SOUTHERN Co GAS 8K Other Events | GAS 13 Jul 09

Exhibit 99.4

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of AGL Resources Inc.:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of AGL Resources Inc. (the “Company”) and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule ( not presented herein) listed in the index appearing under Item 15(a)(2) of the Company’s 2008 Annual Report on Form 10-K presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Notes 4 and 3, respectively, to the consolidated financial statements, AGL Resources Inc. and subsidiaries changed its method of accounting for stock based compensation plans as of January 1, 2006 and its method of accounting for defined benefit pension and other postretirement plans as of December 31, 2006. As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for noncontrolling interests effective January 1, 2009.

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.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Atlanta, Georgia

February 5, 2009, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the change in accounting for noncontrolling interests discussed in Note 1, as to which the date is July 13, 2009.

Management’s Report on Internal Control Over Financial Reporting

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).

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, 2008, in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

February 5, 2009

/s/ John W. Somerhalder II

John W. Somerhalder II

Chairman, President and Chief Executive Officer

/s/ Andrew W. Evans

Andrew W. Evans

Executive Vice President and Chief Financial Officer

GLOSSARY OF KEY TERMS

Atlanta Gas Light	Atlanta Gas Light Company
AGL Capital	AGL Capital Corporation
AGL Networks	AGL Networks, LLC
AGSC	AGL Services Company, a service company established in accordance with SEC regulations
AIP	Annual Incentive Plan
Bcf	Billion cubic feet
Chattanooga Gas	Chattanooga Gas Company
Compass Energy	Compass Energy Services, Inc.
Credit Facilities	$1.0 billion and $140 million credit agreements of AGL Capital
Deregulation Act	1997 Natural Gas Competition and Deregulation Act
Dominion Ohio	Dominion East of Ohio, a Cleveland, Ohio based natural gas company; a subsidiary of Dominion Resources, Inc.
EBIT	Earnings before interest and taxes, a non-GAAP measure that includes operating income, other income and gain on sales of assets and excludes interest and income 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 attributable to AGL Resources Inc. as determined in accordance with GAAP
EITF	Emerging Issues Task Force
Energy Act	Energy Policy Act of 2005
ERC	Environmental remediation costs associated with our distribution operations segment which are recoverable through rates mechanisms
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
Florida Commission	Florida Public Service Commission
FSP	FASB Staff Position
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission
Golden Triangle Storage	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of the effects of weather on our businesses, calculated when the average daily actual temperatures are less than a baseline temperature of 65 degrees Fahrenheit.
Heating Season	The period from November to March when natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems when weather is colder
Jefferson Island	Jefferson Island Storage & Hub, LLC
LIBOR	London interbank offered rate
LNG	Liquefied natural gas
LOCOM	Lower of weighted average cost or current market price
Louisiana DNR	Louisiana Department of Natural Resources
Magnolia	Magnolia Enterprise Holdings, Inc.
Maryland Commission	Maryland Public Service Commission
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
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%
MGP	Manufactured gas plant
MMBtu	NYMEX equivalent contract units of 10,000 million British thermal units
Moody’s	Moody’s Investors Service
New Jersey Commission	New Jersey Board of Public Utilities
NUI	NUI Corporation - an acquisition which was completed in November 2004
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A 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 or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our statements of consolidated income.
OTC	Over-the-counter
Piedmont	Piedmont Natural Gas
Pivotal Propane	Pivotal Propane of Virginia, Inc.
Pivotal Utility	Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PP&E	Property, plant and equipment
PRP	Pipeline replacement program for Atlanta Gas Light
S&P	Standard & Poor’s Ratings Services
Saltville	Saltville Gas Storage Company
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
SFAS	Statement of Financial Accounting Standards
SNG	Southern Natural Gas Company, a subsidiary of El Paso Corporation
SouthStar	SouthStar Energy Services LLC
Tennessee Commission	Tennessee Regulatory Authority
VaR	Value at risk is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability
Virginia Natural Gas	Virginia Natural Gas, Inc.
Virginia Commission	Virginia State Corporation Commission
WACOG	Weighted average cost of goods
WNA	Weather normalization adjustment

REFERENCED ACCOUNTING STANDARDS

APB 25	APB Opinion No. 25, “Accounting for Stock Issued to Employees”
EITF 98-10	EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”
EITF 99-02	EITF Issue No. 99-02, “Accounting for Weather Derivatives”
EITF 00-11	EITF Issue No. 00-11, “Lessor’s Evaluation of Whether Leases of Certain Integral Equipment Meet the Ownership Transfer Requirements of FASB Statement No. 13, Accounting for Leases, for Leases of Real Estate”
EITF 02-03	EITF 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 39	FASB Interpretation No. (FIN) 39 “Offsetting of Amounts Related to Certain Contracts”
FSP FIN 39-1	FASB Staff Position 39-1 “Amendment of FIN 39”
FIN 46 & FIN 46R	FIN 46, “Consolidation of Variable Interest Entities”
FIN 48	FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of SFAS Statement No. 109”

FSP EITF 03-6-1	FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”
FSP EITF 06-3	FSP EITF 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation)”
FSP FAS 133-1	FSP No. FAS 133-1, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133”
FSP FAS 140-R and FIN 46R-8	FSP No. FAS 140-R and FIN 46R-8, “Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities”
FSP FAS 157-3	FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”
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 87	SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS 106	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS 123 & SFAS 123R	SFAS No. 123, “Accounting for Stock-Based Compensation”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 140	SFAS No. 140, “Accounting for Transfers and Servicing Financial Assets and Extinguishments of Liabilities”
SFAS 141	SFAS No. 141, “Business Combinations”
SFAS 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 148	SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”
SFAS 149	SFAS No. 149, “Amendment of SFAS 133 on Derivative Instruments and Hedging Activities”
SFAS 157	SFAS No. 157, “Fair Value Measurements”
SFAS 158	SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”
SFAS 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements”
SFAS 161	SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of SFAS 133”

AGL Resources Inc.

Consolidated Statements of Financial Position - Assets

	As of
In millions	December 31, 2008			December 31, 2007
Current assets
Cash and cash equivalents (Note 1)	$	16		$	19
Receivables (Note 1)
Energy marketing		549			598
Gas		264			213
Unbilled revenues		181			179
Other		27			13
Less allowance for uncollectible accounts		(16	)		(14	)
Total receivables		1,005			989
Inventories (Note 1)
Natural gas stored underground		629			521
Other		34			30
Total inventories		663			551
Derivative financial instruments – current portion (Note 2)		207			69
Unrecovered pipeline replacement program costs – current portion (Note 1)		41			31
Unrecovered environmental remediation costs – current portion (Notes 1 and 7)		18			23
Other current assets		92			115
Total current assets		2,042			1,797
Long-term assets and other deferred debits
Property, plant and equipment		5,500			5,177
Less accumulated depreciation		1,684			1,611
Property, plant and equipment – net (Note 1)		3,816			3,566
Goodwill (Note 1)		418			420
Unrecovered pipeline replacement program costs (Note 1)		196			254
Unrecovered environmental remediation costs (Notes 1 and 7)		125			135
Other		113			86
Total long-term assets and other deferred debits		4,668			4,461
Total assets	$	6,710		$	6,258

See Notes to Consolidated Financial Statements.

AGL Resources Inc.

Consolidated Statements of Financial Position - Liabilities and Equity

	As of
In millions, except share amounts	December 31, 2008		December 31, 2007
Current liabilities
Short-term debt (Note 6)	$	866	$	580
Energy marketing trade payable		539		578
Accounts payable – trade		202		172
Customer deposits		50		35
Accrued pipeline replacement program costs – current portion (Note 1)		49		55
Derivative financial instruments – current portion (Note 2)		50		16
Accrued wages and salaries		42		24
Accrued taxes		36		23
Accrued interest		35		39
Deferred natural gas costs (Note 1)		25		28
Accrued environmental remediation liabilities – current portion (Notes 1 and 7)		17		10
Other current liabilities		72		74
Total current liabilities		1,983		1,634
Long-term liabilities and other deferred credits
Long-term debt (Note 6)		1,675		1,675
Accumulated deferred income taxes (Note 8)		571		566
Accrued pension obligations (Note 3)		199		43
Accumulated removal costs (Note 1)		178		169
Accrued pipeline replacement program costs (Note 1)		140		190
Accrued environmental remediation liabilities (Notes 1 and 7)		89		97
Accrued postretirement benefit costs (Note 3)		46		24
Other long-term liabilities and other deferred credits		145		152
Total long-term liabilities and other deferred credits		3,043		2,916
Commitments and contingencies (Note 7)
Equity (Note 5)
AGL Resources Inc. common shareholders’ equity, $5 par value; 750 million shares authorized; 76.9 million and 76.4 million shares outstanding at December 31, 2008 and 2007		1,652		1,661
Noncontrolling interest		32		47
Total equity		1,684		1,708
Total liabilities and equity	$	6,710	$	6,258

See Notes to Consolidated Financial Statements.

AGL Resources Inc.

Consolidated Statements of Income

	Years ended December 31,
In millions, except per share amounts	2008			2007			2006
Operating revenues (Note 1)	$	2,800		$	2,494		$	2,621
Operating expenses
Cost of gas (Note 1)		1,654			1,369			1,482
Operation and maintenance		472			451			473
Depreciation and amortization (Note 1)		152			144			138
Taxes other than income taxes		44			41			40
Total operating expenses		2,322			2,005			2,133
Operating income		478			489			488
Other income (expenses)		6			4			(1	)
Interest expense, net		(115	)		(125	)		(123	)
Earnings before income taxes		369			368			364
Income taxes (Note 8)		132			127			129
Net income		237			241			235
Less net income attributable to the noncontrolling interest (Note 1)		20			30			23
Net income attributable to AGL Resources Inc.	$	217		$	211		$	212
Per common share data (Note 1)
Basic earnings per common share attributable to AGL Resources Inc. common shareholders	$	2.85		$	2.74		$	2.73
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders	$	2.84		$	2.72		$	2.72
Cash dividends declared per common share	$	1.68		$	1.64		$	1.48
Weighted average number of common shares outstanding (Note 1)
Basic		76.3			77.1			77.6
Diluted		76.6			77.4			78.0

See Notes to Consolidated Financial Statements.

AGL Resources Inc.

Consolidated Statements of Equity

	AGL Resources Inc. Shareholders
	Common stock					Premium on common			Earnings			Accumulated other comprehensive			Shares held in treasury and			Noncontrolling
In millions, except per share amounts	Shares			Amount		stock			reinvested			loss			trust			interest			Total
Balance as of December 31, 2005		77.8		$	389	$	655		$	508		$	(53	)	$	-		$	38		$	1,537
Net income		-			-		-			212			-			-			23			235
Other comprehensive gain		-			-		-			-			21			-			3			24
Dividends on common stock ($1.48 per share)		-			-		1			(115	)		-			3			-			(111	)
Distributions to noncontrolling interest		-			-		-			-			-			-			(22	)		(22	)
Benefit, stock compensation, dividend reinvestment and stock purchase plans		0.3			1		2			-			-			-			-			3
Issuance of treasury shares		0.6			-		(3	)		(4	)		-			21			-			14
Purchase of treasury shares		(1.0	)		-		-			-			-			(38	)		-			(38	)
Stock-based compensation expense (net of tax of $5)		-			-		9			-			-			-			-			9
Balance as of December 31, 2006		77.7			390		664			601			(32	)		(14	)		42			1,651
Net income		-			-		-			211			-			-			30			241
Other comprehensive gain (loss)		-			-		-			-			19			-			(2	)		17
Dividends on common stock ($1.64 per share)		-			-		-			(127	)		-			4			-			(123	)
Distributions to noncontrolling interest		-			-		-			-			-			-			(23	)		(23	)
Issuance of treasury shares		0.7			-		(6	)		(5	)		-			27			-			16
Purchase of treasury shares		(2.0	)		-		-			-			-			(80	)		-			(80	)
Stock-based compensation expense (net of tax of $3)		-			-		9			-			-			-			-			9
Balance as of December 31, 2007		76.4			390		667			680			(13	)		(63	)	$	47			1,708
Net income		-			-		-			217			-			-			20			237
Other comprehensive loss		-			-		-			-			(121	)		-			(5	)		(126	)
Dividends on common stock ($1.68 per share)		-			-		-			(128	)		-			4			-			(124	)
Distributions to noncontrolling interest		-			-		-			-			-			-			(30	)		(30	)
Issuance of treasury shares		0.5			-		(1	)		(6	)		-			16			-			9
Stock-based compensation expense (net of tax of $1)		-			-		10			-			-			-			-			10
Balance as of December 31, 2008		76.9		$	390	$	676		$	763		$	(134	)	$	(43	)	$	32		$	1,684

See Notes to Consolidated Financial Statements.

AGL Resources Inc.

Consolidated Statements of Comprehensive Income

			Components of other comprehensive (loss) gain (net of taxes)
			Cash flow hedges
In millions	Net income		Unrealized (losses) gains on derivative instruments arising during the period			Reclassification of realized (gains) on derivative instruments included in net income			(Loss) gain resulting from unfunded pension and postretirement obligation arising during the period			Other comprehensive (loss) gain (Note 1)			Comprehensive income
Year ended December 31, 2008:
AGL Resources	$	217	$	(4	)	$	(6	)	$	(111	)	$	(121	)	$	96
Noncontrolling interest		20		(1	)		(4	)		-			(5	)		15
Consolidated	$	237	$	(5	)	$	(10	)	$	(111	)	$	(126	)	$	111

Year ended December 31, 2007:
AGL Resources	$	211	$	3		$	(8	)	$	24		$	19		$	230
Noncontrolling interest		30		1			(3	)		-			(2	)		28
Consolidated	$	241	$	4		$	(11	)	$	24		$	17		$	258

Year ended December 31, 2006:
AGL Resources	$	212	$	11		$	(1	)	$	11		$	21		$	233
Noncontrolling interest		23		4			(1	)		-			3			26
Consolidated	$	235	$	15		$	(2	)	$	11		$	24		$	259

See Notes to Consolidated Financial Statements.

AGL Resources Inc.

Statements of Consolidated Cash Flows

	Years ended December 31,
In millions	2008			2007			2006
Cash flows from operating activities
Net income	$	237		$	241		$	235
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization		152			144			138
Deferred income taxes (Note 8)		89			30			133
Change in derivative financial instrument assets and liabilities (Note 2)		(129	)		74			(112	)
Changes in certain assets and liabilities
Trade payables		30			(35	)		(53	)
Accrued expenses		26			(34	)		15
Energy marketing receivables and energy marketing trade payables, net		10			(26	)		(95	)
Gas, unbilled and other receivables		(65	)		(15	)		170
Inventories		(112	)		46			(54	)
Other – net		(11	)		(48	)		(26	)
Net cash flow provided by operating activities		227			377			351
Cash flows from investing activities
Expenditures for property, plant and equipment		(372	)		(259	)		(253	)
Other		-			6			5
Net cash flow used in investing activities		(372	)		(253	)		(248	)
Cash flows from financing activities
Net payments and borrowings of short-term debt		286			52			6
Issuances of variable rate gas facility revenue bonds (Note 6)		161			-			-
Issuance of treasury shares		9			16			14
Distribution to noncontrolling interest		(30	)		(23	)		(22	)
Dividends paid on common shares		(124	)		(123	)		(111	)
Payments of gas facility revenue bonds (Note 6)		(161	)		-			-
Issuances of senior notes		-			125			175
Payments of medium-term notes		-			(11	)		-
Payments of trust preferred securities		-			(75	)		(150	)
Purchase of treasury shares		-			(80	)		(38	)
Other		1			(3	)		8
Net cash flow provided by (used in) financing activities		142			(122	)		(118	)
Net (decrease) increase in cash and cash equivalents		(3	)		2			(15	)
Cash and cash equivalents at beginning of period		19			17			32
Cash and cash equivalents at end of period	$	16		$	19		$	17
Cash paid during the period for
Interest	$	115		$	127		$	109
Income taxes		27			118			37

See Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements

Note 1 - Accounting Policies and Methods of Application

General

AGL Resources Inc. is an energy services holding company that conducts substantially all its operations through its subsidiaries. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company”, or “AGL Resources” mean consolidated AGL Resources Inc. and its subsidiaries. We have prepared the accompanying consolidated financial statements under the rules of the SEC. For a glossary of key terms and referenced accounting standards, see pages 4 and 5.

Basis of Presentation

Our consolidated financial statements as of and for the period ended December 31, 2008, 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. We have eliminated any intercompany profits and transactions in consolidation; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation.

We currently own a noncontrolling 70% financial interest in SouthStar and Piedmont owns the remaining 30%. Our 70% interest is noncontrolling because all significant management decisions require approval by both owners. We record the earnings allocated to Piedmont as net income attributable to the noncontrolling interest in our consolidated statements of income and we record Piedmont’s portion of SouthStar’s capital as noncontrolling interest in our consolidated statements of financial position.

We are the primary beneficiary of SouthStar’s activities and have determined that SouthStar is a variable interest entity as defined by FIN 46 revised in December 2003, FIN 46R. We determined that SouthStar was a variable interest entity because our equal voting rights with Piedmont are not proportional to our economic obligation to absorb 75% of any losses or residual returns from SouthStar, except those losses and returns related to customers in Ohio and Florida. Earnings related to SouthStar’s customers in Ohio and Florida are allocated 70% to us and 30% to Piedmont. The nature of restrictions on SouthStar’s assets are immaterial. The primary risks associated with SouthStar include weather, government regulation, competition, market risk, natural gas prices, economic conditions, inflation and bad debt. See Note 9 for income statement, statement of financial position and capital expenditure information related to the retail energy operations segment. In addition, SouthStar obtains substantially all its transportation capacity for delivery of natural gas through our wholly-owned subsidiary, Atlanta Gas Light.

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.

Receivables and Allowance for Uncollectible Accounts

Our receivables consist of natural gas sales and transportation services billed to residential, commercial, industrial and other customers. We bill customers 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 and other factors. 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. We write-off our customer’s accounts once we deem them to be uncollectible.

Inventories

For our distribution operations subsidiaries, we record natural gas stored underground at WACOG. For Sequent and SouthStar, we account for natural gas inventory at the lower of WACOG or market price.

Sequent and SouthStar evaluate the average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, adjustments are recorded to reduce the weighted average cost of the natural gas inventory to market price. Consequently, as a result of declining natural gas prices, Sequent recorded LOCOM adjustments against cost of gas to reduce the value of its inventories to market value of $40 million in 2008, $4 million in 2007 and $43 million in 2006. SouthStar recorded LOCOM adjustments of $24 million in 2008 and $6 million in 2006, but was not required to make LOCOM adjustments in 2007.

In Georgia’s competitive environment, Marketers including SouthStar, our marketing subsidiary, 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

A summary of our PP&E by classification as of December 31, 2008 and 2007 is provided in the following table.

In millions	2008				2007
Transmission and distribution	$	4,344		$	4,193
Storage		290			285
Other		543			509
Construction work in progress		323			190
Total gross PP&E		5,500			5,177
Accumulated depreciation		(1,684	)		(1,611	)
Total net PP&E	$	3,816		$	3,566

Distribution Operations PP&E expenditures consist of property and equipment that is in use, being held for future use and under construction. We report PP&E at its original cost, which includes:

·	material and labor

·	contractor costs

·	construction overhead costs

·	an allowance for funds used during construction (AFUDC) which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects and is capitalized in rate base for ratemaking purposes when the completed projects are placed in service

We charge property retired or otherwise disposed of to accumulated depreciation since such costs are recovered in rates.

Retail Energy Operations, Wholesale Services, Energy Investments and Corporate PP&E expenditures include property that is in use and under construction, and we report it at cost. We record a gain or loss for retired or otherwise disposed-of property. Natural gas in storage at Jefferson Island that is retained as pad gas (volumes of non-working natural gas used to maintain the operational integrity of the cavern facility) is classified as non-depreciable property, plant and equipment and is valued at cost.

Depreciation Expense

We compute depreciation expense for distribution operations by applying composite, straight-line rates (approved by the state regulatory agencies) to the investment in depreciable property. The composite straight-line depreciation rate for depreciable property -- excluding transportation equipment for Atlanta Gas Light, Virginia Natural Gas and Chattanooga Gas -- was approximately 2.5% during 2008, 2007 and 2006. The composite, straight-line rate for Elizabethtown Gas, Florida City Gas and Elkton Gas was approximately 3.3 % for 2008, 3.2% during 2007 and 3.0% during 2006. 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 up to 35 years based on the useful life of the asset.

AFUDC

Four of our utilities are authorized by applicable state regulatory agencies or legislatures to record the cost of debt and equity funds as part of the cost of construction projects in our consolidated statements of financial position and as AFUDC of $8 million in 2008, $4 million in 2007 and $5 million in 2006 within in the consolidated statements of income. The capital expenditures of our two other utilities do not qualify for AFUDC treatment. More information on our authorized AFUDC rates is provided in the following table.

	Authorized AFUDC rate
Atlanta Gas Light		8.53	%
Chattanooga Gas (1)		7.89	%
Elizabethtown Gas (2)		2.84	%
Virginia Natural Gas (3)		8.91	%

(1)	Prior to 2007, the authorized rate was 7.43%.

(2)	Variable rate as of December 31, 2008, and is determined by FERC method of AFUDC accounting.

(3)	Approved only for Hampton Roads construction project.

Goodwill

We have included $418 million of goodwill in our consolidated statements of financial position as of December 31, 2008, which consists of:

Date	Acquisition	Goodwill amount
2004	NUI	$	227
2004	Jefferson Island		14
2000	Virginia Natural Gas		170
1998	Chattanooga Gas		7

SFAS 142 requires us to perform an annual goodwill impairment test at a reporting unit level which generally equates to our operating segments as discussed in Note 9 “Segment Information.” We performed this annual test as of our fiscal year-end or December 31, 2008, 2007 and 2006 and did not recognize any impairment charges. We also assess goodwill for impairment if events or changes in circumstances may indicate an impairment of goodwill exists. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, we record an impairment loss equal to the excess of the asset’s carrying value over its fair value. We conduct this assessment principally through a review of our market capitalization relative to our net book value, financial results, changes in state and federal legislation and regulation, regulatory and legal proceedings and the periodic regulatory filings for our regulated utilities.

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 we generally depreciate assets for tax purposes over a shorter period of time than for book purposes. The determination of our provision for income taxes requires significant judgment, the use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items. We report the tax effects of depreciation and other differences in those items as deferred income tax assets or liabilities in our consolidated statements of financial position in accordance with SFAS 109 and FIN 48. Investment tax credits of approximately $14 million previously deducted for income tax purposes for Atlanta Gas Light, Elizabethtown Gas, Florida City Gas and Elkton Gas 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.

We do not collect income taxes from our customers on behalf of governmental authorities. We collect and remit various taxes on behalf of various governmental authorities. We record these amounts in our consolidated statements of financial position except taxes in the state of Florida which we are required to include in revenues and operating expenses. These Florida related taxes are not material for any periods presented.

Revenues

Distribution operations We record revenues when services are provided to customers. Those revenues are based on rates approved by the state regulatory commissions of our utilities.

As required by the Georgia Commission, in July 1998, Atlanta Gas Light began billing Marketers in equal monthly installments for each residential, commercial and industrial customer’s distribution costs. 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, 2008 and 2007 (included as current assets in the consolidated statements of financial position) related to the difference between the billings under the seasonal rate design and the SFV revenue recognized.

The Elizabethtown Gas, Virginia Natural Gas, Florida City Gas, Chattanooga Gas and Elkton 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. Revenues from residential and certain commercial and industrial customers are recognized 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 last meter reading date to the end of the accounting period. These are included in the consolidated statements of financial position as unbilled revenue. For other commercial and industrial customers and all wholesale customers, revenues are based on actual deliveries to the end of the period.

The tariffs for Elizabethtown Gas, Virginia Natural Gas and Chattanooga Gas contain WNA’s that partially 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.

Retail energy operations We record retail energy operations’ revenues when services are provided to customers. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Sales revenues from residential and certain commercial and industrial customers are recognized 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 most recent meter reading date to the end of the accounting period. These are included in the consolidated statements of financial position as unbilled revenue. For other commercial and industrial customers and all wholesale customers, revenues are based on actual deliveries to the end of the period.

Wholesale services We record wholesale services’ revenues when services are provided to customers. 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 133 are recorded at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses.

Energy investments We record operating revenues at Jefferson Island in the period in which actual volumes are transported and storage services are provided. The majority of our storage services are covered under medium to long-term contracts at fixed market rates.

We record operating revenues at AGL Networks from leases of dark fiber pursuant to indefeasible rights-of-use (IRU) agreements as services are provided. Dark fiber IRU agreements generally require the customer to make a down payment upon execution of the agreement; however in some cases AGL Networks receives up to the entire lease payment at the inception of the lease and recognizes ratably over the lease term. AGL Networks had deferred revenue in our consolidated statement of financial position of $33 million at December 31, 2008 and $38 million at December 31, 2007. In addition, AGL Networks recognizes sales revenues upon the execution of certain sales-type agreements for dark fiber when the agreements provide for the transfer of legal title to the dark fiber to the customer at the end of the agreement’s term. This sales-type accounting treatment is in accordance with EITF 00-11 and SFAS 66, which provides that such transactions meet the criteria for sales-type lease accounting if the agreement obligates the lessor to convey ownership of the underlying asset to the lessee by the end of the lease term.

Cost of gas

Excluding Atlanta Gas Light, we charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the state regulatory agencies. Under the these mechanisms, we defer (that is, include as a current asset or liability in the consolidated statements of financial position and exclude from the statements of consolidated income) the difference between the actual cost of gas and what is collected from or billed to customers in a given period. The deferred amount is either billed or refunded to our customers prospectively through adjustments to the commodity rate.

Our retail energy operations customers are charged for natural gas consumed. We also include within our cost of gas amounts for fuel and lost and unaccounted for gas, adjustments to reduce the value of our inventories to market value and for gains and losses associated with derivatives.

Comprehensive Income

Our comprehensive income includes net income and net income attributable to AGL Resources Inc. plus OCI, which includes other gains and losses affecting equity that GAAP excludes from net income and net income attributable to AGL Resources Inc. Such items consist primarily of unrealized gains and losses on certain derivatives designated as cash flow hedges and overfunded or unfunded pension obligation adjustments.

Earnings Per Common Share

We compute basic earnings per common share attributable to AGL Resources Inc. common shareholders by dividing our income attributable to AGL Resources Inc. common shareholders by the daily weighted average number of common shares outstanding. Diluted earnings per common share attributable to AGL Resources Inc. common shareholders reflect the potential reduction in earnings per common share attributable to AGL Resources Inc. common shareholders 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 restricted stock, restricted stock units and stock options. The future issuance of shares underlying the restricted stock and restricted share units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends on whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. The following table shows the calculation of our diluted earnings per share attributable to AGL Resources Inc. 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	2008		2007		2006
Denominator for basic earnings per share attributable to AGL Resources Inc. (1)		76.3		77.1		77.6
Assumed exercise of potential common shares		0.3		0.3		0.4
Denominator for diluted earnings per share attributable to AGL Resources Inc.		76.6		77.4		78.0

(1)	Daily weighted average shares outstanding.

The following table contains the weighted average shares attributable to outstanding stock options that were excluded from the computation of diluted earnings per share attributable to AGL Resources Inc. because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price:

	December 31,
In millions	2008		2007		2006
Twelve months ended (1)		1.6		0.0		0.0

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

The increase in the number of shares that were excluded from the computation is the result of a significant decline in the market value of our common shares attributable to AGL Resources Inc. common shareholders at December 31, 2008 as compared to December 31, 2007 and 2006.

Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our consolidated statements of financial position in accordance with SFAS 71. Our regulatory assets and liabilities, and associated liabilities for our unrecovered PRP costs, unrecovered ERC and the associated assets and liabilities for our Elizabethtown Gas hedging program, are summarized in the following table.

	December 31,
In millions	2008		2007
Regulatory assets
Unrecovered PRP costs	$	237	$	285
Unrecovered ERC (1)		143		158
Unrecovered postretirement benefit costs		11		12
Unrecovered seasonal rates		11		11
Unrecovered natural gas costs		19		23
Other		30		24
Total regulatory assets		451		513
Associated assets
Elizabethtown Gas derivative financial instruments		23		4
Total regulatory and associated assets	$	474	$	517
Regulatory liabilities
Accumulated removal costs	$	178	$	169
Elizabethtown Gas derivative financial instruments		23		4
Unamortized investment tax credit		14		16
Deferred natural gas costs		25		28
Regulatory tax liability		19		20
Other		22		19
Total regulatory liabilities		281		256
Associated liabilities
PRP costs		189		245
ERC (1)		96		96
Total associated liabilities		285		341
Total regulatory and associated liabilities	$	566	$	597

(1)	For a discussion of ERC, see Note 7.

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 regulatory assets that would result in a charge to net income, and be classified as an extraordinary item. Additionally, the regulatory liabilities would not be written-off but would continue to be recorded as liabilities but not as regulatory liabilities. Although the natural 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 preceding table are included in base rates except for the unrecovered PRP costs, unrecovered ERC and deferred natural gas costs, which are recovered through specific rate riders on a dollar for dollar basis. The rate riders that authorize recovery of unrecovered PRP costs and the deferred natural gas costs 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 ERC. The ERC 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. ERC 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. Elizabethtown Gas’ derivative financial instruments asset and liability reflect unrealized losses or gains that will be recovered from or passed to rate payers through the recovery of its natural gas costs on a dollar for dollar basis, once the losses or gains are realized. Unrecovered postretirement benefit costs are recoverable through base rates over the next 5 to 24 years based on the remaining recovery period as designated by the applicable state regulatory commissions. Unrecovered seasonal rates reflect the difference between the recognition of a portion of Atlanta Gas Light’s residential base rates revenues on a straight-line basis as compared to the collection of the revenues over a seasonal pattern. The unrecovered amounts are fully recoverable through base rates within one year.

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.

Pipeline Replacement Program

Atlanta Gas Light The PRP, ordered by the Georgia Commission to be administered by Atlanta Gas Light, requires, among other things, that Atlanta Gas Light 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 subsequently identified an additional 320 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.

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 straight-fixed-variable 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

On June 10, 2005, Atlanta Gas Light and the Georgia Commission entered into a Settlement Agreement that, among other things, extends Atlanta Gas Light’s PRP by five years to require that all replacements be completed by December 2013. The timing of replacements was subsequently specified in an amendment to the PRP stipulation. This amendment, which was approved by the Georgia Commission on December 20, 2005, requires Atlanta Gas Light to replace all cast iron pipe and 70% of all bare steel pipe by December 2010. The remaining 30% of bare steel pipe is required to be replaced by December 2013. These replacements are on schedule.

Under the Settlement Agreement, base rates charged to customers will remain unchanged through April 30, 2010, but Atlanta Gas Light will recognize reduced base rate revenues of $5 million on an annual basis through April 30, 2010. The five-year total reduction in recognized base rate revenues of $25 million will be applied to the allowed amount of costs incurred to replace pipe, which will reduce the amounts recovered from customers under the PRP rider. The Settlement Agreement also set the per customer fixed PRP rate that Atlanta Gas Light will charge at $1.29 per customer per month from May 2005 through September 2008 and at $1.95 from October 2008 through December 2013 and includes a provision that allows for a true-up of any over- or under-recovery of PRP revenues that may result from a difference between PRP charges collected through fixed rates and actual PRP revenues recognized through the remainder of the program.

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

Atlanta Gas Light has recorded a long-term regulatory asset of $196 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 $41 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:

·	$30 million in 2008

·	$27 million in 2007

·	$27 million in 2006

As of December 31, 2008, Atlanta Gas Light had recorded a current liability of $49 million representing expected program expenditures for the next 12 months and a long-term liability of $140 million, representing expected program expenditures starting in 2009 through the end of the program in 2013.

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.

Elizabethtown Gas In August 2006, the New Jersey Commission issued an order adopting a pipeline replacement cost recovery rider program for the replacement of certain 8” cast iron main pipes and any unanticipated 10”-12” cast iron main pipes integral to the replacement of the 8” main pipes. The order allows Elizabethtown Gas to recognize revenues under a deferred recovery mechanism for costs to replace the pipe that exceeds a baseline amount of $3 million. Elizabethtown Gas’ recognition of these revenues could be disallowed by the New Jersey Commission if its return on equity exceeds the authorized rate of 10%. The term of the stipulation was from the date of the order through December 31, 2008. Total replacement costs through December 31, 2008 were $21 million, of which $16 million will be eligible for the deferred recovery mechanism. Revenues recognized and deferred for recovery under the stipulation are estimated to be approximately $2 million. All costs incurred under the program will be included in Elizabethtown Gas’ next rate case to be filed in 2009.

Use of Accounting Estimates

The preparation of our financial statements in conformity with GAAP requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, and we evaluate our estimates on an ongoing basis. Each of our estimates involve complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. The most significant estimates include our PRP accruals, environmental liability accruals, uncollectible accounts and other allowance for contingencies, pension and postretirement obligations, derivative and hedging activities and provision for income taxes. Our actual results could differ from our estimates.

Accounting Developments

Previously discussed

SFAS 160 In December 2007, the FASB issued SFAS 160, which is effective for fiscal years beginning after December 15, 2008. We adopted SFAS 160 on January 1, 2009, and applied the presentation and disclosure requirements retrospectively for all periods presented. SFAS 160 does not change the requirements of FIN 46R and provides that the noncontrolling interest should be reported as a separate component of equity on our consolidated statement of financial position.

Additionally, prior to adoption of SFAS 160, we recorded our earnings allocated to Piedmont as a component of earnings before income taxes in our consolidated statements of income. SFAS 160 requires that any net income attributable to the noncontrolling interest be presented separately in our consolidated statements of income. As a result, net income from noncontrolling interest is reported after net income in order to report net income attributable to the parent and the noncontrolling interest. The adoption of SFAS 160 has no effect on our calculation of basic or diluted earnings per share amounts, which will continue to be based upon amounts attributable to AGL Resources.

Recently issued

SFAS 161 In March 2008, the FASB issued SFAS 161, which is effective for fiscal years beginning after November 15, 2008. SFAS 161 amends the disclosure requirements of SFAS 133 to provide an enhanced understanding of how and why derivative instruments are used, how they are accounted for and their effect on an entity’s financial condition, performance and cash flows. We will adopt SFAS 161 effective on January 1, 2009, which will require additional disclosures, but will not have a financial impact to our consolidated results of operations, cash flows or financial condition.

FSP EITF 03-6-1 The FASB issued this FSP in June 2008 and it is effective for fiscal years beginning after December 15, 2008. This FSP classifies unvested share-based payment grants containing nonforfeitable rights to dividends as participating securities that will be included in the computation of earnings per share. As of December 31, 2008, we had approximately 145,000 restricted shares with nonforfeitable dividend rights. We will adopt FSP EITF 03-6-1 effective on January 1, 2009.

FSP FAS 133-1 The FASB issued this FSP in September 2008 and it is effective for fiscal years beginning after November 15, 2008. This FSP requires more detailed disclosures about credit derivatives, including the potential adverse effects of changes in credit risk on the financial position, financial performance and cash flows of the sellers of the instruments. This FSP will have no financial impact to our consolidated results of operations, cash flows or financial condition. We will adopt FSP FAS 133-1 effective on January 1, 2009.

FSP FAS 157-3 The FASB issued this FSP in October 2008 and it is effective upon issuance including prior periods for which financial statements have not been issued. This FSP clarifies the application of SFAS 157 in an inactive market, including; how internal assumptions should be considered when measuring fair value, how observable market information in a market that is not active should be considered and how the use of market quotes should be used when assessing observable and unobservable data. We adopted this FSP as of September 30, 2008, it had no financial impact to our consolidated results of operations, cash flows or financial condition.

FSP FAS 140-4 and FIN 46R-8 The FASB issued this FSP in December 2008 and it is effective for the first reporting period ending after December 15, 2008. This FSP requires additional disclosures related to variable interest entities in accordance with SFAS 140 and FIN 46R. These disclosures include significant judgments and assumptions, restrictions on assets, risks and the affects on financial position, financial performance and cash flows. We adopted this FSP as of December 31, 2008, it had no financial impact to our consolidated results of operations, cash flows or financial condition.

Note 2 – Derivative Financial Instruments and Risk Management

Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting Arrangements

We maintain accounts with brokers to facilitate financial derivative transactions in support of our derivative instrument activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts.

On January 1, 2008, we adopted FIN 39-1, which required that we offset cash collateral held in these broker accounts on our condensed consolidated statements of financial position with the associated fair value of the instruments in the accounts. Prior to the adoption of FIN 39-1, we presented such cash collateral on a gross basis within other current assets and liabilities on our condensed consolidated statements of financial position. Our cash collateral amounts are provided in the following table.

	As of December 31,
In millions	2008			2007
Right to reclaim cash collateral	$	128		$	3
Obligations to return cash collateral		(4	)		(10	)
Total cash collateral	$	124		$	(7	)

Fair value measurements

In September 2006, the FASB issued SFAS 157, which establishes a framework for measuring fair value and requires expanded disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements; however, it eliminates inconsistencies in the guidance provided in previous accounting pronouncements. The carrying value of cash and cash equivalents, receivables, accounts payable, other current liabilities and accrued interest approximate fair value. The following table shows the carrying amounts and fair values of our long-term debt including any current portions included in our condensed consolidated statements of financial position.

In millions	Carrying amount		Estimated fair value
As of December 31, 2008	$	1,675	$	1,647
As of December 31, 2007		1,675		1,710

We estimate the fair value of our long-term debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we considered our currently assigned ratings for unsecured debt of BBB+ by S&P, Baa1 by Moody’s and A- by Fitch.

SFAS 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In December 2007, the FASB provided a one-year deferral of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value on a recurring basis, at least annually. We adopted SFAS 157 on January 1, 2008, for our financial assets and liabilities, which primarily consist of derivatives we record in accordance with SFAS 133. The adoption of SFAS 157 primarily impacts our disclosures and did not have a material impact on our condensed consolidated results of operations, cash flows and financial condition. We will adopt SFAS 157 for our nonfinancial assets and liabilities on January 1, 2009, and are currently evaluating the impact to our condensed consolidated results of operations, cash flows and financial condition.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observance of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1

Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of financial instruments with exchange-traded derivatives.

Level 2

Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options.

Level 3

Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. We do not have any material assets or liabilities classified as level 3.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Recurring fair value measurements as of December 31, 2008

In millions	Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Netting of cash collateral			Total carrying value
Assets: (1)
Derivatives at wholesale services	$	17	$	154	$	-	$	35		$	206
Derivatives at distribution operations		23		-		-		-			23
Derivatives at retail energy operations (3)		12		-		-		-			12
Total assets	$	52	$	154	$	-	$	35		$	241
Liabilities: (2)
Derivatives at wholesale services	$	62	$	27	$	-	$	(62	)	$	27
Derivatives at distribution operations		23		-		-		4			27
Derivatives at retail energy operations		32		1		-		(31	)		2
Total liabilities	$	117	$	28	$	-	$	(89	)	$	56
(1) Includes $203 million of current assets and $38 million of long-term assets reflected within our consolidated statement of financial position. (2) Includes $50 million of current liabilities and $6 million of long-term liabilities reflected within our consolidated statement of financial position. (3) $4 million premium associated with weather derivatives has been excluded as they are based on intrinsic value, not fair value.

The determination of the fair values above incorporates various factors required under SFAS 157. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities.

Derivatives at distribution operations relate to Elizabethtown Gas and are utilized in accordance with a directive from the New Jersey Commission to create a program to hedge the impact of market fluctuations in natural gas prices. These derivative products are accounted for at fair value each reporting period. In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in purchased gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset or liability, as appropriate, in our condensed consolidated statements of financial position.

Sequent’s and SouthStar’s derivatives include exchange-traded and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within level 1. Some exchange-traded derivatives are valued using broker or dealer quotation services, or market transactions in either the listed or OTC markets, which are classified within level 2.

At the beginning of 2008, we had a notional principal amount of $100 million of interest rate swap agreements associated with our senior notes. In March 2008, we terminated these interest rate swap agreements. We received a payment of $2 million, which included accrued interest and the fair value of the interest rate swap agreements at the termination date. The payment was recorded as deferred income and classified as a liability in our consolidated statements of financial position. The amount will be amortized through January 2011, the remaining life of the associated senior notes. The following table sets forth a reconciliation of the termination of our interest rate swaps, classified as level 3 in the fair value hierarchy.

In millions	Year ended December 31, 2008
Balance as of January 1, 2008	$	(2	)
Realized and unrealized gains		-
Settlements		2
Transfers in or out of level 3		-
Balance as of December 31, 2008	$	-
Change in unrealized gains (losses) relating to instruments held as of December 31, 2008	$	-

Transfers in or out of level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the methodology inputs became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

Risk Management

Our risk management activities are monitored by our Risk Management Committee (RMC), which consists of members of senior management. The RMC and is charged with reviewing and enforcing 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, interest rate, weather, fuel price and foreign currency risks:

·	forward contracts

·	futures contracts

·	options contracts

·	financial swaps

·	treasury locks

·	weather derivative contracts

·	storage and transportation capacity transactions

·	foreign currency forward contracts

Interest Rate Swaps

To maintain an effective capital structure, our policy is to borrow funds using a mix of fixed-rate and variable-rate debt. We entered into interest rate swap agreements for the purpose of managing the appropriate mix of risk associated with our fixed-rate and variable-rate debt obligations. We designated these interest rate swaps as fair value hedges in accordance with SFAS 133. 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 interest rate risk being hedged.

Commodity-related Derivative Instruments

All activities associated with price risk management activities and derivative instruments are included as a component of cash flows from operating activities in our consolidated statements of cash flows. Our derivatives not designated as hedges under SFAS 133, included within operating cash flows as a source (use) of cash was $(129) million in 2008, $74 million in 2007, and $(112) million in 2006.

Elizabethtown Gas In accordance with a directive from the New Jersey Commission, Elizabethtown Gas enters into derivative transactions to hedge the impact of market fluctuations in natural gas prices. Pursuant to SFAS 133, such derivative transactions are marked to market each reporting period. In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in purchased gas costs and ultimately included in billings to customers. As of December 31, 2008, Elizabethtown Gas had entered into OTC swap contracts to purchase approximately 11 Bcf of natural gas. Approximately 57% of these contracts have durations of one year or less, and none of these contracts extends beyond January 2011. The fair values of these derivative instruments were reflected as a current asset and liability of $23 million at December 31, 2008 and $4 million at December 31, 2007. For more information on our regulatory assets and liabilities see Note 1.

SouthStar Commodity-related derivative financial instruments (futures, options and swaps) are used by SouthStar to manage exposures arising from changing commodity prices. SouthStar’s objective for holding these derivatives is to utilize the most effective method to reduce or eliminate the impact of this exposure. We have designated a portion of SouthStar’s derivative transactions as cash flow hedges under SFAS 133. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period as the settlement of the underlying hedged item. We record any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not offset and are greater than the losses or gains on the hedged item, in cost of gas in our statement of consolidated income in the period in which it occurs. SouthStar currently has minimal hedge ineffectiveness. We have not designated the remainder of SouthStar’s derivative instruments as hedges under SFAS 133 and, accordingly, we record changes in their fair value as cost of gas in our statements of consolidated income in the period of change.

At December 31, 2008, the fair values of these derivatives were reflected in our consolidated financial statements as a current asset of $11 million, a long-term asset of $5 million and a current liability of $2 million representing a net position of 28 Bcf. This includes a $4 million current asset associated with a premium for weather derivatives.

SouthStar also enters into both exchange and OTC derivative transactions to hedge commodity price risk. Credit risk is mitigated for exchange transactions through the backing of the NYMEX member firms. For OTC transactions, SouthStar utilizes master netting arrangements to reduce overall credit risk. As of December 31, 2008, SouthStar’s maximum exposure to any single OTC counterparty was $8 million.

Sequent We 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 use.

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

At December 31, 2008, Sequent’s commodity-related derivative financial instruments represented purchases (long) of 819 Bcf and sales (short) of 688 Bcf with approximately 92% of purchase instruments and 94% of the sales instruments are scheduled to mature in less than 2 years and the remaining 8% and 6%, respectively, in 3 to 9 years. At December 31, 2008, the fair values of these derivatives were reflected in our consolidated financial statements as an asset of $206 million and a liability of $27 million.

The changes in fair value of Sequent’s derivative instruments utilized in its derivative instrument activities and contract settlements increased the net fair value of its contracts outstanding by $25 million during 2008, reduced net fair value by $62 million during 2007 and increased net fair value by $132 million during 2006.

Weather Derivatives

In 2008 and 2007, SouthStar entered into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal and colder-than-normal weather in the heating season, primarily from November through March. SouthStar accounts for these contracts using the intrinsic value method under the guidelines of EITF 99-02. SouthStar recorded current assets for this hedging activity of $4 million at December 31, 2008 and $5 million at December 31, 2007.

Concentration of Credit Risk

Atlanta Gas Light Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 11 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the nonpeak summer months and the 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 no less than two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light.

Wholesale Services Sequent has a concentration of credit risk for services it provides to marketers and to utility and industrial counterparties. This credit risk is measured by 30-day receivable exposure plus forward exposure, which is generally concentrated in 20 of its counterparties. Sequent evaluates the credit risk of its counterparties using a S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody’s rating to an internal rating ranging from 9.00 to 1.00, with 9.00 being equivalent to AAA/Aaa by S&P and Moody’s and 1.00 being equivalent to D or Default by S&P and Moody’s. For a customer without an external rating, Sequent assigns an internal rating based on Sequent’s analysis of the strength of its financial ratios. At December 31, 2008, Sequent’s top 20 counterparties represented approximately 63% of the total credit exposure of $505 million, derived by adding together 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 S&P equivalent rating of A- at December 31, 2008.

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

Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, including requirements for posting of collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. Government Securities held by a trustee. When Sequent is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Sequent’s credit risk. Sequent also uses other netting agreements with certain counterparties with which it conducts significant transactions.

Note 3 - Employee Benefit Plans

Oversight of Plans

The Retirement Plan Investment Committee (the Committee) appointed by our Board of Directors is responsible for overseeing the investments of the retirement plans. Further, we have an Investment Policy (the Policy) for the retirement and postretirement benefit plans that aims to preserve these plans’ capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the retirement and postretirement benefit plans’ assets are actively managed to optimize 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 diversify retirement plan investments 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 preceding tables, but the Committee can vary allocations between various classes or investment managers in order to improve 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 difference 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.

Pension Benefits

We sponsor two tax-qualified defined benefit retirement plans for our eligible employees, the AGL Resources Inc. Retirement Plan (AGL Retirement Plan) and the Employees’ Retirement Plan of NUI Corporation (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 AGL Retirement Plan is a career average earnings formula, except for participants who were employees as of July 1, 2000, and who were at least 50 years of age as of that date. For those participants, we use a final average earnings benefit formula, and will continue to use this benefit formula for such participants until June 2010, at which time any of those participants who are still active will accrue future benefits under the career average earnings formula.

The NUI Retirement Plan covers substantially all of NUI’s employees who were employed on or before December 31, 2006, except Florida City Gas union employees, who until February 2008 participated in a union-sponsored multiemployer plan. Pension benefits are based on years of credited service and final average compensation.

Postretirement Benefits

We sponsor a defined benefit postretirement health care plan for our eligible employees, the Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Postretirement Plan). Eligibility for these benefits is based on age and years of service.

The AGL Postretirement Plan covers all eligible AGL Resources employees who were employed as of June 30, 2002, if they reach retirement age while working for us. The state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery. We recorded a regulatory asset for these future recoveries of $11 million as of December 31, 2008 and $12 million as of December 31, 2007. In addition, we recorded a regulatory liability of $5 million as of December 31, 2008 and $4 million as of December 31, 2007 for our expected expenses under the AGL Postretirement Plan. We expect to pay $7 million of insurance claims for the postretirement plan in 2009, but we do not anticipate making any additional contributions.

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

Medicare-eligible participants receive prescription drug benefits through a Medicare Part D plan offered by a third party and to which we subsidize participant premiums. Medicare-eligible retirees who opt out of the AGL Postretirement Plan are eligible to receive a cash subsidy which may be used towards eligible prescription drug expenses.

SFAS 158 In September 2006, the FASB issued SFAS 158, which we adopted prospectively on December 31, 2007. SFAS 158 requires that we recognize all obligations related to defined benefit pensions and other postretirement benefits. This statement requires that we quantify the plans’ funding status as an asset or a liability on our consolidated statements of financial position. SFAS 158 further requires that we measure the plans’ assets and obligations that determine our funded status as of the end of the fiscal year. We are also required to recognize as a component of OCI the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit cost as explained in SFAS 87, or SFAS 106.

Based on the funded status of our defined benefit pension and postretirement benefit plans as of December 31, 2008, we reported an after-tax loss to our OCI of $111 million, a net increase of $184 million to accrued pension and postretirement obligations and a decrease of $73 million to accumulated deferred income taxes. Our adoption of SFAS 158 on December 31, 2007, had no impact on our earnings.

Contributions

Our employees do not contribute to the retirement plans. Additionally, we annually fund our postretirement plan; however, our retirees contribute 20% of medical premiums, 50% of the medical premium for spousal coverage and 100% of the dental premium to the AGL Postretirement Plan. We fund the plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the minimum required amount. We calculate the minimum amount of funding using the projected unit credit cost method.

The Pension Protection Act (the Act) of 2006 contained new funding requirements for single employer defined benefit pension plans. The Act establishes a 100% funding target for plan years beginning after December 31, 2008. However, a delayed effective date of 2011 may apply if the pension plan meets the following targets; 92% funded in 2008; 94% funded in 2009; and 96% funded in 2010. In December 2008, the Worker, Retiree and Employer Recovery Act of 2008 allowed us to measure our 2008 and 2009 funding target at 92%. In 2008 and 2007, we did not make contributions as one was not required for our pension plans. For more information on our 2009 contributions to our pension plans, see Note 7.

The following tables present details about our pension and postretirement plans.

	AGL Retirement Plan						NUI Retirement Plan						AGL Postretirement Plan
Dollars in millions	2008			2007			2008			2007			2008			2007
Change in benefit obligation
Benefit obligation, January 1,	$	353		$	368		$	74		$	86		$	94		$	95
Service cost		7			7			-			-			-			1
Interest cost		22			21			4			5			6			6
Actuarial loss (gain)		9			(23	)		-			(9	)		(1	)		-
Benefits paid		(21	)		(20	)		(6	)		(8	)		(4	)		(8	)
Benefit obligation, December 31,	$	370		$	353		$	72		$	74		$	95		$	94
Change in plan assets
Fair value of plan assets, January 1,	$	313		$	303		$	70		$	72		$	70		$	63
Actual (loss) gain on plan assets		(93	)		30			(22	)		6			(21	)		7
Employer contribution		1			-			-			-			4			8
Benefits paid		(21	)		(20	)		(6	)		(8	)		(4	)		(8	)
Fair value of plan assets, December 31,	$	200		$	313		$	42		$	70		$	49		$	70
Amounts recognized in the consolidated statements of financial position consist of
Current liability	$	(1	)	$	(1	)	$	-		$	-		$	-		$	-
Long-term liability		(169	)		(39	)		(30	)		(4	)		(46	)		(24	)
Total liability at December 31,	$	(170	)	$	(40	)	$	(30	)	$	(4	)	$	(46	)	$	(24	)
Assumptions used to determine benefit obligations
Discount rate		6.2	%		6.4	%		6.2	%		6.4	%		6.2	%		6.4	%
Rate of compensation increase		3.7	%		3.7	%		-			3.7	%		3.7	%		3.7	%
Accumulated benefit obligation	$	352		$	337		$	73		$	74			N/A			N/A

The components of our pension and postretirement benefit costs are set forth in the following table.

	AGL Retirement Plan									NUI Retirement Plan									AGL Postretirement Plan
Dollars in millions	2008			2007			2006			2008			2007			2006			2008			2007			2006
Net benefit cost
Service cost	$	7		$	7		$	7		$	-		$	-		$	-		$	-		$	1		$	1
Interest cost		22			21			20			4			5			5			6			6			5
Expected return on plan assets		(26	)		(25	)		(24	)		(6	)		(6	)		(7	)		(6	)		(5	)		(4	)
Net amortization		(1	)		(1	)		(1	)		(1	)		(1	)		(1	)		(4	)		(4	)		(4	)
Recognized actuarial loss		3			7			9			-			-			-			1			1			1
Net annual pension cost	$	5		$	9		$	11		$	(3	)	$	(2	)	$	(3	)	$	(3	)	$	(1	)	$	(1	)
Assumptions used to determine benefit costs
Discount rate		6.4	%		5.8	%		5.5	%		6.4	%		5.8	%		5.5	%		6.4	%		5.8	%		5.5	%
Expected return on plan assets		9.0	%		9.0	%		8.8	%		9.0	%		9.0	%		8.8	%		9.0	%		9.0	%		8.5	%
Rate of compensation increase		3.7	%		3.7	%		4.0	%		-			-			-			3.7	%		3.7	%		4.0	%

There were no other changes in plan assets and benefit obligations recognized for our retirement and postretirement plans for the year ended December 31, 2008.The 2009 estimated OCI amortization and expected refunds for these plans are set forth in the following table.

In millions	AGL Retirement Plan			NUI Retirement Plan			AGL Postretirement Plan
Amortization of prior service cost	$	(1	)	$	(1	)	$	(4	)
Amortization of net loss		14			1			2
Refunds expected		-			-			-

We consider a number of factors in determining and selecting assumptions for 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, and 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.

We consider a variety of factors in determining and selecting our assumptions for the discount rate at December 31. We consider certain market indices, including Moody’s Corporate AA long-term bond rate, the Citigroup Pension Liability rate, a single equivalent discount rate derived with the assistance of our actuaries and our own payment stream based on these indices to develop our rate. Consequently, we selected a discount rate of 6.2% as of December 31, 2008, following our review of these various factors. Our actual retirement and postretirement plans’ weighted average asset allocations at December 31, 2008 and 2007 and our target asset allocation ranges are as follows:

	Target Range Asset Allocation	AGL Retirement Plan		NUI Retirement Plan		AGL Postretirement Plan
	Target Range Asset Allocation	2008	2007	2008	2007	2008	2007
Equity	30%-95%	63%	68%	63%	71%	70%	73%
Fixed income	10%-40%	30%	25%	32%	27%	28%	26%
Real estate and other	10%-35%	6%	3%	-	2%	-	-
Cash	0%-10%	1%	4%	5%	-	2%	1%

Our health care trend rate for the AGL Postretirement Plan is capped at 2.5%. This cap limits the increase in our contributions to the annual change in the consumer price index (CPI). An annual CPI rate of 2.5% was assumed for future years. Assumed health care cost trend rates impact 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 for the AGL Postretirement Plan.

	AGL Postretirement Plan
	One-Percentage-Point
In millions	Increase		Decrease
Effect on total of service and interest cost	$	-	$	-
Effect on accumulated postretirement benefit obligation		4		(3	)

The following table presents expected benefit payments for the years ended December 31, 2009 through 2018 for our retirement and postretirement plans. There will be benefit payments under these plans beyond 2018.

In millions	AGL Retirement Plan		NUI Retirement Plan		AGL Postretirement Plan
2009	$	20	$	6	$	7
2010		20		6		7
2011		21		6		7
2012		21		6		7
2013		21		6		7
2014-2018		116		28		35
Total	$	219	$	58	$	70

The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated OCI as of December 31, 2008.

In millions	AGL Retirement Plan			NUI Retirement Plan			AGL Postretirement Plan
Prior service credit	$	(7	)	$	(12	)	$	(17	)
Net loss		195			21			39
Accumulated OCI		188			9			22
Net amount recognized in consolidated statement of financial position		(170	)		(30	)		(46	)
Prepaid (accrued) cumulative employer contributions in excess of net periodic benefit cost	$	18		$	(21	)	$	(24	)

There were no other changes in plan assets and benefit obligations recognized in our retirement and postretirement plans for the year ended December 31, 2008.

Employee Savings Plan Benefits

We sponsor the Retirement Savings Plus Plan (RSP), a defined contribution benefit plan that allows eligible participants to make contributions to their accounts up to specified limits. Under the RSP, we made matching contributions to participant accounts of $6 million in 2008, 2007 and 2006.

Note 4 - Stock-based and Other Incentive Compensation Plans and Agreements

General

We currently sponsor the following stock-based and other incentive compensation plans and agreements:

	Shares issuable upon exercise of outstanding stock options and / or SARs (1)		Shares issuable and / or SARs available for issuance (1)		Details
2007 Omnibus Performance Incentive Plan		280,200		4,561,386	Grants of incentive and nonqualified stock options, stock appreciation rights (SARs), shares of restricted stock, restricted stock units and performance cash awards to key employees.
Long-Term Incentive Plan (1999) (2)		2,221,407		-	Grants of incentive and nonqualified stock options, shares of restricted stock and performance units to key employees.
Officer Incentive Plan		76,224		211,409	Grants of nonqualified stock options and shares of restricted stock to new-hire officers.
2006 Non-Employee Directors Equity Compensation Plan	not applicable			173,433	Grants of stock to non-employee directors in connection with non-employee director compensation (for annual retainer, chair retainer and for initial election or appointment).
1996 Non-Employee Directors Equity Compensation Plan		42,924		13,304	Grants of nonqualified stock options and stock to non-employee directors in connection with non-employee director compensation (for annual retainer and for initial election or appointment). The plan was amended in 2002 to eliminate the granting of stock options.
Employee Stock Purchase Plan	not applicable			321,912	Nonqualified, broad-based employee stock purchase plan for eligible employees

(1)	As of December 31, 2008

(2)	Following shareholder approval of the Omnibus Performance Incentive Plan, no further grants will be made except for reload options that may be granted under the plan’s outstanding options.

Accounting Treatment and Compensation Expense

Effective January 1, 2006, we adopted SFAS 123R, using the modified prospective application transition method. Prior to January 1, 2006, we accounted for our share-based payment transactions in accordance with SFAS 123, as amended by SFAS 148. This allowed us to rely on APB 25 and related interpretations in accounting for our stock-based compensation plans under the intrinsic value method. SFAS 123R requires us to measure and recognize stock-based compensation expense in our financial statements based on the estimated fair value at the date of grant for our stock-based awards, which include:

·	stock options

·	stock awards, and

·	performance units (restricted stock units and performance cash units)

Performance-based stock awards and performance units contain market conditions. Stock options, restricted stock awards and performance units also contain a service condition. In accordance with SFAS 123R, we recognize compensation expense over the requisite service period for:

·	awards granted on or after January 1, 2006 and

·	unvested awards previously granted and outstanding as of January 1, 2006

In addition, we estimate forfeitures over the requisite service period when recognizing compensation expense. These estimates are adjusted to the extent that actual forfeitures differ, or are expected to materially differ, from such estimates.

The following table provides additional information on compensation costs and income tax benefits related to our stock-based compensation awards. We recorded these amounts in our consolidated statements of income for the years ended December 31, 2008, 2007 and 2006.

In millions	2008		2007		2006
Compensation costs	$	10	$	9	$	9
Income tax benefits		1		3		3

Prior to our adoption of SFAS 123R, benefits of tax deductions in excess of recognized compensation costs were reported as operating cash flows. SFAS 123R requires excess tax benefits to be reported as a financing cash inflow rather than as a reduction of taxes paid. In 2007 and 2006, our cash flows from financing activities included an immaterial amount for recognized compensation costs in excess of the benefits of tax deductions. In 2008, we included $2 million of such benefits in cash flow provided by operating activities.

Incentive and Nonqualified Stock Options

We grant incentive and nonqualified stock options with a strike price equal to the fair market value on the date of the grant. “Fair market value” is defined under the terms of the applicable plans as the most recent closing price per share of AGL Resources common stock as reported in The Wall Street Journal. Stock options generally have a three-year vesting period. Nonqualified options generally expire 10 years after the date of grant. Participants realize value from option grants only to the extent that the fair market value of our common stock on the date of exercise of the option exceeds the fair market value of the common stock on the date of the grant. Compensation expense associated with stock options is generally recorded over the option vesting period; however, for unvested options that are granted to employees who are retirement-eligible, the remaining compensation expense is recorded in the current period rather than over the remaining vesting period.

As of December 31, 2008, we had $2 million of total unrecognized compensation costs related to stock options. These costs are expected to be recognized over the remaining average requisite service period of approximately 2 years. Cash received from stock option exercises for 2008 was $5 million, and the income tax benefit from stock option exercises was $1 million. The following tables summarize activity related to stock options for key employees and non-employee directors.

Stock Options
	Number of options			Weighted average exercise price		Weighted average remaining life (in years)		Aggregate intrinsic value (in millions)
Outstanding – December 31, 2005		2,221,245		$	27.79
Granted		914,216			35.81
Exercised		(543,557	)		24.69
Forfeited (1)		(266,418	)		34.93
Outstanding – December 31, 2006		2,325,486		$	30.85
Granted		735,196			39.11
Exercised		(361,385	)		27.78
Forfeited (1)		(181,799	)		36.75
Outstanding – December 31, 2007		2,517,498		$	33.28		7.1
Granted		258,017			38.70		8.5
Exercised		(212,600	)		23.53		2.1
Forfeited (1)		(86,926	)		38.01		8.5
Outstanding – December 31, 2008		2,475,989		$	34.52		6.7	$	3

Exercisable – December 31, 2008		1,447,508		$	32.18		5.9	$	3

(1) Includes 4,226 shares which expired in 2008, none in 2007 and 452 in 2006.

Unvested Stock Options
	Number of unvested options			Weighted average exercise price		Weighted average remaining vesting period (in years)		Weighted average fair value
Outstanding – December 31, 2007		1,414,962		$	37.02		1.6	$	4.82
Granted		258,017			38.70		2.0		2.64
Forfeited		(51,497	)		38.68		2.2		4.39
Vested		(593,001	)		36.26		-		4.77
Outstanding – December 31, 2008		1,028,481		$	37.80		1.1	$	4.33

Information about outstanding and exercisable options as of December 31, 2008, 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
$	16.25 to 20.79		27,274		1.5	$	19.53		27,274	$	19.53
$	20.80 to 25.34		173,326		3.1		21.82		173,326		21.82
$	25.35 to 29.89		233,157		4.4		27.07		233,157		27.07
$	29.90 to 34.44		406,701		6.0		33.21		406,701		33.21
$	34.45 to 38.99		1,388,835		7.5		37.15		587,250		36.83
$	39.00 to 43.54		246,696		8.8		39.43		19,800		41.20
Outstanding - Dec. 31, 2008			2,475,989		6.7	$	34.52		1,447,508	$	32.18

Summarized below are outstanding options that are fully exercisable.

Exercisable at:	Number of options		Weighted average exercise price
December 31, 2006		1,013,672	$	25.45
December 31, 2007		1,102,536	$	28.48
December 31, 2008		1,447,508	$	32.18

In accordance with the fair value method of determining compensation expense, we use the Black-Scholes pricing model. Below are the ranges for per share value and information about the underlying assumptions used in developing the grant date value for each of the grants made during 2008, 2007 and 2006.

	2008		2007		2006
Expected life (years)		7		7		7
Risk-free interest rate % (1)		2.93 - 3.31		3.87 – 5.05		4.5 – 5.1
Expected volatility % (2)		12.8 - 13.0		13.2 – 14.3		14.2 – 15.9
Dividend yield % (3)		4.3 – 4.84		3.8 – 4.2		3.7 – 4.2
Fair value of options granted (4)	$	0.19 – $2.69	$	3.55 – $5.98	$	4.55– $6.18

(1)	US Treasury constant maturity - 7 years

(2)	Volatility is measured over 7 years, the expected life of the options; weighted average volatility % for 2008 was 13.0%, 2007 was 14.2% and 2006 was 15.8%.

(3)	Weighted average dividend yields for 2008 was 4.3%, 2007 was 4.2% and 2006 was 4.1%

(4)	Represents per share value.

Intrinsic value for options is defined as the difference between the current market value and the grant price. Total intrinsic value of options exercised during 2008 was $2 million. With the implementation of our share repurchase program in 2006, we use shares purchased under this program to satisfy share-based exercises to the extent that repurchased shares are available. Otherwise, we issue new shares from our authorized common stock.

Performance Units

In general, a performance unit is an award of the right to receive (i) an equal number of shares of our common stock, which we refer to as a restricted stock unit or (ii) cash, subject to the achievement of certain pre-established performance criteria, which we refer to as a performance cash unit. Performance units are subject to certain transfer restrictions and forfeiture upon termination of employment. The dollar value of restricted stock unit awards is equal to the grant date fair value of the awards, over the requisite service period, determined pursuant to FAS 123R. The dollar value of performance cash unit awards is equal to the grant date fair value of the awards measured against progress towards the performance measure, over the requisite service period, determined pursuant to FAS 123R. No other assumptions are used to value these awards.

Restricted Stock Units In general, a restricted stock unit is an award that represents the opportunity to receive a specified number of shares of our common stock, subject to the achievement of certain pre-established performance criteria. In 2008, we granted to a select group a total of 206,700 restricted stock units (the 2008 restricted stock units), of which 196,100 of these units were outstanding as of December 31, 2008. These restricted stock units had a performance measurement period that ended December 31, 2008, and a performance measure related to a basic earnings per share attributable to AGL Resources Inc. goal that was met.

Performance Cash Units In general, a performance cash unit is an award that represents the opportunity to receive a cash award, subject to the achievement of certain pre-established performance criteria. In 2008, we granted performance cash awards to a select group of officers. These awards have a performance measure that is related to annual growth in basic earnings per share attributable to AGL Resources Inc., plus the average dividend yield, as adjusted to reflect the effect of economic value created during the performance measurement period by our wholesale services segment. In 2008, basic earnings per share attributable to AGL Resources Inc. growth target were not achieved with respect to the 2007 awards. Accruals in connection with these grants are as follows:

Dollars in millions	Units		Measurement period end date	Accrued at Dec. 31, 2008		Maximum aggregate payout
Year of grant
2006 (1)		15	Dec. 31, 2008	$	1	$	2
2007		23	Dec. 31, 2009		-		3
2008		3	Dec. 31, 2010		1		2

(1)	In February 2009, the 2006 performance cash units vested and resulted in an aggregate payout of $1 million.

Stock and Restricted Stock Awards

In general, we refer to a stock award as an award of our common stock that is 100% vested and not forfeitable as of the date of grant. We refer to restricted stock as an award of our common stock that is subject to time-based vesting or achievement of performance measures. Restricted stock awards are subject to certain transfer restrictions and forfeiture upon termination of employment. The dollar value of both stock awards and restricted stock awards are equal to the grant date fair value of the awards, over the requisite service period, determined pursuant to FAS 123R. No other assumptions are used to value the awards.

Stock Awards – Non-Employee Directors Non-employee director compensation may be paid in shares of our common stock in connection with initial election, the annual retainer, and chair retainers, as applicable. Stock awards for non-employee directors are 100% vested and nonforfeitable as of the date of grant. The following table summarizes activity during 2008, related to stock awards for our non-employee directors.

Restricted Stock Awards	Shares of restricted stock		Weighted average fair value
Issued		15,674	$	35.05
Forfeited		-		-
Vested		15,674	$	35.05
Outstanding		-		-

Restricted Stock Awards – Employees From time to time, we may give restricted stock awards to our key employees. The following table summarizes activity during the year ended December 31, 2008, related to restricted stock awards for our key employees.

Restricted Stock Awards	Shares of restricted stock			Weighted average remaining vesting period (in years)		Weighted average fair value
Outstanding – December 31, 2007 (1)		349,036			2.1	$	38.15
Issued		28,024			0.6		35.63
Forfeited		(6,483	)		1.2		38.43
Vested		(70,199	)		-		36.75
Outstanding – December 31, 2008 (1)		300,378			1.3	$	37.87

(1)	Subject to restriction

Employee Stock Purchase Plan (ESPP)

Under the ESPP, employees may purchase shares of our common stock in quarterly intervals at 85% of fair market value. Employee contributions under the ESPP may not exceed $25,000 per employee during any calendar year.

	2008		2007		2006
Shares purchased on the open market		66,247		52,299		45,361
Average per-share purchase price	$	33.22	$	34.69	$	31.40
Purchase price discount	$	326,615	$	313,584	$	252,752

Note 5 - Equity

Treasury Shares

Our Board of Directors has authorized us to purchase up to 8 million treasury shares through our repurchase plans. These plans are used to offset shares issued under our employee and non-employee director incentive compensation plans and our dividend reinvestment and stock purchase plans. Stock purchases under these plans may be made in the open market or in private transactions at times and in amounts that we deem appropriate. There is no guarantee as to the exact number of shares that we will purchase, and we can terminate or limit the program at any time. We will hold the purchased shares as treasury shares and account for them using the cost method. As of December 31, 2008 we had 5 million remaining authorized shares available for purchase. The following table provides more information on our treasury share activity.

In millions, except per share amounts	Total amount purchased		Shares purchased		Weighted average price per share
2006	$	38		1	$	36.67
2007		80		2		39.56
2008		-		-		-

Dividends

Our shareholders may receive dividends when declared at the discretion of our Board of Directors. Dividends may be paid in cash, stock or other form of payment, and payment of future dividends will depend on our future earnings, cash flow, financial requirements and other factors. Additionally, we derive a substantial portion of our consolidated assets, earnings and cash flow from the operation of regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. As with most other companies, the payment of dividends are restricted by laws in the states where we do business. In certain cases, our ability to pay dividends to our shareholders is limited by the following:

·	our ability to pay our debts as they become due in the usual course of business, satisfy our obligations under certain financing agreements, including debt-to-capitalization covenants

·	our total assets are less than our total liabilities, and

·	our ability to satisfy our obligations to any preferred shareholders

Note 6 - Debt

Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies, including state public service commissions, the SEC and the FERC as granted by the Energy Policy Act of 2005. The following table provides more information on our various securities.

						Weighted average			Outstanding as of December 31,
In millions	Year(s) due		Interest rate (1)			interest rate (2)			2008		2007
Short-term debt
Credit Facilities	2009			0.8	%		2.9	%	$	500	$	-
Commercial paper	2009			2.2			3.6			273		566
SouthStar line of credit	2009			1.1			2.9			75		-
Sequent lines of credit	2009			0.9			2.3			17		1
Capital leases	2009			4.9			4.9			1		1
Pivotal Utility line of credit		-		-			-			-		12
Total short-term debt				1.3	%		3.3	%	$	866	$	580
Long-term debt - net of current portion
Senior notes		2011-2034		4.5-7.1	%		5.9	%	$	1,275	$	1,275
Gas facility revenue bonds		2022-2033		0.7-5.3			3.2			200		200
Medium-term notes		2012-2027		6.6-9.1			7.8			196		196
Capital leases	2013			4.9			4.9			4		6
AGL Capital interest rate swaps		-		-			-			-		(2	)
Total long-term debt				5.6	%		5.7	%	$	1,675	$	1,675

Total debt				4.1	%		5.2	%	$	2,541	$	2,255

(1)	As of December 31, 2008.

(2)	For the year ended December 31, 2008.

Short-term Debt

Our short-term debt at December 31, 2008 and 2007 was composed of borrowings under our commercial paper program; Credit Facilities; current portions of our capital lease obligations; and lines of credit for Sequent, SouthStar and Pivotal Utility.

Commercial Paper and Credit Facilities Our commercial paper consists of short-term, unsecured promissory notes with maturities ranging from 2 to 16 days. These unsecured promissory notes are supported by our $1 billion Credit Facility which expires in August 2011 and a supplemental $140 million Credit Facility that expires in September 2009. We have the option to request an increase in the aggregate principal amount available for borrowing under the $1 billion Credit Facility to $1.25 billion on not more than three occasions during each calendar year. The $140 million Credit Facility allows for the option to request an increase in the borrowing capacity to $150 million.

Several of our subsidiaries, including SouthStar participate in our commercial paper program. As of December 31, 2008, we had $273 million of commercial paper borrowings and $500 million outstanding under the Credit Facilities. As of December 31, 2007, we did not have any amounts outstanding under the Credit Facilities.

SouthStar Credit Facility SouthStar’s five-year $75 million unsecured credit facility expires in November 2011. SouthStar will use this line of credit for working capital and its general corporate needs. We had $75 million of outstanding borrowings on this line of credit at December 31, 2008. At December 31, 2007, there were no outstanding borrowings on this line of credit. We do not guarantee or provide any other form of security for the repayment of this credit facility.

Sequent Lines of Credit In June 2008, we extended Sequent’s $25 million unsecured line of credit to June 2009, which bears interest at the federal funds effective rate plus 0.75%. In September 2008, Sequent extended its second $20 million line of credit that bears interest at the LIBOR rate plus 1.0% to September 2009. In December 2008 the terms of this line of credit were amended to $5 million bearing interest at the LIBOR Rate plus 3.0%. Both lines of credit are used solely for the posting of margin deposits for NYMEX transactions and are unconditionally guaranteed by us.

Pivotal Utility Line of Credit This $20 million line of credit, which had been established to support Elizabethtown Gas’ hedging program, was terminated in October 2008. For more information on this hedging program, see Note 2.

Long-term Debt

Our long-term debt at December 31, 2008 and 2007 matures more than one year from the statement of financial position date 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; and capital leases. Our annual maturities of long-term debt, excluding capital leases of $4 million, are as follows:

Year	Amount (in millions)
2011	$	300
2012		15
2013		225
2015		200
2016		300
2017		22
2021		30
2022		93
2024		20
2026		69
2027		53
2032		55
2033		39
2034		250
Total	$	1,671

Medium-term notes The following table provides more information on our medium-term notes, which were issued to refinance portions of our existing short-term debt and for general corporate purposes. Our annual maturities of our medium-term notes are as follows:

Issue Date	Amount (in millions)		Interest rate			Maturity
June 1992	$	5		8.4	%	June 2012
June 1992		5		8.3		June 2012
June 1992		5		8.3		July 2012
July 1997		22		7.2		July 2017
Feb. 1991		30		9.1		Feb. 2021
April 1992		5		8.55		April 2022
April 1992		25		8.7		April 2022
April 1992		6		8.55		April 2022
May 1992		10		8.55		May 2022
Nov. 1996		30		6.55		Nov. 2026
July 1997		53		7.3		July 2027
Total	$	196

Senior Notes The following table provides more information on our senior notes, which were issued to refinance portions of our existing short-term and long-term debt, to finance acquisitions and for general corporate purposes.

Issue date	Amount (in millions)		Interest rate			Maturity
Feb. 2001	$	300		7.125	%	Jan 2011
July 2003		225		4.45		Apr 2013
Dec. 2004		200		4.95		Jan 2015
June 2006		175		6.375		Jul 2016
Dec. 2007		125		6.375		Jul 2016
Sep. 2004		250		6.0		Oct 2034
Total	$	1,275

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 Bonds Pivotal Utility is party to a series of loan agreements with the New Jersey Economic Development Authority (NJEDA) pursuant to which the NJEDA has issued a series of gas facility revenue bonds as shown in the following table.

Issue Date	Amount (in millions)		Interest rate			Maturity
July 1994 (1)	$	47		0.70	%	Oct. 2022
July 1994 (1)		20		1.10		Oct. 2024
June 1992 (1)		39		1.10		June 2026
June 1992 (1)		55		0.85		June 2032
July 1997		39		5.25		Nov. 2033
Total	$	200

(1)	Interest rate is adjusted daily or weekly. Rates indicated are as of December 31, 2008.

In 2008, a portion of our gas facility revenue bonds failed to draw enough potential buyers due to the dislocation or disruption in the auction markets as a result of the downgrades to the bond insurers that provide credit protections for these instruments which reduced investor demand and liquidity for these types of investments. In March and April 2008, we tendered these bonds with a cumulative principal amount of $161 million through commercial paper borrowings.

In June and September 2008, we completed a Letter of Credit Agreement for these bonds which provided additional credit support which increased investor demand for the bonds. As a result, these bonds with a cumulative principal amount of $161 million were successfully auctioned and issued as variable rate gas facility bonds and reduced our commercial paper borrowings. The bonds with principal amounts of $55 million, $47 million and $39 million now have interest rates that reset daily and the bond with a principal amount of $20 million has an interest rate that resets weekly. There was no change to the maturity dates on these bonds.

Preferred Securities As of December 31, 2008, we had 10 million shares of authorized, unissued Class A junior participating preferred stock, no par value, and 10 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 City Gas related to its gas meters and other equipment and will be repaid at approximately $1 million per year until 2013. Pursuant to the terms of the lease agreement, Florida City Gas is required to insure the leased equipment during the lease term. In addition, at the expiration of the lease term, Florida City Gas has the option to purchase the leased meters from the lessor at their fair market value. The fair market value of the equipment will be determined on the basis of an arm’s-length transaction between an informed and willing buyer.

Default Events

Our Credit Facilities’ financial covenants requires us to maintain a ratio of total debt to total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. Our ratio of total debt to total capitalization calculation contained in our debt covenant includes noncontrolling interest, standby letters of credit, surety bonds and the exclusion of other comprehensive income pension adjustments. Adjusting for these items, our debt-to-equity calculation, as defined by our Credit Facilities, was 59% at December 31, 2008 and 58% at December 31, 2007. These amounts are within our required and targeted ranges. Our debt-to-equity calculation, as calculated from our consolidated statements of financial position, was 60% at December 31, 2008 and 57% at December 31, 2007.

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

·	insolvency events and nonpayment of scheduled principal or interest payments

·	acceleration of other financial obligations

·	change of control provisions

We have no 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.

Note 7 - Commitments and Contingencies

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities that are reasonably likely to have a material affect on liquidity or the availability of requirements for capital resources. 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. As we do for other subsidiaries, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations. The following table illustrates our expected future contractual payments such as debt and lease agreements, and commitment and contingencies as of December 31, 2008.

In millions	Total		2009		2010 & 2011		2012 & 2013		2014 & thereafter
Recorded contractual obligations:
Long-term debt	$	1,675	$	-	$	302	$	242	$	1,131
Short-term debt		866		866		-		-		-
PRP costs (1)		189		49		91		49		-
Environmental remediation liabilities (1)		106		17		41		38		10
Total	$	2,836	$	932	$	434	$	329	$	1,141

Unrecorded contractual obligations and commitments (2):
Pipeline charges, storage capacity and gas supply (3)	$	1,713	$	491	$	573	$	299	$	350
Interest charges (4)		975		94		168		137		576
Operating leases (5)		137		30		45		25		37
Standby letters of credit, performance / surety bonds		52		48		3		1		-
Asset management agreements (6)		32		12		19		1		-
Pension contributions (7)		7		7		-		-		-
Total	$	2,916	$	682	$	808	$	463	$	963

(1)	Includes charges recoverable through rate rider mechanisms.

(2)	In accordance with GAAP, these items are not reflected in our consolidated statements of financial position.

(3)

Charges recoverable through a natural gas cost recovery mechanism or alternatively billed to Marketers. Also includes demand charges associated with Sequent. A subsidiary of NUI entered into two 20-year agreements for the firm transportation and storage of natural gas during 2003 with annual aggregate demand charges of approximately $5 million. As a result of our acquisition of NUI and in accordance with SFAS 141, we valued the contracts at fair value and established a long-term liability of $38 million for the excess liability that will be amortized to our consolidated statements of income over the remaining lives of the contracts of $2 million annually through November 2023 and $1 million annually from November 2023 to November 2028. The gas supply amount includes SouthStar gas commodity purchase commitments of 15 Bcf at floating gas prices calculated using forward natural gas prices as of December 31, 2008, and is valued at $85 million.

(4)	Floating rate debt is based on the interest rate as of December 31, 2008 and the maturity of the underlying debt instrument. As of December 31, 2008, we have $35 million of accrued interest on our consolidated statement of financial position that will be paid in 2009.

(5)

We have certain operating leases with provisions for step rent or escalation payments and certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms, in accordance with SFAS 13. However, this lease accounting treatment does not affect the future annual operating lease cash obligations as shown herein.

(6)	Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.

(7)	Based on the current funding status of the plans, we would be required to make a minimum contribution to our pension plans of approximately $7 million in 2009. We may make additional contributions in 2009.

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 Light The presence of coal tar and certain other byproducts of a natural gas manufacturing process used to produce natural gas prior to the 1950s has been identified at or near 10 former Atlanta Gas Light operating sites in Georgia and at 3 sites of predecessor companies in Florida. Atlanta Gas Light has active environmental remediation or monitoring programs in effect at 10 of these sites. Two sites in Florida are currently in the investigation or preliminary engineering design phase, and one Georgia site has been deemed compliant with state standards.

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

Atlanta Gas Light’s current estimate for the remaining cost of future actions at its former operating sites is $38 million, which may change depending on whether future measures for groundwater will be required. As of December 31, 2008, we have recorded a liability equal to the low end of the range of $38 million, of which $10 million is expected to be incurred over the next 12 months.

These liabilities do not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, unbudgeted legal expenses or other costs for which Atlanta Gas Light may be held liable but for which it cannot reasonably estimate an amount.

The ERC liability is included as a corresponding regulatory asset, which is a combination of accrued ERC and unrecovered cash expenditures for investigation and cleanup costs. Atlanta Gas Light has three ways of recovering investigation and cleanup costs. First, the Georgia Commission has approved an ERC recovery rider. The ERC recovery mechanism allows for recovery of expenditures over a five-year period subsequent to the period in which the expenditures are incurred. Atlanta Gas Light expects to collect $17 million in revenues over the next 12 months under the ERC recovery rider, which is reflected as a current asset. The amounts recovered from the ERC recovery rider during the last three years were:

·	$22 million in 2008

·	$26 million in 2007

·	$29 million in 2006

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 2008, 2007 or 2006.

The third way to recover costs is from the receipt of net profits from the sale of remediated property.

Elizabethtown Gas In New Jersey, Elizabethtown Gas is currently conducting remediation activities with oversight from the New Jersey Department of Environmental Protection. Although we cannot estimate the actual total cost of future environmental investigation and remediation efforts with precision, based on probabilistic models similar to those used at Atlanta Gas Light’s former operating sites, the range of reasonably possible costs is $58 million to $116 million. As of December 31, 2008, we have recorded a liability equal to the low end of that range, or $58 million, of which $7 million in expenditures are expected to be incurred over the next 12 months.

Prudently incurred remediation costs for the New Jersey properties have been authorized by the New Jersey Commission to be recoverable in rates through a remediation adjustment clause. As a result, Elizabethtown Gas has recorded a regulatory asset of approximately $66 million, inclusive of interest, as of December 31, 2008, reflecting the future recovery of both incurred costs and accrued carrying charges. Elizabethtown Gas expects to collect approximately $1 million in revenues over the next 12 months. 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.

We own a site in Elizabeth City, North Carolina that is subject to a remediation order by the North Carolina Department of Energy and Natural Resources. We had recorded liabilities of $10 million as of December 31, 2008 and $11 million as of December 31, 2007 related to this site.

There is one other site in North Carolina where investigation and remediation is likely, although no remediation order exists and we do not believe costs associated with this site can be reasonably estimated. In addition, there are as many as six other sites with which we had some association, although no basis for liability has been asserted, and accordingly we have not accrued any remediation liability. There are currently no cost recovery mechanisms for the environmental remediation sites in North Carolina.

Rental Expense

We incurred rental expense in the amounts of $21 million in 2008, $21 million in 2007 and $19 million in 2006.

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.

In August 2006, the Office of Mineral Resources of the Louisiana DNR informed Jefferson Island that its mineral lease – which authorizes salt extraction to create two new storage caverns – at Lake Peigneur had been terminated. The Louisiana DNR identified two bases for the termination: (1) failure to make certain mining leasehold payments in a timely manner, and (2) the absence of salt mining operations for six months.

In September 2006, Jefferson Island filed suit against the State of Louisiana, in the 19th Judicial District Court in Baton Rouge, to maintain its lease to complete an ongoing natural gas storage expansion project in Louisiana. The project would add two salt dome storage caverns under Lake Peigneur to the two caverns currently owned and operated by Jefferson Island. In its suit, Jefferson Island alleges that the Louisiana DNR accepted all leasehold payments without reservation and never provided Jefferson Island with notice and opportunity to cure, as required by state law. In its answer to the suit, the State denied that anyone with proper authority approved the late payments. As to the second basis for termination, the suit contends that Jefferson Island’s lease with the State of Louisiana was amended in 2004 so that mining operations are no longer required to maintain the lease. The State’s answer denies that the 2004 amendment was properly authorized. In March 2008, Jefferson Island served discovery requests on the State of Louisiana and sought a trial date in its pending lawsuit over its natural gas storage expansion project at Lake Peigneur. Jefferson Island also asserted additional claims against the State seeking to obtain a declaratory ruling that Jefferson Island’s surface lease, under which it operates its existing two storage caverns, authorizes the creation of the two new expansion caverns separate and apart from the mineral lease challenged by the State.

In addition, in June 2008, the State of Louisiana passed legislation restricting water usage from the Chicot aquifer, which is a main source of fresh water required for the expansion of our Jefferson Island capacity. We contend that this legislation is unconstitutional and have sought to amend the pending litigation to seek a declaration that the legislation is invalid and cannot be enforced. Even if we are not successful on those grounds, we believe the legislation does not materially impact the feasibility of the expansion project. If we are unable to reach a settlement, we are not able to predict the outcome of the litigation. As of January 2009, our current estimate of costs incurred that would be considered unusable if the Louisiana DNR was successful in terminating our lease and causing us to cease the expansion project is approximately $6 million.

In February 2008, the consumer affairs staff of the Georgia Commission alleged that GNG charged its customers on variable rate plans prices for natural gas that were in excess of the published price, that it failed to give proper notice regarding the availability of potentially lower price plans and that it changed its methodology for computing variable rates. GNG asserted that it fully complied with all applicable rules and regulations, that it properly charged its customers on variable rate plans the rates on file with the Georgia Commission, and that, consistent with its terms and conditions of service, it routinely switched customers who requested to move to another price plan for which they qualified. In order to resolve this matter GNG agreed to pay $2.5 million in the form of credits to customers, or as directed by the Georgia Commission, which was recorded in our statements of consolidated income for the year ended December 31, 2008.

In February 2008, a class action lawsuit was filed in the Superior Court of Fulton County in the State of Georgia against GNG containing similar allegations to those asserted by the Georgia Commission staff and seeking damages on behalf of a class of GNG customers. This lawsuit was dismissed in September 2008. In October 2008, the plaintiffs appealed the dismissal of the lawsuit and the parties are in the process of filing briefs on that appeal.

In March 2008, a second class action suit was filed against GNG in the State Court of Fulton County in the State of Georgia, regarding monthly service charges. This lawsuit alleges that GNG arbitrarily assigned customer service charges rather than basing each customer service charge on a specific credit score. GNG asserts that no violation of law or Georgia Commission rules has occurred, that this lawsuit is without merit and has filed motions to dismiss this class action suit on various grounds. The ultimate resolution of this lawsuit cannot be determined, but is not expected to have a material adverse effect on our condensed consolidated results of operations, cash flows or financial condition.

Review of Compliance with FERC Regulations

In 2008, we conducted an internal review of our compliance with FERC interstate natural gas pipeline capacity release rules and regulations. Independent of our internal review, we also received data requests from FERC’s Office of Enforcement relating specifically to compliance with FERC’s capacity release posting and bidding requirements. We have responded to FERC’s data requests and are fully cooperating with FERC in its investigation. As a result of this process, we have identified certain instances of possible non-compliance. We are committed to full regulatory compliance and we have met with the FERC Enforcement staff to discuss with them these instances of possible non-compliance. Accordingly we have accrued an appropriate estimate of possible penalties assessed by the FERC. This estimate does not have, and management does not believe the ultimate resolution will have, a material financial impact to our consolidated results of operations, cash flows or financial condition.

Note 8 - 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 and Other Tax Credits

Deferred investment tax credits associated with distribution operations are included as a regulatory liability in our consolidated statements of financial position (see Note 1, “Accounting Policies and Methods of Application”). These investment tax credits are being amortized over the estimated life of the related properties as credits to income in accordance with regulatory requirements. In 2007, we invested in a guaranteed affordable housing tax credit fund. 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, including the affordable housing credits. Components of income tax expense shown in the statements of consolidated income are shown in the following table.

Income Tax Expense

The relative split between current and deferred taxes is due to a variety of factors including true ups of prior year tax returns, and most importantly, the timing of our property-related deductions.

In millions	2008			2007			2006
Current income taxes
Federal	$	37		$	86		$	(4	)
State		7			12			2
Deferred income taxes
Federal		77			23			115
State		12			7			18
Amortization of investment tax credits		(1	)		(1	)		(2	)
Total	$	132		$	127		$	129

The amount of total income tax expense on our consolidated statements of income for the years ended years ended December 31, 2008, 2007 and 2006 is presented in the following table. Our adoption of SFAS 160 had no effect on the total income tax expense reported in our consolidated statements of income or on our accrued federal and state income taxes, including accumulated deferred income taxes as reported in our consolidated statements of financial position.

In millions		2008			2007			2006
Computed tax expense at statutory rate	$	129		$	129		$	127
State income tax, net of federal income tax benefit		15			14			13
Tax effect of net income attributable to the noncontrolling interest		(8	)		(12	)		(9	)
Amortization of investment tax credits		(1	)		(1	)		(2	)
Affordable housing credits		(2	)		(1	)		-
Flexible dividend deduction		(2	)		(2	)		(2	)
Other – net		1			-			2
Total income tax expense on consolidated statements of income	$	132		$	127		$	129

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. We report the tax effects of the differences in those items as deferred income tax assets or liabilities in our consolidated statements of financial position. We measure the assets and liabilities using income tax rates that are currently in effect. Because of the regulated nature of the utilities’ business, we recorded a regulatory tax liability in accordance with SFAS 109, which we are amortizing over approximately 30 years (see Note 1 “Accounting Policies and Methods of Application”). Our deferred tax assets include $86 million related to an unfunded pension and postretirement benefit obligation an increase of $51 million from 2007.

As indicated in the following table, 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 reduce 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.

	As of December 31,
In millions	2008			2007
Accumulated deferred income tax liabilities
Property – accelerated depreciation and other property-related items	$	635		$	568
Mark to market		5			4
Other		32			44
Total accumulated deferred income tax liabilities		672			616
Accumulated deferred income tax assets
Deferred investment tax credits		5			6
Unfunded pension and postretirement benefit obligation		86			35
Net operating loss – NUI (1)		2			5
Other		11			7
Total accumulated deferred income tax assets		104			53
Valuation allowances (2)		(3	)		(3	)
Total accumulated deferred income tax assets, net of valuation allowance		101			50
Net accumulated deferred tax liability	$	571		$	566

(1)	Expire in 2021.

(2)	Valuation allowance is due to the net operating losses on NUI headquarters that are not usable in New Jersey.

Tax Benefits

In June 2006, the FASB issued FIN 48, which addressed the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, we may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. We adopted the provisions of FIN 48 on January 1, 2007. At the date of adoption, as of December 31, 2007 and as of December 31, 2008, we did not have a liability for unrecognized tax benefits. Based on current information, we do not anticipate that this will change materially in 2009.

We recognize accrued interest and penalties related to uncertain tax positions in operating expenses in the consolidated statements of income, which is consistent with the recognition of these items in prior reporting periods. As of December 31, 2008, we did not have a liability recorded for payment of interest and penalties associated with uncertain tax positions.

We file a U.S. federal consolidated income tax return and various state income tax returns. We are no longer subject to income tax examinations by the Internal Revenue Service or any state for years before 2002, but we are currently under audit by the Internal Revenue Service for tax years 2006 and 2007.

Note 9 - Segment Information

We are an energy services holding company whose principal business is the distribution of natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. We generate nearly all our operating revenues through the sale, distribution, transportation and storage of natural gas. We are involved in several related and complementary businesses, including retail natural gas marketing to end-use customers primarily in Georgia; natural gas asset management and related logistics activities for each of our utilities as well as for nonaffiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability natural gas storage assets. We manage these businesses through four operating segments – distribution operations, retail energy operations, wholesale services and energy investments and a nonoperating corporate segment which includes intercompany eliminations.

We evaluate segment performance based primarily on the non-GAAP measure of EBIT, which includes the effects of corporate expense allocations. EBIT is a non-GAAP measure that includes operating income and other income and expenses. Items we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated level. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which 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 attributable to AGL Resources Inc. 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, earnings before income taxes and net income attributable to AGL Resources Inc. for 2008, 2007 and 2006 are presented below.

In millions	2008		2007		2006
Operating revenues	$	2,800	$	2,494	$	2,621
Operating expenses		2,322		2,005		2,133
Operating income		478		489		488
Other income (expense)		6		4		(1	)
EBIT		484		493		487
Interest expense		115		125		123
Earnings before income taxes		369		368		364
Income taxes		132		127		129
Net income		237		241		235
Less net income attributable to the noncontrolling interest		20		30		23
Net income attributable to AGL Resources Inc.	$	217	$	211	$	212

Summarized income statement, statement of financial position and capital expenditure information by segment as of and for the years ended December 31, 2008, 2007 and 2006 is shown in the following tables.

2008
In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments		Corporate and intercompany eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	1,581	$	987	$	170	$	55	$	7		$	2,800
Intercompany revenues (1)		187		-		-		-		(187	)		-
Total operating revenues		1,768		987		170		55		(180	)		2,800
Operating expenses
Cost of gas		950		838		48		5		(187	)		1,654
Operation and maintenance		330		67		55		24		(4	)		472
Depreciation and amortization		128		4		5		6		9			152
Taxes other than income taxes		35		2		2		1		4			44
Total operating expenses		1,443		911		110		36		(178	)		2,322
Operating income (loss)		325		76		60		19		(2	)		478
Other income		4		1		-		-		1			6
EBIT	$	329	$	77	$	60	$	19	$	(1	)	$	484
Identifiable and total assets	$	5,138	$	315	$	970	$	353	$	(66	)	$	6,710
Goodwill	$	404	$	-	$	-	$	14	$	-		$	418
Capital expenditures	$	278	$	6	$	1	$	75	$	12		$	372

2007
In millions	Distribution operations		Retail energy operations		Wholesale services		Energy investments		Corporate and intercompany eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	1,477	$	892	$	83	$	42	$	-		$	2,494
Intercompany revenues (1)		188		-		-		-		(188	)		-
Total operating revenues		1,665		892		83		42		(188	)		2,494
Operating expenses
Cost of gas		845		704		6		2		(188	)		1,369
Operation and maintenance		330		69		38		19		(5	)		451
Depreciation and amortization		122		5		4		5		8			144
Taxes other than income taxes		33		1		1		1		5			41
Total operating expenses		1,330		779		49		27		(180	)		2,005
Operating income (loss)		335		113		34		15		(8	)		489
Other income		3		-		-		-		1			4
EBIT	$	338	$	113	$	34	$	15	$	(7	)	$	493
Identifiable and total assets	$	4,847	$	282	$	890	$	287	$	(48	)	$	6,258
Goodwill	$	406	$	-	$	-	$	14	$	-		$	420
Capital expenditures	$	201	$	2	$	2	$	26	$	28		$	259

2006
In millions	Distribution operations		Retail energy operations			Wholesale services		Energy investments		Corporate and intercompany eliminations			Consolidated AGL Resources
Operating revenues from external parties	$	1,467	$	930		$	182	$	41	$	1		$	2,621
Intercompany revenues (1)		157		-			-		-		(157	)		-
Total operating revenues		1,624		930			182		41		(156	)		2,621
Operating expenses
Cost of gas		817		774			43		5		(157	)		1,482
Operation and maintenance		350		64			46		20		(7	)		473
Depreciation and amortization		116		3			2		5		12			138
Taxes other than income taxes		33		1			1		1		4			40
Total operating expenses		1,316		842			92		31		(148	)		2,133
Operating income (loss)		308		88			90		10		(8	)		488
Other income (expense)		2		(2	)		-		-		(1	)		(1	)
EBIT	$	310	$	86		$	90	$	10	$	(9	)	$	487
Identifiable and total assets	$	4,565	$	293		$	830	$	373	$	62		$	6,123
Goodwill	$	406	$	-		$	-	$	14	$	-		$	420
Capital expenditures	$	174	$	9		$	2	$	23	$	45		$	253

(1) Intercompany revenues – Wholesale services records its derivative instrument revenue on a net basis. Wholesale services total operating revenues include intercompany revenues of $982 million in 2008, $638 million in 2007 and $531 million in 2006.

Note 10 - Quarterly Financial Data (Unaudited)

Our quarterly financial data for 2008, 2007 and 2006 are summarized below. The variance in our quarterly earnings is the result of the seasonal nature of our primary business.

In millions, except per share amounts	March 31		June 30			Sept. 30		Dec. 31
2008
Operating revenues	$	1,012	$	444		$	539	$	805
Operating income		188		6			126		158
Net income (loss) attributable to AGL Resources Inc.		89		(11	)		65		74
Basic earnings (loss) per common share attributable to AGL Resources Inc. common shareholders		1.17		(0.15	)		0.85		0.97
Diluted earnings (loss) per common share attributable to AGL Resources Inc. common shareholders		1.16		(0.15	)		0.85		0.97
2007
Operating revenues	$	973	$	467		$	369	$	685
Operating income		216		78			55		140
Net income attributable to AGL Resources Inc.		102		30			13		66
Basic earnings per common share attributable to AGL Resources Inc. common shareholders		1.31		0.40			0.17		0.86
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders		1.30		0.40			0.17		0.86
2006
Operating revenues	$	1,044	$	436		$	434	$	707
Operating income		228		60			90		110
Net income attributable to AGL Resources Inc.		110		19			36		47
Basic earnings per common share attributable to AGL Resources Inc. common shareholders		1.42		0.25			0.46		0.60
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders		1.41		0.25			0.46		0.60

Our basic and 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 diluted earnings per common share attributable to AGL Resources Inc. common shareholders shown in 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.

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