SOUTHERN Co GAS (GAS) 8-K Other Events

EXHIBIT 99.2

TABLE OF CONTENTS

Exhibit 99.2

Item 8, "Financial Statements and Supplementary Data"

	Page(s)
Glossary of Key Terms	3
Referenced Accounting Standards	4
Consolidated Balance Sheets	5 - 6
Statements of Consolidated Income	7
Statements of Consolidated Common Shareholders' Equity	8
Statements of Consolidated Cash Flows	9
Note 1 - Accounting Policies and Methods of Application	10 - 14
Note 2 - Acquisitions	15
Note 3 - Recent Accounting Pronouncements	16 - 18
Note 4 - Risk Management	19 - 21
Note 5 - Regulatory Assets and Liabilities	22 - 25
Note 6 - Employee Benefit Plans	26 - 32
Note 7 - Stock-based Compensation Plans	33 - 36
Note 8 - Financing	37 - 39
Note 9 - Common Shareholders' Equity	40 - 41
Note 10 - Commitments and Contingencies	42 - 43
Note 11 - Fair Value of Financial Instruments	44
Note 12 - Income Taxes	44 - 46
Note 13 - Related Party Transactions	46
Note 14 - Segment Information	47 - 49
Note 15 - Quarterly Financial Information (Unaudited)	50
Management's Report on Internal Control Over Financial Reporting	51 & 53
Reports of Independent Auditors	52 & 54 - 56
Schedule II - Valuation and Qualifying Accounts	57

2

GLOSSARY OF KEY TERMS

Atlanta Gas Light	Atlanta Gas Light Company
AGL Capital	AGL Capital Corporation
AGL Networks	AGL Networks, LLC
Chattanooga Gas	Chattanooga Gas Company
Credit Facility	Credit agreement supporting our commercial paper program
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income, other income, equity in SouthStar’s income, donations and gain on sales of assets and excludes interest and tax expense; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, operating income or net income as determined in accordance with GAAP
Elizabethtown Gas	Elizabethtown Gas Company
ERC	Environmental response costs
FASB	Financial Accounting Standards Board
Florida Commission	Florida Public Service Commission
Florida Gas	Florida City Gas Company
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission
Heritage	Heritage Propane Partners, L.P.
LNG	Liquefied natural gas
Marketers	Georgia Public Service Commission-certificated marketers selling retail natural gas in Georgia
Medium-Term notes	Notes issued by Atlanta Gas Light with scheduled maturities between 2012 and 2027 bearing interest rates ranging from 6.6% to 9.1%
NJBPU	New Jersey Board of Public Utilities
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as revenues minus cost of gas, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain on the sale of our Caroline Street campus; these items are included in our calculation of operating income as reflected in our statements of consolidated income; operating margin should not be considered an alternative to, or more meaningful than, operating income or net income as determined in accordance with GAAP
PGA	Purchased gas adjustment
PRP	Pipeline replacement program
PUHCA	Public Utility Holding Company Act of 1935, as amended
Sequent	Sequent Energy Management, L.P.
SFAS	Statement of Financial Accounting Standards
SouthStar	SouthStar Energy Services LLC
US Propane	US Propane LP
Virginia Natural Gas	Virginia Natural Gas, Inc.
Virginia Commission	Virginia State Corporation Commission

3

REFERENCED ACCOUNTING STANDARDS

APB 25	Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”
EITF 98-10	Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”
EITF 99-02	Emerging Issues Task Force Issue No. 99-02, “Accounting for Weather Derivatives”
EITF 02-03	Emerging Issues Task Force Issue No. 02-03, “Issues Involved in Accounting for Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’”
FIN 46 & FIN 46R	FASB Interpretation No. 46, “Consolidation of Variable Interest Entities”
FSP 106-1	FASB Staff Position (FSP) No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”
SFAS 5	SFAS No. 5, “Accounting for Contingencies”
SFAS 13	SFAS No. 13, “Accounting for Leases”
SFAS 66	SFAS No. 66, “Accounting for Sales of Real Estate”
SFAS 71	SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 106	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions”
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 121	SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of”
SFAS 123 & SFAS 123R	SFAS No. 123, “Accounting for Stock-Based Compensation”
SFAS 132	SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits-an amendment of FASB Statements No. 87, 88 and 106”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141	SFAS No. 141, “Business Combinations”
SFAS 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS 144	SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS 148	SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure-an amendment of FASB Statement No. 123”
SFAS 149	SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”

4

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

AGL Resources Inc.

Consolidated Balance Sheets - Assets

	As of:
In millions	December 31, 2004			December 31, 2003
Current assets
Cash and cash equivalents	$	49		$	17
Receivables
Energy marketing		514			319
Gas		217			65
Other		21			12
Less allowance for uncollectible accounts		(15	)		(2	)
Total receivables		737			394
Income tax receivable		29			-
Unbilled revenues		152			40
Inventories
Natural gas stored underground		320			198
Other		12			12
Total inventories		332			210
Energy marketing and risk management assets		38			13
Unrecovered environmental remediation costs - current portion		27			24
Unrecovered pipeline replacement program costs - current portion		24			22
Unrecovered seasonal rates		11			11
Other current assets		58			11
Total current assets		1,457			742
Property, plant and equipment
Property, plant and equipment		4,615			3,390
Less accumulated depreciation		1,437			1,045
Property, plant and equipment-net		3,178			2,345
Deferred debits and other assets
Goodwill		354			184
Unrecovered pipeline replacement program costs		337			410
Unrecovered environmental remediation costs		173			155
Investments in equity interests		14			101
Unrecovered postretirement benefit costs		14			9
Other		113			26
Total deferred debits and other assets		1,005			885
Total assets	$	5,640		$	3,972

See Notes to Consolidated Financial Statements.

5

AGL Resources Inc.

Consolidated Balance Sheets - Liabilities and Capitalization

	As of:
In million, except share amounts	December 31, 2004		December 31, 2003
Current liabilities
Energy marketing trade payable	$	521	$	329
Short-term debt		334		306
Accounts payable-trade		207		74
Accrued pipeline replacement program costs - current portion		85		82
Customer deposits		50		19
Deferred purchased gas adjustment		37		30
Accrued interest		28		21
Accrued environmental remediation costs - current portion		27		40
Accrued wages and salaries		23		18
Energy marketing and risk management liabilities - current portion		15		17
Accrued taxes		14		15
Current portion of long-term debt		-		77
Other current liabilities		136		20
Total current liabilities		1,477		1,048
Accumulated deferred income taxes		437		376
Long-term liabilities
Accrued pipeline replacement program costs		242		323
Accrued postretirement benefit costs		58		51
Accumulated removal costs		94		102
Accrued environmental remediation costs		63		43
Accrued pension obligations		84		39
Accrued pipeline demand charges		38		-
Other long-term liabilities		30		11
Total long-term liabilities		609		569
Deferred credits
Unamortized investment tax credit		20		19
Regulatory tax liability		12		12
Other deferred credits		41		47
Total deferred credits		73		78
Commitments and contingencies (see Note 10)
Minority interest		36		-
Capitalization
Long-term debt		1,623		956
Common shareholders’ equity, $5 par value; 750,000,000 shares authorized (see accompanying statements of consolidated common shareholders’ equity)		1,385		945
Total capitalization		3,008		1,901
Total liabilities and capitalization	$	5,640	$	3,972

See Notes to Consolidated Financial Statements.

6

AGL Resources Inc.

Statements of Consolidated Income

	Years ended December 31,
In millions, except per share amounts	2004			2003			2002
Operating revenues	$	1,832		$	983		$	877
Operating expenses
Cost of gas		994			339			268
Operation and maintenance		377			283			274
Depreciation and amortization		99			91			89
Taxes other than income taxes		30			28			29
Total operating expenses		1,500			741			660
Gain on sale of Caroline Street campus		-			16			-
Operating income		332			258			217
Equity in earnings of SouthStar		-			46			27
Other (loss) income		-			(6	)		3
Minority interest		(18	)		-			-
Interest expense		(71	)		(75	)		(86	)
Earnings before income taxes		243			223			161
Income taxes		90			87			58
Income before cumulative effect of change in accounting principle		153			136			103
Cumulative effect of change in accounting principle, net of $5 in taxes		-			(8	)		-
Net income	$	153		$	128		$	103
Basic earnings per common share:
Income before cumulative effect of change in accounting principle	$	2.30		$	2.15		$	1.84
Cumulative effect of change in accounting principle		-			(0.12	)		-
Basic earnings per common share	$	2.30		$	2.03		$	1.84
Fully diluted earnings per common share:
Income before cumulative effect of change in accounting principle	$	2.28		$	2.13		$	1.82
Cumulative effect of change in accounting principle		-			(0.12	)		-
Fully diluted earnings per common share	$	2.28		$	2.01		$	1.82
Weighted average number of common shares outstanding:
Basic		66.3			63.1			56.1
Fully diluted		67.0			63.7			56.6

See Notes to Consolidated Financial Statements.

7

AGL Resources Inc.

Statements of Consolidated Common Shareholders’ Equity

										Other			Shares Held
	Common Stock				Premium on		Earnings			Comprehensive			in Treasury
In millions, except per share amounts	Shares		Amount		Common Stock		Reinvested			Income			and Trust			Total
Balance as of December 31, 2001		57.8	$	289	$	204	$	237			($1	)		($39	)	$	690
Comprehensive income:
Net income		-		-		-		103			-			-			103
Other comprehensive income (OCI) - loss resulting from unfunded pension obligation (net of tax benefit of $31)		-		-		-		-			(48	)		-			(48	)
Total comprehensive income																	55
Dividends on common stock ($1.08 per share)		-		-		-		(61	)		-			-			(61	)
Benefit, stock compensation, dividend reinvestment and stock purchase plans (net of tax benefit of $1)		-		-		6		-			-			20			26
Balance as of December 31, 2002		57.8		289		210		279			(49	)		(19	)		710
Comprehensive income:
Net income		-		-		-		128			-			-			128
OCI - Gain resulting from unfunded pension obligation (net of tax of $6)		-		-		-		-			8			-			8
Unrealized gain from equity investments hedging activities (net of tax )		-		-		-		-			1			-			1
Total comprehensive income																	137
Dividends on common stock ($1.11 per share)		-		-		-		(70	)		-			-			(70	)
Issuance of common shares:
Equity offering on February 14, 2003		6.7		32		105		-			-			-			137
Benefit, stock compensation, dividend reinvestment and stock purchase plans (net of tax benefit of $2)		-		1		11		-			-			19			31
Balance as of December 31, 2003		64.5		322		326		337			(40	)		-			945
Comprehensive income:
Net income		-		-		-		153			-			-			153
OCI - Loss resulting from unfunded pension obligation (net of tax benefit of $7)		-		-		-		-			(11	)		-			(11	)
Unrealized gain from hedging activities (net of tax of $2)		-		-		-		-			4			-			4
Other		-		-		-		-			1			-			1
Total comprehensive income																	147
Dividends on common stock ($1.15 per share)		-		-		-		(75	)		-			-			(75	)
Issuance of common shares:
Equity offering on November 24, 2004		11.0		55		277		-			-			-			332
Benefit, stock compensation, dividend reinvestment and stock purchase plans (net of tax benefit of $5)		1.2		7		29		-			-			-			36
Balance as of December 31, 2004		76.7	$	384	$	632	$	415			($46	)	$	-		$	1,385

See Notes to Consolidated Financial Statements.

8

AGL Resources Inc.

Statements of Consolidated Cash Flows

	Years ended December 31,
In millions	2004			2003			2002
Cash flows from operating activities
Net income	$	153		$	128		$	103
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		99			91			89
Deferred income taxes		81			55			82
Cumulative effect of change in accounting principle		-			13			-
Cash received from equity interests		-			40			-
Equity in earnings of unconsolidated subsidiaries		(2	)		(47	)		(27	)
Gain on sale of Caroline Street campus		-			(16	)		-
Change in risk management assets and liabilities		(27	)		(1	)		(3	)
Changes in certain assets and liabilities
Payables		247			61			244
ERC - net		(13	)		(6	)		(18	)
Inventories		(28	)		(91	)		42
Receivables		(264	)		(67	)		(269	)
Other - net		41			(38	)		43
Net cash flow provided by operating activities		287			122			286
Cash flows from investing activities
Acquisition of NUI, net of cash acquired		(116	)		-			-
Property, plant and equipment expenditures		(264	)		(158	)		(187	)
Acquisition of Jefferson Island		(90	)		-			-
Purchase of Dynegy’s 20% ownership interest in SouthStar		-			(20	)		-
Cash received from sale of Caroline Street campus		-			23			-
Sale of US Propane		31			-			-
Cash received from equity interests		-			2			27
Other		17			8			(1	)
Net cash flow used in investing activities		(422	)		(145	)		(161	)
Cash flows from financing activities
Issuances of Senior Notes		450			225			-
Equity offering		332			137			-
Sale of treasury shares		-			19			20
Sale of common stock		36			12			6
Dividends paid on common shares		(75	)		(70	)		(53	)
Net payments and borrowings of short-term debt		(480	)		(82	)		4
Distribution to minority interest		(14	)		-			-
Payments of Medium-Term notes		(82	)		(207	)		(93	)
Other		-			(3	)		(8	)
Net cash flow provided by (used in) financing activities		167			31			(124	)
Net increase in cash and cash equivalents		32			8			1
Cash and cash equivalents at beginning of period		17			9			8
Cash and cash equivalents at end of period	$	49		$	17		$	9
Cash paid during the period for
Interest (net of allowance for funds used during construction)	$	50		$	60		$	73
Income taxes		27			23			15

See Notes to Consolidated Financial Statements.

9

> 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 consolidated financial statements under the rules of the Securities and Exchange Commission (SEC).

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 regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. On April 1, 2004, we received approval from the SEC, under the Public Utility Holding Company Act of 1935 (PUHCA), for the renewal of our financing authority to issue securities through April 2007. For a glossary of key terms and referenced accounting standards, see pages 4-5.

Basis of Presentation

Our consolidated financial statements as of and for the periods ended December 31, 2004 include our accounts, the accounts of our majority-owned and controlled subsidiaries and the accounts of variable interest entities for which we are the primary beneficiary. This means that our accounts are combined with the subsidiaries’ accounts. Certain amounts from prior periods have been reclassified to conform to the current-period presentation. Any intercompany profits and transactions between segments have been eliminated in consolidation; however, intercompany profits are not eliminated when such amounts are probable of recovery under the affiliates’ rate regulation process. On November 30, 2004, we completed our acquisition of NUI Corporation (NUI); for more information see Note 2.

As of January 1, 2004, our consolidated financial statements include the accounts of SouthStar Energy Services LLC (SouthStar), a variable interest entity of which we are the primary beneficiary. Prior to January 1, 2004, we accounted for our 70% noncontrolling financial ownership interest in SouthStar using the equity method of accounting. Under the equity method, our ownership interest in SouthStar was reported as an investment within our consolidated balance sheets, and our share of SouthStar’s earnings was reported in our consolidated statements of income as a component of other income. We utilize the equity method to account for and report investments where we exercise significant influence but do not control and where we are not the primary beneficiary as defined by Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 was revised in December 2003 (FIN 46R); consequently, as of January 1, 2004, we consolidated all SouthStar’s accounts with our subsidiaries’ accounts and eliminated any intercompany balances between segments. For more discussion of FIN 46R and the impact of its adoption on our consolidated financial statements, see Note 3.

Our equity method investments generally include entities where we have a 20% to 50% voting interest. In 2004, our investments in equity interests was composed of our 50% ownership in Saltville Gas Storage Company, LLC, a joint venture with a subsidiary of Duke Energy Corporation to develop a high-deliverability natural gas storage facility in Saltville, Virginia.

Cash and Cash Equivalents

Our cash and cash equivalents consist primarily of cash on deposit, money market accounts and certificates of deposit with original maturities of three months or less.

10

Receivables and allowance for uncollectible accounts 

Our receivables consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers. Customers are billed monthly and accounts receivable are due within 30 days. For the majority of our receivables, we establish an allowance for doubtful accounts based on our collection experience. On certain other receivables where we are aware of a specific customer’s inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be different. Circumstances that could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Inventories

Our gas inventories are accounted for using the weighted average cost method. Materials and supplies inventories are stated at the lower of average cost or market. At December 31, 2004, Sequent’s natural gas inventory for reservoir and salt dome storage was recorded on an accrual basis. At December 31, 2004, Sequent’s inventory held under park and loan arrangements was recorded at the lower of average cost or market. However, for those park and loan arrangements that are payable or to be repaid at determinable dates to third parties, the inventory was recorded at fair value.

In Georgia’s competitive environment, Marketers—that is, marketers who are certificated by the Georgia Public Service Commission (Georgia Commission) to sell retail natural gas in Georgia— including the Atlanta Gas Light marketing affiliate SouthStar, began selling natural gas in 1998 to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation that provides for this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. Atlanta Gas Light assigns, on a monthly basis, the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory.

Property, Plant and Equipment

Distribution Operations Property, plant and equipment expenditures consist of property and equipment that is in use, being held for future use and under construction. It is reported at its original cost, which includes

·   material and labor

·   contractor costs

·   construction overhead costs

·   an allowance for funds used during construction

Property retired or otherwise disposed of is charged to accumulated depreciation.

Retail Energy Operations, Wholesale Services, Energy Investments and Corporate Property, plant and equipment expenditures include property that is in use and under construction, and is reported at cost. A gain or loss is recorded for retired or otherwise disposed of property.

Goodwill

We adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142), effective October 1, 2001. Under SFAS 142, goodwill is no longer amortized. SFAS 142 further requires an initial goodwill impairment assessment in the year of adoption and annual impairment tests thereafter. We have included $354 million of goodwill in our consolidated balance sheets, of which $157 million is related to our acquisition of NUI in November 2004 (see Note 2 for further details), $176 million is related to our acquisition of Virginia Natural Gas, Inc. (Virginia Natural Gas) in 2000, $14 million is related to our acquisition of Jefferson IslandStorage & Hub, LLC in October 2004 and $7 million is related to our acquisition of Chattanooga Natural Gas Company in 1988.

We annually assess goodwill for impairment as of our fiscal year end and have not recognized any impairment charges for the years ended December 31, 2004, 2003 and 2002. We also assess goodwill for impairment if events or changes in circumstances may indicate an impairment of goodwill exists. We conduct this assessment principally through a review of financial results, changes in state and federal legislation and regulation, and the periodic regulatory filings for our regulated utilities.

11

Accumulated Deferred Income Taxes

The reporting of our assets and liabilities for financial accounting purposes differs from the reporting for income tax purposes. The principal differences between net income and taxable income relate to the timing of deductions, primarily due to the benefits of tax depreciation since assets are generally depreciated for tax purposes over a shorter period of time than for book purposes. The tax effects of depreciation and other differences in those items are reported as deferred income tax assets or liabilities in our consolidated balance sheets. Investment tax credits of approximately $20 million previously deducted for income tax purposes for Atlanta Gas Light, Chattanooga Gas and Elizabethtown Gas, and have been deferred for financial accounting purposes and are being amortized as credits to income over the estimated lives of the related properties in accordance with regulatory requirements.

Revenues

Distribution Operations Revenues are recorded when services are provided to customers. Those revenues are based on rates approved by the regulatory state commissions of our utilities.

As required by the Georgia Commission, in July 1998, Atlanta Gas Light began billing Marketers for each residential, commercial and industrial customer’s distribution costs in equal monthly installments. As required by the Georgia Commission, effective February 1, 2001, Atlanta Gas Light implemented a seasonal rate design for the calculation of each residential customer’s annual straight-fixed-variable (SFV) capacity charge, which is billed to Marketers and reflects the historic volumetric usage pattern for the entire residential class. Generally, this change results in residential customers being billed by Marketers for a higher capacity charge in the winter months and a lower charge in the summer months. This requirement has an operating cash flow impact but does not change revenue recognition. As a result, Atlanta Gas Light continues to recognize its residential SFV capacity revenues for financial reporting purposes in equal monthly installments.

Any difference between the billings under the seasonal rate design and the SFV revenue recognized is deferred and reconciled to actual billings on an annual basis. Atlanta Gas Light had unrecovered seasonal rates of approximately $11 million as of December 31, 2004 and 2003 (included as current assets in the consolidated balance sheets), related to the difference between the billings under the seasonal rate design and the SFV revenue recognized.

The Virginia Natural Gas and Chattanooga Gas rate structures include volumetric rate designs that allow recovery of costs through gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Virginia Natural Gas and Chattanooga Gas recognize sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. In addition, revenues are recorded for estimated deliveries of gas, not yet billed to these customers, from the meter reading date to the end of the accounting period. These are included in the consolidated balance sheets as unbilled revenue. For other commercial and industrial customers and all wholesale customers, revenues are based upon actual deliveries to the end of the period.

The tariffs for Elizabethtown Gas, Virginia Natural Gas and Chattanooga Gas contain weather normalization adjustments (WNA) that largely mitigate the impact of unusually cold or warm weather on customer billings and operating margin. The WNA’s purpose is to reduce the effect of weather on customer bills by reducing bills when winter weather is colder than normal and increasing bills when weather is warmer than normal.

Wholesale Services Wholesale services’ revenues are recorded when services are provided to customers. Intercompany profits from sales between segments are eliminated in the corporate segment and are recognized as goods or services sold to end-use customers. Transactions that qualify as derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), are recorded at fair value with changes in fair value recorded as revenues in our statements of income.

Cost of Gas

We charge our utility customers for the natural gas they consume using purchased gas adjustment (PGA) mechanisms set by the state regulatory agencies. Under the PGA, we defer (that is, include as a current asset or liability in the consolidated balance sheets and exclude from the statements of consolidated income) the difference between the actual cost of gas and what is collected from customers in a given period. The deferred amount is either billed or refunded to our customers.

12

Stock-based Compensation

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

In millions, except per share amounts	2004			2003			2002
Net income, as reported	$	153		$	128		$	103
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effect		(1	)		(1	)		(2	)
Pro forma net income	$	152		$	127		$	101
Earnings per share:
Basic-as reported	$	2.30		$	2.03		$	1.84
Basic-pro forma	$	2.28		$	2.02		$	1.80
Fully diluted-as reported	$	2.28		$	2.01		$	1.82
Fully diluted-pro forma	$	2.26		$	2.00		$	1.79

Depreciation Expense

Depreciation expense for distribution operations is computed by applying composite, straight-line rates (approved by the state regulatory agencies) to the investment of depreciable property. Excluding the utilities acquired from NUI, distribution operations’ composite straight-line depreciation rate for depreciable property excluding transportation equipment was approximately 2.6% during 2004, 2.7% during 2003 and 2.8% during 2002. The composite, straight-line rate for the utilities acquired from NUI was 3.25%. As of May 1, 2002, the Georgia Commission required a decrease of depreciation rates for Atlanta Gas Light, which decreased depreciation expense by $6 million in 2002 and approximately $10 million annually on a going forward basis. We depreciate transportation equipment on a straight-line basis over a period of 5 to 10 years. We compute depreciation expense for other segments on a straight-line basis over a period of 1 to 35 years.

Allowance for Funds Used During Construction (AFUDC)

The applicable state regulatory agencies authorize Atlanta Gas Light, Elizabethtown Gas and Chattanooga Gas to record the cost of debt and equity funds as part of the cost of construction projects in our consolidated balance sheets and as AFUDC in the statements of consolidated income. The Georgia Commission has authorized a rate of 9.16%, the New Jersey Board of Public Utilities (NJBPU) has authorized a rate of 7.60% and the Tennessee Regulatory Authority (Tennessee Authority) has authorized a rate of 9.08%. The capital expenditures of our other regulated utilities do not qualify for AFUDC treatment.

13

Comprehensive Income

Our comprehensive income includes net income plus other comprehensive income (OCI), which includes other gains and losses affecting shareholders’ equity that accounting principles generally accepted in the United States (GAAP) exclude from net income. Such items consist primarily of unrealized gains and losses on certain derivatives and minimum pension liability adjustments.

In 2004, our OCI decreased $6 million as a result of an $11 million increase in our unfunded pension obligation, net of a $7 million income tax benefit, which was offset by changes in the fair value of derivatives designated as cash flow hedges at SouthStar of $4 million. For more information on SouthStar’s derivative financial instruments, see Note 4.

In 2003, our OCI increased $9 million as a result of an $8 million decrease in our unfunded pension obligation and $1 million for our 70% ownership interest in SouthStar’s unrealized gain associated with its cash flow hedges. In 2002, our OCI decreased by $48 million, net of income tax benefit of $31 million, as a result of a increase in our unfunded pension obligation.

Earnings per Common Share

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

We derive our potentially dilutive common shares by calculating the number of shares issuable under performance units and stock options. The future issuance of shares underlying the performance units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. No items are antidilutive. The following table shows the calculation of our fully diluted earnings per share for the periods presented if performance units currently earned under the plan ultimately vest and if stock options currently exercisable at prices below the average market prices are exercised:

In millions	2004		2003		2002
Denominator for basic earnings per share (1)		66.3		63.1		56.1
Assumed exercise of potential common shares		0.7		0.6		0.5
Denominator for fully diluted earnings per share		67.0		63.7		56.6

(1)   Daily weighted average shares outstanding.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include our regulatory accounting, the allowance for doubtful accounts, allowance for contingencies, pipeline replacement program accruals, environmental liability accruals, unbilled revenue recognition, pension obligations, derivative and hedging activities and purchase price allocations. Actual results could differ from those estimates.

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> Note 2

Acquisitions

NUI Corporation

On November 30, 2004, we acquired all the outstanding shares of NUI for approximately $218 million, incurred $7 million of transaction costs and repaid $500 million of NUI's outstanding short-term debt. At closing, NUI had $709 million in debt and approximately $109 million of cash on its balance sheet (including the return of an interest escrow balance), bringing the net value of the acquisition to approximately $825 million. In connection with the acquisition, we incurred $23 million in employee-related restructuring charges, which include $16 million in severance costs, $4 million in change in control payments to certain NUI executives and the NUI Board of Directors, and $3 million of employee retention and relocation costs. The acquisition significantly expands our existing natural gas utilities, storage and pipeline businesses.

We funded the purchase price with a portion of the proceeds from our November 2004 common stock offering and proceeds from short-term borrowings under our commercial paper program. Additionally, NUI Utilities, Inc., a wholly owned subsidiary of NUI, had outstanding, at closing, $199 million of indebtedness pursuant to Gas Facility Revenue Bonds and $10 million in capital leases.

Our allocation of the purchase price is preliminary and is subject to change. The preliminary nature is a result of the timing of the acquisition, which occurred late in our fourth quarter. The amount currently allocated to property, plant and equipment represents our estimate of the fair value of the assets acquired. We based that estimate on a preliminary independent valuation counselor’s report, which is expected to be finalized during the first quarter of 2005. The following table summarizes the fair values of the assets acquired and liabilities assumed on November 30, 2004:

In millions	Preliminary Fair Value
Purchase price	$	825
Current assets		299
Property, plant and equipment		612
Other long term assets		117
Goodwill		157
Current liabilities excluding debt		(108	)
Short-term debt and capital leases		(502	)
Long-term debt and capital leases		(207	)
Other long-term liabilities		(143	)
Equity		225

The excess of the purchase price over the fair value of the identifiable net assets acquired of $157 million was allocated to goodwill. We believe the acquisition resulted in the recognition of goodwill primarily because of the strength of NUI’s underlying assets and the synergies and opportunities in the regulated utilities. Goodwill is not deductible for income tax purposes.

The table below reflects the unaudited pro forma results of AGL Resources and NUI for the years ended December 31, 2004 and 2003 as if the acquisition and related financing had taken place on January 1. The pro-forma results are not necessarily indicative of the results that would have occurred if the acquisition had been in effect for the periods presented.  In addition, the pro-forma results are not intended to be a projection of future results and do not reflect any synergies that might be achieved from combining the operations or eliminating significant expenses that NUI incurred in its last year of operations. Our results of operations for 2004 include one month of the acquired operations of NUI.

In millions, except per share amounts	2004		2003
Operating revenue	$	2,343	$	1,630
Income before cumulative effect of change in accounting principle		105		88
Net income		105		74
Net income per fully diluted share		1.44		1.05

Jefferson Island Storage & Hub, LLC (Jefferson Island)

We acquired Jefferson Island from American Electric Power in October 2004 for $90 million, which included approximately $9 million of working gas inventory. We funded the acquisition with a portion of the net proceeds we received from our November 2004 common stock offering and borrowings.

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> Note 3

Recent Accounting Pronouncements

Adopted in 2004

FIN 46

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

In December 2003, the FASB revised FIN 46, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance. For potential variable interest entities other than any special purpose entities, the FASB required FIN 46R to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004. FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities. We adopted FIN 46R effective January 1, 2004, resulting in the consolidation of SouthStar’s accounts in our consolidated financial statements and the deconsolidation of the accounts related to our Trust Preferred Securities. FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities.

Notes Payable to Trusts and Trust Preferred SecuritiesIn June 1997 and March 2001, we established AGL Capital Trust I and AGL Capital Trust II (Trusts) to issue our Trust Preferred Securities. The Trusts are considered to be special purpose entities under FIN 46 and FIN 46R since

·   our equity in the Trusts is not considered to be sufficient to allow the Trusts to finance their own activities

·   our equity investment is not considered to be at risk since the equity amounts were financed by the Trusts

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

The revisions in FIN 46R included specific guidance that instruments such as the call options included in our loan agreements with the Trusts do not constitute variable interests and should not be considered in the determination of the primary beneficiary. As a result, as of January 1, 2004 (when we adopted FIN 46R), we were required to exclude the accounts of the Trusts from our consolidated financial statements and to classify amounts payable to the Trusts as “Notes payable to Trusts” within long-term debt in our consolidated balance sheets as of December 31, 2004.

Due to deconsolidation of the Trusts, we included in our consolidated balance sheets at December 31, 2004, an asset of approximately $10 million representing our investment in the Trusts and a note payable to the Trusts totaling approximately $235 million, net of an interest rate swap of $3 million. We also removed $222 million related to the Trust Preferred Securities issued by the Trusts. The notes payable represent the loan payable to fund our investments in the Trusts of $10 million and the amounts due to the Trusts from the proceeds received from their issuances of Trust Preferred Securities of $222 million.

Consolidation of SouthStarIn 1998 a joint venture, SouthStar, was formed by our wholly owned subsidiary, Georgia Natural Gas Company, Piedmont Natural Gas Company, Inc. (Piedmont) and Dynegy Inc. (Dynegy) to market natural gas and related services to retail customers, principally in Georgia. SouthStar, which operates under the trade name Georgia Natural Gas, competes with other energy marketers, including Marketers in Georgia, to provide natural gas and related services to customers in Georgia and the Southeast. In March 2003, we purchased Dynegy’s 20% ownership interest in a transaction that for accounting purposes had an effective date of February 18, 2003. We currently own a noncontrolling 70% financial interest in SouthStar and Piedmont owns the remaining 30%. Our 70% interest is noncontrolling because all significant management decisions require approval by both owners.

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In March 2004, we executed an amended and restated partnership agreement with Piedmont that calls for SouthStar’s earnings starting in 2004 to be allocated 75% to our subsidiary and 25% to Piedmont. Consequently, as of January 1, 2004 we consolidated all SouthStar’s accounts with our subsidiaries’ accounts and eliminated any intercompany balances between segments. We recorded Piedmont’s portion of SouthStar’s earnings as a minority interest in our consolidated statements of income, and we recorded Piedmont’s portion of SouthStar’s capital as a minority interest in our consolidated balance sheet. For all periods prior to February 18, 2003, SouthStar’s earnings were allocated based on our 50% ownership interests in those periods. We determined that SouthStar is a variable interest entity as defined in FIN 46R because

·   Our equal voting rights with Piedmont are not proportional to our economic obligation to absorb 75% of any losses or residual returns from SouthStar.

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

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

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

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

However, as SouthStar’s results of operations and financial condition were material in 2002 and 2003 to our financial results, we present below the summarized amounts for 100% of SouthStar. These results are not comparable with our earnings or losses from SouthStar in those prior periods, which we reported as other income (loss) in our statements of consolidated income, as those amounts were reported based on our ownership percentage.

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In millions	Dec. 31, 2003
Balance Sheet
Current assets	$	174
Noncurrent assets		2
Current liabilities		75
Noncurrent liabilities		-
In millions		2003		2002
Income Statement
Revenues	$	746	$	630
Operating margin		124		115
Operating income		63		41
Net income from continuing operations		63		42

Issued but Not Yet Adopted in 2004

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 supercedes APB 25, and its related implementation guidance. SFAS 123R focuses primarily on the accounting for share-based payments to employees in exchange for services, and it requires a public entity to measure and recognize compensation cost for these payments. Our share-based payments are typically in the form of stock option and restricted stock awards. The primary change in accounting is related to the requirement to recognize compensation cost for stock option awards that was not recognized under APB 25.

Compensation cost will be measured based on the fair value of the equity or liability instruments issued.  For stock option awards, fair value would be estimated using an option pricing model such as the Black-Scholes model. SFAS 123R becomes effective as of the first interim or annual reporting period that begins after June 15, 2005, and therefore we will adopt SFAS 123R in the third quarter of 2005. We expect to recognize approximately $1 million of compensation cost during the last six months of 2005 related to our stock option awards. For a discussion of our stock-based compensation plans and agreements, see Note 7.

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> Note 4

Risk Management

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

·   forward contracts

·   futures contracts

·   options contracts

·   financial swaps

·   storage and transportation capacity transactions

Interest Rate Swaps

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

Accordingly, we adjust the carrying value of each interest rate swap to its fair value at the end of each period, with an offsetting and equal adjustment to the carrying value of the debt securities whose fair value is being hedged. Consequently, our earnings are not affected negatively or positively with changes in fair value of the interest swaps each quarter.

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

As of December 31, 2004, a notional principal amount of $175 million of these agreements effectively converted the interest expense associated with a portion of our senior notes and notes payable to the Trusts from fixed rates to variable rates based on an interest rate equal to the London Interbank Offered Rate (LIBOR), plus a spread determined at the swap date. The fair value of these interest rate swaps was recorded as an asset of $1 million at December 31, 2004 and a liability of $4 million at December 31, 2003. For more information on the effective rates and maturity dates of our interest rate swaps, see Note 8.

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

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Commodity-related derivative instruments

Elizabethtown Gas Certain derivatives are utilized by Elizabethtown Gas for nontrading purposes to hedge the impact of market fluctuations on assets, liabilities and other contractual commitments.  Pursuant to SFAS 133, such derivative products are marked-to-market each reporting period.  Pursuant to regulatory requirements, realized gains and losses related to such derivatives are reflected in purchased gas costs and included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset (loss) or liability (gain), as appropriate, on the consolidated balance sheet.  As of December 31, 2004, Elizabethtown Gas had entered into New York Mercantile Exchange (NYMEX) futures contracts to purchase 9.7 billion cubic feet (Bcf) of natural gas at equivalent prices ranging from $3.609 to $8.291 per thousand cubic feet.  Approximately 84% of these contracts have a duration of one-year or less, and none of these contracts extend beyond October 2006.

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

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

At December 31, 2004, our commodity-related derivative financial instruments represented purchases (long) of 521 Bcf and sales (short) of 550 Bcf with approximately 93% of these scheduled to mature in less than two years and the remaining 7% in three to nine years. Excluding the cumulative effect of a change in accounting principle in 2003, our unrealized gains were $22 million in 2004, $1 million in 2003 and $4 million in 2002.

SouthStarThe commodity-related derivative financial instruments (futures, options and swaps) used by SouthStar manage exposures arising from changing commodity prices. SouthStar’s objective for holding these derivatives is to utilize the most effective methods to reduce or eliminate the impacts of changing commodity prices. A significant portion of SouthStar’s derivative transactions are designated as cash flow hedges under SFAS 133. Derivative gains or losses arising from cash flow hedges are recorded in OCI and are reclassified into earnings in the same period as the settlement of the underlying hedged item. Any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not perfectly offset the losses or gains on the hedged item, is recorded in our cost of gas on our consolidated income statement in the period in which it occurs. SouthStar currently has only minimal hedge ineffectiveness.

SouthStar’s remaining derivative instruments do not meet the hedge criteria under SFAS 133; therefore, changes in the fair value of these derivatives are recorded in earnings in the period of change. At December 31, 2004, the fair values of these derivatives were reflected in our consolidated financial statements as an asset of $9 million and a liability of $2 million. The maximum maturity of open positions is less than one year and represents purchases and sales of 8 Bcf.

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Concentration of Credit Risk

Atlanta Gas LightConcentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 10 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the nonpeak summer months and highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. These retail functions include customer service, billing, collections, and the purchase and sale of natural gas. Atlanta Gas Light’s tariff allows it to obtain security support in an amount equal to a minimum of two times a Marketer’s highest monthly invoice.

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

The weighted average credit rating is obtained by multiplying each counterparty’s assigned internal rating by the counterparty’s credit exposure and the individual results are then summed for all counterparties. That total is divided by the aggregate total counterparties’ exposure. This numeric value is converted to an S&P equivalent. At December 31, 2004, Sequent’s top 20 counterparties represented approximately 57% of the total counterparty exposure of $328 million, derived by adding the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures. Sequent’s counterparties or the counterparties’ guarantors had a weighted average Standard & Poor’s Rating Services equivalent of an A- rating at December 31, 2004.

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

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> Note 5

Regulatory Assets and Liabilities

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

In millions	Dec. 31, 2004		Dec.31, 2003
Regulatory assets
Unrecovered PRP costs	$	361	$	432
Unrecovered environmental remediation costs		200		179
Unrecovered postretirement benefit costs		14		9
Unrecovered seasonal rates		11		11
Unrecovered PGA		5		-
Regulatory tax asset		2		3
Other		20		5
Total regulatory assets	$	613	$	639
Regulatory liabilities
Accumulated removal costs	$	94	$	102
Unamortized investment tax credit		20		19
Deferred PGA		37		30
Regulatory tax liability		14		15
Other		18		3
Total regulatory liabilities		183		169
Associated liabilities
PRP costs		327		405
Environmental remediation costs		90		83
Total associated liabilities		417		488
Total regulatory and associated liabilities	$	600	$	657

Our regulatory assets are recoverable through either rate riders or base rates specifically authorized by a state regulatory commission. Base rates are designed to provide both a recovery of cost and a return on investment during the period rates are in effect. As such, all our regulatory assets are subject to review by the respective state regulatory commission during any future rate proceedings. In the event that the provisions of SFAS 71 were no longer applicable, we would recognize a write-off of net regulatory assets (regulatory assets less regulatory liabilities) that would result in a charge to net income, which would be classified as an extraordinary item. However, although the gas distribution industry is becoming increasingly competitive, our utility operations continue to recover their costs through cost-based rates established by the state regulatory commissions. As a result, we believe that the accounting prescribed under SFAS 71 remains appropriate. It is also our opinion that all regulatory assets are recoverable in future rate proceedings, and therefore, we have not recorded any regulatory assets that are recoverable but are not yet included in base rates or contemplated in a rate rider.

All the regulatory assets included in the table above are included in base rates except for the unrecovered PRP costs, unrecovered environmental remediation costs and deferred PGA, which are recovered through specific rate riders. The rate riders that authorize recovery of unrecovered PRP costs and the deferred PGA include both a recovery of costs and a return on investment during the recovery period. We have two rate riders that authorize the recovery of unrecovered environmental remediation costs. The environmental remediation cost rate rider for Atlanta Gas Light only allows for recovery of the costs incurred and the recovery period occurs over the five years after the expense is incurred. Environmental remediation costs associated with the investigation and remediation of Elizabethtown Gas’ remediation sites located in the state of New Jersey are recovered under a Remediation Adjustment Clause and include the carrying cost on unrecovered amounts not currently in rates.

The regulatory liabilities are refunded to ratepayers through a rate rider or base rates. If the regulatory liability is included in base rates, the amount is reflected as a reduction to the rate base in setting rates.

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Pipeline Replacement Program

The PRP, ordered by the Georgia Commission to be administered by Atlanta Gas Light, requires, among other things, that it replace all bare steel and cast iron pipe in its system in the state of Georgia within a 10-year period, beginning October 1, 1998. Atlanta Gas Light identified, and provided notice to the Georgia Commission, of 2,312 miles of pipe to be replaced. Atlanta Gas Light has subsequently identified an additional 188 miles of pipe subject to replacement under this program. If Atlanta Gas Light does not perform in accordance with this order, it will be assessed certain nonperformance penalties. October 1, 2004 marked the beginning of the seventh year of the 10-year PRP.

The order also provides for recovery of all prudent costs incurred in the performance of the program, which Atlanta Gas Light has recorded as a regulatory asset. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the program net of any cost savings from the program. All such amounts will be recovered through a combination of SFV rates and a pipeline replacement revenue rider. The regulatory asset has two components:

·   the costs incurred to date that have not yet been recovered through the rate rider

·   the future expected costs to be recovered through the rate rider

Atlanta Gas Light has recorded a long-term regulatory asset of $337 million, which represents the expected future collection of both expenditures already incurred and expected future capital expenditures to be incurred through the remainder of the program. Atlanta Gas Light has also recorded a current asset of $24 million, which represents the expected amount to be collected from customers over the next 12 months. The amounts recovered from the pipeline replacement revenue rider during the last three years were

·   $28 million in 2004

·   $15 million in 2003

·   $8 million in 2002

As of December 31, 2004, Atlanta Gas Light had recorded a current liability of $85 million, representing expected program expenditures for the next 12 months. Atlanta Gas Light anticipates that its capital expenditures for the PRP will end by June 30, 2008, unless we agree with the Georgia Commission to an extension of the program.

Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the PRP over the life of the assets. Operation and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operation and maintenance costs in excess of those included in its current base rates, depreciation expense and an allowed rate of return on capital expenditures. In the near term, the primary financial impact to Atlanta Gas Light from the PRP is reduced cash flow from operating and investing activities, as the timing related to cost recovery does not match the timing of when costs are incurred. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under-recovered balance resulting from the timing difference.

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Environmental Remediation Costs

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

Atlanta Gas LightThe presence of coal tar and certain other by-products of a natural gas manufacturing process used to produce natural gas prior to the 1950s have been identified at or near 13 former operating sites in Georgia and Florida. Atlanta Gas Light has active environmental remediation or monitoring programs in effect at 10 sites. Two of three sites in Florida and one Georgia site are currently in the preliminary investigation or engineering design phase. The required soil remediation at our Georgia sites is scheduled to be completed by June 2005. As of December 31, 2004, Atlanta Gas Light’s remediation program was approximately 78% complete.

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

Our current engineering estimate projects costs associated with Atlanta Gas Light’s engineering estimates and in-place contracts to be $36 million. This is a reduction of $30 million from last year’s estimate of projected engineering and in-place contracts, resulted from $50 million of program expenditures incurred in the year ended September 30, 2004. During the same 12-month period Atlanta Gas Light realized increases in its future cost estimates totaling $20 million related to

·   an increase in the contract value at its Augusta, Georgia site for treatment of two areas and additional deep excavation of contaminants

·   the addition of harbor sediment removal at its St. Augustine, Florida site

·   an increase at its Savannah, Georgia site for phase 2 excavation and a partially offsetting decrease in engineering and oversight costs

·   an increase in the program management costs due to legal matters, environmental regulatory activities and oversight costs for the extension of work at the Savannah and Augusta sites

The engineering estimate was $66 million in 2003, which was a reduction of $43 million from the 2002 estimate. The decrease was a result of $37 million of program expenditures incurred in the year ended September 30, 2003 and a $6 million reduction in future cost estimates. For those remaining elements of Atlanta Gas Light’s environmental remediation program where it is unable to perform engineering cost estimates at the current state of investigation, considerable variability remains in the estimates for future remediation costs. For these elements, the estimate for the remaining cost of future actions at these former operating sites is $14 million. Atlanta Gas Light estimates certain other costs related to administering the remediation program and remediation of sites currently in the investigation phase. Through January 2006, Atlanta Gas Light estimates the administrative costs to be $2 million.

For those sites currently in the investigation phase, Atlanta Gas Light’s estimate for remediation is $9 million. This estimate is based on preliminary data received during 2004 with respect to the existence of contamination at those sites. Atlanta Gas Light’s range of estimates for these sites is $4 million to $15 million. Atlanta Gas Light has accrued $9 million as this is its best estimate at this phase of the remediation process.

The liability does not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, unbudgeted legal expenses, or other costs for which Atlanta Gas Light may be held liable but with respect to which it cannot reasonably estimate the amount. The liability also does not include certain potential cost savings as described above. As of December 31, 2004, the remediation expenditures expected to be incurred over the next 12 months are reflected as a current liability of $27 million. Atlanta Gas Light’s environmental remediation cost liability is composed of the following elements:

In millions	Dec. 31, 2004			Dec. 31, 2003			2004 vs. 2003
Projected engineering estimates and in-place contracts (1)	$	36		$	67			($31	)
Estimated future remediation costs (1)		14			15			(1	)
Administrative expenses (2)		2			3			(1	)
Other expenses (2)		9			9			-
Cash payments for cleanup expenditures (3)		(5	)		(11	)		6
Environmental remediation cost liability	$	56		$	83			($27	)

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

(2) For the respective calendar years.

(3) Expenditures during the three months ended December 31, 2004 and December 31, 2003.

24

The environmental remediation cost liability is included in a corresponding regulatory asset, which is a combination of accrued environmental remediation costs 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 environmental remediation cost recovery rider. It allows recovery of the costs of investigation, testing, cleanup and litigation. Because of that rider, these actual and projected future costs related to investigation and cleanup to be recovered from customers in future years are included in our regulatory assets. The environmental remediation cost 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 $27 million in revenues over the next 12 months under the environmental remediation cost recovery rider, which is reflected as a current asset. The amounts recovered from the recovery rider during the last three years were

·   $25 million in 2004

·   $23 million in 2003

·   $17 million in 2002

The second way to recover costs is by exercising the legal rights Atlanta Gas Light believes it has to recover a share of its costs from other potentially responsible parties, typically former owners or operators of these sites. There were no material recoveries from potentially responsible parties during 2004, 2003 or 2002.

The third way to recover costs is from the receipt of net profits from the sale of remediated property. In June 2004, a residential and retail development located in Savannah, Georgia and adjacent to a former remediation site was sold, resulting in a gain of $6 million. All gains on sales of remediated property are required to be shared 70% with ratepayers through a reduction to the regulatory asset. Consequently, the unrecovered environmental remediation costs were reduced by approximately $4 million.

Elizabethtown Gas In New Jersey, Elizabethtown Gas is currently conducting remedial activities with oversight from the New Jersey Department of Environmental Protection. Although the actual total cost of future environmental investigation and remediation efforts cannot be estimated with precision, the range of reasonably probable costs is from $30 million to $116 million. As of December 31, 2004, we recorded a liability of $30 million, as this is the best estimate at this phase of the remediation process.

Elizabethtown Gas’ prudently incurred remediation costs for the New Jersey properties have been authorized by the NJBPU to be recoverable in rates through its Remediation Adjustment Clause. As a result, Elizabethtown Gas has recorded a regulatory asset of approximately $34 million, inclusive of interest, as of December 31, 2004, reflecting the future recovery of both incurred costs and future remediation liabilities in the state of New Jersey. Elizabethtown Gas has also been successful in recovering a portion of remediation costs incurred in New Jersey from its insurance carriers and continues to pursue additional recovery. As of December 31, 2004, the variation between the amounts of the environmental remediation cost liability recorded on the consolidated balance sheet and the associated regulatory asset result from expenditures for environmental investigation and remediation exceeding recoveries from ratepayers and insurance carriers.

Other We also own a former NUI remediation site in Elizabeth City, North Carolina, which is subject to an order by the North Carolina Department of Energy and Natural Resources. We do not have precise estimates for the cost of investigating and remediating this site, although preliminary estimates for these costs range from $4 million to $16 million. As of December 31, 2004, we have recorded a liability of $4 million related to this site. There is another site in North Carolina where investigation and remediation is probable, although no regulatory order exists and we do not believe costs associated with this site can be reasonably estimated. In addition, there are as many as six other sites with which NUI had some association, although no basis for liability has been asserted. We do not believe that costs to investigate and remediate these sites, if any, can be reasonably estimated at this time.

With respect to these costs we are currently pursuing or intend to pursue recovery from ratepayers, former owners and operators and insurance carriers. Although we have been successful in recovering a portion of these remediation costs from our insurance carriers, we are not able to express a belief as to the success of additional recovery efforts. We are working with the regulatory agencies to prudently manage our remediation costs so as to mitigate the impact of such costs on both ratepayers and shareholders.

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> Note 6

Employee Benefit Plans

Pension Benefits

We sponsor two defined benefit retirement plans (Retirement Plan) for our eligible employees, the AGL Resources Inc. Retirement Plan (AGL Retirement Plan) and NUI Corporation Retirement Plan (NUI Retirement Plan). A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant.

We generally calculate the benefits under the AGL Retirement Plan based on age, years of service and pay. The benefit formula for the Retirement Plan is a career average earnings formula for participants other than those participants who were employees as of July 1, 2000, and who were at least 50 years of age as of that date. We utilize a final average earnings benefit formula for participants who were both employees and over age 50 as of July 1, 2000, and will continue to utilize the final average earnings benefit formula for such participants until June 2010, at which time we will convert those Retirement Plan participants to a career average earnings formula.

NUI has a qualified noncontributing defined benefit retirement plan that covers substantially all of its employees, other than Florida City Gas Company union employees, who participate in a union sponsored multi-employer plan. Pension benefits are based on the number of years of credited service and on final average compensation.

Effective with our acquisition of NUI, we now administer the NUI Retirement Plan. Throughout 2005, we will maintain existing benefits for NUI employees, including participation in the NUI Retirement Plan. Beginning in 2006, eligible non-union participants in the NUI Retirement Plan will become eligible to participate in the AGL Resources Retirement Plan. Currently, participants of the NUI Retirement Plan have the option of receiving a lump sum distribution upon retirement, which is not permitted under the AGL Retirement Plan. However, the option to receive a lump sum payment will be provided for all benefits earned through December 31, 2005. The following tables present details about our pension plans:

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	AGL Retirement Plan						NUI Retirement Plan
In millions	Dec. 31, 2004			Dec. 31, 2003			Dec. 31, 2004
Change in benefit obligation
Benefit obligation at beginning of year	$	314		$	290		$	144
Service cost		5			4			-
Interest cost		19			19			1
Actuarial loss		21			20			-
Benefits paid		(19	)		(19	)		(1	)
Benefit obligation at end of year	$	340		$	314		$	144
Change in plan assets
Fair value of plan assets at beginning of year	$	259		$	208		$	108
Actual return on plan assets		26			48			4
Employer contribution		13			22			-
Benefits paid		(19	)		(19	)		(1	)
Fair value of plan assets at end of year	$	279		$	259		$	111
Funded status
Plan assets less than benefit obligation at end of year	$	(61	)	$	(55	)	$	(33	)
Unrecognized net loss		108			95			-
Unrecognized prior service benefit		(11	)		(12	)		(3	)
Accrued pension cost	$	36		$	28		$	(36	)
Amounts recognized in the statement of financial position consist of
Prepaid benefit cost	$	43		$	34		$	-
Accrued benefit liability		(7	)		(7	)		(36	)
Accumulated OCI		(84	)		(66	)		-
Net amount recognized at year end	$	(48	)	$	(39	)	$	(36	)

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The accumulated benefit obligation (ABO) for our retirement plan and other information for our pension plans are indicated in the following tables:

	AGL Retirement Plan					NUI Retirement Plan
	Dec. 31, 2004		Dec. 31, 2003			Dec. 31, 2004
Projected benefit obligation	$	340	$	314		$	144
ABO		327		298			118
Fair value of plan assets		279		259			111
Increase (decrease) in minimum liability included in OCI		18		(14	)		-

Components of net periodic benefit cost
Service cost	$	5		$	4		$	-
Interest cost		19			19			1
Expected return on plan assets		(23	)		(22	)		(1	)
Net amortization		(1	)		(1	)		-
Recognized actuarial (gain) loss		5			2			-
Net annual pension cost	$	5		$	2		$	-

The following table indicates our weighted average assumptions used to determine benefit obligations at the balance sheet date:

	AGL Retirement Plan						NUI Retirement Plan
	Dec. 31, 2004			Dec. 31, 2003			Dec. 31, 2004
Discount rate		5.8	%		6.3	%		5.8	%
Rate of compensation increase		4.0	%		4.5	%		4.0	%

We consider a number of factors in the determination and selection of our assumptions of the overall expected long-term rate of return on plan assets. We consider the historical long-term return experience of our assets, the current and expected allocation of our plan assets as well as expected long-term rates of return. We derive these expected long-term rates of return with the assistance of our investment advisors and generally base these rates on a 10-year horizon for various asset classes, our expected investments of plan assets and active asset management as opposed to investment in a passive index fund. We base our expected allocation of plan assets on a diversified portfolio consisting of domestic and international equity securities, fixed income, real estate, private equity securities and alternative asset classes.

As of December 1, 2004, the discount rate used to determine NUI’s opening balance sheet benefit obligation was 5.8%. This discount rate was also utilized to determine net periodic benefit cost for the month of December 2004. The following table presents the weighted average assumptions used to determine net periodic benefit cost at the beginning of the period, which was January 1, for the AGL Retirement Plan.

	AGL Retirement Plan						NUI Retirement Plan
	Dec. 31, 2004			Dec. 31, 2003			Dec. 31, 2004
Discount rate		6.3	%		6.8	%		5.8	%
Expected return on plan assets		8.8	%		8.8	%		8.5	%
Rate of compensation increase		4.0	%		4.5	%		4.0	%

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Our Retirement Plans’ weighted average asset allocations at December 31, 2004 and 2003 and our target asset allocation ranges are as follows:

				Actual allocation on a weighted average basis
				AGL Resources Retirement Plan						NUI Retirement Plan
	Target Range Allocation of Assets			2004			2003			2004
Equity		40%-85	%		71	%		67	%		72	%
Fixed income		25%-50	%		25			30			28
Real estate and other		0%-10	%		3			-			-
Cash		0%-10	%		1			3			-

The Retirement Plan Investment Committee (the Committee) appointed by our Board of Directors and responsible for overseeing the investments of the Retirement Plan. Further, we have an Investment Policy (the Policy) for the Retirement Plans, which has a goal to preserve the Retirement Plan’s capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the Retirement Plan assets are actively managed with the objective of optimizing long-term return while maintaining a high standard of portfolio quality and proper diversification.

The Policy’s risk management strategy establishes a maximum tolerance for risk in terms of volatility to be measured at 75% of the volatility experienced by the S&P 500. We will continue to more broadly diversify the Retirement Plan to minimize the risk of large losses in a single asset class. The Policy’s permissible investments include domestic and international equities (including convertible securities and mutual funds), domestic and international fixed income (corporate and U.S. government obligations), cash and cash equivalents and other suitable investments. The asset mix of these permissible investments is maintained within the Policy’s target allocations as included in the table above, but the Committee can establish different allocations between various classes and/or investment managers in order to better achieve expected investment results.

Equity market performance and corporate bond rates have a significant effect on our reported unfunded ABO, as the primary factors that drive the value of our unfunded ABO are the assumed discount rate and the actual return on plan assets. Additionally, equity market performance has a significant effect on our market-related value of plan assets (MRVPA), which is a calculated value and differs from the actual market value of plan assets. The MRVPA recognizes the differences between the actual market value and expected market value of our plan assets and is determined by our actuaries using a five-year moving weighted average methodology. Gains and losses on plan assets are spread through the MRVPA based on the five-year moving weighted average methodology, which affects the expected return on plan assets component of pension expense.

Our employees do not contribute to the Retirement Plans. We fund the plan by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. We calculate the amount of funding using an actuarial method called the projected unit credit cost method. However, we may also fund the Retirement Plans in excess of the minimum required amount. We expect to make a $1 million contribution to the pension plans in 2005.

Postretirement Benefits

We sponsor two defined benefit postretirement health care plans for our eligible employees, the AGL Resources Inc. Postretirement Health Care Plan (AGL Postretirement Plan) and the NUI Corporation Postretirement Plan Health Care Plan (NUI Postretirement Plan). Eligibility for these benefits is based on age and years of service.

The NUI Postretirement Plan provides certain medical and dental healthcare benefits to retirees, other than retirees of Florida City Gas Company, depending on their age, years of service and start date. The healthcare plans are contributory and NUI funded a portion of these future benefits through a Voluntary Employees’ Beneficiary Association. Effective July 2000, NUI no longer offers postretirement benefits other than pensions for any new hires. In addition, NUI capped its share of costs at $500 per participant, per month for retirees under age 65, and at $150 per participant, per month for retirees over age 65. Effective with our acquisition of NUI, we acquired the NUI Postretirement Plan. Beginning in 2006, eligible participants in the NUI Postretirement Plan will become eligible to participate in the AGL Postretirement Plan.

The AGL Postretirement Plan covers all eligible AGL Resources’ employees who were employed as of June 30, 2002, if they reach retirement age while working for us. In addition, the state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery. We recorded a regulatory asset of $14 million as of December 31, 2004 and $9 million as of December 31, 2003. In addition, we recorded a regulatory liability of $2 million as of December 31, 2004 and $2 million as of December 31, 2003.

Effective December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Prescription Drug Act) was signed into law. This act provides for a prescription drug benefit under Medicare (Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

Effective July 2004, the AGL Postretirement Plan was amended to remove prescription drug coverage for Medicare-eligible retirees, effective January 1, 2006. Certain grandfathered NUI retirees participating in the NUI Postretirement Plan will continue receiving a prescription drug benefit for some period of time.

The AGL Resources Postretirement Plan’s accumulated postretirement benefit obligation decreased by approximately $24 million due and net annual cost decreased $2 million due to the elimination of prescription drug coverage for Medicare-eligible retirees. The 2004 net periodic postretirement benefit cost reflects both the plan amendment to remove prescription drug coverage under the AGL Postretirement Plan, described above, and the federal subsidy for NUI grandfathered retirees. The following tables present details about our postretirement benefits:

29

	AGL Postretirement Plan						NUI Postretirement Plan
In millions	Dec. 31, 2004			Dec. 31, 2003			Dec. 31, 2004
Change in benefit obligation
Benefit obligation at beginning of year	$	134		$	129		$	23
Service cost		1			1			-
Interest cost		7			8			-
Plan amendments		(24	)		-			-
Actuarial loss		(12	)		6			-
Benefits paid		(8	)		(10	)		-
Benefit obligation at end of year	$	98		$	134		$	23
Change in plan assets
Fair value of plan assets at beginning of year	$	44		$	38		$	9
Actual return on plan assets		5			8			-
Employer contribution		8			8			-
Benefits paid		(8	)		(10	)		-
Fair value of plan assets at end of year	$	49		$	44		$	9
Funded status
ABO in excess of plan assets	$	(49	)	$	(90	)	$	(14	)
Unrecognized loss		30			44			-
Unrecognized transition amount		1			1			-
Unrecognized prior service cost (benefit)		(26	)		(6	)		-
Accrued benefit cost	$	(44	)	$	(51	)	$	(14	)
Amounts recognized in the statement of financial position consist of
Prepaid benefit cost	$	-		$	-		$	-
Accrued benefit liability		(44	)		(51	)		(14	)
Accumulated OCI		-			-			-
Net amount recognized at year end	$	(44	)	$	(51	)	$	(14	)

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The following table presents details on the components of our net periodic benefit costs at the balance sheet date:

	AGL Postretirement Plan						NUI Postretirement Plan
In millions	2004			2003			2004
Service cost	$	1		$	1		$	-
Interest cost		7			8			-
Expected return on plan assets		(3	)		(3	)		-
Amortization of transition amount		(2	)		-			-
Amortization of regulatory asset		1			2			-
Net periodic postretirement benefit cost	$	4		$	8		$	-

The following table presents our weighted average assumptions used to determine benefit obligations at the beginning of the period, which was January 1, for the AGL Postretirement Plan and December 1 for the NUI Postretirement Plan:

	AGL Postretirement Plan						NUI Postretirement Plan
	2004			2003			2004
Discount rate		5.8	%		6.3	%		5.8	%

The following table presents our weighted average assumptions used to determine net periodic benefit cost:

	AGL Postretirement Plan						NUI Postretirement Plan
	2004			2003			2004
Discount rate		6.3	%		6.8	%		5.8	%
Expected return on plan assets		8.8	%		8.8	%		2.0	%
Rate of compensation increase		4.0	%		4.5	%		-

We consider the same factors in the determination and selection of our assumptions of the overall expected long-term rate of return on plan assets as those considered in the determination and selection of the overall expected long-term rate of return on plan assets for our Retirement Plan. For purposes of measuring our accumulated postretirement benefit obligation, the assumed pre-Medicare and post-Medicare health care inflation rates are as follows:

	AGL Postretirement Plan
	Pre-Medicare Cost (pre-65 years old)						Post-Medicare Cost (post-65 years old)
Assumed Health Care Cost Trend Rates at December 31,	2004			2003			2004			2003
Health care costs trend assumed for next year		11.3	%		10.0	%		11.3	%		12.0	%
Rate to which the cost trend rate gradually declines		2.5	%		5.0	%		2.5	%		5.0	%
Year that the rate reaches the ultimate trend rate		2006			2010			2006			2011

	NUI Postretirement Plan
Assumed Health Care Cost Trend Rates at December 31,	2004
Health care costs trend assumed for next year		9.0	%
Rate to which the cost trend rate gradually declines		5.0	%
Year that the rate reaches the ultimate trend rate		2008

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Assumed health care cost trend rates have a significant effect on the amounts reported for our health care plans. A one-percentage-point change in the assumed health care cost trend rates would have the following effects:

	One-Percentage-Point
In millions	Increase		Decrease
Effect on total of service and interest cost (1)	$	1		($1	)
Effect on accumulated postretirement benefit obligation (1)		6		(6	)

(1)   There were no material amounts for the NUI Postretirement benefit obligation or interest costs.

The following table presents expected benefit payments covering the periods 2005 through 2014 for our qualified pension plans and postretirement healthcare plans. There will be benefit payments under these plans beyond 2014.

	AGL Resources’ plans				NUI’s plans
For the year ended Dec. 31, (in millions)	Pension plan		Postretirement healthcare plans		Pension plan		Postretirement healthcare plans
2005	$	19	$	8	$	17	$	2
2006		18		7		8		2
2007		18		7		8		2
2008		18		7		9		2
2009		19		7		9		2
2010-2014		101		34		61		9

Our investment policies and strategies, including target allocation ranges, are similar to those of our Retirement Plan. We fund the plan annually, and retirees contribute 20% of medical premiums, 50% of the medical premium for spousal coverage and 100% of the dental premium. Our postretirement benefit plan’s weighted-average asset allocations for 2004, 2003 and 2002 and our target asset allocation ranges are as follows:

	Target Asset Allocation Ranges			2004			2003
Equity		40%-85	%		67	%		59	%
Fixed income		25%-50	%		32	%		40	%
Real Estate and other		0%-10	%		-	%		-	%
Cash		0%-10	%		1	%		1	%

Employee Savings Plan Benefits

We sponsor the Retirement Savings Plus Plan (RSP), a defined contribution benefit plan that allows eligible participants to make contributions up to specified limits to its account. Under the RSP, we made matching contributions to participant accounts in the following amounts:

·   $5 million in 2004

·   $4 million in 2003

·   $4 million in 2002

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

Effective December 1, 2004, all NUI employees who were participating in NUI’s qualified defined contribution benefit plan were eligible to participate in the RSP, and those who were participants in NUI’s nonqualified defined contribution plan became eligible to participate in the NSP.

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> Note 7

Stock-based Compensation Plans

Employee Stock-based Compensation Plans and Agreements

We currently sponsor the following stock-based compensation plans

·   The Long-Term Incentive Plan (LTIP) provides for grants of performance units, restricted stock and incentive and nonqualified stock options to key employees. The LTIP currently authorizes the issuance of up to 7.9 million shares of our common stock.

·   A predecessor plan, the Long-Term Stock Incentive Plan (LTSIP), provides for grants of restricted stock, incentive and nonqualified stock options and stock appreciation rights (SARs) to key employees. Following shareholder approval of the LTIP, no further grants have been made under the LTSIP.

·   The Officer Incentive Plan (Officer Plan) provides for grants of nonqualified stock options and restricted stock to new-hire officers. The Officer Plan authorizes the issuance of up to 600,000 shares of our common stock.

·   SARs have been granted to key employees under individual agreements that permit the holder to receive cash in an amount equal to the difference between the fair market value of a share of our common stock on the date of exercise and the SAR base value. A total of 26,863 SARs currently are outstanding.

·   We amended the Non-Employee Directors Equity Compensation Plan (Directors Plan), in which all nonemployee directors participate, to eliminate the granting of stock options effective December 2002. As a result, the Directors Plan now provides solely for the issuance of restricted stock. It currently authorizes the issuance of up to 200,000 shares of our common stock.

The following table summarizes activity for key employees and nonemployee directors related to grants of stock options:

	Number of			Weighted Average
	Options			Exercise Price
Outstanding-December 31, 2001		3,587,501		$	20.06
Granted		988,564			21.49
Exercised		(785,853	)		19.28
Forfeited		(156,255	)		21.59
Outstanding-December 31, 2002		3,633,957		$	20.55
Granted		939,262			26.76
Exercised		(863,112	)		20.08
Forfeited		(199,137	)		22.00
Outstanding-December 31, 2003		3,510,970		$	22.25
Granted		103,900			29.72
Exercised		(1,050,053	)		20.90
Forfeited		(390,745	)		22.44
Outstanding-December 31, 2004		2,174,072		$	23.23

33

Information about outstanding and exercisable options as of December 31, 2004 is as follows:

	Options Outstanding						Options Exercisable
Range of Exercise Prices	Number of Options		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Number of Options		Weighted Average Exercise Price
$13.75 to $17.49		2,199		5.0	$	16.99		2,199	$	16.99
$17.50 to $19.99		201,640		3.8	$	18.85		199,973	$	18.84
$20.00 to $24.10		1,164,156		5.5	$	21.23		1,126,827	$	21.17
$24.11 to $30.00		751,936		8.4	$	26.97		325,737	$	26.91
$30.01 to $34.00		54,141		6.2	$	31.07		3,524	$	31.20
Outstanding-Dec. 31, 2004		2,174,072		6.4	$	23.23		1,658,260	$	22.04

Summarized below are outstanding options that are fully exercisable:

	Number of Options		Weighted Average Exercise Price
Exercisable-December 31, 2002		2,483,756	$	20.07
Exercisable-December 31, 2003		2,154,877	$	20.47
Exercisable-December 31, 2004		1,658,260	$	22.04

Our stock-based employee compensation plans are accounted for under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations. For our stock option plans, we generally do not reflect stock-based employee compensation cost in net income, as options for those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. For our stock appreciation rights, we reflect stock-based employee compensation cost based on the fair value of our common stock at the balance sheet date since these awards constitute a variable plan under APB 25.

In accordance with the fair value method of determining compensation expense, we utilized the Black-Scholes pricing model and the estimate below for the years ended December 31, 2004, 2003 and 2002:

	2004			2003			2002
Expected life (years)		7			7			7
Interest rate		3.7	%		3.8	%		4.6	%
Volatility		16.9	%		19.2	%		19.2	%
Dividend yield		3.9	%		4.2	%		5.0	%
Fair value of options granted	$	3.72		$	3.75		$	2.92

Participants realize value from option grants or SARs only to the extent that the fair market value of our common stock on the date of exercise of the option or SAR exceeds the fair market value of the common stock on the date of the grant. The compensation costs that have been charged against income for performance units, restricted stock and other stock-based awards were $7 million in 2004, $8 million in 2003 and $2 million in 2002.

Incentive and Nonqualified Stock Options

We grant incentive and nonqualified stock options at the fair market value on the date of the grant. The vesting of incentive options is subject to a statutory limitation of $100,000 per year under Section 422A of the Internal Revenue Code. Otherwise, nonqualified options generally become fully exercisable not earlier than six months after the date of grant and generally expire 10 years after that date.

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Performance Units

In general, a performance unit is an award to receive an equal number of shares of company common stock or an equivalent value of cash subject to the achievement of certain pre-established performance criteria.

In February 2002, we granted to a select group of executives a total of 1.5 million in performance units with a performance measurement period that ended December 31, 2004. The amount actually earned would be based on the highest average closing price of our common stock over any 10 consecutive trading days during the performance measurement period and could range from a minimum of 10% to 100% of the granted units. The performance units were subject to certain transfer restrictions and forfeiture upon termination of employment. In addition, during a portion of the performance measurement period, performance units were eligible for dividend credits based on vested performance units. Of the 1.5 million units that were granted, only 1 million units were eligible for vesting at December 31, 2004. Upon vesting, the performance units were payable in shares of our common stock, provided, however, at the election of the participant, up to 50% was payable in cash.

At December 31, 2004, based on the highest average closing price over any 10 consecutive trading days during the performance measurement period, only 18.31% of units were vested, representing an aggregate of 198,000 units, including accrued dividends. These units were valued at our closing stock price on December 31, 2004 of $33.24 per unit representing a value of $6.6 million. The total value of the awards in the amount of $6.2 million was paid out as follows

·   $2.6 million paid in cash

·   $2.8 million withheld to cover applicable taxes

·   35,342 shares of common stocks with an approximate value of $1.2 million

In November 1999, we granted performance units that vested in September 2002. Based on performance achievement and the accrual of dividend credit, a total of 10,254 shares of common stock were issued to the participants. We did not grant performance units in 2004 or 2003.

Stock Appreciation Rights

We grant SARs, which are payable in cash, at fair market value on the date of grant. SARs generally become fully exercisable not earlier than 12 months after the date of grant and generally expire six years after that date. We recognize the intrinsic value of the SARs as compensation expense over the vesting period. Compensation expense for 2004 and 2003 was immaterial. The following table summarizes activity related to grants of SARs:

	Number of SARs			Weighted Average Exercise Price
Outstanding as of December 31, 2002		141,253		$	23.50
Issued		45,790			24.30
Exercised		(17,718	)		23.50
Forfeited		(9,368	)		23.99
Outstanding as of December 31, 2003		159,957			23.70
Issued		-			-
Exercised		(60,262	)		23.70
Forfeited		(72,832	)		23.50
Outstanding as of December 31, 2004		26,863			24.24

Directors Plan

Under the Directors Plan, each nonemployee director receives an annual retainer that has an aggregate value of $60,000. At the election of each director, the annual retainer is paid in cash (with a $30,000 limit) and/or shares of our common stock or is deferred and invested in common stock equivalents under the 1998 Common Stock Equivalent Plan for Non-Employee Directors. Upon initial election to our Board of Directors, each nonemployee director receives 1,000 shares of common stock on the first day of service.

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Restricted Stock Awards

Restricted stock awards generally are subject to some vesting restrictions. We awarded restricted stock, net of forfeitures, to key employees and nonemployee directors in the following amounts:

	2004		2003		2002
Employees		51,300		244,128		30,000
Nonemployee directors		8,727		12,152		1,410
Total		60,027		256,280		31,410
Weighted average fair value at year-end	$	32.45	$	27.15	$	23.19

In addition, 104,000 of the 256,280 shares awarded to selected employees in 2003 vested in 2004. The remaining nonvested shares were contingent upon our achievement of selected cash flow performance measures over the one-year performance measurement period. Recipients were entitled to vote and receive dividends on stock awards. The shares were subject to certain transfer restrictions and are forfeited upon termination of employment, absent a change of control.

Employee Stock Purchase Plan

We have established the Employee Stock Purchase Plan (ESPP), a nonqualified employee stock purchase plan for eligible employees. Under the ESPP, employees may purchase shares of our common stock during quarterly intervals at 85% of fair market value. Employee contributions under the ESPP may not exceed $25,000 per employee during any calendar year. The ESPP currently allows for the purchase of 600,000 shares. As of December 31, 2004, our employees have purchased 73,254 shares leaving 526,746 shares available for purchase. The ESPP was adopted by our Board in 2001, with an initial term of four years that expired January 31, 2005. Our Board of Directors approved an amendment to the ESPP, subject to shareholder approval at the next annual meeting of shareholders, to extend the term of the ESPP for a ten-year period effective January 31, 2005. More information about the ESPP is presented below:

	2004		2003		2002
Shares purchased on the open market		35,789		24,871		12,594
Average per share purchase price	$	25.20	$	22.08	$	23.22
Purchase price discount paid	$	159,144	$	97,400	$	44,024

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> Note 8

Financing

						Outstanding as of:
Dollars in millions	Year(s) Due		Int. rate as of Dec. 31, 2004			Dec. 31, 2004		Dec. 31, 2003
Short-term debt
Commercial paper (1)		2005		2.5	%	$	314	$	303
Current portion of long-term debt		-		-			-		77
Sequent line of credit (2)		2005		2.5			18		3
Current portion of capital leases		2005		4.9			2		-
Total short-term debt (3)				2.5	%	$	334	$	383
Long-term debt - net of current portion
Medium-Term notes
Series A		2021		9.1	%	$	30	$	30
Series B		2012-2022		8.3-8.7			61		61
Series C		2014-2027		6.6-7.3			117		122
Senior Notes		2011-2013		4.5-7.1			975		525
Gas facility revenue bonds, net of unamortized issuance costs		2022-2033		1.9-6.4			199		-
Notes payable to Trusts		2037-2041		8.0-8.2			232		-
Trust Preferred Securities		2037-2041		-			-		222
Capital leases		2013		4.9			8		-
AGL Capital interest rate swaps		2011-2041		3.6-5.2			1		(4	)
Total long-term debt (3)				6.0	%	$	1,623	$	956
Total short-term and long-term debt (3)				5.4	%	$	1,957	$	1,339

(1)   The daily weighted average rate was 1.6% for 2004 and 1.3% for 2003.

(2)   The daily weighted average rate was 2.0% for 2004 and 1.6% for 2003.

(3)   The weighted average interest rate excludes capital leases but includes interest rate swaps, if applicable

Short-term Debt

Our short-term debt at December 31, 2004 and 2003 was composed of borrowings under our commercial paper program which consisted of short-term, unsecured promissory notes with maturities ranging from 3 to 56 days, Atlanta Gas Light’s Medium-Term notes with maturities within one year, current portions of our capital lease obligations, Sequent’s line of credit and SouthStar’s line of credit.

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

Sequent line of creditIn June 2004, Sequent’s $25 million unsecured line of credit was extended to July 2005. This unsecured line of credit is used solely for the posting of exchange deposits and is unconditionally guaranteed by us. This line of credit bears interest at the federal funds effective rate plus 0.5%.

SouthStar line of creditIn April 2004, SouthStar amended its $75 million revolving line of credit, which is used to meet seasonal working capital needs. SouthStar’s line of credit is scheduled to expire in April 2007 and is not guaranteed by us. At December 31, 2004, there were no amounts outstanding under this facility.

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Long-term Debt

Our long-term debt matures more than one year from the date of issuance and consists of Medium-Term notes Series A, Series B and Series C, which we issued under an indenture dated December 1, 1989, Senior Notes, Gas Facility Revenue Bonds, Notes Payable to Trusts and capital leases. The notes are unsecured and rank on parity with all of our other unsecured indebtedness. Our annual maturities of long-term debt are as follows:

·   no maturities in 2005-2010

·   $1,623 million in 2011 and beyond

Senior NotesIn February 2001, we issued $300 million of Senior Notes with a maturity date of January 14, 2011. These Senior Notes have an interest rate of 7.125% payable on January 14 and July 14, beginning July 14, 2001. The proceeds from the issuance were used to refinance a portion of the existing short-term debt under the commercial paper program.

In March 2003, we entered into interest rate swaps of $100 million to effectively convert a portion of the fixed-rate interest obligation on the $300 million in Senior Notes Due 2011 to a variable-rate obligation. We pay floating interest each January 14 and July 14 at six-month LIBOR plus 3.4%. The effective variable interest rate at December 31, 2004 was 5.2%. These interest rate swaps expire January 14, 2011, unless terminated earlier. For more information on our interest rate swaps, see Note 4.

In July 2003, we issued $225 million in Senior Notes with a maturity date of April 15, 2013. The Senior Notes have an interest rate of 4.45% payable on April 15 and October 15 of each year, beginning October 15, 2003 with interest accruing from July 2, 2003. We used the net proceeds from the Senior Notes to repay approximately $204 million of Medium-Term notes as well as approximately $20 million of short-term debt.

In September 2004, we issued $250 million in Senior Notes with a maturity of October 1, 2034. The Senior Notes have an interest rate of 6.00% payable on April 1 and October 1 of each year, beginning April 1, 2005 with interest accruing from September 27, 2004.

In December 2004, we issued $200 million in Senior Notes with a maturity of January 15, 2015. The Senior Notes have an interest rate of 4.95% payable on January 15 and July 15 of each year, beginning July 15, 2005 with interest accruing from December 20, 2004. We used the net proceeds from both of the senior notes issuances in 2004 to repay commercial paper borrowings and for general corporate purposes.

The trustee with respect to all of the above-referenced senior notes is the Bank of New York Trust Company, N.A., pursuant to an indenture dated February 20, 2001. We fully and unconditionally guarantee all of our senior notes.

Gas Facility Revenue BondsNUI Utilities, Inc., a wholly owned subsidiary of NUI, had outstanding at closing $200 million of indebtedness pursuant to Gas Facility Revenue Bonds. We do not guarantee or provide any other form of security for the repayment of this indebtedness. NUI Utilities is party to a series of loan agreements with the New Jersey Economic Development Authority (NJEDA) pursuant to which the NJEDA has issued four series of gas facilities revenue bonds:

·   $46 million of bonds at 6.35 %, due October 1, 2022

·   $20 million of bonds at 6.4%, due October 1, 2024

·   $39 million of bonds at variable rates, due June 1, 2026 (Variable Bonds)

·   $55 million of bonds at 5.7 %, due June 1, 2032

·   $40 million of bonds at 5.25%, due November 1, 2033

The Variable Bonds contain a provision whereby the holder can "put" the bonds back to the issuer. In 1996, NUI Utilities executed a long-term Standby Bond Purchase Agreement (SBPA) with a syndicate of banks, which was amended and restated on June 12, 2001. Under the terms of the SBPA, as further amended, The Bank of New York Trust Company, N.A. (Bank of New York) is obligated under certain circumstances to purchase Variable Bonds that are tendered by the holders thereof and not remarketed by the remarketing agent. Such obligation of the Bank of New York would remain in effect until the expiration of the SBPA, unless it is extended or earlier terminated.

The terms of the SBPA restrict the payment of dividends by NUI Utilities to an amount based, in part, on the earned surplus of NUI Utilities. On May 19, 2004, NUI Utilities and The Bank of New York amended the SBPA to eliminate the effect of NUI Utilities’ settlement with the New Jersey Board of Public Utilities (NJBPU) and the estimated refunds to customers in Florida on the earned surplus of NUI Utilities. In addition the amendment extended the expiration date of the SBPA to June 29, 2005.

If the SBPA is not further extended beyond June 29, 2005, in accordance with the terms of the Variable Bonds, all of the Variable Bonds would be subject to mandatory tender at a purchase price of 100 percent of the principal amount, plus accrued interest, to the date of tender. In such case, any Variable Bonds that are not remarketable by the remarketing agent will be purchased by the Bank of New York.

Beginning six months after the expiration or termination of the SBPA, any Variable Bonds still held by the bank must be redeemed or purchased by NUI Utilities in 10 equal, semi-annual installments. In addition, while the SBPA is in effect, any tendered Variable Bonds that are purchased by the bank and not remarketed within one year must be redeemed or purchased by NUI Utilities at such time, and every six months thereafter, in 10 equal, semi-annual installments.

As of December 31, 2004, the aggregate principal and accrued interest on the outstanding Variable Bonds totaled approximately $39 million. Principal and any unpaid interest on the outstanding Variable Bonds are due on June 1, 2026, unless the put option is exercised before that time.

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Notes Payable to TrustsIn June 1997, we established AGL Capital Trust I (Trust I), a Delaware business trust, of which AGL Resources owns all the common voting securities. Trust I issued and sold $75 million of 8.17% capital securities (liquidation amount $1,000 per capital security) to certain initial investors. Trust I used the proceeds to purchase 8.17% Junior Subordinated Deferrable Interest Debentures issued by us. Trust I capital securities are subject to mandatory redemption at the time of the repayment of the junior subordinated debentures on June 1, 2037, or the optional prepayment by us after May 31, 2007.

In March 2001, we established AGL Capital Trust II (Trust II), a Delaware business trust, of which AGL Capital owns all the common voting securities. In May 2001, Trust II issued and sold $150 million of 8.00% capital securities (liquidation amount $25 per capital security). Trust II used the proceeds to purchase 8.00% Junior Subordinated Deferrable Interest Debentures issued by us. The proceeds from the issuance were used to refinance a portion of our existing short-term debt under the commercial paper program. Trust II capital securities are subject to mandatory redemption at the time of the repayment of the junior subordinated debentures on May 15, 2041, or the optional prepayment by AGL Capital after May 21, 2006. Additionally we entered into interest rate swaps to effectively convert a portion of the fixed-rate interest obligation on our Notes Payable to Trusts to a variable-rate obligation. The effective variable interest rate at December 31, 2004 was 3.6%. For more information on our interest rate swaps, see Note 4.

The trustee is the Bank of New York with respect to the 8.17% capital securities pursuant to an indenture dated June 11, 1997, and with respect to the 8.00% capital securities pursuant to an indenture dated May 21, 2001. We fully and unconditionally guarantee all our Trusts’ obligations for the capital securities.

Other Preferred SecuritiesAs of December 31, 2003, we had 10.0 million shares of authorized, unissued Class A Junior Participating Preferred Stock, no par value, and 10.0 million shares of authorized, unissued preferred stock, no par value.

Capital leases Our capital leases consist primarily of a sale/leaseback transaction completed in 2002 by Florida Gas related to its gas meters and other equipment and will be repaid over 11 years. Pursuant to the terms of the lease agreement, Florida Gas is required to insure the leased equipment during the lease term. In addition, at the expiration of the lease term, Florida Gas has the option to purchase the leased meters from the lessor at their fair market value.

Default Events

Our Credit Facility financial covenants and the Public Utility Holding Company Act of 1935, as amended (PUHCA), require us to maintain a ratio of total debt to total capitalization of no greater than 70%. 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

·   a maximum leverage ratio

·   minimum net worth

·   insolvency events and nonpayment of scheduled principal or interest payments

·   acceleration of other financial obligations

·   change of control provisions

We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that requires us to issue equity based on credit ratings or other trigger events. We are currently in compliance with all existing debt provisions and covenants.

39

> Note 9

Common Shareholders’ Equity

Shareholder Rights Plan

On March 6, 1996, our Board of Directors adopted a Shareholder Rights Plan. The plan contains provisions to protect our shareholders in the event of unsolicited offers to acquire us or other takeover bids and practices that could impair the ability of the Board of Directors to represent shareholders’ interests fully. As required by the Shareholder Rights Plan, the Board of Directors declared a dividend of one preferred share purchase right (a Right) for each outstanding share of our common stock, with distribution made to shareholders of record on March 22, 1996.

The Rights, which will expire March 6, 2006, are represented by and traded with our common stock. The Rights are not currently exercisable and do not become exercisable unless a triggering event occurs. One of the triggering events is the acquisition of 10% or more of our common stock by a person or group of affiliated or associated persons. Unless previously redeemed, upon the occurrence of one of the specified triggering events, each Right will entitle its holder to purchase one one-hundredth of a share of Class A Junior Participating Preferred Stock at a purchase price of $60. Each preferred share will have 100 votes, voting together with the common stock. Because of the nature of the preferred shares’ dividend, liquidation and voting rights, one one-hundredth of a share of preferred stock is intended to have the value, rights and preferences of one share of common stock. As of December 31, 2004, 1.0 million shares of Class A Junior Participating Preferred Stock were reserved for issuance under that plan.

Equity Offering

On November 18, 2004, we completed our public offering of 11.04 million shares of common stock. We priced the offering at $31.01 per share and generated net proceeds of approximately $332 million, which we used to purchase the outstanding capital stock of NUI and to repay short-term debt incurred to fund the purchase of Jefferson Island Storage & Hub LLC. In February 2003, we completed our public offering of 6.4 million shares of common stock. The offering generated net proceeds of approximately $137 million, which we used to repay outstanding short-term debt and for general corporate purposes.

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Dividends

Our common shareholders may receive dividends when declared by our Board of Directors, which may be paid in cash, stock or other form of payment. In certain cases, our ability to pay dividends to our common shareholders is limited by the following:

·   satisfying our obligations under certain financing agreements, including debt-to-capitalization and total shareholders’ equity covenants

·   satisfying our obligations to any preferred shareholders

·   restrictions under the PUHCA on our payment of dividends out of capital or unearned surplus without prior permission from the SEC

Under Georgia law, the payment of dividends to the holders of our common stock is limited to our legally available assets and subject to the prior payment of dividends on any outstanding shares of preferred stock and junior preferred stock. Our assets are not legally available for paying dividends if

·   we could not pay our debts as they become due in the usual course of business

·   our total assets would be less than our total liabilities plus, subject to some exceptions, any amounts necessary to satisfy the preferential rights upon dissolution of shareholders whose preferential rights are superior to those of shareholders receiving the dividends

We announced the following increases in our cash dividends payable on our common stock:

·   In February 2005, we announced a 7% increase in our common stock dividend. The increase raised the quarterly dividend from $0.29 per share to $0.31 per share, for an indicated annual dividend of $1.24 per share.

·   In April 2004, we announced a 4% increase in our common stock dividend, raising the quarterly dividend from $0.28 per share to $0.29 per share which indicated an annual dividend of $1.16 per share.

·   In April 2003, we announced a 4% increase in our common stock dividend from $0.27 per share to $0.28 per share, which indicated an annual dividend of $1.12

41

> Note 10

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. We calculate any expected pension contributions using an actuarial method called the projected unit credit cost method, and pursuant to these calculations, we expect to make a $1 million pension contribution in 2005. The following table illustrates our expected future contractual cash obligations as of December 31, 2004:

			Payments Due Before December 31,
					2006		2008		2010
					&		&		&
In millions	Total		2005		2007		2009		Thereafter
Long-term debt (1) (2)	$	1,623	$	-	$	2	$	2	$	1,619
Pipeline charges, storage capacity and gas supply (3) (4)		1,051		258		262		179		352
Short-term debt (2)		334		334		-		-		-
PRP costs (5)		327		85		162		80		-
Operating leases (6)		170		27		39		29		75
ERC (5)		90		27		10		12		41
Commodity and transportation charges		20		19		1		-		-
Total	$	3,615	$	750	$	476	$	302	$	2,087
(1) Includes $232 million of Notes Payable to Trusts redeemable in 2006 and 2007. (2) Does not include the interest expense associated with the long-term and short-term debt. (3) Charges recoverable through a PGA mechanism or alternatively billed to Marketers. Also includes demand charges associated with Sequent. (4) A subsidiary of NUI entered into two 20-year agreements for the firm transportation and storage of natural gas during 2003 with the annual demand charges aggregate of approximately $5 million. As a result of our acquisition of NUI and in accordance with SFAS 141, the contracts were valued at fair value. The $38 million currently allocated to accrued pipeline demand charges on our consolidated balance sheets represent our estimate of the fair value of the acquired contracts. The liability will be amortized over the remaining lives of the contract. (5) Charges recoverable through rate rider mechanisms. (6) 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" (SFAS 13). 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 an index plus premium basis. At December 31, 2004, SouthStar had obligations under these arrangements for 11.2 Bcf for the year ending December 31, 2005. This obligation is not included in the above table. SouthStar also had capacity commitments related to the purchase of transportation rights on interstate pipelines.

We also have incurred various contingent financial commitments in the normal course of business. Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our expected contingent financial commitments as of December 31, 2004:

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			Commitments Due Before December 31,
					2006		2008		2010
					&		&		&
In millions	Total		2005		2007		2009		Thereafter
Guarantees (1)	$	7	$	7	$	-	$	-	$	-
Standby letters of credit and performance/ surety bonds		12		12		-		-		-
Total	$	19	$	19	$	-	$	-	$	-
(1) We provide a guarantee on behalf of our affiliate, SouthStar. We guarantee 70% of SouthStar's obligations to Southern Natural under certain agreements between the parties up to a maximum of $7 million if SouthStar fails to make payment to Southern Natural. We have certain guarantees that are recorded on our consolidated balance sheet that would not cause any additional impact on our financial statements beyond what was already recorded.

Rental expense and sublease income

The following table illustrates our total rental lease expenses and sublease credits incurred for property and equipment:

In millions	2004		2003		2002
Rental expense	$	22	$	22	$	20
Sublease income		-		-		(2	)

Litigation

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

NUI shareholder complaintIn September 2004, a shareholder class action complaint (Complaint) was filed in a civil action captioned Green Meadows Partners, LLP on behalf of itself and all others similarly situated v. Robert P. Kenney, Bernard S. Lee, Craig G. Mathews, Dr. Vera King Farris, James J. Forese, J. Russell Hawkins, R. Van Whisnand, John Kean, NUI and the Company, pending in the Superior Court of the State of New Jersey, County of Somerset, Law Division. The Complaint, brought on behalf of a potential class of the stockholders of NUI, names as defendants all of the directors of NUI (Individual Defendants), NUI and the Company.

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

On October 12, 2004, we reached an agreement in principle with Green Meadows Partners, LLP to settle this litigation. The settlement called for NUI to provide certain additional information and disclosures to its shareholders, as reflected in the “Additional Disclosure” section of NUI’s proxy statement supplement, filed on October 12, 2004 with the SEC. In addition, as part of the settlement, NUI and the Company consented to a settlement class that consists of persons holding shares of NUI common stock at any time from July 15, 2004 until November 30, 2004, and we agreed to pay plaintiff’s attorney’s fees and costs in the amount of $285,000. No part of these attorney’s fees or costs will be paid out of funds that would otherwise have been paid to NUI’s shareholders.

On December 22, 2004, the trial court entered an order conditionally certifying a class for settlement purposes and designating the Plaintiff as a Settlement Class representative. The trial court’s order also established deadlines for Defendants to provide notice to the Settlement Class, for Settlement Class members to object to the settlement and for a final Settlement Hearing.

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> Note 11

Fair Value of Financial Instruments

The following table shows the carrying amounts and fair values of financial instruments included in our consolidated balance sheets:

In millions	Carrying Amount		Estimated Fair Value
As of December 31, 2004
Long-term debt including current portion	$	1,623	$	1,816
As of December 31, 2003
Long-term debt including current portion		1,033		1,166

The estimated fair values are determined based on interest rates that are currently available for issuance of debt with similar terms and remaining maturities. For the Notes payable to Trusts, we used quoted market prices and dividend rates for preferred stock with similar terms.

Considerable judgment is required to develop the fair value estimates; therefore, the values are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value estimates are based on information available to management as of December 31, 2004. We are not aware of any subsequent factors that would significantly affect the estimated fair value amounts. For more information about the fair values of our interest rate swaps, see Note 4.

> Note 12

Income Taxes

We have two categories of income taxes in our statements of consolidated income: current and deferred. Current income tax expense consists of federal and state income tax less applicable tax credits related to the current year. Deferred income tax expense generally is equal to the changes in the deferred income tax liability and regulatory tax liability during the year.

Investment Tax Credits

Deferred investment tax credits associated with distribution operations are included as a regulatory liability in our consolidated balance sheets (see Note 5). These investment tax credits are being amortized over the estimated life of the related properties as credits to income in accordance with regulatory treatment. We reduce income tax expense in our statements of consolidated income for the investment tax credits and other tax credits associated with our nonregulated subsidiaries. Components of income tax expense shown in the statements of consolidated income are as follows:

44

In millions	2004			2003			2002
Included in expenses:
Current income taxes
Federal	$	25		$	20			($19	)
State		1			13			(4	)
Deferred income taxes
Federal		60			52			79
State		5			3			3
Amortization of investment tax credits		(1	)		(1	)		(1	)
Total	$	90		$	87		$	58

The reconciliations between the statutory federal income tax rate, the effective rate and the related amount of tax for the years ended December 31, 2004, 2003 and 2002 are presented below:

	2004						2003						2002
Dollars in millions	Amount			% of Pretax Income			Amount			% of Pretax Income			Amount			% of Pretax Income
Computed tax expense	$	85			35.0	%	$	78			35.0	%	$	56			35.0	%
State income tax, net of federal income tax benefit		9			3.5			8			3.8			4			2.4
Amortization of investment tax credits		(1	)		(0.6	)		(1	)		(0.6	)		(1	)		(0.8	)
Flexible dividend deduction		(2	)		(0.6	)		(1	)		(0.6	)		(2	)		(0.9	)
Other-net		(1	)		(0.2	)		3			1.4			1			0.3
Total income tax expense	$	90			37.1	%	$	87			39.0	%	$	58			36.0	%

Accumulated Deferred Income Tax Assets and Liabilities

We report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes. The tax effects of the differences in those items are reported as deferred income tax assets or liabilities in our consolidated balance sheets. The assets and liabilities are measured utilizing income tax rates that are currently in effect. Because of the regulated nature of the utilities’ business, a regulatory tax liability has been recorded in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS 109). The regulatory tax liability is being amortized over approximately 30 years (see Note 5). Our deferred tax asset includes an additional pension liability of $33 million, which increased $7 million from 2003 in accordance with SFAS 109 (see Note 6).

As indicated in the table below, our deferred tax assets and liabilities include certain items we acquired from NUI. We have provided a valuation allowance for some of these items that reduces our net deferred tax assets to amounts we believe are more likely than not to be realized in future periods. With respect to our continuing operations, we have net operating losses in various jurisdictions. Components that give rise to the net accumulated deferred income tax liability are as follows:

45

	As of:
In millions	Dec. 31, 2004			Dec. 31, 2003
Accumulated deferred income tax liabilities
Property-accelerated depreciation and other property-related items	$	323		$	294
Other		238			125
Total accumulated deferred income tax liabilities		561			419
Accumulated deferred income tax assets
Deferred investment tax credits		8			7
Deferred pension additional minimum liability		34			27
Net operating loss - NUI (1)		31			-
Net operating loss - Virginia Gas Company (2)		6			-
Capital loss carryforward		5			-
Alternative minimum tax credit (3)		7			-
Other		41			9
Total accumulated deferred income tax assets		132			43
Valuation allowances		(8	)		-
Total accumulated deferred income tax assets, net of valuation allowance		124			43
Net accumulated deferred tax liability	$	437		$	376

(1)   Includes NUI’s federal net operating loss carryforwards of approximately $79 million that expire in 2024

(2)   Includes Virginia Gas Company’s $18 million pre-acquisition net operating losses, which are subject to a Internal Revenue Service Section 382 limitation (or reduced amount available for deduction as a result of change in control) and expire in 2016 through 2020.

(3)   Was generated by NUI and can be carried forward indefinitely to reduce our future tax liability.

> Note 13

Related Party Transactions

We previously recognized revenue and had accounts receivable from our affiliate, SouthStar, as detailed in the table below. As a result of our adoption of FIN 46R in January 1, 2004, we consolidated all of SouthStar’s accounts with our subsidiaries’ accounts and eliminated any intercompany balances between segments. For more discussion of FIN 46R and the impact of its adoption on our consolidated financial statements, see Note 3.

In millions	2004		2003		2002
Recognized revenue	$	-	$	169	$	171
Accounts receivable		-		11		-

46

> Note 14

Segment Information

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

Beginning in 2005, we added an additional segment, retail energy operations, which consists of the operations of SouthStar, our retail gas marketing subsidiary that conducts business primarily in Georgia. We added this segment due to our application of accounting guidance in SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS 131) in consideration of the impact of our acquisitions of NUI and Jefferson Island Storage & Hub, LLC (Jefferson Island). The addition of this segment also is consistent with our desire to provide transparency and visibility to SouthStar on a stand-alone basis and to provide additional visibility to the remaining businesses in the energy investments segment, principally Jefferson Island and Pivotal Propane of Virginia, Inc. (Pivotal Propane), which are more closely related in structure and operation. Additionally, we have recast the segment information for the years ended December 31, 2004, 2003 and 2002 in accordance with the guidance set forth in SFAS 131 as shown in the tables below. Our four operating segments are now as follows:

·   Distribution operations consists primarily of our regulated utilities Atlanta Gas Light, Chattanooga Gas, Elizabethtown Gas, Florida Gas and Virginia Natural Gas.

·   Retail energy operations consists of SouthStar.

·   Wholesale services consists primarily of Sequent.

·   Energy investments consists primarily of Pivotal Jefferson Island, Pivotal Propane, Virginia Gas Company and AGL Networks.

We treat corporate, our fifth segment, as a nonoperating business segment that consists primarily of AGL Resources Inc., AGL Services Company, nonregulated financing and captive insurance subsidiaries and the effect of intercompany eliminations. We eliminated intersegment sales for the years ended December 31, 2004, 2003 and 2002 from our statements of consolidated income.

We evaluate segment performance based primarily on the non-GAAP measure of earnings before interest and taxes (EBIT), which includes the effects of corporate expense allocations. EBIT is a non-GAAP measure that includes operating income, other income, equity in SouthStar’s income in 2003 and 2002, donations, minority interest in 2004 and gains on sales of assets. Items that we do not include in EBIT are financing costs, including interest and debt expense, income taxes and the cumulative effect of a change in accounting principle, each of which we evaluate on a consolidated level. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

You should not consider EBIT an alternative to, or a more meaningful indicator of our operating performance than, operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income and net income for the years ended December 31, 2004, 2003 and 2002 are presented below:

In millions	2004			2003			2002
Operating revenues	$	1,832		$	983		$	877
Operating expenses		(1,500	)		(741	)		(660	)
Gain on sale of Caroline Street campus		-			16			-
Operating income		332			258			217
Other income		-			40			30
Minority interest		(18	)		-
EBIT		314			298			247
Interest expense		71			75			86
Earnings before income taxes		243			223			161
Income taxes		90			87			58
Income before cumulative effect of change in accounting principle		153			136			103
Cumulative effect of change in accounting principle		-			8			-
Net income	$	153		$	128		$	103

47

Summarized income statement, balance sheet and capital expenditure information by segment as of and for the years ended December 31, 2004, 2003 and 2002 are shown in the following tables:

2004
In millions	Distribution Operations		Retail Energy Operations			Wholesale Services		Energy Investments		Corporate and Intersegment Eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	926	$	827		$	54	$	25	$	-		$	1,832
Intersegment revenues (1)		185		-			-		-		(185	)		-
Total revenues		1,111		827			54		25		(185	)		1,832
Operating expenses
Cost of gas		470		695			1		12		(184	)		994
Operating and maintenance		286		60			27		5		(1	)		377
Depreciation and amortization		85		2			1		2		9			99
Taxes other than income taxes		24		-			1		1		4			30
Total operating expenses		865		757			30		20		(172	)		1,500
Operating income (loss)		246		70			24		5		(13	)		332
Earnings in equity interests		-		-			-		2		-			2
Minority interest		-		(18	)		-		-		-			(18	)
Other income (loss)		1		-			-		-		(3	)		(2	)
EBIT	$	247	$	52		$	24	$	7		($16	)	$	314
Identifiable assets	$	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
Goodwill	$	340	$	-		$	-	$	14	$	-		$	354
Capital expenditures	$	205	$	4		$	8	$	36	$	11		$	264

2003
In millions	Distribution Operations			Retail Energy Operations		Wholesale Services		Energy Investments			Corporate and Intersegment Eliminations			Consolidated AGL Resources
Operating revenues (1)	$	936		$	-	$	41	$	6		$	-		$	983
Operating expenses
Cost of gas		337			-		1		1			-			339
Operation and maintenance		261			-		20		9			(7	)		283
Depreciation and amortization		81			-		-		1			9			91
Taxes other than income taxes		24			-		-		-			4			28
Total operating expenses		703			-		21		11			6			741
Gain (loss) on sale of Caroline Street campus (2)		21			-		-		-			(5	)		16
Operating income (loss)		254			-		20		(5	)		(11	)		258
Donation to private foundation		(8	)		-		-		-			-			(8	)
Earnings in equity interests		-			46		-		2			-			48
Other income (loss)		1			-		-		-			(1	)		-
EBIT	$	247		$	46	$	20		($3	)		($12	)	$	298
Identifiable assets	$	3,325		$	-	$	460	$	90		$	2		$	3,877
Investment in joint ventures		-			71		-		30			-			101
Total assets	$	3,325		$	71	$	460	$	120		$	2		$	3,978
Goodwill	$	177		$	-	$	-	$	-		$	-		$	177
Capital expenditures	$	126		$	-	$	2	$	8		$	22		$	158

48

2002
In millions	Distribution Operations		Retail Energy Operations		Wholesale Services		Energy Investments			Corporate and Intersegment Eliminations			Consolidated AGL Resources
Operating revenues (1)	$	852	$	-	$	23	$	2		$	-		$	877
Operating expenses
Cost of gas		267		-		-		-			1			268
Operation and maintenance		255		-		13		8			(2	)		274
Depreciation and amortization		82		-		-		-			7			89
Taxes other than income taxes		25		-		1		1			2			29
Total operating expenses		629		-		14		9			8			660
Operating income (loss)		223		-		9		(7	)		(8	)		217
Interest income		1		-		-		-			-			1
Earnings in equity interests		-		27		-		-			-			27
Other income (loss)		1		-		-		4			(3	)		2
EBIT	$	225	$	27	$	9		($3	)		($11	)	$	247
Identifiable assets	$	3,150	$	-	$	364	$	107		$	46		$	3,667
Investment in joint ventures		-		45		-		30			-			75
Total assets	$	3,150	$	45	$	364	$	137		$	46		$	3,742
Capital expenditures	$	128	$	-	$	1	$	29		$	29		$	187

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

In millions	Third-Party Gross Revenues		Intersegment Revenues		Total Gross Revenues
2004	$	4,378	$	369	$	4,747
2003		3,298		353		3,651
2002		1,639		131		1,770

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

49

> Note 15

Quarterly Financial Data (Unaudited)

Our quarterly financial data for 2004, 2003 and 2002 are summarized below. The variance in our quarterly earnings is the result of the seasonal nature of our primary business.

2004
In millions, except per share amounts	March 31		June 30		Sept. 30		Dec. 31
Operating revenues	$	651	$	294	$	262	$	625
Operating income		133		53		46		100
Net income		66		21		20		46
Basic earnings per share		1.02		0.34		0.31		0.64
Fully diluted earnings per share		1.00		0.33		0.31		0.64

2003
In millions, except per share amounts	March 31		June 30		Sept. 30		Dec. 31
Operating revenues	$	353	$	187	$	166	$	278
Operating income		101		41		58		58
Income before cumulative effect of change in accounting principle		60		19		22		35
Net income		52		19		22		35
Basic earnings per share before cumulative change in accounting principle		0.99		0.30		0.35		0.54
Basic earnings per share		0.86		0.30		0.35		0.54
Fully diluted earnings per share before cumulative change in accounting principle		0.98		0.29		0.34		0.54
Fully diluted earnings per share		0.85		0.29		0.34		0.54

2002
In millions, except per share amounts	March 31		June 30		Sept. 30		Dec. 31
Operating revenues	$	272	$	161	$	193	$	251
Operating income		74		42		38		63
Net income		50		12		10		31
Basic earnings per share		0.90		0.22		0.17		0.55
Fully diluted earnings per share		0.89		0.22		0.17		0.55

Our basic and fully diluted earnings per common share are calculated based on the weighted daily average number of common shares and common share equivalents outstanding during the quarter. Those totals differ from the basic and fully diluted earnings per share as shown on the statements of consolidated income, which are based on the weighted average number of common shares and common share equivalents outstanding during the entire year.

50

Management's Reports on Internal Control Over Financial Reporting

AGL Resources Inc.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We excluded Jefferson Island Storage & Hub, LLC and NUI Corporation from our assessment of internal control over financial reporting as of December 31, 2004 because they were acquired by us in purchase business combinations during the fourth quarter of 2004. Jefferson Island Storage & Hub, LLC's and NUI Corporation's total assets represents $86 million and $1,352 million, and total revenues represents $11 million and $86 million, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2004.

Based on our evaluation under the framework in Internal Control -- Integrated Framework issued by COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which insofar as it relates to the effectiveness of SouthStar Energy Services LLC is based solely upon the report of other auditors and is included herein.

February 14, 2005

/s/ Paula Rosput Reynolds

Paula Rosput Reynolds

Chairman, President and Chief Executive Officer

/s/ Richard T. O'Brien

Richard T. O'Brien

Executive Vice President and Chief Financial Officer

51

Report of Independent Registered Public Accounting Firm

TotheBoard of Directors and Shareholders of AGL Resources Inc.:

We have completed an integrated audit of AGL Resources Inc.’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits and the reports of other auditors, are presented below.

Consolidated financial statements and financial statement schedule

In our opinion, based on our audits and the report of other auditors, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of AGL Resources Inc. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, based on our audits and the report of other auditors, the 2004 and 2003 financial statement schedule information listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement scheduleare the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedulebased on our audits. We did not audit the financial statements of SouthStar Energy Services LLC, a joint venture in which a subsidiary of the Company has a non-controlling 70% financial interest, which statements reflect total assets of $243 million and total revenues of $827 million as of and for the year ended December 31, 2004. The Company’s equity investment in SouthStar Energy Services LLC was $71 million and equity in earnings was $46 million as of and for the year ended December 31, 2003. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for SouthStar Energy Services LLC., is based solely on the report of the other auditors. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

As discussed in Note 3 to the consolidated financial statements, effective January 1, 2004, AGL Resources Inc. and subsidiaries adopted Financial Accounting Standards Board (FASB) Interpretation No. 46-R, “Consolidation of Variable Interest Entities”.

Internal control over financial reporting

Also, in our opinion, based on our audit and the report of other auditors, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting related to AGL Resources Inc. appearing above, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, based on our audit and the report of other auditors, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We did not examine the effectiveness of internal control of SouthStar Energy Services LLC as of December 31, 2004. The effectiveness of SouthStar Energy Services LLC’s internal control over financial reporting was audited by other auditors whose report has been furnished to us, and our opinions expressed herein, insofar as they relate to the effectiveness of SouthStar Energy Services LLC’s internal control over financial reporting are based solely on the report of the other auditors. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit and the report of the other auditors provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Jefferson Island Storage & Hub LLC and NUI Corporation from its assessment of internal control over financial reporting as of December 31, 2004 because they were acquired by the Company in purchase business combinations during 2004. We have also excluded Jefferson Island Storage & Hub LLC and NUI Corporation from our audit of internal control over financial reporting. Jefferson Island Storage & Hub LLC and NUI Corporation are wholly owned subsidiaries whose total assets represent $86 million and $1,352 million and total revenues represent $11 million and $86 million, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2004.

/s/ PricewaterhouseCoopers LLP

Atlanta, Ga.

February 14, 2005 except as to the effects of reclassifications of 2004, 2003 and 2002 amounts for reportable segments as discussed in Note 14, as to which the date is July 22, 2005

52

Management's Reports on Internal Control Over Financial Reporting

SouthStar Energy Services LLC

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and in accordance with, 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. Based on our evaluation under the framework in Internal Control - Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

February 2, 2005

/s/ Michael A. Braswell

Michael A. Braswell

President, SouthStar Energy Services LLC

/s/ Michael A. Degnan

Michael A. Degnan

Director, Finance & Accounting, SouthStar Energy Services LLC

53

REPORT OF ERNST & YOUNG LLP,

INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Executive Committee and Members

SouthStar Energy Services LLC

We have audited the balance sheets of SouthStar Energy Services LLC (the Company) as of December 31, 2004 and 2003, and the related statements of income, changes in members’ capital, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of SouthStar Energy Services LLC at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of SouthStar Energy Services LLC's internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 4, 2005 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Atlanta, Georgia

February 4, 2005

54

Report of Independent Registered Public Accounting Firm

The Executive Committee and Members of SouthStar Energy Services LLC

We have audited management’s assessment, included in the accompanying Report of Management on Internal Control Over Financial Reporting, that SouthStar Energy Services LLC (“SouthStar”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). SouthStar’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that SouthStar maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, SouthStar maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of SouthStar as of December 31, 2004 and 2003, and the related statements of income, changes in members’ capital, and cash flows for each of the three years in the period ended December 31, 2004 of SouthStar and our report dated February 4, 2005 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Atlanta, Georgia

February 4, 2005

55

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of

Directors of AGL Resources Inc.:

We have audited the accompanying consolidated statements of income, common shareholders’ equity, and cash flows for the year ended December 31, 2002 (prior to restatement of the segment presentation in Footnote 14) of AGL Resources Inc. and subsidiaries (the “Company”). Our audit also included the financial statement schedule listed in the accompanying index for the year ended December 31, 2002. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of AGL Resources Inc. and subsidiaries for the year ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

January 27, 2003

56

Schedule II

AGL Resources Inc. and Subsidiaries

VALUATION AND QUALIFYING ACCOUNTS - ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS AND INCOME TAX VALUATION FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 2004.

In millions	Allowance for uncollectible accounts			Income tax valuation
Balance at December 31, 2001	$	7		$	-
Provisions charged to income in 2002		3			-
Accounts written off as uncollectible, net in 2002		(8	)		-
Balance at December 31, 2002		2			-
Provisions charged to income in 2003		6			-
Accounts written off as uncollectible, net in 2003		(6	)		-
Balance at December 31, 2003		2			-
Provisions charged to income in 2004		5			-
Accounts written off as uncollectible, net in 2004		(5	)		-
Additional provisions due to NUI acquisition		4			8
Additional provisions due to consolidation of SouthStar		9			-
Balance at December 31, 2004	$	15		$	8

57