florida. Atlanta Gas Light has active environmental remediation or monitoring programs in effect at 10 of these sites. Two sites in Florida are currently in the investigation or preliminary engineering design phase, and one Georgia site has been deemed compliant with state standards, subject to approval of a continuing action plan. The required soil remediation at our remaining Georgia sites is substantially complete, although actions on groundwater impacts continue. As of September 30, 2005, Atlanta Gas Light’s remediation program was approximately 96% complete with respect to its Georgia sites.

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

Atlanta Gas Light’s current engineering estimate projects costs to be $20 million for completion of Georgia site remediation, excluding monitoring. This is a reduction of $10 million from September 2004’s estimate resulting primarily from program expenditures.

The current estimate for the remaining cost of future actions at these former operating sites is $15 million, which may change depending on whether future measures for groundwater will be required. Atlanta Gas Light estimates certain other costs related to administering the remediation program, including administrative costs, to be $2 million.

For those Florida sites currently in the investigation phase, Atlanta Gas Light’s estimate for remediation is a range from $5 million to $12 million. This estimate is based on preliminary data received during 2004 and 2005 with respect to the existence of contamination at those sites.

These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, unbudgeted legal expenses or other costs for which Atlanta Gas Light may be held liable but with respect to which it cannot reasonably estimate an amount. As of September 30, 2005, the remediation expenditures expected to be incurred over the next 12 months are reflected as a current liability of $8 million.

The ERC liability is included in a corresponding regulatory asset, which is a combination of accrued ERC and unrecovered cash expenditures for investigation and cleanup costs. Atlanta Gas Light has three ways of recovering investigation and cleanup costs. First, the Georgia Commission has approved an ERC recovery rider. The ERC recovery mechanism allows for recovery of expenditures over a five-year period subsequent to the period in which the expenditures are incurred. Atlanta Gas Light expects to collect $29 million in revenues over the next 12 months under the ERC recovery rider, which is reflected as a current asset.

The second way to recover costs is by exercising the legal rights Atlanta Gas Light believes it has to recover a share of its costs from other potentially responsible parties, typically former owners or operators of these sites. The third way to recover costs is from the receipt of net profits from the sale of remediated property. There were no material recoveries from potentially responsible parties or remediated property sales during the nine months ended September 30, 2005.

Elizabethtown Gas In New Jersey, Elizabethtown Gas is currently conducting remedial activities with oversight from the New Jersey Department of Environmental Protection. Although the actual total cost of future environmental investigation and remediation efforts cannot be estimated with precision, based on probabilistic models similar to those used at Atlanta Gas Light’s former operating sites, the range of reasonably probable costs is $57 million to $109 million. As of September 30, 2005, no value within this range is a better estimate than any other value, so we have recorded a liability equal to the low end of that range, or $57 million.

Prudently incurred remediation costs for the New Jersey properties have been authorized by the New Jersey Board of Public Utilities to be recoverable in rates through a remediation adjustment clause. As a result, Elizabethtown Gas has recorded a regulatory asset of approximately $64 million, inclusive of interest, as of September 30, 2005, reflecting the future recovery of both incurred costs and accrued carrying charges. Elizabethtown Gas has also been successful in recovering a portion of remediation costs incurred in New Jersey from its insurance carriers and continues to pursue additional recovery.

14

Sites in North CarolinaWe also own a former NUI remediation site in Elizabeth City, North Carolina, which is subject to a remediation order by the North Carolina Department of Energy and Natural Resources. We currently have only limited information regarding environmental impacts at the Elizabeth City site, and therefore we can make quantitative cost estimates only for limited components of a site cleanup, such as investigative efforts. However, experience at other similar sites suggests that costs for remediation of this site will likely range from $4 million to $19 million. As of September 30, 2005, we have recorded a liability of $4 million related to this site.

There is one other site in North Carolina where investigation and remediation is probable, although no remediation order exists and we do not believe costs associated with this site can be reasonably estimated. In addition, there are as many as six other sites with which NUI had some association, although no basis for liability has been asserted, and accordingly we have not accrued any remediation liability. There are currently no cost recovery mechanisms for the environmental remediation sites in North Carolina. As a result, any change in estimate occurring after our purchase price allocation period which ends in November 2005 could affect our environmental costs and, hence, reported earnings in future periods.

We are continuing to evaluate the estimates at Elizabethtown Gas and at NUI’s other former remediation sites. The differences between our current estimates and new estimates identified within one year of the acquisition of NUI could affect the amount ultimately recorded as part of our purchase price of NUI.

Note 6

Pension and Other Post-retirement Benefits

Pension Benefits We sponsor two defined benefit post-retirement plans for our eligible employees: the AGL Resources Inc. Retirement Plan and the NUI Corporation Retirement Plan. A defined benefit plan specifies the amount of benefits an eligible participant will receive following retirement using information about the participant. We contributed $5 million in August 2005 to the AGL Resources Inc. Retirement Plan. The following are the cost components of our two pension plans for the periods indicated:

	Three months ended
	September 30,
In millions	2005			2004
Service cost	$	2		$	1
Interest cost		7			5
Expected return on plan assets		(8	)		(6	)
Net amortization		-			-
Recognized actuarial loss		2			2
Net annual cost	$	3		$	2

	Nine months ended
	September 30,
In millions	2005			2004
Service cost	$	7		$	4
Interest cost		20			14
Expected return on plan assets		(24	)		(17	)
Net amortization		(1	)		(1	)
Recognized actuarial loss		5			3
Net annual cost	$	7		$	3

15

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

	Three months ended
	September 30,
In millions	2005			2004
Service cost	$	-		$	-
Interest cost		1			1
Expected return on plan assets		(1	)		-
Net amortization		(1	)		(1	)
Recognized actuarial loss		-			-
Net annual cost	$	(1	)	$	-

	Nine months ended
	September 30,
In millions	2005			2004
Service cost	$	1		$	1
Interest cost		4			5
Expected return on plan assets		(3	)		(2	)
Net amortization		(3	)		(1	)
Recognized actuarial loss		1			1
Net annual cost	$	-		$	4

Note 7

Compensation Plans

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

In January 2005, we granted to a group of officers a total of 85,900 restricted stock units. As of September 30, 2005, only 77,100 of these units were outstanding. The awards were made pursuant to our Amended and Restated Long-Term Incentive Plan (1999) (Incentive Plan), as amended.

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

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

In January 2005, we granted performance cash units to a select group of officers pursuant to our Incentive Plan. The performance cash units represent a maximum aggregate payout of $5 million. The performance cash units have a performance measurement period that ranges from 12 to 36 months. The performance criteria relate to our internal measure of total shareholder return. Based on our anticipated performance and the related vesting schedules, as of September 30, 2005, we had recorded a liability of $2 million for these performance cash units.

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Note 8

Financing

Our financing consists of short and long-term debt as indicated in the following table. There have been no significant changes to our financing as described in Note 8 to our Consolidated Financial Statements in our 2004 Annual Report on Form 10-K, as updated in our Current Report on Form 8-K filed with the SEC on July 28, 2005, other than the information described below.

						Outstanding as of:
Dollars in millions	Year(s) due (1)		Int. rate(1)			Sept. 30, 2005			Dec. 31, 2004		Sept. 30, 2004
Short-term debt
Commercial paper		2005		3.8%(2	)	$	318		$	314	$	51
Current portion of long-term debt		-		-			-			-		34
Sequent lines of credit		2005		4.4(3	)		25			18		-
Current portion of capital leases		2005		4.9			1			2		-
Total short-term debt				3.9%(4	)	$	344		$	334	$	85
Long-term debt - net of current portion
Medium-term notes		2012-2027		6.6 - 9.1	%	$	208		$	208	$	208
Senior notes		2011-2034		4.5 - 7.1	%		975			975		775
Gas facility revenue bonds, net of unamortized issuance costs		2022-2033		2.5 - 5.7	%		199			199		-
Notes payable to trusts		2037-2041		8.0 - 8.2	%		232			232		232
Capital leases		2013		4.9	%		7			8		-
Interest rate swaps		2011		7.2	%		(5	)		1		1
Total long-term debt				6.1%(4	)	$	1,616		$	1,623	$	1,216
Total short-term and long-term debt				5.7%(4	)	$	1,960		$	1,957	$	1,301

(1)   As of September 30, 2005.

(2)   The daily weighted average rate was 3.1% for the nine months ended September 30, 2005.

(3)   The daily weighted average rate was 3.7% for the nine months ended September 30, 2005.

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

Commercial Paper On August 30, 2005 we amended our credit facility that supports our commercial paper program. Under the terms of the amendment, the aggregate principal amount available under the credit facility has been increased from $750 million to $850 million and we have the option to increase the aggregate principal amount available for borrowing to $1.1 billion on not more than three occasions during each calendar year. The amended credit facility expires on August 31, 2010.

Sequent Line of Credit In June 2005, Sequent’s existing $25 million unsecured line of credit was extended to July 2006. In September 2005, Sequent entered into an additional $20 million unsecured line of credit scheduled to expire in September 2006. These unsecured lines of credit, which total $45 million, are used solely for the posting of exercise deposits and are unconditionally guaranteed by AGL Resources.

Gas Facility Revenue Bonds In April 2005, we refinanced $20 million of our Gas Facility Revenue Bonds due October 1, 2024. The original bonds had a fixed interest rate of 6.4% per year and were refunded with $20 million of adjustable rate Gas Facility Revenue Bonds. The maturity date of these bonds remains October 1, 2024. The new bonds were issued at an initial annual interest rate of 2.8% and initially have a 35-day auction period where the interest rate will adjust every 35 days. The interest rate at September 30, 2005 was 2.5%.

In May 2005, we refinanced an additional $47 million in Gas Facility Revenue Bonds due October 1, 2022 and bearing interest at an annual fixed rate of 6.35%. The new bonds were issued at an initial annual interest rate of 2.9% and initially have a 35-day auction period where the interest rate will adjust every 35 days. The maturity date remains October 1, 2022. The interest rate at September 30, 2005 was 2.5%.

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Note 9

Commitments and Contingencies

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.

SouthStar has natural gas purchase commitments related to the supply of minimum natural gas volumes to its customers. These commitments are priced on both a fixed basis and an index plus premium basis. At September 30, 2005, SouthStar had obligations under these arrangements for 6.9 Bcf through December 31, 2005.

We have also incurred various contingent financial commitments in the normal course of business. The following table sets forth, as of September 30, 2005, the maximum potential amount of our expected contingent financial commitments representing obligations that become payable only if certain pre-defined events occur.

			Commitments due before Dec. 31,
					2006 &
In millions	Total		2005		thereafter
Standby letters of credit, performance / surety bonds	$	20	$	20	$	-

Litigation We are involved in litigation arising in the normal course of business, and we believe the ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. There has been no significant change in the litigation which was described in Note 10 to our Consolidated Financial Statements in our 2004 Annual Report on Form 10-K, as updated in our Current Report on Form 8-K filed with the SEC on July 28, 2005.

Note 10

Segment Information

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

Beginning in 2005, we added an additional segment, retail energy operations, which consists of the operations of SouthStar, our retail gas marketing subsidiary that conducts business primarily in Georgia. We added this segment as a result of the way management views its operations in consideration of the impact of our acquisitions of NUI and Pivotal Jefferson Island Storage & Hub, LLC (Pivotal Jefferson Island) in the fourth quarter of 2004. The addition of this segment also is consistent with our desire to provide transparency and visibility to SouthStar on a stand-alone basis and to provide additional visibility to the remaining businesses in the energy investments segment, principally Pivotal Jefferson Island and Pivotal Propane of Virginia, Inc. (Pivotal Propane), which are more closely related in structure and operation.

We have recast the segment information for the three and nine months ended September 30, 2004 in accordance with the guidance set forth in SFAS 131 as shown in the tables below. Additionally, we have recast the segment information for the years ended December 31, 2004, 2003 and 2002 in our Current Report on Form 8-K filed with the SEC on July 28, 2005.

Our four operating segments are now as follows:

·   Distribution operations consists primarily of:

o   Atlanta Gas Light

o   Chattanooga Gas Company

o   Elizabethtown Gas

o   Elkton Gas

o   Florida City Gas

o   Virginia Natural Gas, Inc.

·   Retail energy operations consists of SouthStar

·   Wholesale services consists of Sequent

·   Energy investments consists primarily of:

o   Pivotal Jefferson Island

o   Pivotal Propane

o   AGL Networks, LLC

We treat corporate, our fifth segment, as a non-operating business segment, and it includes AGL Resources Inc., AGL Services Company, Pivotal Energy Development, nonregulated financing subsidiaries and the effect of intercompany eliminations. We eliminated intersegment sales for the three and nine months ended September 30, 2005 and 2004 from our condensed consolidated statements of income.

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

You should not consider EBIT as an alternative to, or a more meaningful indicator of our operating performance than, operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly-titled measure of another company. The reconciliations of EBIT to operating income and net income for the three and nine months ended September 30, 2005 and 2004 are presented in the following table.

	Three months ended September 30,
In millions	2005			2004
Operating revenues	$	393		$	262
Operating expenses		339			216
Operating income		54			46
Other income		-			-
Minority interest		(2	)		-
EBIT		52			46
Interest expense		27			17
Earnings before income taxes		25			29
Income taxes		10			9
Net income	$	15		$	20

	Nine months ended September 30,
In millions	2005			2004
Operating revenues	$	1,736		$	1,206
Operating expenses		1,435			974
Operating income		301			232
Other income		2			2
Minority interest		(18	)		(14	)
EBIT		285			220
Interest expense		79			49
Earnings before income taxes		206			171
Income taxes		79			64
Net income	$	127		$	107

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Summarized income statement information and capital expenditures by segment for the periods indicated are shown in the following tables:

Three months ended September 30, 2005
In millions	Distribution operations		Retail energy operations			Wholesale services			Energy investments		Corporate and intersegment eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	225	$	153		$	1		$	14	$	-		$	393
Intersegment revenues (1)		38		-			-			-		(38	)		-
Total revenues		263		153			1			14		(38	)		393
Operating expenses
Cost of gas		95		129			-			4		(37	)		191
Operation and maintenance		85		13			6			4		(2	)		106
Depreciation and amortization		28		1			1			1		2			33
Taxes other than income taxes		7		1			-			-		1			9
Total operating expenses		215		144			7			9		(36	)		339
Operating income (loss)		48		9			(6	)		5		(2	)		54
Other income		1		-			-			-		(1	)		-
Minority interest		-		(2	)		-			-		-			(2	)
EBIT	$	49	$	7		$	(6	)	$	5	$	(3	)	$	52
Capital expenditures	$	51	$	-		$	-		$	1	$	12		$	64

Three months ended September 30, 2004
In millions	Distribution operations		Retail energy operations			Wholesale services			Energy investments			Corporate and intersegment eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	129	$	128		$	3		$	2		$	-		$	262
Intersegment revenues (1)		37		-			-			-			(37	)		-
Total revenues		166		128			3			2			(37	)		262
Operating expenses
Cost of gas		31		110			-			1			(37	)		105
Operation and maintenance		63		16			4			1			(1	)		83
Depreciation and amortization		20		1			-			-			2			23
Taxes other than income taxes		4		(1	)		-			1			1			5
Total operating expenses		118		126			4			3			(35	)		216
Operating income (loss)		48		2			(1	)		(1	)		(2	)		46
Other income		-		-			-			-			-			-
Minority interest		-		-			-			-			-			-
EBIT	$	48	$	2		$	(1	)	$	(1	)	$	(2	)	$	46
Capital expenditures	$	49	$	2		$	2		$	6		$	5		$	64

20

Nine months ended September 30, 2005
In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intersegment eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	1,045	$	627		$	21	$	43	$	-		$	1,736
Intersegment revenues (1)		145		-			-		-		(145	)		-
Total revenues		1,190		627			21		43		(145	)		1,736
Operating expenses
Cost of gas		590		513			-		12		(143	)		972
Operation and maintenance		269		40			19		12		(6	)		334
Depreciation and amortization		85		2			2		4		6			99
Taxes other than income taxes		24		1			-		1		4			30
Total operating expenses		968		556			21		29		(139	)		1,435
Operating income (loss)		222		71			-		14		(6	)		301
Other income		2		-			-		1		(1	)		2
Minority interest		-		(18	)		-		-		-			(18	)
EBIT	$	224	$	53		$	-	$	15	$	(7	)	$	285
Capital expenditures	$	160	$	2		$	1	$	7	$	24		$	194

Nine months ended September 30, 2004
In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments			Corporate and intersegment eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	595	$	583		$	23	$	5		$	-		$	1,206
Intersegment revenues (1)		144		-			-		-			(144	)		-
Total revenues		739		583			23		5			(144	)		1,206
Operating expenses
Cost of gas		284		485			-		1			(144	)		626
Operation and maintenance		199		42			17		3			(4	)		257
Depreciation and amortization		62		1			-		1			7			71
Taxes other than income taxes		16		-			-		1			3			20
Total operating expenses		561		528			17		6			(138	)		974
Operating income (loss)		178		55			6		(1	)		(6	)		232
Other income		1		-			-		2			(1	)		2
Minority interest		-		(14	)		-		-			-			(14	)
EBIT	$	179	$	41		$	6	$	1		$	(7	)	$	220
Capital expenditures	$	134	$	4		$	7	$	17		$	6		$	168

(1)   Intersegment revenues - Wholesale services records its energy marketing and risk management revenues net of its cost of gas. The following table provides information regarding wholesale services’ gross revenues from distribution operations and total gross revenues:

	Three months ended September 30,				Nine months ended September 30,
In millions	2005		2004		2005		2004
Third-party gross revenues	$	1,663	$	1,007	$	4,133	$	3,069
Intersegment revenues		201		88		450		279
Total gross revenues	$	1,864	$	1,095	$	4,583	$	3,348

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Balance sheet information at September 30, 2005 and 2004 and December 31, 2004 by segment is shown in the following tables: 

As of September 30, 2005
In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments		Corporate and intersegment eliminations (2)			Consolidated AGL Resources
Goodwill	$	390	$	1	$	-	$	14	$	-		$	405
Identifiable assets (1)	$	4,597	$	226	$	1,108	$	348	$	(193	)	$	6,086
Investment in joint ventures		-		-		-		-		-			-
Total assets	$	4,597	$	226	$	1,108	$	348	$	(193	)	$	6,086

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

As of September 30, 2004
In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments		Corporate and intersegment eliminations (2)			Consolidated AGL Resources
Goodwill	$	177	$	-	$	-	$	-	$	-		$	177
Identifiable assets (1)	$	3,360	$	162	$	458	$	135	$	(81	)	$	4,034
Investment in joint ventures		-		-		-		-		-			-
Total assets	$	3,360	$	162	$	458	$	135	$	(81	)	$	4,034

(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.

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain expectations and projections regarding our future performance referenced in this “Management’s Discussion and Analysis of Financial Condition and Results of Operation” section and elsewhere in this report, as well as in other reports and proxy statements we file with the Securities and Exchange Commission (SEC) are forward-looking statements. Officers and other key employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.

Forward-looking statements involve matters that are not historical facts, and because these statements involve anticipated events or conditions, forward-looking statements often include words such as "anticipate," "assume," "can," "could," "estimate," "expect," "forecast," "future," "indicate," "intend," "may," "plan," "predict," "project, "seek," "should," "target," "will," "would," or similar expressions. Our expectations are not guarantees and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations are reasonable in view of the currently available information, our expectations are subject to future events, risks and uncertainties, and there are several factors - many beyond our control - that could cause results to differ significantly from our expectations. Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products, impact of changes in state and federal legislation and regulation, actions taken by government agencies on rates and other matters, concentration of credit risk, utility and energy industry consolidation, impact of acquisitions and divestitures, direct or indirect effects on AGL Resources' business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors, interest rate fluctuations, financial market conditions and general economic conditions, uncertainties about environmental issues and the related impact of such issues, impacts of changes in weather upon the temperature-sensitive portions of the business, impacts of natural disasters such as hurricanes upon the supply and price of natural gas, acts of war or terrorism, and other factors contained in our filings with the SEC.

We caution readers that, in addition to the important factors described elsewhere in this report, the factors set forth in our 2004 Annual Report on Form 10-K, as updated in our Current Report on Form 8-K filed with the SEC on July 28, 2005 (2004 Form 10-K), under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Risk Factors,” among others, could cause our business, results of operations or financial condition in 2005 and thereafter to differ significantly from those expressed in any forward-looking statements. There also may be other factors not described in these reports that could cause results to differ significantly from our expectations.

Forward-looking statements are only as of the date they are made, and we do not undertake any obligation to update these statements to reflect subsequent changes.

Overview

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

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

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We derived approximately 97% of our earnings before interest and taxes (EBIT) during the nine months ended September 30, 2005 from our regulated natural gas distribution business and the sale of natural gas to end-use customers primarily in Georgia by SouthStar. This statistic is significant because it represents the portion of our earnings that results directly from the underlying business of supplying natural gas to retail customers. Although SouthStar is not subject to the same regulatory framework as our utilities, it is an integral part of the retail framework for providing gas service to end-use customers in the state of Georgia. For more information regarding our measurement of EBIT and the items it excludes from operating income and net income, see “Results of Operations - AGL Resources.”

The remaining 3% of our EBIT was principally derived from businesses that are complementary to our natural gas distribution business. We engage in natural gas asset management and operation of high deliverability natural gas underground storage as ancillary activities to our utility franchises. These businesses allow us to be opportunistic in capturing incremental value at the wholesale level, provide us with deepened business insight about natural gas market dynamics and facilitate our ability, in the case of asset management, to provide transparency to regulators as to how that value can be captured to benefit our utility customers through profit sharing arrangements. Given the volatile and changing nature of the natural gas resource base in North America and globally, we believe that participation in these related businesses strengthens our business.

Seasonality The operating revenues and EBIT of our distribution operations, retail energy operations and wholesale services segments are impacted by seasonality.  Approximately two-thirds of these segments’ annual operating revenues and EBIT were generated during the six month heating season (October to March) reflected in our condensed consolidated income statements for the quarters ended March 31, 2004 and December 31, 2004. Our base operating expenses excluding gas and interest expense, are incurred relatively equally over any given year. Thus, our operating results vary significantly from quarter to quarter.

Seasonality also affects the comparison of certain balance sheet items such as receivables, unbilled revenue, inventories and short-term debt. We have presented the condensed consolidated balance sheet as of September 30, 2004 to provide comparisons of these items with the corresponding balance sheet amounts as of September 30, 2005 and December 31, 2004.

Impact of Hurricanes on AGL Resources and Our Industry The natural gas production, processing and pipeline infrastructure in the Gulf of Mexico was significantly affected by hurricanes Katrina and Rita in the months of August and September 2005. In preparation for these hurricanes, production, processing and pipeline facilities ceased or curtailed operations in order to protect and minimize damage to the facilities.

Following the hurricanes, much of the pipeline and processing infrastructure in the Gulf of Mexico was inoperable. As of October 14, 2005, approximately 56% of the Gulf of Mexico’s normal natural gas production of 10 Bcf per day remained unavailable for transmission. The Energy Information Administration (EIA) predicts that 2 Bcf per day of this production will remain unavailable for transportation through December 2005. Additionally, natural gas processing plants were idle due to lack of gas flow, lack of power, or hurricane damage, with 20 processing plants, representing 13.1 Bcf per day of processing capacity, remaining idle as of October 13, 2005. Consequently, the already tight natural gas supply markets prior to these two hurricanes were further strained as nearly 8% of the Gulf Coast’s annual production of 3.65 trillion cubic feet of natural gas was unavailable for transmission. This has resulted in higher natural gas prices which are expected by the EIA to significantly increase the cost to heat a home during the upcoming heating season.

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The impact of hurricanes Katrina and Rita on natural gas prices, as well as on automobile gas prices and transportation costs, creates diverse effects on our business, some of which offset others. Increased energy and transportation prices are expected to represent a significantly larger portion of consumer household incomes as we move into the 2005/2006 winter heating season. As a result, it is likely we will experience some additional bad debt expenses during the winter season, as well as some margin erosion from increased consumer conservation in an environment of high gas prices. While we expect these factors to have some impact on our financial statements, primarily in the first half of 2006, we have regulatory and operational mechanisms in place in most of our jurisdictions that we expect to help mitigate our exposure.

These risks of increased bad debt expense and decreased operating margins from conservation are minimized at our largest utility, Atlanta Gas Light, as a result of its straight-fixed variable rate structure and because customers in Georgia buy gas from certificated marketers rather than from Atlanta Gas Light. Our credit exposure at Atlanta Gas Light is primarily related to the provision of services for the certificated marketers, but that exposure is mitigated, as we obtain security support in an amount equal to a minimum of two times a marketer’s highest month’s estimated bill.

SouthStar, our unregulated marketing affiliate that serves 35% of the Georgia market, may be affected by the conservation and bad debt trends, but its overall exposure is partially mitigated by the credit quality of SouthStar’s customer base and the unregulated pricing structure in Georgia. Chattanooga Gas is partially insulated from increased bad debt expense because uncollectible expenses associated with its commodity costs are recovered through a regulatory purchased gas cost adjustment.

In our New Jersey and Florida utilities, acquired in November 2004, we have exerted considerable effort, as part of our integration strategy, in implementing rigorous measures to collect delinquent accounts, similar to our processes at Virginia Natural Gas, Chattanooga Gas and SouthStar. In our first year of operating those utilities, we saw substantial improvements in bad debt as a percentage of total revenues. Across our utility system, bad debt levels are lower year-to-date than they have been in previous years, and we will continue to be rigorous in monitoring, and mitigating the impact of, uncollectible expenses.

We expect to further mitigate the bad debt and conservation effects in the 2005/2006 winter heating season by utilizing both open market gas purchases to meet customer demand when it is economic to do so, and by withdrawing gas from inventory storages when the weighted average cost of that gas is lower than flowing gas supplies.

We already have begun partnering with regulators and state agencies in each of our jurisdictions to educate customers about these issues in advance of the winter heating season, in particular to ensure that those qualified for the Low Income Home Energy Assistance funds and other similar programs will receive that assistance.

The market dynamics brought on by the two hurricanes significantly increased forward NYMEX gas prices, primarily in the months of August and September. From June 30, 2005 to September 30, 2005, the forward NYMEX prices through March 2006 increased on average by approximately $6.10, a 75% increase. These market dynamics created significant market opportunities. Sequent drew upon its knowledge of the natural gas grid to move gas from supply sources and deliver it to its customers, which involved moving gas over less traditional routes due to Gulf Coast infrastructure limitations.

As disclosed in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, we had expected Sequent’s inventory balances to decrease approximately 11 Bcf during the third quarter of 2005. Our inventory balances actually decreased 10 Bcf. Our physical salt dome storage volumes from June 30 to September 30, 2005 were down only slightly. However, we cycled through approximately 6 Bcf of natural gas in the third quarter of 2005 utilizing the high injection and withdrawal capabilities of salt dome storage to meet customer demand. This storage activity during the quarter created increased economic value as compared to the third quarter of last year not only for Sequent but also for our own utilities through Sequent’s affiliate asset management agreements. However, this increased economic value was offset by mark-to-market losses of $35 million on the hedges of inventory (after estimated regulatory sharing) during the quarter. Those losses will be recovered primarily in the fourth quarter of 2005 and the first quarter of 2006 when the physical gas is withdrawn from storage. For additional information regarding the economic value created during the quarter and the mark-to-market unrealized losses, see “Results of Operations - Wholesale Services.”

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The operations of our Pivotal Jefferson Island Storage & Hub, LLC (Pivotal Jefferson Island) were curtailed during hurricane Rita. Pivotal Jefferson Island partially re-opened operations shortly after hurricane Rita and was able to operate half of the pipeline interconnects as the remaining interconnects remained underwater and could not be operated. Pivotal Jefferson Island’s operations were fully restored in mid-October 2005. We are assessing the impact of the curtailment of these operations on our operating revenue, but we believe the impacts were immaterial as the commercial operations of the Henry Hub also were not operational during this period. The Henry Hub, located in Louisiana, is the largest centralized point for natural gas spot and futures trading in the United States. Pivotal Jefferson Island did incur some minor damage to its electrical system and wellheads, but we expect the impact of these repairs on our earnings to be immaterial.

Regulatory Environment Our business goal is to become the preferred provider of gas distribution and related services in our markets by adopting the most advanced and lowest-cost business practices.  We believe that we no longer can think of ourselves in terms of an insular, North American market. Global forces are at work -- both in terms of the worldwide market for our primary fuel, natural gas, and in terms of customers' demands for ever better, faster and cheaper service.  This environment requires that we seek efficiencies more aggressively than ever before, and we recognize that our long-term viability depends on both our investors and our customers reaping the rewards of our efforts. 

Against this backdrop, we continue to manage the ongoing challenge of operating in a regulatory environment that generally does not measure or reward innovation and operational efficiency. In particular, traditional "cost of service" regulation which was originally designed to simulate the actions of a competitive market, has not kept pace with the vast changes taking place in the natural gas industry in technology utilization and in the global economy, all factors that to various degrees affect our company. The staffs of various state rate-setting agencies have argued for significantly lower rates of return on regulated investments without adequate attention to the effects those lower returns might have on capital reinvestment in the company’s regulated asset base; the “opportunity cost” to customers of not providing better and more efficient services; and the disincentive to excellence in management and operations that such returns create.  Much of the rate setting is done by states in adversarial proceedings where rules of evidence and due process can vary greatly among the states.  As a result of these ongoing regulatory challenges, we will continue to work cooperatively with our regulators, legislators and others to seek, through rate freezes and performance-based rates, to create a framework in each jurisdiction that is more conducive to our business goals. Furthermore, we will continue to make strategic investments in energy-related businesses that either are not subject to traditional state and federal rate regulation or are subject to limited oversight in order to incrementally add value to our shareholders.  For more information regarding pending federal and state regulatory matters, see “Results of Operations - Distribution Operations” and “Results of Operations - Wholesale Services.”

Integration of NUI and Pivotal Jefferson Island We have substantially completed the integration into our operations of our two recent acquisitions, NUI, which we acquired on November 30, 2004, and Pivotal Jefferson Island, which we acquired on October 1, 2004.  In 2005, we consolidated a number of NUI’s business technology platforms into our enterprise-wide systems, including the accounting, payroll, human resources and supply chain functions.  We also consolidated the former NUI utility call center operations into our own centralized call center.  The combination of system integrations and the application of our best-practice operational model in managing both the NUI and Pivotal Jefferson Island assets have resulted in significant improvements in the operations of both businesses, as measured by the various metrics we use to manage our business.  As a result of these integration efforts, we believe we have achieved our performance goal of successfully integrating these acquisitions and making them accretive to our consolidated earnings within one year of the acquisition closing date.

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

We have substantially completed our efforts to assess the systems of internal control related to NUI’s and Pivotal Jefferson Island’s businesses to comply with the SEC’s requirements under the Sarbanes-Oxley Act. During the first nine months of 2005, we converted and integrated substantially all of NUI’s accounting systems and internal control processes into our corporate accounting systems and internal control processes. As part of this process, we are addressing and resolving the material deficiencies in internal controls for the NUI business identified by NUI’s external and internal auditors during audits performed in fiscal years 2003 and 2004, as more fully described in our 2004 Form 10-K. While the conversion of financial systems and resulting integration of internal control processes into our internal control processes is a key step toward remediation of the control deficiencies, we still are in the process of documenting and assessing the internal control processes for the NUI businesses not covered by our internal control systems following the conversion, and we continue to remediate known deficiencies in the NUI internal controls.

Results of Operations

AGL Resources

We acquired Pivotal Jefferson Island and NUI in the fourth quarter of 2004. As a result, these acquired operations are included in our results of operations for the three and nine months ended September 30, 2005 but are not included for the same period in 2004.

Beginning in first quarter of 2005, we added an additional segment, retail energy operations, which consists of the operations of SouthStar, our retail gas marketing subsidiary that conducts business primarily in Georgia. We added this segment as a result of a change in the way management views its operations and in consideration of the impact of the NUI and Pivotal Jefferson Island acquisitions. The addition of this segment also is consistent with our desire to provide transparency and visibility to SouthStar on a stand-alone basis and to provide additional visibility to the remaining businesses in the energy investments segment, principally Pivotal Jefferson Island and Pivotal Propane of Virginia, Inc. (Pivotal Propane), which are more closely related in structure and operation.

We have recast the segment information for the three and nine months ended September 30, 2004 in accordance with the guidance set forth in SFAS 131. Additionally, we have recast the segment information for the years ended December 31, 2004, 2003 and 2002 in our Current Report on Form 8-K filed with the SEC on July 28, 2005.

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

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

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Operating margin and EBITWe evaluate the performance of our operating segments using the measures of operating margin (operating revenues less cost of gas) and EBIT. We believe operating margin is a better indicator than revenues for the contribution resulting from customer growth in our distribution operations and retail energy operations segments since the cost of gas can vary significantly and is generally passed directly to our customers. We also consider operating margin to be a better indicator in our wholesale services and energy investments segments since it is a direct measure of gross profit before overhead costs.

We believe EBIT is useful to investors as a measurement of our operating segments’ performance because it can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which affects the efficiency of the underlying operations.

Operating margin and EBIT are not measures that are considered to be calculated in accordance with GAAP. You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our operating margin or EBIT measures may not be comparable to a similarly titled measure of another company. The following are reconciliations of our operating margin and EBIT to operating income and net income, together with other consolidated financial information, for the three and nine months ended September 30, 2005 and 2004.

Third quarter 2005 compared to third quarter 2004

	Three months ended Sept. 30,
In millions	2005			2004		2005 vs. 2004
Operating revenues	$	393		$	262		50	%
Cost of gas		191			105		82
Operating margin		202			157		29
Operating expenses		148			111		33
Operating income		54			46		17
Other income		-			-		-
Minority interest		(2	)		-		(100	)
EBIT		52			46		13
Interest expense		27			17		59
Earnings before income taxes		25			29		(14	)
Income taxes		10			9		11
Net income	$	15		$	20		(25	%)

Segment information Operating revenues, operating margin and EBIT information for each of our segments are contained in the following table for the three months ended September 30, 2005 and 2004:

In millions	Operating revenues			Operating margin			EBIT
2005
Distribution operations	$	263		$	168		$	49
Retail energy operations		153			24			7
Wholesale services		1			1			(6	)
Energy investments		14			10			5
Corporate (1)		(38	)		(1	)		(3	)
Consolidated	$	393		$	202		$	52
2004
Distribution operations	$	166		$	135		$	48
Retail energy operations		128			18			2
Wholesale services		3			3			(1	)
Energy investments		2			1			(1	)
Corporate (1)		(37	)		-			(2	)
Consolidated	$	262		$	157		$	46

(1)   Includes intercompany eliminations

EBIT Consolidated EBIT for the quarter ended September 30, 2005 increased by $6 million or 13% from the previous year, primarily as a result of improved results in retail energy operations and the addition of Pivotal Jefferson Island. Retail energy operations’ EBIT increased $5 million, primarily due to higher commodity margins. Pivotal Jefferson Island contributed $4 million of additional EBIT. This was offset by $2 million in EBIT loss from the former NUI subsidiaries. Wholesale services’ EBIT decreased as a result of increased operating expenses and lower operating margins. EBIT at distribution operations remained virtually flat as compared to the same period last year.

Operating Margin Operating margin for the quarter increased $45 million, including $33 million from distribution operations, primarily as a result of the addition of the NUI assets. Atlanta Gas Light had improved margin as a result of higher revenues for pipeline replacement and natural gas stored for marketers, as well as higher net customer growth, which partially offset the impact of reduced authorized rates. Operating margin for SouthStar increased $6 million year-over-year due to greater retail spreads as compared to wholesale prices, including gains on hedging transactions. Sequent’s operating margins decreased $2 million primarily from mark-to-market losses on hedged storage positions, partially offset by realized margins on physical gas sales and storage transactions brought on by the increased market volatility from Hurricanes Katrina and Rita. Energy investments’ margin increased $9 million as a result of the addition of Pivotal Jefferson Island, NUI non-utility subsidiaries and Pivotal Propane of Virginia, as well as improvements year-over-year at AGL Networks.

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Operating Expenses Operating expenses increased $37 million, primarily the result of expenses in distribution operations of $33 million primarily from the addition of NUI. Expenses increased $3 million in the wholesale services segment due to higher payroll and increased depreciation and $3 million in the energy investments segment because of the addition of both Pivotal Jefferson Island and the NUI non-utility assets. There was no change in retail energy operations’ operating expenses.

Interest Expense Interest expense increased $10 million, reflecting the additional interest associated with debt incurred in the NUI transaction as well as higher short-term interest rates.

Income Taxes Income tax expense increased by $1 million in the third quarter of 2005 as compared to the same period last year. In 2004 we made adjustments that reduced our income tax expense by $3 million for the three months ended September 30, 2004. These adjustments resulted from a reconciliation of our income tax accruals as compared to our 2003 income tax returns which were filed in September 2004. Excluding these adjustments, our income tax expense would have decreased by $2 million for the third quarter of 2005 as compared to the same period last year. The decrease is a result of lower earnings before income taxes.

Nine months 2005 compared to nine months 2004

	Nine months ended Sept. 30,
In millions	2005			2004			2005 vs. 2004
Operating revenues	$	1,736		$	1,206			44	%
Cost of gas		972			626			55
Operating margin		764			580			32
Operating expenses		463			348			33
Operating income		301			232			30
Other income		2			2			-
Minority interest		(18	)		(14	)		(29	)
EBIT		285			220			30
Interest expense		79			49			61
Earnings before income taxes		206			171			20
Income taxes		79			64			23
Net income	$	127		$	107			19	%

Segment information Operating revenues, operating margin and EBIT information for each of our segments are contained in the following table for the nine months ended September 30, 2005 and 2004:

In millions	Operating revenues			Operating margin			EBIT
2005
Distribution operations	$	1,190		$	600		$	224
Retail energy operations		627			114			53
Wholesale services		21			21			-
Energy investments		43			31			15
Corporate (1)		(145	)		(2	)		(7	)
Consolidated	$	1,736		$	764		$	285
2004
Distribution operations	$	739		$	455		$	179
Retail energy operations		583			98			41
Wholesale services		23			23			6
Energy investments		5			4			1
Corporate (1)		(144	)		-			(7	)
Consolidated	$	1,206		$	580		$	220

(1)   Includes intercompany eliminations

EBIT Consolidated EBIT for the nine months ended September 30, 2005 increased by $65 million or 30% from the previous year, of which $43 million relates to EBIT contributions from the acquisitions of NUI and Pivotal Jefferson Island. The increase further reflects increased contributions from Atlanta Gas Light in distribution operations, retail energy operations and AGL Networks. Wholesale services’ EBIT decreased $6 million primarily due to decreased operating margins and increased operating expenses. The corporate segment remained virtually flat as compared to the same period last year.

Operating Margin Operating margin increased $184 million, primarily reflecting the NUI and Pivotal Jefferson Island acquisitions and completion of the Pivotal Propane facility in Virginia, as well as improved margins at SouthStar and AGL Networks. Excluding the addition of the NUI utilities, distribution operations margins improved by $7 million mainly as a result of higher pipeline replacement revenues and additional carrying costs charged to retail marketers in Georgia for gas storage. Retail energy operations’ margins were up $16 million, due primarily to higher commodity margins.Sequent’s operating margins were down $2 million year-over-year, primarily due to the activity during the third quarter of 2005.

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Operating Expenses Operating expenses increased $115 million, primarily the result of higher expenses in distribution operations of $101 million from the addition of NUI. In addition, operating expenses increased $12 million in the energy investments segment because of the addition of Pivotal Jefferson Island and the NUI non-utility assets and by $4 million in wholesale services due to increased payroll and depreciation.

Interest Expense Interest expense increased by $30 million from last year, primarily as a result of $574 million in additional debt related to the NUI and Pivotal Jefferson Island acquisition ($24 million) and higher short-term interest rates and higher debt balances ($7 million) as shown in the following table:

	Nine months ended Sept. 30,
Dollars in millions	2005			2004			2005 vs. 2004
Average debt outstanding (1)	$	1,780		$	1,187			593
Average rate		6.0	%		5.5	%		0.5	%

(1)   Daily average of all outstanding debt.

If, for the nine months ended September 30, 2005, market interest rates on our variable rate debt (3.9% at September 30, 2005) had been 100 basis points higher or lower, our year-to-date pretax interest expense would have changed by $3 million.

Income Taxes Income taxes increased by $15 million, primarily as a result of the higher pre-tax income for the nine months ended September 30, 2005. However, as discussed above, in 2004 we made adjustments which reduced our income tax expense by $3 million. The following table provides information on our effective tax rates and the effects of the 2004 income tax expense adjustment.

	Nine months ended Sept. 30,
	2005			2004			2005 vs. 2004
Effective tax rate, as reported		38.3	%		37.4	%		0.9	%
Income tax adjustment		-			1.8			1.8
Effective tax rate, revised to exclude 2004 adjustment		38.3	%		39.2	%		(0.9	)%

Distribution Operations

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

·   Atlanta Gas Light

·   Elizabethtown Gas

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

·   Florida City Gas

·   Chattanooga Gas Company (Chattanooga Gas)

·   Elkton Gas

Each utility operates subject to regulations of the state regulatory agencies in its service territories with respect to rates charged to our customers, maintenance of accounting records and various other service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. Rates are set at levels that should generally allow for the recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return on common equity.  Rate base 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 of deferred income tax liabilities and certain other deductions.  We continuously monitor the performance of our utilities to determine whether rates need to be adjusted through the regulatory process.

Atlanta Gas Light On June 10, 2005, the Georgia Public Service Commission (Georgia Commission) approved a Settlement Agreement with Atlanta Gas Light that freezes Atlanta Gas Light’s base rates billed to customers as of April 30, 2005 through April 30, 2010. The Settlement Agreement also requires Atlanta Gas Light to recognize reduced revenues of $25 million in total over the same period, to spend $2 million annually on energy conservation programs and to spend $1.5 million in increased social responsibility costs. The Settlement Agreement is effective for rates as of May 1, 2005. Atlanta Gas Light has identified and implemented reductions in its operating costs which are expected to offset the impact of the Settlement Agreement on its 2005 EBIT.

Under the Settlement Agreement, Atlanta Gas Light will not seek a rate increase, nor will the Georgia Commission initiate a new rate proceeding, during the agreement’s effective period. However, Atlanta Gas Light will file information equivalent to information that would be required for a general rate case on November 1, 2009, with new rates to be effective on May 1, 2010.

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The Settlement Agreement extends Atlanta Gas Light’s Pipeline Replacement Program (PRP) by five years to require that all replacements be completed by December 2013. Atlanta Gas Light will apply the five-year total reduction in recognized base rate revenues of $25 million to the amount of costs incurred to replace pipe, reducing the amount recovered from customers under the PRP. Atlanta Gas Light is currently working with the Georgia Commission staff on the revised PRP replacement time schedule.

The Settlement Agreement includes a provision that allows for a true-up of any over or under recovery of PRP revenues that may result from a difference between PRP charges collected through fixed rates and actual PRP revenues recognized through the remainder of the program. The effect on customers’ bills during this five-year period can be seen in the table below.

Years	Typical monthly base charge			Monthly PRP charge			Total			Change in monthly bill
2005 - 2007		$	21.27		$	1.29		$	22.56		$	0.00
2008 - 2009		$	21.27		$	1.95		$	23.22		$	0.66

The Settlement Agreement also establishes an authorized return on equity of 10.9% for Atlanta Gas Light, resulting in an overall rate of return of 8.53%. Prior to the settlement, Atlanta Gas Light’s authorized return on equity was 11% and its overall return was set at 9.16%.

The Settlement Agreement also allows Atlanta Gas Light to recover through the PRP $4 million of the $32 million in capital costs associated with its March 2005 purchase of 250 miles of pipeline in central Georgia from Southern Natural Gas Company, a subsidiary of El Paso Corporation. The acquisition will improve deliverable capacity and reliability of the storage capacity from our LNG facility in Macon to our markets in Atlanta. The remaining capital costs are included in Atlanta Gas Light’s rate base and collected through base rates.

Virginia Natural Gas In March 2005, the Virginia State Corporation Commission (Virginia Commission) staff issued a report alleging that Virginia Natural Gas’ rates were excessive and that its rates should be adjusted to produce a $15 million reduction in revenue. The staff also filed a motion requesting that Virginia Natural Gas’ rates be declared interim and subject to refund.

On April 11, 2005, Virginia Natural Gas responded to the staff’s report and motion, contested the allegations in the report and objected to the motion filed by the staff. On April 29, 2005, the Virginia Commission ordered the staff’s motion to be held in abeyance and directed Virginia Natural Gas to file a rate case by July 1, 2005. 

On July 1, 2005, Virginia Natural Gas filed a Performance-Based Regulation (PBR) plan with the Virginia Commission and included the schedules required for a general rate case in support of its proposal. Under the PBR plan, Virginia Natural Gas proposes to freeze base rates at their 1996 levels for five additional years. This would provide Virginia Natural Gas’ customers an additional five years of rate stability, for a total of 14 years without a rate increase. If the Virginia Commission approves the proposal, Virginia Natural Gas will become the first Virginia natural gas utility to operate under a 1996 state law that authorized PBR plans for natural gas utilities. Consistent with state law, Virginia Natural Gas has proposed two exceptions that allow for adjustments to frozen base rates. Virginia Natural Gas could request a rate adjustment in connection with (1) any changes in taxation of gas utility revenues by the Commonwealth and (2) any financial distress of Virginia Natural Gas beyond its control.

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Also on July 1, 2005, to meet the requirements of the Virginia Commission’s April 29th order, Virginia Natural Gas filed schedules to support a $19 million per year rate increase that would be justified under a traditional rate case. This would increase base charges for gas distribution by more than $6 per month for the typical residential customer.

Based on the Virginia Commission’s scheduling order issued on July 14, 2005, current rates will stay in effect until the PBR is decided, and there will be no impact on Virginia Natural Gas’ 2005 revenues. Based on this scheduling order the PBR proposal to freeze rates for another five years will be considered on the following timeframe:

·   Virginia Commission staff will file its testimony and exhibits on or before December 15, 2005;

·   Virginia Natural Gas will file rebuttal testimony and exhibits on or before January 12, 2006; and

·   Public hearings will convene on January 24, 2006.

The Virginia state law authorizing PBR plans also allows a utility to withdraw or modify its PBR application at any time prior to a final ruling by the Virginia Commission. Virginia Natural Gas is currently evaluating withdrawing or modifing its PBR plan in light of current market conditions including rising interest rates, tight natural gas supplies, rising costs and material constraints caused by lower oil supplies. If the PBR plan is not approved or is modified by the Virginia Commission in a manner that Virginia Natural Gas chooses not to accept, the Virginia Commission can take action in the general rate case filing. Virginia Natural Gas’ proposal would not affect its Virginia Commission-authorized purchased gas cost, which passes gas commodity costs through to consumers.

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

Elizabethtown Gas’ collective bargaining agreement with its employees who belong to the Utility Workers Union of America local 424 expires in November 2005. Elizabethtown Gas is currently working on a two-year renewal of the agreement with these employees. However, Elizabethtown Gas is prepared to safely serve its customers should there be a work stoppage.

Chattanooga Gas In October 2004, the Tennessee Regulatory Authority (Tennessee Authority) denied Chattanooga Gas’ request for a $4 million rate increase, instead approving an increase of approximately $1 million based on a 10.2% return on equity and a capital structure of 35.5% common equity. In November 2004, the Tennessee Authority granted Chattanooga Gas’ motion for reconsideration of the rate increase and in December 2004 heard oral arguments on the issues of the appropriate capital structure and the return on equity to be used in setting Chattanooga Gas’ rates. In March 2005, Chattanooga Gas filed additional testimony and supporting documentation at the request of the Tennessee Authority.

On June 13, 2005, the Tennessee Authority voted 3-0 to uphold its previous order related to the reconsideration petition filed by Chattanooga Gas. Chattanooga Gas is reviewing its options with regard to the Tennessee Authority’s decision, including legal appeal and filing of a new rate case.

Florida City Gas In April 2005, approximately 53 of 77 Florida City Gas employees covered under collective bargaining agreements with Teamster’s locals 769 and 385 began a work stoppage for 39 days. The strike began on April 7, 2005 and ended on May 16, 2005 when a new agreement was reached.  The new three-year agreement provides management additional tools to improve service for our customers.  Florida City Gas was able to maintain the service levels at pre-strike levels throughout the strike through the use of both union and non-union workers.

Results of Operationsfor our distribution operations segmentfor the three and nine months ended September 30, 2005 and 2004 are shown in the following tables:

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Third quarter 2005 compared to third quarter 2004

	Three months ended September 30,
In millions	2005		2004		2005 vs. 2004
Operating revenues	$	263	$	166	$	97
Cost of gas		95		31		64
Operating margin		168		135		33
Operation and maintenance		85		63		22
Depreciation and amortization		28		20		8
Taxes other than income		7		4		3
Total operating expenses		120		87		33
Operating income		48		48		-
Other income		1		-		1
EBIT	$	49	$	48	$	1

EBIT Third quarter 2005 EBIT was flat, as a $33 million increase in operating margin was offset by a $33 million increase in operating expenses.  

Operating MarginThe $33 million increase in operating margin was primarily the result of the addition of NUI’s operations, which contributed $31 million.  The remainder reflects higher operating margins at Atlanta Gas Light and Virginia Natural Gas.  A $1 million increase in operating margin at Atlanta Gas Light reflects higher PRP revenues, net customer growth and additional revenues from gas storage carrying charges billed to marketers.  A $1 million increase in operating margin for Virginia Natural Gas was due primarily to customer growth.

Operating ExpensesThe $33 million increase in operating expenses reflects the addition of NUI’s operations, which contributed $32 million.  The additional $1 million increase resulted from higher corporate overhead expenses.

Nine months 2005 compared to nine months 2004

	Nine months ended September 30,
In millions	2005		2004		2005 vs. 2004
Operating revenues	$	1,190	$	739	$	451
Cost of gas		590		284		306
Operating margin		600		455		145
Operation and maintenance		269		199		70
Depreciation and amortization		85		62		23
Taxes other than income		24		16		8
Total operating expenses		378		277		101
Operating income		222		178		44
Other income		2		1		1
EBIT	$	224	$	179	$	45
Metrics(includes information only for 2005 for utilities acquired from NUI)
Average end-use customers (in thousands)		2,247		1,853		21	%
Operation and maintenance expenses per customer	$	120	$	107		12	%
EBIT per customer	$	100	$	97		3	%
Throughput (in millions of dekatherms)
Firm		158		129		22	%
Interruptible		91		77		18	%
Total		249		206		21	%
Heating degree days						% Colder / (Warmer	)
Florida		531		-		n/a
Georgia		1,595		1,661		(4	%)
Maryland		3,270		-		n/a
New Jersey		3,334		-		n/a
Tennessee		1,781		1,932		(8	%)
Virginia		2,329		2,078		12	%

EBIT The $45 million EBIT improvement reflects increased operating margin of $145 million, partially offset by increased operating expenses of $101 million.  The utilities acquired from NUI contributed approximately $33 million of the increase in EBIT.

Operating MarginThe $145 million increase in operating margin was primarily due to the addition of NUI’s operations, which contributed $137 million. The remainder reflects a combination of $8 million of higher operating margin at Atlanta Gas Light, offset by $1 million of lower margin at Virginia Natural Gas.  The increase at Atlanta Gas Light resulted primarily from higher PRP revenues and net customer growth. Operating margin at Virginia Natural Gas decreased as a result of lower usage per heating degree day relative to the same period in 2004.

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Operating ExpensesThe $101 million increase in operating expenses reflects the addition of NUI’s operations, which resulted in an increase in operating expenses of $105 million, offset by lower operating expenses of $4 million primarily at Atlanta Gas Light.  Operating expenses at Virginia Natural Gas and Chattanooga Gas were relatively flat compared to the prior year period.

Retail Energy Operations

Our retail energy operations segment consists of SouthStar, a joint venture owned 70% by our subsidiary, Georgia Natural Gas Company, and 30% by Piedmont Natural Gas Company, Inc. (Piedmont). SouthStar markets natural gas and related services to retail customers on an unregulated basis, principally in Georgia.   

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

We consolidated with our subsidiaries’ accounts all the accounts of SouthStar and eliminated all intercompany balances in the consolidation. We recorded the portion of SouthStar’s earnings that are attributable to our joint venture partner, Piedmont, 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 in our condensed consolidated balance sheets.

Operating Margin SouthStar generates its operating margin primarily in two ways.  The first is through the commodity sales of natural gas to retail customers in the residential, commercial and industrial sectors, primarily in Georgia.  SouthStar captures a spread between wholesale and retail natural gas commodity prices and also realizes a portion of its operating margin through the collection of a monthly service fee and customer late-payment fees.  SouthStar’s operating margins are impacted by weather seasonality as well as by customer growth and its related market share in Georgia that traditionally ranges from 35 percent to 38 percent.  SouthStar employs a strategy to attract and retain a higher-quality customer base through the application of stringent credit requirements and enrollment of new customers with multiple natural gas burner tips.  This strategy results not only in higher operating margin contributions as customers tend to utilize higher volumes of natural gas but also higher EBIT through a reduction in bad debt expenses.

The second way in which SouthStar generates margin relates to the active management of storage positions through a variety of hedging transactions and derivative instruments, aimed at managing exposures arising from changing commodity prices.  SouthStar uses these hedging instruments opportunistically to lock in economic margins (as spreads widen between periods) and thereby minimizing retail price exposure, but does not hold speculative positions. 

SouthStar is actively seeking to improve its margin-generation capabilities by evaluating a number of growth opportunities, including incremental customer growth in Georgia and expansion of its retail model to other markets, either through organic growth or acquisition of an existing customer portfolio.

Bad Debt Expense SouthStar’s bad debt expense as a percentage of operating revenues was 0.9% for the nine months ended September 30, 2005, although the dollar amount of bad debt expense declined in both periods. These percentages are consistent with those in the same period of last year.  We believe SouthStar’s higher-quality customer base should provide some buffer for the anticipated bad debt expense related to the upcoming winter heating season and natural gas prices that are expected to be higher than in prior years.

Results of operations for our retail energy operations segment for the three and nine months ended September 30, 2005 and 2004 are shown in the following tables.

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Third quarter 2005 compared to third quarter 2004

	Three months ended September 30,
In millions	2005			2004			2005 vs. 2004
Operating revenues	$	153		$	128		$	25
Cost of sales		129			110			19
Operating margin		24			18			6
Operation and maintenance		13			16			(3	)
Depreciation and amortization		1			1			-
Taxes other than income		1			(1	)		2
Total operating expenses		15			16			(1	)
Operating income		9			2			7
Minority interest		(2	)		-			(2	)
EBIT	$	7		$	2		$	5

EBITThe $5 million EBIT increase primarily resulted from higher operating margins of $6 million and lower operating expenses of $1 million, offset by a $2 million increase in minority interest as discussed below.

Operating MarginOperating margin increased $6 million, primarily as a result of greater retail price spreads, mark-to-market gains recognized in 2005 on hedging instruments and higher interruptible margins driven primarily from the peaking sales during curtailments. In addition, SouthStar’s improved customer base lowered its late payment fees.

Operating ExpensesOperating expenses decreased $1 million, primarily as a result of lower customer service and marketing expenses due to timing of campaigns in 2004 and lower customer care expenses as a result of system upgrades. These decreases were offset by higher bad debt expenses from higher billed revenues.

Nine months 2005 compared to nine months 2004

	Nine months ended September 30,
In millions	2005			2004			2005 vs. 2004
Operating revenues	$	627		$	583		$	44
Cost of sales		513			485			28
Operating margin		114			98			16
Operation and maintenance		40			42			(2	)
Depreciation and amortization		2			1			1
Taxes other than income		1			-			1
Total operating expenses		43			43			-
Operating income		71			55			16
Minority interest		(18	)		(14	)		(4	)
EBIT	$	53		$	41		$	12
Metrics
12 month average customers (in thousands)		534			537			(1	%)
Market share in Georgia		35	%		36	%		(3	%)

EBIT The $12 million increase was driven by a $16 million increase in operating margin and relatively flat operating expenses, offset by a $4 million increase in minority interest as discussed below.

Operating MarginThe $16 million increase in operating margin was primarily the result of higher commodity margins, offset by lower asset management margins and lower late payment fees relative to the prior year.

Operating Expenses There was no change in operating expenses for the nine months in 2005 as compared to the same period in 2004.

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Wholesale Services

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

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

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

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

Dollars in millions

Duration of contract (in years)

Expiration date

Frequency of payment

Type of fee structure

Profits shared / fees paid in 2005(1)

Profits shared / fees paid in 2004 (2)

Atlanta Gas Light

3

Feb 2006

Semi-annually

Profit sharing

$

3

$

4

Elkton Gas

2

Mar 2007

Monthly

Fixed-fee

-

-

Chattanooga Gas

3

Mar 2007

Annually

Profit sharing

2

1

Elizabethtown Gas

3

Mar 2008

Monthly

Fixed fee

-

-

Florida City Gas

3

Mar 2008

Annually

Profit sharing

-

-

Virginia Natural Gas (3)

3

Mar 2009

Annually

Profit sharing

-

3

(1)   For the nine months ended September 30, 2005.

(2)   For the twelve months ended December 31, 2004.

(3)   In October 2005, the agreement between Sequent and Virginia Natural Gas was renewed. The agreement remains subject to receipt of Virginia Commission approval.

Energy Marketing and Risk Management Activities The tables below illustrate the change in the net fair value of Sequent’s derivative instruments and energy-trading contracts during the three and nine months ended September 30, 2005 and 2004 and provide details of the net fair value of contracts outstanding as of September 30, 2005.

	Three months ended September 30,						Nine months ended September 30,
In millions	2005			2004			2005			2004
Net fair value of contracts outstanding at beginning of period	$	8		$	10		$	17		$	(5	)
Contracts realized or otherwise settled during period		6			9			23			16
Change in net fair value of contracts		(122	)		(19	)		(148	)		(11	)
Net fair value of contracts outstanding at end of period		(108	)		-			(108	)		-
Less net fair value of contracts outstanding at beginning of period		8			10			17			(5	)
Unrealized (loss) gain related to changes in the fair value of derivative instruments	$	(116	)	$	(10	)	$	(125	)	$	5

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The sources of Sequent’s net fair value at September 30, 2005 are as follows:

In millions	Matures through Sept. 2006			Matures through Sept. 2009		Matures through Sept. 2011		Matures after Sept. 2012		Total net fair value
Prices actively quoted (1)	$	(52	)	$	4	$	-	$	-	$	(48	)
Prices provided by other external sources (1)		(61	)		-		1		-		(60	)

(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. Sequent’s basis spreads are primarily based on quotes obtained either directly from brokers or through electronic trading platforms.

Mark-to-Market versus Lower of Average Cost or Market Sequent purchases natural gas for storage when the current market price it pays plus the cost for transportation and storage is less than the market price it could receive in the future. Sequent attempts to mitigate substantially all of its commodity price risk associated with its storage portfolio. Sequent uses derivative instruments to reduce the risk associated with future changes in the price of natural gas. Sequent sells NYMEX futures contracts or other over-the-counter derivatives in forward months to substantially lock-in the profit margin it will ultimately realize when the stored gas is actually sold.

Natural gas stored in inventory is accounted for differently than the derivatives Sequent uses to mitigate the commodity price risk associated with its storage portfolio. The natural gas that Sequent purchases and injects into storage is accounted for at the lower of average cost or market. The derivatives that Sequent uses to mitigate commodity price risk are accounted for at fair value and marked to market each period. The difference in accounting can result in volatility in Sequent’s reported results, even though the expected profit margin is essentially unchanged from the date the transactions were consummated.

Earnings Volatility and Price Sensitivity The aforementioned accounting differences also impact the comparability of Sequent’s period-over-period results as changes in forward NYMEX prices do not increase and decrease on a consistent basis from year to year. During 2005 Sequent’s first quarter results were negatively impacted by a decline in forward NYMEX prices during December 2004. This decline resulted in the recognition of unrealized gains in the fourth quarter of 2004 rather than in the first quarter of 2005 when the physical inventory was actually withdrawn. During the second quarter of 2005, forward NYMEX prices decreased once again, resulting in the recognition of unrealized gains in Sequent’s reported results. In contrast, forward NYMEX prices increased during the first and third quarters of 2005, resulting in the recognition of unrealized losses in the quarterly results. In comparison, the reported quarterly results during 2004 were not as significantly impacted by changes in forward NYMEX prices. As a result, a comparison of the 2005 and 2004 reported quarterly results yields an unfavorable variance for the first and third quarters and a favorable variance for the second quarter. However, the September 30 year-to-date results are relatively consistent year over year due to the offsetting effect of the unrealized gains and losses in conjunction with improved commercial operations during 2005. For additional information regarding the quarterly and year-to-date results, see “Results of Operations” below.

Based upon Sequent’s storage positions at September 30, 2005, a $1.00 change in the forward NYMEX prices would result in a $6 million impact to Sequent’s EBIT after regulatory sharing.

Storage Inventory Outlook The NYMEX forward curve graph set forth below reflects the NYMEX natural gas prices as of June 30, 2005 and September 30, 2005 for the period of October 2005 through September 2006, and reflects the prices at which Sequent could buy natural gas at the Henry Hub for delivery in the same time period. October 2005 futures expired on September 28, 2005; however they are included in the table below 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.

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The NYMEX forward curve graph above displays the significant increase in fourth quarter 2005 and first quarter 2006 NYMEX prices experienced during the third quarter of 2005. As shown in the table below, Sequent’s entire inventory in storage as of September 30, 2005 is scheduled for withdrawal during the fourth quarter of 2005 and the first quarter of 2006. Since Sequent has NYMEX contracts in place, its original economic profit margin is unaffected. However, the increase in forward NYMEX prices during the third quarter of 2005 resulted in unrealized losses associated with Sequent’s NYMEX contracts. Sequent did not experience the same level of increase in forward NYMEX prices during the third quarter of 2004. See further discussions in “Results of Operations” below.

As shown in the table below, “Open futures NYMEX contracts” represents the volume in contract equivalents of the transactions Sequent executed to lock in its storage inventory margin. Each contract equivalent represents 10,000 million British thermal units (MMBtu).The expected withdrawal schedule of this inventory as of September 30, 2005 is also reflected in the table. At September 30, 2005 the weighted average cost of gas (WACOG) in salt dome storage was $10.47 and the WACOG for gas in reservoir storage was $6.59.

The table also reflects that Sequent’s storage inventory is fully hedged with futures as evidenced by the NYMEX short positions being equal to the physical long positions, which results in an overall locked-in margin, timing notwithstanding. “Expected gross margin after regulatory sharing” reflects the gross margin Sequent would generate in future periods based on the forward curve and inventory withdrawal schedule at September 30, 2005.

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Sequent’s current inventory level and pricing as of September 30, 2005 should result in gross margin of approximately $43 million through March 2006 and will likely change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months. This represents an increase of $38 million in expected gross margin from Sequent’s withdrawal activity during the fourth quarter of 2005 and the first quarter of 2006 from the amounts previously reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2005. The change in value is primarily a result of forward NYMEX prices increasing in excess of $6 per MMBtu during the third quarter (as shown in the NYMEX forward curve graph above) and a slight increase in the September 30 inventory balance in excess of the June 30 expectation.

Volumes in MMBtu, dollars in millions	Oct 2005			Nov 2005		Dec 2005			Jan 2006			Feb 2006			Mar 2006			Total
Open futures NYMEX contracts (short) long		(299	)		-		(64	)		(50	)		(114	)		(223	)		(750	)
Physical salt dome withdrawal schedule		-			-		63			-			-			-			63
Physical reservoir withdrawal schedule		299			-		1			50			114			223			687
Total		299			-		64			50			114			223			750
Expected gross margin, after regulatory sharing, for withdrawal activity	$	15		$	-	$	2		$	4		$	8		$	14		$	43

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 AGL Resources’ credit ratings are downgraded to non-investment grade status. Under such circumstances, Sequent would need to post collateral to continue transacting with some of its counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, Sequent’s ability to continue transacting with these counterparties would be impaired. If at September 30, 2005, our credit ratings had been downgraded to non-investment grade, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $31 million.

Results of Operations for our wholesale services segmentfor the three and nine months ended September 30, 2005 and 2004 are as follows:

Third quarter 2005 compared to third quarter 2004

	Three months ended September 30,
In millions	2005			2004			2005 vs. 2004
Operating revenues	$	1		$	3		$	(2	)
Cost of sales		-			-			-
Operating margin		1			3			(2	)
Operation and maintenance		6			4			2
Depreciation and amortization		1			-			1
Taxes other than income		-			-			-
Total operating expenses		7			4			3
Operating income		(6	)		(1	)		(5	)
Other income		-			-			-
EBIT	$	(6	)	$	(1	)	$	(5	)
Metrics
Physical sales volumes (Bcf/day)		2.33			2.08			12	%

EBIT The decrease in EBIT of $5 million in 2005 as compared to 2004 was due to a decrease in operating margin of $2 million and an increase in operating expenses of $3 million.

Operating MarginThe $2 million decrease in operating margin was driven by unrealized losses on our inventory hedging instruments, partially offset by improved results associated with market volatility created by hurricanes Katrina and Rita. During the third quarter of 2005 there was a significant increase in forward NYMEX prices, specifically associated with the months of October 2005 through March 2006 in response to the unusually high level of hurricane activity in the Gulf of Mexico. This rise in forward prices resulted in the recognition of $35 million of unrealized losses associated with the financial instruments that Sequent uses to economically hedge its natural gas inventory held in storage.

These unrealized losses are expected to be offset by operating margin expected to be recognized over the next six months as Sequent withdraws its inventory held in storage. During the comparable period of 2004 the corresponding loss was $3 million. In addition, Sequent was able to partially offset the unrealized losses as market opportunities in the current year exceeded those during 2004 due to increased demand and price volatility caused by disruptions in the natural gas industry as a result of hurricane activity. During August and September 2005 Sequent transported natural gas to customers using non-traditional routes and cycled through its salt dome storage capacity in order to meet market demands. The third quarter of 2004 experienced more modest levels of market volatility.

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Operating ExpensesThe $3 million increase in operating expenses reflects additional payroll costs associated with increased headcount and hurricane related costs associated with the temporary relocation of Sequent’s commercial operations. Sequent also incurred additional depreciation expense in connection with its new energy trading and risk management (ETRM) system which was implemented during 2004.

Nine months 2005 compared to nine months 2004

	Nine months ended September 30,
In millions	2005		2004		2005 vs. 2004
Operating revenues	$	21	$	23	$	(2	)
Cost of sales		-		-
Operating margin		21		23		(2	)
Operation and maintenance		19		17		2
Depreciation and amortization		2		-		2
Taxes other than income		-		-		-
Total operating expenses		21		17		4
Operating income		-		6		(6	)
Other income		-		-		-
EBIT	$	-	$	6	$	(6	)
Metrics
Physical sales volumes (Bcf/day)		2.27		2.06		10	%

EBIT The decrease in EBIT of $6 million in 2005 as compared to 2004 was due to a decrease in operating margin of $2 million and an increase in operating expenses of $4 million.

Operating Margin The $2 million decrease in operating margin reflects the net impact of a decline in first and third quarter operating revenues, partially offset by an increase in second quarter operating revenues, as compared to the corresponding periods in 2004. During the first quarter, Sequent experienced a $9 million reduction in operating revenues due to the negative impact of changes in forward NYMEX prices during late 2004 and early 2005, partially offset by improved origination activities during the 2005 period. During the second quarter, Sequent experienced an $8 million increase in operating revenues due to improved results from its affiliated asset management and origination activities. Contributing to the higher results were declines in forward NYMEX prices and the associated impact on Sequent’s financial instruments that it used to economically hedge its natural gas inventory held in storage.

Sequent’s results for the first six months of the year were consistent with the prior period in the aggregate. During the third quarter Sequent reported significant unrealized losses on its storage hedges due to a $6 per MMBtu increase in forward NYMEX prices. These unrealized losses were partially offset by its physical gas sales and transportation activity in response to increased demand resulting from hurricanes impacting the Gulf Coast region. By contrast, the results for 2004 were not as significantly impacted by changes in forward NYMEX prices and market volatility.

Operating Expenses The $4 million increase in operating expenses is a result of additional payroll costs associated with increased headcount due to growth in Sequent’s business and depreciation expense in connection with Sequent’s new ETRM system, which was implemented during the prior year.

Energy Investments

Our energy investments segment includes:

·   Pivotal Jefferson Island

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

·   AGL Networks

Pivotal Jefferson IslandOn October 17, 2005, Pivotal Jefferson Island announced that it was soliciting bids for current firm and interruptible natural gas contracts that will expire in early 2006.  Pivotal Jefferson Island will have an additional 300 million dekatherms (MDth) of storage capacity available beginning January 1, 2006, and another 1,100 MDth available beginning April 1, 2006.

Pivotal Jefferson Island also has substantially completed a capital project to improve its compression capabilities, which will expand the number of times it is able to cycle natural gas inventory in and out of the facility.  We expect to have the additional compression in service in November 2005.

On October 27, 2005, we announced we are soliciting customer interest, in the form of non-binding bids for capacity, in a project that would expand Pivotal Jefferson Island’s salt-dome storage facility from its current capacity of 6.9 Bcf to as much as 18.9 Bcf.  The expansion would require the development of a third and fourth storage cavern at the facility, with each cavern having a working gas capacity of 6 Bcf.  If there is sufficient customer interest in the project, construction would begin in early 2006.  We would expect to complete the third cavern by mid-2008, and would expect the fourth cavern to be operational by mid-2010.  The expansion project also includes expanding the number of pipeline interconnections in order to enhance our flexibility with regard to storage capacity and deliverability.  Final construction plans, as well as the total projected capital cost of the project, will be determined upon completion of the bid process.

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Sale of Saltville On August 10, 2005, we completed the sale of our 50% interest in Saltville Gas Storage Company, LLC (Saltville) and associated subsidiaries (Virginia Gas Pipeline and Virginia Gas Storage) to a subsidiary of Duke Energy Corporation, the other 50% partner in the Saltville joint venture. We acquired these assets as part of our purchase of NUI in November 2004. We received $66 million in cash at closing, which included $4 million in working capital adjustments, and used the proceeds to repay debt and for other general corporate purposes.

Sale of Other NUI Assets On September 15, 2005, we completed the sale of an appliance business in Florida for approximately $7 million. We are marketing certain other related NUI entities for sale, with buyers being actively solicited. The assets, liabilities, revenues and expenses of these entities are not considered to be material to our financial statements.

Results of operations for our energy investments segment for the three and nine months ended September 30, 2005 and 2004 are shown in the following table.

Third quarter 2005 compared to third quarter 2004

	Three months ended September 30,
In millions	2005		2004			2005 vs. 2004
Operating revenues	$	14	$	2		$	12
Cost of sales		4		1			3
Operating margin		10		1			9
Operation and maintenance		4		1			3
Depreciation and amortization		1		-			1
Taxes other than income		-		1			(1	)
Total operating expenses		5		2			3
Operating income		5		(1	)		6
Other income		-		-			-
EBIT	$	5	$	(1	)	$	6

EBITThe $6 million EBIT increase was primarily the result of improved operating margin of $9 million, offset by higher operating expenses of $3 million as discussed below.

Operating MarginThe $9 million improvement in operating margin reflects $5 million from the addition of Pivotal Jefferson Island, $2 million from AGL Networks, $1 million from Pivotal Propane of Virginia, and $1 million from the addition of NUI’s non-utility businesses.

Operating ExpensesThe $3 million increase in operating expenses reflects $1 million from the addition of Pivotal Jefferson Island and $2 million from NUI’s non-utility businesses.

Nine months 2005 compared to nine months 2004

	Nine months ended September 30,
In millions	2005		2004			2005 vs. 2004
Operating revenues	$	43	$	5		$	38
Cost of sales		12		1			11
Operating margin		31		4			27
Operation and maintenance		12		3			9
Depreciation and amortization		4		1			3
Taxes other than income		1		1			-
Total operating expenses		17		5			12
Operating income		14		(1	)		15
Other income		1		2			(1	)
EBIT	$	15	$	1		$	14

EBITThe $14 million EBIT increase was primarily the result of improved operating margin of $27 million, offset by $12 million in higher operating expenses as discussed below.  

Operating MarginOf the $27 million increase in operating margin, $20 million resulted from the acquisition of Pivotal Jefferson Island, which contributed $12 million, and NUI’s non-utility businesses, which contributed $8 million. AGL Networks contributed $5 million primarily from margins associated with a network infrastructure project in Georgia.

Operating ExpensesOf the $12 million increase in operating expenses, $11 million resulted from the acquisition of Pivotal Jefferson Island, which contributed $3 million, and NUI’s non-utility businesses, which contributed $8 million.

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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.

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

We allocate substantially all of AGSC’s and AGL Capital’s operating expenses and interest costs to our operating segments in accordance with PUHCA and state regulations. Our corporate segment also includes intercompany eliminations for transactions between our operating business segments. Our EBIT results include the impact of these allocations to the various operating segments.  The acquisition of additional assets, such as NUI and Pivotal Jefferson Island, typically will enable us to allocate corporate costs across a larger number of businesses and, as a result, lower the relative allocations charged to those business units we owned prior to the acquisition of the new businesses.

AGL Services Company Restructuring As a result of the NUI acquisition, the associated centralization of certain administrative and operational functions and our ongoing desire to operate as efficiently as possible, we began, during the first quarter of 2005, a review of certain functions within our AGSC subsidiary. We expect this process to be part of an ongoing effort to optimize staffing levels and work processes across our entire company, including an ongoing review of functions within Atlanta Gas Light in part precipitated by its June 2005 settlement related to base rates (see "Results of Operations - Distribution Operations" for more information).

The immediate effects of this effort are the restructuring of certain key corporate functions and the elimination of filled and vacant positions within AGSC. We recorded a charge of $3 million during the third quarter of 2005, primarily as a result of severance-related costs associated with the restructuring and elimination of the filled positions at AGSC. This charge will be earnings neutral in 2005, as it will be offset by payroll and benefits savings. Based on the efforts performed to date, as well as actual costs incurred to date and our original basis for the earnings guidance previously provided, we estimate the annual savings from these efforts to be in the range of $6 million to $10 million. While these savings will be reflected in the allocated costs to various business units, the most significant portion of the allocation is intended to be in the distribution operations segment of our Georgia operations.

Repeal of PUHCA In August 2005 the Energy Policy Act of 2005 repealed PUHCA, effective in February 2006. As a result, many of the geographic and structural restrictions on the ownership of public utilities will be removed. We expect some of the reporting requirements, financing authorizations and affiliate relationship approvals that were previously required by the SEC under PUHCA to be replaced by the requirements of the Federal Energy Regulation Commission, which was granted increased oversight of utility merger and acquisition activity. We also expect that the state regulatory agencies in each of our jurisdictions will require the filing of some of the data that were previously required to be filed with the SEC.

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Results of operations for our corporate segment for the three and nine months ended September 30, 2005 and 2004 are as follows:

Third quarter 2005 compared to third quarter 2004

	Three months ended September 30,
In millions	2005			2004			2005 vs. 2004
Payroll	$	15		$	12		$	3
Benefits and incentives		6			4			2
Outside services		12			6			6
Depreciation and amortization		2			2			-
Taxes other than income		1			1			-
Other		11			9			2
Total operating expenses before allocations		47			34			13
Allocation to operating segments		(45	)		(32	)		(14	)
Total operating expenses		2			2			(1	)
Other losses		1			-			2
EBIT	$	(3	)	$	(2	)	$	(1	)

Nine months 2005 compared to nine months 2004

	Nine months ended September 30,
In millions	2005			2004			2005 vs. 2004
Payroll	$	43		$	24		$	19
Benefits and incentives		20			15			5
Outside services		31			13			18
Depreciation and amortization		7			5			2
Taxes other than income		4			2			2
Other		33			20			13
Total operating expenses before allocations		138			79			59
Allocation to operating segments		(132	)		(73	)		(59	)
Total operating expenses		6			6			-
Other losses		1			1			-
EBIT	$	(7	)	$	(7	)		-

The corporate segment is a non-operating segment, and as such, comparative EBIT variances for the indicated periods reflect the relative change in various general and administrative expenses, such as payroll, benefits and incentives and outside services.

The higher payroll expenses in the three and nine month periods of 2005 were the result of increased headcount in the corporate segment due to the acquisition of NUI in November of 2004 and the realignment of certain corporate functions to AGSC.

Outside services expenses increased primarily due to higher costs associated with process improvement projects in the information technology, finance and human resources areas.

Benefits and incentives increased primarily as a result of higher payroll related expenses. In addition, severance expenses increased as a result of the AGSC restructuring and process improvement initiatives.

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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.

The availability of borrowings under our Credit Facility is limited and subject to a total debt-to-capital ratio financial covenant specified within the Credit Facility, which we currently meet.

In August 2005 we amended the Credit Facility. Under the terms of the amendment, the aggregate principal amount available under the Credit Facility has been increased from $750 million to $850 million, and we have the option to increase the aggregate principal amount available for borrowing to $1.1 billion on not more than three occasions during each calendar year. The amended Credit Facility expires on August 31, 2010. Our total cash and available liquidity under our Credit Facility as of the dates indicated are represented in the table below.

In millions	Sept. 30, 2005		Dec. 31, 2004
Unused availability under the Credit Facility	$	850	$	750
Cash and cash equivalents		57		49
Total cash and available liquidity under the Credit Facility	$	907	$	799

We believe these sources will be sufficient for our working capital needs, debt service obligations and scheduled capital expenditures for the foreseeable future. The relatively stable operating cash flows of our distribution operations businesses currently contribute most of our cash flow from operations, and we anticipate this to continue in the future.

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

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

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

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

·   regulatory changes and changes in rate-making policies of regulatory commissions

·   contractual cash obligations and other commercial commitments

·   interest rate changes

·   pension and postretirement funding requirements

·   changes in income tax laws

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

·   operational risks

·   the impact of natural disasters, including weather

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Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.

We calculate any required pension contributions using an actuarial method called the projected unit credit cost method. Under this method, we were not required to make any pension contribution in 2005, but we voluntarily made a $5 million contribution in August 2005. The following table illustrates our expected future contractual obligations:

			Payments due before December 31,
					2006		2008		2010
					&		&		&
In millions	Total		2005		2007		2009		thereafter
Pipeline charges, storage capacity and gas supply (1)	$	1,651	$	76	$	521	$	435	$	619
Long-term debt (2) (3)		1,616		-		2		2		1,612
Short-term debt (3)		344		344		-		-		-
Pipeline replacement program costs (4)		316		24		61		83		148
Commodity and transportation charges		269		102		81		14		72
Operating leases (5)		133		5		32		29		67
ERC (4)		98		2		27		30		39
Communication/network service and maintenance		11		3		8		-		-
Total	$	4,438	$	556	$	732	$	593	$	2,557
(1) Charges recoverable through a purchased gas adjustment mechanism or alternatively billed to Georgia Commission certificated marketers selling retail natural gas in Georgia. Also includes demand charges associated with Sequent.
(2) Includes $232 million of notes payable to trusts, callable in 2006 and 2007.
(3) Does not include the interest expense associated with long-term and short-term debt.
(4) Charges recoverable through rate rider mechanisms.
(5) We have certain operating leases with provisions for step rent or escalation payments, or certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms in accordance with SFAS No. 13, “Accounting for Leases.” However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein.

SouthStar has natural gas purchase commitments related to the supply of minimum natural gas volumes to its customers. These commitments are priced on both a fixed basis and an index plus premium basis. At September 30, 2005, SouthStar had obligations under these arrangements for 6.9 Bcf through December 31, 2005.

We have also incurred various contingent financial commitments in the normal course of business. The following table sets forth as of September 30, 2005 the maximum potential amount of our expected contingent financial commitments, representing obligations that become payable only if certain pre-defined events occur:

			Commitments due before Dec. 31,
					2006 &
In millions	Total		2005		thereafter
Standby letters of credit, performance / surety bonds	$	20	$	20	$	-

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

Year-over-year changes in our operating cash flows are attributable primarily to working capital changes within our distribution operations, wholesale services and retail energy operations segments resulting from the impact of weather, the price of natural gas, the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

In the first nine months of 2005, our net cash flow provided from operating activities was $187 million, a decrease of $68 million or 27% from the same period last year. The decrease was primarily a result of increased spending of $85 million for seasonal inventory injections in advance of the winter sales demand. We spent more on these injections in 2005 primarily because of higher natural gas prices and the addition of NUI’s inventory requirements. This decrease was offset by increased net income of $20 million and other working capital contributions.

Cash flow used in investing activities Our cash used in investing activities consists primarily of property, plant and equipment expenditures. For the nine months ended September 30, 2005, those expenditures were $194 million, an increase of $26 million or 15% from the same period last year.

The increase is primarily from higher expenditures at our distribution operations segment, including $32 million for the acquisition of a 250 mile pipeline in Georgia from SNG and approximately $16 million in expenditures at Elizabethtown Gas and Florida City Gas which were acquired in November 2004 as part of the NUI acquisition.

These increases were offset by reduced expenditures of $10 million at the Pivotal Propane plant in Virginia as most of the construction expenditures were incurred last year. In addition, there were reductions at Sequent of $6 million, primarily due to the completion of the ETRM system in 2004.

Cash flow used in financing activities Our financing activities primarily consist of borrowings and payments of short-term debt, payments of medium-term notes, borrowings of senior notes, distributions to minority interests, cash dividends on our common stock and issuances of common stock. Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of equity and debt securities. This strategy includes active management by us of the percentage of our total debt relative to our total capitalization, as well as the term and interest rate profile of our debt securities.

We also work to maintain or improve our credit ratings on our senior notes to effectively manage our existing financing costs and enhance our ability to raise additional capital on favorable terms. Factors considered important in assessing our credit ratings include our balance sheet leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger events in our debt instruments that are tied to changes in our credit ratings or our stock price and have not entered into any transaction that would require us to issue equity based on credit ratings or other trigger events. As of October - 2005, our senior unsecured debt ratings were:

·   BBB+ from Standard & Poor’s Rating Services (S&P)

·   Baa1 from Moody’s Investor Service (Moody’s) and

·   A- from Fitch Ratings.

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

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Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. Our most important default events include maintaining covenants with respect to a maximum leverage ratio of 70%, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions.

Our Credit Facility’s financial covenants and our PUHCA financing authority require us to maintain a ratio of total debt-to-total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. We are currently in compliance with all existing debt provisions and covenants.

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

In millions	Sept. 30, 2005				Dec. 31, 2004				Sept. 30, 2004
Short-term debt	$	344	10	%	$	334	10	%	$	51	2	%
Current portion of long-term debt		-	-			-	-			34	1
Long-term debt (1)		1,616	47			1,623	48			1,216	52
Total debt		1,960	57			1,957	58			1,301	55
Minority interest		31	1			36	1			30	1
Common equity		1,451	42			1,385	41			1,023	44
Total capitalization	$	3,442	100	%	$	3,378	100	%	$	2,354	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, the current portion of our capital lease obligation due within the next year and SouthStar’s line of credit. The increase in our short-term debt of $10 million from December 31, 2004 is primarily the result of higher working capital requirements from higher natural gas prices.

Refinancing of Gas Facility Revenue BondsIn the second quarter of 2005, we refinanced $67 million of our Gas Facility Revenue Bonds. For more information see “Note 8 - Financing.”

Dividends on Common StockIn February 2005, we announced a 7% increase in our common stock dividend, raising the quarterly dividend from $0.29 per share to $0.31 per share, which equates to an indicated annual dividend of $1.24 per share. The increase in our common stock dividend of $16 million for the nine months ended September 30, 2005 as compared to the same period last year was a result of our increased quarterly dividend and the increase in the number of shares outstanding as a result of our November 2004 equity offering.

Critical Accounting Policies and Estimates

The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates on an ongoing basis, and our actual results may differ from these estimates.

Our critical accounting policies used in the preparation of our consolidated financial statements are described in our 2004 Form 10-K and include the following:

·   Regulatory Accounting

·   Pipeline Replacement Program

·   Environmental Remediation Liabilities

·   Revenue Recognition

·   Purchase Price Allocation

·   Derivatives and Hedging Activities

·   Accounting for Contingencies

·   Allowance for Doubtful Accounts

·   Accounting for Pension Benefits

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Each of our critical accounting policies and estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. There have been no significant changes to our critical accounting policies from those disclosed in our 2004 Form 10-K.

Accounting Developments

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

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 in distribution operations and in wholesale services.

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

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, 2005, December 31, 2004 and September 30, 2004. We based the average values on monthly averages for the nine months ended September 30, 2005 and the twelve months ended December 31, 2004.

Natural gas contracts
	Average values
In millions	Nine months ended Sept. 30, 2005		Twelve months ended Dec. 31, 2004
Asset	$	71	$	28
Liability		83		21

	Value at:
In millions	Sept. 30, 2005		Dec. 31, 2004		Sept. 30, 2004
Asset	$	150	$	36	$	28
Liability		258		19		28

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

We use a 1-day and a 10-day holding period and a 95% confidence interval to evaluate our VaR exposure. A 95% confidence interval means there is a 5% probability that the actual change in portfolio value will be greater than the calculated VaR value over the holding period. We calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price volatility, confidence interval and holding period. Our VaR may not be comparable to a similarly titled measure of another company because, although VaR is a common metric in the energy industry, there is no established industry standard for calculating VaR or for the assumptions underlying such calculations.

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

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Our management actively monitors open commodity positions and the resulting VaR. We continue to maintain a relatively matched book, where our total buy volume is close to our sell volume, with minimal open commodity risk. Based on a 95% confidence interval and employing a 1-day and a 10-day holding period for all positions, our portfolio of positions for the three and nine months ended September 30, 2005 had the following 1-day and 10-day holding period VaRs:

	Three months ended September 30, 2005
In millions	1-day		10-day
Period end (1)	$	0.8	$	2.5
Average		0.7		2.2
High		1.1		3.5
Low (1)		0.5		1.1

	Nine months ended September 30, 2005
In millions	1-day		10-day
Period end (1)	$	0.8	$	2.5
Average		0.3		1.0
High		1.1		3.5
Low (1)		0.0		0.0

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

Sequent’s VaR amounts increased from the prior quarter due to additional market volatility resulting from hurricane activity in the Gulf Coast and significant increases in spot and forward natural gas prices. Sequent refined the methodology associated with its VaR calculation and applied the new methodology on a prospective basis during the third quarter of 2005. This refinement does not produce significantly different VaR amounts.

Retail Energy Operations SouthStar’s use of derivatives is governed by a risk management policy which prohibits the use of derivatives for speculative purposes. This policy also establishes VaR limits of $0.5 million on a 1-day holding period and $0.7 million on a 10-day holding period. A 95% confidence interval is used to evaluate VaR exposure. The maximum VaR experienced during the three months and nine months ended September 30, 2005 was less than $0.2 million for the 1-day holding period and $0.7 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. In addition to its collateral requirements and credit evaluation process, Sequent may, in certain instances, purchase credit insurance in order to mitigate its exposure to a counterparty that faces possible future business risks that are unknown or not quantifiable at the time of the initial credit evaluation.

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

The weighted average credit rating is obtained by multiplying each counterparty’s assigned internal rating by the counterparty’s credit exposure and then adding the individual results 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, 2005, which is consistent with our previously reported rating of A- at December 31, 2004 and slightly below our rating of A at September 30, 2004. For more information on Sequent’s counterparties credit ratings, see the discussion in “Results of Operations - Wholesale Services.” The following tables show Sequent’s commodity receivable and payable positions as of the dates indicated:

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In millions	Sept. 30, 2005		Dec. 31, 2004		Sept. 30, 2004
Gross receivables
Receivables with netting agreements in place:
Counterparty is investment grade	$	488	$	378	$	213
Counterparty is non-investment grade		69		36		18
Counterparty has no external rating		92		78		37
Receivables without netting agreements in place:
Counterparty is investment grade		20		16		6
Counterparty is non-investment grade		1		6		-
Counterparty has no external rating		-		-		-
Amount recorded on balance sheet	$	670	$	514	$	274

Gross payables
Payables with netting agreements in place:
Counterparty is investment grade	$	388	$	291	$	159
Counterparty is non-investment grade		57		45		37
Counterparty has no external rating		188		139		76
Payables without netting agreements in place:
Counterparty is investment grade		14		40		22
Counterparty is non-investment grade		-		6		2
Counterparty has no external rating		3		-		-
Amount recorded on balance sheet	$	650	$	521	$	296

Item 4. Controls and Procedures

(a)   Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of September 30, 2005, the end of the period covered by this report, except, and in accordance with the Public Company Accounting Oversight Board’s Auditing Standard No. 2, An Audit of Internal Control Over Financial Reporting Performed in Conjunction With an Audit of Financial Statements, the disclosure controls and procedures of Pivotal Jefferson Island and NUI were excluded from management’s evaluation, as Pivotal Jefferson Island and NUI were acquired on October 1, 2004 and November 30, 2004, respectively. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2005 in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

(b)  Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting identified in connection with the evaluation described in paragraph (a) above that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II -- OTHER INFORMATION

Item 1. Legal Proceedings

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The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities and litigation incidental to the business. For information regarding pending federal and state regulatory matters, see "Results of Operations - Distribution Operations" contained in Item 2 of Part I under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations." With regard to other legal proceedings, we are a party, as both plaintiff and defendant, to a number of other suits, claims and counterclaims on an ongoing basis. Management believes that the outcome of all such other litigation in which it is involved will not have a material adverse effect on our consolidated financial statements.

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

The following table presents information about our purchases of our common stock during the third quarter of 2005:

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased (1)		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 2005		136	$	37.70		N/A		N/A
August 2005		9,432	$	36.70		N/A		N/A
September 2005		32,996	$	37.16		N/A		N/A
Total third quarter		42,564	$	37.19

(1)The total number of shares purchased reflects an aggregate of 42,564 shares surrendered to us to satisfy tax withholding obligations in connection with the vesting of shares of restricted stock and/or the exercise of stock options.

Item 6. Exhibits

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

3.2.a Articles of Amendment to the Amended and Restated Articles of Incorporation of AGL Resources Inc. filed May 9, 2005 with the Secretary of State of the state of Georgia (incorporated herein by reference to Exhibit 3.2.a of AGL Resources Inc. Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).

3.2.b Form of Amended and Restated Articles of Incorporation filed January 5, 1996 with the Secretary of State of the state of Georgia, as amended by the Articles of Amendment to the Amended and Restated Articles of Incorporation filed May 9, 2005 with the Secretary of State of the state of Georgia.

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

31.1 Certification of Paula R. Reynolds pursuant to Rule 13a - 14(a)

31.2 Certification of Andrew W. Evans pursuant to Rule 13a - 14(a)

32.1 Certification of Paula R. Reynolds pursuant to 18 U.S.C. Section 1350

32.2 Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350

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SIGNATURE

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

	AGL RESOURCES INC.
	(Registrant)
Date: October 27, 2005	/s/ Andrew W. Evans
	Senior Vice President and Chief Financial Officer

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