~~Focus on maintaining strong investment-grade profile and high level~~Table of ~~liquidity~~We will continue to maintain a disciplined approach to capital spending and improving operating margins to optimize cash flow generation. Additionally, we seek to reduce in the near term our ratio of total debt to total capitalization in order to strengthen our balance sheet and allow us to respond to the capital needs of our operating businesses. We understand the importance of maintaining strong, investment-grade credit ratings in order to support our operating and investment needs, and we intend to execute our strategy in a way that enhances our ability to maintain or improve those ratings.Contents

~~Achieve appropriate regulatory outcomes that support stable utility earnings~~~~We currently are involved in regulatory proceedings in Georgia~~The market dynamics brought on by the two hurricanes presented opportunities for Sequent, and ~~Tennessee. In Georgia, Atlanta Gas Light’s rate case is in process and expected to be completed by April 30, 2005. In Tennessee, we anticipate receiving a final ruling on~~for our appeal of a 2004 Chattanooga Gas Company (Chattanooga Gas) rate case in the first quarter. Achieving favorable outcomes in these cases, and any other formal or informal regulatory proceedings in which we may be involved, is integral to the achievement of our earnings targets.

~~Selectively evaluate the acquisition of natural gas assets~~We will selectively examine and evaluate the acquisition of natural gas distribution, gas pipeline or other gas-related assets. Our acquisition criteria include the ability to generate operational synergies, strategic fit relative to our core competencies, value from near-term earnings contributions and adequate returns on invested capital, while maintaining or improving our investment-grade credit ratings.

~~Selectively expand our other energy businesses~~We intend to continue to expand our wholesale services and natural gas storage businesses to provide disciplined incremental earnings growth for shareholders. Sequent intends to continue providing credits to our utility customersutilities through effective management of our affiliated utility assets. In our asset management business, we intend to grow our business with non-affiliated third parties, as well as the services we provide to our affiliated utilities, by providing producers with markets for their gas commodity; providing end-users with gas supply, storage and asset management options; and arbitraging pipeline and storage assets across various gas markets and time horizons. However, we intend to continue protecting our earnings-at-risk by maintaining our commitment to limited open-position and credit risks and by providing transparency and visibility to regulators under ourSequent’s affiliate asset management agreements. ~~As our portfolio~~Sequent drew on its knowledge of ~~assets and our ability to store more physical gas inventory grow,~~ the volatility of reported earnings from this business may increase. In our high deliverability underground storage business, we will seek to expand the operating capabilities of our existing facilities to provide more flexible and valuable injection and withdrawal capabilities for our customers. Pivotal Jefferson Island, LLC is currently expanding its compression capabilities to increase the number of times a customer can inject and withdraw natural gas. We will complete and begin operation of our propane peaking facility, and look for additional opportunities to provide economical peaking services in the regions in which our utilities operate.

~~Acquire and retain~~ natural gas ~~customers~~~~We continue~~grid to ~~focus significant efforts in our distribution operations business on improving our net customer growth trends, despite~~move gas from supply sources and deliver it to its customers, which involved moving gas over less traditional routes due to Gulf Coast infrastructure limitations. For additional information regarding the ~~industry-wide challenges~~impacts of rising prices for natural gas and competition from alternative fuels, declining natural gas usage per customer and declining regional load factors. In each of our utility service areas, we will continue to implement programs aimed at emphasizing natural gas as the fuel of choice for customers and maximizing the use of natural gas through a variety of promotional opportunities. We also are focused on similar customer growth initiatives in our SouthStar retail marketing business in Georgia. In addition, we continue to improve the credit quality of our customers in the retail marketing business and will use those techniques to improve credit and collections activities within our regulated utilities.

~~Continue to improve revenue and cash flow stability~~ We have taken a number of actions in recent years to promote more stable and predictable revenues and cash flows in each of our business segments, as well as to moderate the effects of variable factors, such as weather and natural gas pricesthese hurricanes on our business, ~~results. Some~~see Results of ~~the improvements we have initiated include performance-based ratemaking treatment in Georgia; weather normalization adjustment programs in Virginia~~Operations - Distribution Operations and Tennessee; more efficient cost management and cash recovery from our environmental response cost (ERC) program in Georgia and reduced credit losses from our retail marketing business. We estimate that in 2005 our spending for property, plant and equipment will be $276 million compared to $264 million in 2004. Our capital expenditures should decrease in successive years by reduced spending related to the pipeline replacement program (PRP), a mandated regulatory program that has required significant expenditures. We expect to improve our net cash flow, which should provide enhanced financial flexibility around business investment opportunities and potentially a returnResults of ~~capital to investors to provide additional shareholder value.~~

Operations - Wholesale Services.

Regulatory Environment

We continue to manage the ongoing challenge of operating in a regulatory environment that generally does not measure or reward innovation and operational efficiency. In particular, traditional "cost of service" regulation, which was originally designed to simulate the actions of a competitive market, has not kept pace with the vast changes taking place in the natural gas industry, in technology utilization and in the global economy. These are factors that to various degrees affect our company. The staffs of various state rate setting agencies have argued for significantly lower rates of return on regulated investments without adequate attention to the effects those lower returns might have on capital reinvestment in the company’s regulated asset base; the “opportunity cost” to customers of not providing better and more efficient services; and the disincentive for excellence in management and operations that such returns create.

Much of the rate setting is done in adversarial proceedings where rules of evidence and due process can vary greatly among the states. As a result of these ongoing regulatory challenges, we will continue to work cooperatively with our regulators, legislators and others as we seek, through rate freezes and performance-based rates, to create a framework in each jurisdiction that is conducive to our business goals. Furthermore, we will continue to make strategic investments in energy-related businesses that either are not subject to traditional state and federal rate regulation or are subject to limited oversight in order to add value for our shareholders.

In August 2005, the ~~rate regulation~~Energy Policy Act of 2005 (Energy Act) was enacted. The Energy Act authorized many broad energy policy provisions including significant funding for consumers and ~~accounting~~businesses for energy-related activities, energy-related tax credits, accelerated depreciation for certain natural gas utility infrastructure investments and the repeal of the Public Utility Holding Company Act of 1935, as amended (PUHCA). The effective date of the PUHCA repeal is February 8, 2006. We continue to evaluate the Energy Act, but we expect to benefit from provisions in the legislation that will support our efforts to promote energy efficiency in a manner that benefits customers and shareholders.

The Energy Act gives the Federal Energy Regulatory Commission (FERC) increased authority over utility merger and acquisition activity, removes many of the geographic and structural restrictions on the ownership of public utilities and eliminates certain regulatory burdens. Some of the SEC reporting requirements, financing authorizations and affiliate relationship approvals that previously applied to us under the PUHCA were replaced by the requirements of ~~various state~~the Energy Act.

In addition, the Energy Act requires a public utility holding company to maintain its books and ~~federal regulatory agencies in the jurisdictions in which we do business. We are committed to working cooperatively~~records and constructively with the regulatory agencies in these states, as well as with federal regulatory agencies in a way that benefits our customers, shareholders and other stakeholders. We believe the dynamic energy environment in which we operate demands that we maintain an open, respectful and ongoing dialogue with these agencies. This posture is the best way to ensure we are working toward common solutionsmake them available to the ~~many issues~~FERC and to comply with certain reporting requirements. However, the FERC may exempt a class of entities or class of transactions if the FERC finds that they are not relevant to the jurisdictional rate of a public utility or natural gas company.

In February 2006, we requested an exemption from Energy Act oversight of our ~~industry faces. These issues include~~local distribution companies that were previously exempt from regulation by the ~~changing nature~~FERC. Our filing request will provide us with a temporary exemption. If the FERC has not taken action within 60 days of ~~resource availability, pricing volatility, price levels and their effect on economic development in~~ our ~~service territories,~~request, the ~~likelihood of increased importation of LNG and the need~~exemption shall be deemed to have been granted. We expect to qualify for ~~reasonably-priced alternatives for our customers to meet their rapidly growing peak demands.~~ an exemption from these reporting requirements.

For more information regarding pending federal and state regulatory matters, see ~~"Results~~Results of Operations - Distribution ~~Operations"~~Operations and ~~“Results~~Results of Operations - Wholesale Services.”

~~Technology Initiatives~~

We continue to make progress with regard to several of our strategic technology initiatives. During the third quarter of 2004, we implemented new technological tools that enable marketers of natural gas in Georgia (Marketers) to create and input service orders directly into Atlanta Gas Light’s systems, eliminating the need for duplicate data entry or three-way calls between the customer, Marketers and our customer call center. This system allowed for a reduction in the number of customer service representatives servicing Marketers in our call center, while providing enhanced service to the Marketers. It also allowed us to further develop our strategy for the replacement of our customer information system, which should result in less capital investment over time than previously estimated.

In addition, we implemented our new energy trading and risk management (ETRM) system at Sequent in the fourth quarter of 2004. The ETRM system is designed to enhance internal controls and provide additional transparency into the activities of Sequent’s business. We also anticipate the system will enable Sequent to continue to grow its commercial business without significant growth in support staff.

~~Internal Controls~~

~~Section 404 of the Sarbanes-Oxley Act of 2002 (SOX 404) compliance~~SOX 404 and related rules of the SEC require management of public companies to assess the effectiveness of the company’s internal controls over financial reporting as of the end of each fiscal year. This includes disclosure of any material weaknesses in the company’s internal controls over financial reporting that have been identified by management. In addition, SOX 404 requires the company’s independent auditor to attest to and report on management’s annual assessment of the company’s internal controls over financial reporting. We have documented, tested and assessed our systems of internal control over financial reporting, as required under SOX 404 and Public Accounting Oversight Board Standard No. 2, “An Audit of Internal Control Over Financial Reporting Performed in Conjunction With An Audit of Financial Statements” (Standard No. 2), which was adopted in June 2004, to provide the basis for management’s report and our independent auditor’s attestation on the effectiveness of our internal control over financial reporting as of December 31, 2004. We estimate our SOX 404 compliance costs in 2004 were approximately $8 million, which include $5 million of external costs.

~~There are three levels of possible deficiencies in our internal controls over financial reporting that can be identified during our assessment phase, which are~~

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

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

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

~~As a result, our assessment could result in two possible outcomes at our reporting date:~~Table of Contents

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

we could conclude that our internal controls over financial reporting were not properly designed or did not operate effectively. A material weakness that exists at the reporting date would require our assessment to be that our internal controls over financial reporting are not effective, and we would be required to disclose such material weaknesses

Our independent auditor is now required to issue three opinions annually, beginning with our 2004 consolidated financial statements. First, the auditor must evaluate and opine regarding the process by which we assessed the effectiveness of our internal controls over financial reporting. A second opinion must be issued as to the effectiveness of our internal controls over financial reporting. Finally, the independent auditor must issue an opinion, as is normally done, as to whether our consolidated financial statements are fairly presented, in all material respects.

The scope of our assessment of our internal controls over financial reporting included all of our consolidated entities except those falling under NUI, which we acquired on November 30, 2004, and Jefferson Island, which we acquired on October 1, 2004. In accordance with the SEC’s published guidance, we excluded these entities from our assessment as they were acquired late in the year, and it was not possible to conduct our assessment between the date of acquisition and the end of the year. SEC rules require that we complete our assessment of the internal control over financial reporting of these entities within one year from the date of acquisition.

We have completed the assessment of the effectiveness on our internal controls over financial reporting as of December 31, 2004, and have concluded that our controls are operating effectively. Our report on internal control over financial reporting is included in Item 9A, “Controls and Procedures,” and our independent auditors’ reports are included in Item 8, “Financial Statements and Supplementary Data,” following the notes to the financial statements.

~~NUI internal control weaknesses~~NUI’s external and internal auditors performed audits during NUI’s fiscal 2003 and 2004 years that identified material weaknesses in NUI’s internal controls. These weaknesses were previously discussed in NUI’s filings with the SEC. In March 2004, additional internal control issues and deficiencies were identified in the focused audit of NUI that was conducted at the request of the New Jersey Board of Public Utilities (NJBPU). These deficiencies resulted in a material weakness in internal controls over NUI’s financial reporting process and also resulted in a need for NUI to restate certain of its financial statements. The internal control deficiencies reported by NUI that were identified by NUI’s external and internal auditors included, but were not limited to, the following:

·	~~General ledger cash account balances were not being reconciled to the bank statements.~~

·	~~General ledger account analyses were not being consistently performed.~~

·	~~A listing of debt covenants was not being maintained.~~

·	~~Comprehensive and formalized accounting and financial reporting policies and procedures did not exist.~~

·	~~Instances were noted where management lacked certain technical accounting and tax expertise that resulted in accounting errors.~~

·	~~The flow of accounting information between business units and corporate accounting was not timely or formalized.~~

·	~~Accounts payable invoice processing procedures needed to be improved.~~

·	~~A formal plan and implementation timetable needed to be developed to address compliance with the certification requirements of SOX 404.~~

·	~~The contract review process was not formally documented, and appropriate procedures had not been developed to ensure timely review of contracts for accounting implications.~~

·	~~There was a lack of adherence to policies and procedures for travel and entertainment expense reimbursements and procurement card expenditures.~~

·	~~The payroll timekeeping and tracking process was manual in nature and prone to errors.~~

·	~~Information technology had a number of areas where formal, documented policies and procedures had not been developed.~~

~~The focused audit conducted at the request of the NJBPU revealed the following accounting concerns and weaknesses:~~

·	~~inappropriate and inaccurate treatment of intercompany payable and receivable balances~~

·	~~inappropriate use of a common cash pool~~

·	~~lack of a formal cash management agreement~~

·	~~weaknesses in internal controls for accounts payable and receivable~~

·	~~lack of formal or appropriate policies and procedures in certain accounting functions, and~~

·	~~the need to audit procedures for fixed asset and continuing property records functions~~

To address the deficiencies in its internal controls and procedures noted above, NUI expanded its internal controls and procedures to include the additional analysis and other post-closing procedures described below. The company

provided comprehensive in-house training in early fiscal 2004 covering the financial reporting process and internal accounting controls, including NUI’s written accounting policies and procedures and a policy on disclosure controls, to individuals who participate in the preparation of the company’s financial statements and required disclosures

·	conducted meetings in which NUI’s President and CEO, Vice President and CFO, General Counsel and Secretary reviewed and discussed accounting and operational issues to ensure completeness and accuracy of disclosures in NUI’s SEC filings

·	requested that NUI’s in-house counsel and key financial and operational personnel provide information regarding any known commitments and contingencies that may have financial statement and/or disclosure implications

·	~~obtained internal certifications from key accounting and operational personnel indicating that they reviewed drafts of NUI’s SEC filings for completeness and accuracy~~

·	conducted formal meetings, led by NUI’s Corporate Controller with participation of key accounting personnel (prior to closing the books of account and filing required reports), to identify and resolve accounting and disclosure issues

·	prepared and distributed to participants involved in the preparation and review of NUI’s SEC filings a detailed time schedule outlining key dates and responsibilities for the preparation of financial information and required disclosures

·	~~completed an audit disclosure checklist to ensure all disclosures required by GAAP and applicable securities laws and regulations were properly addressed~~

·	~~assembled supporting documentation for disclosures made in its SEC filings~~

·	~~retained external counsel to review drafts of its SEC filings to assist management in ensuring compliance with SEC rules and regulations~~

·	created documentation, including flowcharts and formal written policies and procedures of NUI’s financial reporting process, to assist management with its responsibility to ensure key internal accounting controls are identified and addressed

·	~~distributed a business ethics policy to all employees requesting their acknowledgement that they received, read and complied with the ethics policy~~

·	~~conducted internal audits to evaluate internal accounting controls of key business functions~~

We have initiated our efforts to assess the systems of internal control related to NUI’s business to comply with the requirements of both Sections 302 and 404 of the Sarbanes-Oxley Act of 2002. We believe that material deficiencies in internal controls discussed above related to the NUI business persists and that we are required to address and resolve these deficiencies. Our integration plans with respect to the NUI businesses include the integration and conversion of NUI’s accounting systems and internal control processes into our accounting systems and internal control processes, the majority of which we expect to complete during the first quarter of 2005. In addition, we have incorporated the NUI businesses into our disclosure control processes, which include the same or similar activities to those undertaken by NUI management described above, as well as other procedures, in our closing and financial reporting process.

Results of Operations

AGL Resources

~~We acquired Jefferson Island on October 1, 2004 and NUI on November 30, 2004. As a result, our~~Our results of operations for 2004 ~~include~~included three months of the acquired operations of Jefferson Island and one month of the acquired operations of NUI.

Pursuant to ~~FIN 46R,~~Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46) as revised, which we adopted in January 2004, we consolidated ~~all of~~ SouthStar’s accounts with our subsidiaries’ accounts as of January 1, 2004. WeFor the years ended December 31, 2005 and 2004, we recorded the Piedmont Natural Gas Company, Inc.’s (Piedmont) portion of SouthStar’s earnings as a minority interest in our statements of consolidated income and ~~Piedmont’s~~the Piedmont portion of SouthStar’s contributed capital as a minority interest onin our consolidated balance ~~sheet.~~sheets. We eliminated any intercompany profits between segments.

In 2003, we accounted for our 70% noncontrolling financial ownership interest in SouthStar using the equity method of accounting because SouthStar did not meet the definition of a variable interest entity under FIN 46. Under the equity method, we reported our ownership interest in SouthStar as an investment in our consolidated balance sheets, and we reported our share of SouthStar’s earnings based on our ownership percentage in our statements of consolidated income as a component of other income.

Seasonality The operating revenues and EBIT of our distribution operations, retail energy operations and wholesale services segments are seasonal. During the heating season (October - March), natural gas usage and operating revenues are higher because generally more customers are connected to our distribution systems and because natural gas usage is higher in periods of colder weather than in periods of warmer weather. Approximately 70% of these segments’ operating revenues and EBIT for the year ended December 31, 2005 were generated during the six-month heating season and are reflected in our consolidated income statements for the quarters ended March 31, 2005 and December 31, 2005. Our base operating expenses, excluding cost of gas, interest expense and certain incentive compensation costs, are incurred relatively equally over any given year. Thus our operating results vary significantly from quarter to quarter as a result of seasonality. Seasonality also affects the comparison of certain balance sheet items such as receivables, unbilled revenue, inventories and short-term debt across quarters.

HedgingChanges in commodity prices subject a significant portion of our operations to variability. Commodity prices tend to be higher in colder months. Our nonutility businesses principally use physical and financial arrangements to economically hedge the risks associated with both seasonal fluctuations and changing commodity prices. In addition, because these economic hedges are generally not designated for hedge accounting treatment, our reported earnings for the wholesale services and retail energy operations segments reflect changes in the fair values of certain derivatives; these values may change significantly from period to period.

Elizabethtown Gas utilizes certain derivatives to hedge the impact of market fluctuations in natural gas prices. These derivative products are marked to market each reporting period. In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in purchased gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset (loss) or liability (gain), as appropriate, in our consolidated balance sheets.

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

~~A significant portion~~

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

Operating ~~margin~~Margin and EBIT We evaluate the performance of our operating segments using the measures of operating margin and EBIT. We believe operating margin is a better indicator than revenues for the contribution resulting from customer growth in our distribution operations segment since the cost of gas can vary significantly and is generally passed directly to our customers. We also consider operating margin to be a better indicator in our retail energy operations, wholesale services and energy investments segments since it is a direct measure of gross profit before overhead costs. We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

Our operating margin and EBIT are not measures that are considered to be calculated in accordance with ~~GAAP.~~accounting principles generally accepted in the United States of America (GAAP). You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our operating margin or EBIT ~~measures~~measure may not be comparable to a similarly titled ~~measure~~measures of ~~another company.~~ other companies.

The following ~~are reconciliations~~table sets forth a reconciliation of our operating margin and EBIT to our operating income and net income, ~~and~~together with other consolidated financial information for the years ended December 31, ~~2004,~~2005 and 2004; and pro-forma results as if SouthStar’s accounts were consolidated with our subsidiaries’ accounts for the year ended December 31, 2003. The unaudited pro-forma results are presented for comparative purposes as a result of our consolidation of SouthStar’s accounts with our subsidiaries’ accounts as of January 1, 2004. This pro-forma basis is a non-GAAP presentation; however, we believe it is useful to readers of our financial statements since it presents our revenues and expenses for 2003 on the same basis as 2005 and ~~2002.~~2004.

In millions	2005			2004			Pro-forma 2003
Operating revenues	$	2,718		$	1,832		$	1,557
Cost of gas		1,626			995			789
Operating margin		1,092			837			768
Operating expenses
Operation and maintenance		477			377			343
Depreciation and amortization		133			99			92
Taxes other than income		40			29			28
Total operating expenses		650			505			463
Gain on sale of Caroline Street campus		-			-			16
Operating income		442			332			321
Other losses		(1	)		-			(6	)
Minority interest		(22	)		(18	)		(17	)
EBIT		419			314			298
Interest expense		109			71			75
Earnings before income taxes		310			243			223
Income taxes		117			90			87
Income before cumulative effect of change in accounting principle		193			153			136
Cumulative effect of change in accounting principle		-			-			(8	)
Net income	$	193		$	153		$	128
Basic earnings per common share:
Income before cumulative effect of change in accounting principle	$	2.50		$	2.30		$	2.15
Cumulative effect of change in accounting principle		-			-			(0.12	)
Basic earnings per common share	$	2.50		$	2.30		$	2.03
Fully diluted earnings per common share:
Income before cumulative effect of change in accounting principle	$	2.48		$	2.28		$	2.13
Cumulative effect of change in accounting principle		-			-			(0.12	)
Fully diluted earnings per common share	$	2.48		$	2.28		$	2.01
Weighted average number of common shares outstanding:
Basic		77.3			66.3			63.1
Diluted		77.8			67.0			63.7

Table of Contents

Segment information Operating revenues, operating margin and EBIT information for each of our segments are presented in the following table for the years ended December 31, 2005, 2004 and 2003:

In millions	Operating revenues			Operating margin			EBIT
2005
Distribution operations	$	1,753		$	814		$	299
Retail energy operations		996			146			63
Wholesale services		95			92			49
Energy investments		56			40			19
Corporate (1)		(182	)		-			(11	)
Consolidated	$	2,718		$	1,092		$	419
2004
Distribution operations	$	1,111		$	640		$	247
Retail energy operations		827			132			52
Wholesale services		54			53			24
Energy investments		25			13			7
Corporate (1)		(185	)		(1	)		(16	)
Consolidated	$	1,832		$	837		$	314
2003
Distribution operations	$	936		$	599		$	247
Retail energy operations (2)		743			124			46
Wholesale services		41			40			20
Energy investments		6			5			(3	)
Corporate (1) (2)		(169	)		-			(12	)
Consolidated	$	1,557		$	768		$	298

In millions

2004

2003

2002

Operating revenues $ 1,832 $ 983 $ 877
Cost of gas 994 339 268
Operating margin 838 644 609
Operating expenses
Operation and maintenance 377 283 274
Depreciation and amortization 99 91 89
Taxes other than income taxes 30 28 29
Total operating expenses 506 402 392
Gain on sale of Caroline Street campus - 16 -
Operating income 332 258 217
Other income - 40 30
Minority interest (18 ) - -
EBIT 314 298 247
Interest expense 71 75 86
Earnings before income taxes 243 223 161
Income taxes 90 87 58
Income before cumulative effect of change in accounting principle 153 136 103
Cumulative effect of change in accounting principle - (8 ) -
Net income $ 153 $ 128 $ 103
Basic earnings per common share
Income before cumulative effect of change in accounting principle $ 2.30 $ 2.15 $ 1.84
Cumulative effect of change in accounting principle - (0.12 ) -
Basic earnings per common share $ 2.30 $ 2.03 $ 1.84
Fully diluted earnings per common share
Income before cumulative effect of change in accounting principle $ 2.28 $ 2.13 $ 1.82
Cumulative effect of change in accounting principle - (0.12 ) -
Fully diluted earnings per common share $ 2.28 $ 2.01 $ 1.82
Weighted average number of common shares outstanding
Basic 66.3 63.1 56.1
Fully diluted 67.0 63.7 56.6

(1)	Includes the elimination of intercompany revenues.

(2)	Includes pro-forma results as if SouthStar’s accounts were consolidated with our subsidiaries’ accounts.

In the following table, our reported results in 2003 are reconciled to the pro-forma presentation presented in the tables above. In 2003, we recognized our portion of SouthStar’s earnings of $46 million as equity earnings. The amounts presented below for SouthStar represent 100% of its revenues and expenses for 2003 and include minority interest which adjusts our 80% share of SouthStar’s earnings to reflect Piedmont’s and Dynegy Inc.’s share of SouthStar’s earnings.

	For the twelve months ended December 31, 2003
	As			South-			Elimin-			Pro-
In millions	Reported			Star			ations			Forma
Operating revenues	$	983		$	743		$	(169	)	$	1,557
Cost of gas		339			619			(169	)		789
Operating margin		644			124			-			768
Operating expenses
Operation and maintenance		283			60			-			343
Depreciation and amortization		91			1			-			92
Taxes other than income		28			-			-			28
Total operating expenses		402			61			-			463
Gain on sale of Caroline Street campus		16			-			-			16
Operating income		258			63			-			321
Equity earnings from SouthStar		46			-			(46	)		-
Other losses		(6	)		-			-			(6	)
Minority interest		-			(17	)		-			(17	)
EBIT		298			46			(46	)		298
Interest expense		75			-			-			75
Earnings before income taxes		223			46			(46	)		223
Income taxes		87			-			-			87
Income before cumulative effect of change in accounting principle	$	136		$	46		$	(46	)	$	136

Discussion of Consolidated Results

~~2004~~2005 compared to ~~2003~~2004 Our earnings per share and net income for the year ended December 31, 2005 were higher than the prior year due to the acquisitions of NUI and Jefferson Island combined with strong contributions from our wholesale services and retail energy operations businesses.

Consolidated EBIT for 2005 increased by $105 million or 33% from the previous year, of which $56 million related to EBIT contributions from the 2004 acquisitions of NUI and Jefferson Island and from Pivotal Propane of Virginia, Inc. (Pivotal Propane) which became operational in 2005. The increase further reflected increased contributions of $8 million from Atlanta Gas Light in distribution operations, $11 million from retail energy operations and $3 million from AGL Networks, LLC (AGL Networks) in energy investments. Wholesale services’ EBIT increased $25 million primarily due to increased operating margins partially offset by higher operating expenses. The corporate segment improved by $5 million as compared to last year primarily due to merger and acquisition related costs incurred in 2004 but not in 2005.

Operating margin increased $255 million or 30%, primarily reflecting the NUI and Pivotal Jefferson Island acquisitions and completion of the Pivotal Propane facility in Virginia, as well as improved margins at SouthStar, Sequent and AGL Networks. Excluding the addition of the NUI utilities, distribution operations’ margins improved by $8 million mainly as a result of higher pipeline replacement revenues and additional carrying costs charged to retail marketers in Georgia for gas storage. Retail energy operations’ margins were up $14 million, due primarily to higher commodity margins. Wholesale services' operating margin increased $39 million year over year, primarily due to activity during the third and fourth quarters of 2005. Energy investments’ margins were also up $27 million, primarily as a result of the acquisition of Jefferson Island that contributed $13 million; contributions from NUI’s nonutility businesses of $8 million; contribution from Pivotal Propane of $3 million; and improved operating margin at AGL Networks of $4 million.

Table of Contents

Operating expenses increased $145 million or 29%, primarily as a result of $124 million in higher expenses at distribution operations due to the addition of NUI. In addition, operating expenses at energy investments increased $15 million due to the addition of Jefferson Island, the NUI nonutility assets and Pivotal Propane. Operating expenses at wholesale services increased $13 million due to increased payroll and employee incentive compensation costs resulting from its operational and financial growth and depreciation on a trading and risk management system placed in service during 2004. The increased operating expenses were offset by lower corporate operating expenses primarily due to prior-year costs incurred with merger and acquisition activities.

Interest expense for 2005 was $109 million, or $38 million higher than in 2004. As indicated in the table below, higher short-term interest rates and higher debt outstanding combined to increase our interest expense in 2005 relative to the previous year. The increase of $549 million in average debt outstanding for 2005 compared to 2004 was due to additional debt incurred as a result of the acquisitions of NUI and Jefferson Island, and higher working capital requirements as a result of higher natural gas prices.

Dollars in millions	2005			2004
Total interest expense	$	109		$	71
Average debt outstanding (1)		1,823			1,274
Average interest rate		6.0	%		5.6	%

(1)	Daily average of all outstanding debt

We anticipate our interest expense in 2006 will be higher than in 2005 due to higher projected interest rates. Based on $728 million of variable-rate debt, which includes $522 million of our short-term debt, $100 million of variable-rate senior notes and $106 million of variable-rate gas facility revenue bonds outstanding at December 31, 2005, a 100 basis point change in market interest rates from 4.7% to 5.7% would result in an increase in annual pretax interest expense of $7 million.

The increase in income tax expense of $27 million or 30% for 2005 compared to 2004 reflected additional income taxes of $25 million due to higher corporate earnings year over year and $2 million due to a slightly higher effective tax rate of 38% for 2005 as compared to 37% in 2004. We expect our effective tax rate for the year ending December 31, 2006 to be similar to the effective rate for the year ended December 31, 2005.

As a result of our 11 million share equity offering in November 2004, earnings results for the year are based on weighted average shares outstanding of 77.3 million, while 2004 results were based on weighted average shares outstanding of 66.3 million.

2004 compared to 2003 Our EBIT for the year ended December 31, 2004 was higher than the prior year due to stronger contributions from our wholesale services business ~~SouthStar~~ and retail energy operations and from the acquisitions of NUI and Jefferson Island. ~~The following table provides a summary of certain items that impacted 2004 earnings.~~

In millions
Increase (Decrease) in 2004 Operating Income (Before Taxes)
Accelerated recognition of margins associated with Sequent storage positions originally were anticipated to be liquidated in the first quarter of 2005 $ 5
Asset sales in the second quarter of 2004 for a residential and retail property in Savannah, Georgia which resulted in a $2 million contribution to EBIT and the sale of our remaining investment units in U.S. Propane LP 3
Change in Atlanta Gas Light’s property taxes as a result of revised estimates and intangible property tax assessment 3
Contributions to the AGL Resources Private Foundation Inc. and for energy assistance by our subsidiary SouthStar (3 )

~~The distribution operations segment’s~~Consolidated EBIT for 2004 ~~was $247~~increased $16 million ~~equal~~or 5% as compared to 2003, ~~results.~~of which $10 million related to EBIT contributions from our acquisitions of NUI ($7 million) and Jefferson Island ($3 million) during the fourth quarter of 2004. Distribution operations’ EBIT for 2004 remained relatively flat as compared to 2003. For comparison purposes, however, ~~the~~ distribution ~~operations segment’s~~operations’ EBIT in 2004 increased by $13 million after excluding the effect of a net $13 million pretax gain on the ~~sale~~sales of company property and a related charitable contribution in ~~2003. In addition,~~2003.The increase further reflected increased contributions from SouthStar in retail energy operations of $6 million, AGL Networks in energy investments of $3 million and Sequent in wholesale services of $4 million. Additionally, our energy investments segment had a $4 million increase in EBIT due to the 2004 ~~EBIT includes~~sale of Heritage Propane and of a $7residential development property in Savannah, Georgia. These increases were partially offset by lower contributions of $4 million ~~contribution~~ from ~~NUI.~~our corporate segment due to increased outside service costs associated with software maintenance, licensing and implementation of our work management project, higher costs due to Section 404 of the Sarbanes-Oxley Act of 2002 (SOX 404) compliance efforts and merger and acquisition related costs.

~~Operating~~Our operating margin for 2004 increased $69 million or 9% as compared to 2003 pro-forma operating margin, primarily reflecting the 2004 NUI and Jefferson Island acquisitions, which contributed $29 million. Sequent, SouthStar and AGL Networks also had improved 2004 operating margins of $13 million, $8 million (on a pro-forma basis) and $2 million, respectively. Excluding the addition of the NUI utilities, distribution ~~operations segment~~operations’ margins improved by $17 million mainly at Atlanta Gas Light and Virginia Natural Gas. Atlanta Gas Light’s operating margin increased as a result of higher pipeline replacement revenues, additional carrying costs charged to retail marketers in Georgia for gas storage, customer growth and higher customer usage. Virginia Natural Gas’ operating margin increased primarily due to customer growth.

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Operating expenses increased $42 million on a pro-forma basis or ~~7%,~~9% primarily as a result of $19 million in higher expenses due to the additions of NUI and Jefferson Island. In addition, operating expenses at wholesale services increased $9 million due to increased outside service costs related to its energy trading and risk management system and SOX 404 compliance projects and an increase in the number of employees, as well as increased depreciation. Excluding the effects of our acquisition of NUI, ~~($25 million) and an approximately 2% increase in the total number of average connected customers at Atlanta Gas Light, Chattanooga Gas and Virginia Natural Gas. Operating~~distribution operations’ expenses increased ~~$29~~$10 million ~~or 8% in 2004 relative to 2003, primarily~~ as a result of ~~NUI ($19 million) and~~ increased costs related to information technology projects, ~~regulatory activities (including Sarbanes-Oxley compliance)~~SOX 404 compliance and depreciation expense, offset by decreased bad debt ~~expense and~~expense. Our corporate segment also had a ~~decrease~~$6 million increase in operating expenses primarily from increased outside service costs associated with ~~postretirement benefits.~~

The wholesale services segment contributed $24 million in EBIT in 2004 compared with $20 million in 2003. The $4 million increase is primarily the result of unusually strong fourth-quarter 2004 results, reflecting the accelerated recognition of margins associated with storage positions that originally were anticipated to be liquidated in the first quarter of 2005. The accelerated margin recognition resulted in $5 million of operating income in the fourth quarter that otherwise would have been recognized in the first quarter of 2005. Primarilysoftware maintenance, licensing and implementation projects, as ~~a result of the decline in forward gas prices at the end of December 2004,~~well as for SOX 404 compliance efforts and the positive mark-to-market impact that decline had on the futures contracts Sequent utilizes to economically hedge its storage positions, approximately $18 million or 75% of Sequent’s full-year EBIT contribution was generated in the fourth quarter of 2004.

~~Sequent also continued to increase its volumes~~merger and ~~business transaction activity in 2004. Full-year volumes~~acquisition activities. These increased 20%, from 1.75 billion cubic feet (Bcf) per day in 2003 to 2.10 Bcf per day in 2004. New peaking and third-party asset management transactions also contributed to strong results for the year. Sequent’s operating expenses ~~for 2004~~ were ~~$29~~offset by a $2 million compared with $20 million in 2003. The increase was due primarily to increased personnel and increased costs associated with the implementation of a new energy trading and risk management system and Sarbanes-Oxley 404 compliance.

The energy investments segment contributed EBIT of $59 million in 2004, a 37% increase over the segment’s $43 million contribution in 2003. The primary driver of this segment’s results was the performance of SouthStar, which contributed $53 million in EBIT in 2004 compared with $46 million in 2003. The improved resultsdecrease at SouthStar on a pro-forma basis mainly ~~reflected higher commodity margins and decreased~~due to lower bad debt expense ~~during the year. Energy investments’ EBIT contribution increased due to~~offset by higher ~~contributions from AGL Networks~~corporate allocated overhead and ~~the acquisition of Jefferson Island in October 2004.~~

~~The corporate segment EBIT contribution decreased by $4 million to ($16) million in 2004, primarily the result of costs associated with information technology projects,~~ SOX 404 compliance ~~and merger-and-acquisition related expenses.~~costs.

Interest expense for 2004 was $71 million ~~which was~~or $4 million lower than in 2003. AAs shown in the following table, a favorable interest rate environment and the issuance of lower-interest long-term debt combined to lower the company’s interest expense in 2004 relative to the previous year. The increase of $19 million in average debt outstanding for 2004 compared to 2003 was due to additional debt incurred as a result of the acquisitions of NUI and Jefferson Island.

Dollars in millions

2004

2003

2004 vs. 2003

Interest rate $ 71 $ 75 ($4 )
Average debt outstanding(1) 1,274 1,255 19
Average rate 5.6 % 6.0 % (0.4 %)

Dollars in millions	2004			2003
Total interest expense	$	71		$	75
Average debt outstanding (1)		1,274			1,255
Average interest rate		5.6	%		6.0	%

(1)	Daily average of all outstanding ~~debt~~

Based on variable-rate debt outstanding at December 31, 2004, a 100 basis point change in market interest rates from 3.1% to 4.1% would result in a change in annual pretax interest expense of $5 million. We anticipate that our interest expense in 2005 will be higher than in 2004 due to the following:

·	~~higher projected short-term interest rates based upon higher 2005 London Interbank Offered Rate (LIBOR) rates~~

·	~~higher debt balances and higher interest rates from 2004 and 2005 on debt issued for the acquisitions of NUI and Jefferson Island~~debt.

The increase in income tax expense of $3 million or 3% for 2004 as compared to 2003 reflected $8 million of additional income taxes due to higher corporate earnings ~~year-over-year,~~year over year, offset by a $5 million decrease in income taxes due to a decrease in the effective tax rate from 39% in 2003 to 37% in 2004. The decline in the effective tax rate was primarily the result of income tax adjustments recorded in the third quarter of 2004 in connection with our annual comparison of ~~our~~ filed tax returns to ~~the~~ related income tax accruals. We expect our effective tax rate for the year ending December 31, 2005 to be higher due to the favorable adjustments recorded in 2004 and the higher state income tax rate that will be applicable to earnings from Elizabethtown Gas in New Jersey.

As a result of ~~the company’s 11-million~~our 11 million share equity offering in November 2004, earnings results for the year are based on weighted average shares outstanding of 66.3 million, while 2003 results were based on weighted average shares outstanding of 63.1 million. ~~Currently, we have approximately 76.9 million shares outstanding.~~

~~2003 compared to 2002~~Net income increased $25 million or 24% from 2002, reflecting higher earnings at each operating segment. EBIT from distribution operations, excluding the net gain on the sale of the Caroline Street campus of $13 million, increased 4% to $234 million from $225 million in 2002 due to higher operating margins, an increase in the number of connected customers and increased pipeline replacement revenue in 2003. Wholesale services contributed $20 million in EBIT compared to $9 million in 2002. The earnings improvement resulted primarily from Sequent’s optimization of various transportation and storage assets and increased physical volumes sold as well as increased margins driven by favorable pricing and market volatility, particularly in the first quarter of 2003.

Energy investments contributed $43 million in EBIT compared to $24 million in 2002. SouthStar accounted for the majority of the increase, and its results were driven primarily by higher operating margins, reduced bad debt expense, our expanded ownership interest in the business and the resolution of an income-sharing issue with Piedmont. Our corporate segment’s expenses decreased primarily as a result of favorable interest expense and lower average debt balances. The 7 million share increase in our weighted average shares outstanding was a result of our 6.4 million share equity offering in February 2003.

~~The following table shows the impact of the 2003 sale of our Caroline Street campus and the related donation to the private foundation:~~

In millions

Distribution Operations

Corporate

Consolidated

Gain (loss) on sale of Caroline Street campus $ 21 ($5 ) $ 16
Donation to private foundation (8 ) - (8 )
EBIT 13 (5 ) 8
Income taxes (3 )
Net income $ 5

The decrease in interest expense of $11 million or 13% for 2003 as compared to 2002 was a result of lower average debt balances, as shown in the following table, due primarily to the proceeds generated from our public offering of 6.4 million shares of common stock in February 2003; repayment of Medium-Term notes, which had higher rates than our bond issuance in July 2003; the benefits of our interest rate swaps; and lower interest rates on commercial paper borrowings.

Dollars in millions

2003

2002

2003 vs. 2002

Total interest expense $ 75 $ 86 ($11 )
Average debt outstanding(1) 1,255 1,412 (157 )
Average rate 6.0 % 6.1 % (0.1 %)

~~(1)~~

~~Daily average of all outstanding debt~~

The increase in income tax expense of $29 million or 50% for 2003 compared to 2002 was primarily due to the increase in earnings before income taxes of $62 million or 39% and an increase in our effective tax rate from 36% in 2002 to 39% in 2003. The increase in the effective tax rate for 2003 was primarily due to higher projected state income taxes resulting from a change in Georgia law governing the methodology by which Georgia companies must compute their tax liabilities and to the accrual of deferred tax liabilities related to temporary differences between the book and tax basis of some of our assets.

~~Consolidation~~Table of ~~SouthStar~~Below are our unaudited pro-forma condensed consolidated balance sheet and statement of income, presented as if SouthStar’s balances were consolidated with our subsidiaries’ accounts as of December 31, 2003. This pro-forma presentation is a non-GAAP presentation; however, we believe this pro-forma presentation is useful to the readers of our financial statements since it presents our financial statements for prior years on the same basis as 2004 following our consolidation of SouthStar pursuant to our adoption of FIN 46R. These unaudited pro-forma amounts are presented only for comparative purposes. The eliminations include intercompany eliminations, our investment in SouthStar, SouthStar’s capitalization and our equity in earnings from SouthStar.Contents

AGL Resources Inc. and Subsidiaries

Pro-forma condensed consolidated balance sheet

December 31, 2003

In millions

As Reported

SouthStar

Eliminations

(Unaudited) Pro-forma

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

Current liabilities $ 1,048 $ 75 ($11 ) $ 1,112
Accumulated deferred income taxes 376 - - 376
Long-term liabilities 569 - - 569
Deferred credits 78 - - 78
Minority interest(2) - - 30 30
Capitalization 1,901 101 (101 ) 1,901
Total liabilities and capitalization $ 3,972 $ 176 ($82 ) $ 4,066

~~(1)~~

~~Our investment in SouthStar was $71 million.~~

~~(2)~~

~~Minority interest adjusts our balance sheet to reflect Piedmont’s portion of SouthStar’s contributed capital.~~

AGL Resources Inc. and Subsidiaries

Pro-forma condensed consolidated statement of income

for the year ended December 31, 2003

In millions

As Reported

SouthStar(1)

Eliminations

(Unaudited) Pro-forma

Operating revenues $ 983 $ 746 ($169 ) $ 1,560
Operating expenses
Cost of gas 339 622 (169 ) 792
Operation and maintenance expenses 283 60 - 343
Depreciation and amortization 91 1 - 92
Taxes other than income 28 - - 28
Total operating expenses 741 683 (169 ) 1,255
Gain on sale of Caroline Street campus 16 - - 16
Operating income 258 63 - 321
Equity earnings from SouthStar 46 - (46 ) -
Donation to private foundation (8 ) - - (8 )
Other income 2 - - 2
Interest expense (75 ) - - (75 )
Minority interest in income of consolidated subsidiary(2) - - (17 ) (17 )
Earnings before income taxes 223 63 (63 ) 223
Income taxes (87 ) - - (87 )
Income before cumulative effect of change in accounting principle $ 136 $ 63 ($63 ) $ 136

~~(1)~~

~~Includes 100% of SouthStar’s revenues and expenses for comparisons of SouthStar’s consolidation in 2004.~~

~~(2)~~

~~Minority interest adjusts our earnings to reflect our 80% share of SouthStar’s earnings, less Dynegy Inc.’s 20% share of SouthStar’s income prior to February 18, 2003.~~

AGL Resources Inc. and Subsidiaries

Pro-forma condensed consolidated statement of income

for the year ended December 31, 2002

In millions

As Reported

SouthStar(1)

Eliminations

(Unaudited) Pro-forma

Operating revenues $ 877 $ 630 ($171 ) $ 1,336
Operating expenses
Cost of gas 268 515 (171 ) 612
Operation and maintenance expenses 274 72 - 346
Depreciation and amortization 89 2 - 91
Taxes other than income 29 - - 29
Total operating expenses 660 589 (171 ) 1,078
Operating income 217 41 - 258
Equity earnings from SouthStar 27 - (27 ) -
Other income 3 1 - 4
Interest expense (86 ) - - (86 )
Minority interest in income of consolidated subsidiary(2) - - (15 ) (15 )
Earnings before income taxes 161 42 (42 ) 161
Income taxes (58 ) - - (58 )
Net income $ 103 $ 42 ($42 ) $ 103

~~(1)~~

~~Includes 100% of SouthStar’s revenues and expenses for comparisons of SouthStar’s consolidation in 2004.~~

~~(2)~~

~~Minority interest adjusts our earnings to reflect our 50% share of SouthStar’s earnings.~~

~~Segment information~~ ~~Operating revenues, operating margin and EBIT information for each of our segments are contained in the following table for the years ended December 31, 2004, 2003 and 2002:~~

2004(in millions)

Operating revenues

Operating margin

EBIT

Distribution operations $ 1,111 $ 641 $ 247
Wholesale services 54 53 24
Energy investments 852 145 59
Corporate (1) (185 ) (1 ) (16 )
Consolidated $ 1,832 $ 838 $ 314
2003

Distribution operations $ 936 $ 599 $ 247
Wholesale services 41 40 20
Energy investments 6 5 43
Corporate - - (12 )
Consolidated $ 983 $ 644 $ 298
2002

Distribution operations $ 852 $ 585 $ 225
Wholesale services 23 23 9
Energy investments 2 1 24
Corporate - - (11 )
Consolidated $ 877 $ 609 $ 247

~~(1)~~

~~Includes the elimination of intercompany revenues.~~

Distribution Operations

Distribution operations includes our natural gas local distribution utility companies ~~which~~that construct, manage and maintain natural gas pipelines and distribution facilities and serve more than 2.2 million end-use customers. Distribution operations’ revenues contributed 61% of our consolidated revenues for 2004, 95% for 2003 and 97% for 2002. The decrease of 34% in the contribution of distribution operations’ revenues from 2003 is due to the impact of our consolidation of SouthStar in 2004. The following table provides operational information for our larger utilities. The daily capacity represents total system capability, and the storage capacity includes on-system ~~LNG~~liquefied natural gas (LNG) and propane volumes.

Atlanta Gas Light
Elizabethtown Gas
Virginia Natural Gas
Florida Gas
Chattanooga Gas

Average end-use customers (in thousands) (1) 1,533 266 256 104 60
   Daily capacity (2) 2.5 0.4 0.4 0.1 0.2
   Storage capacity(2) 55.6 14.0 10.2 - 4.8
   2004 peak day demand (2) 1.8 0.4 0.3 0.04 0.1
   Average monthly throughput (2) 19.8 5.0 2.9 0.8 1.4

   Authorized return on rate base (3) (4) 9.16% 7.95% 9.24% 7.36% 7.43%
   Authorized return on equity (4) 10.0-12.0% 10.0% 10.0-11.4% 11.25% 10.2%
   Authorized rate base % of equity (4) 47.0% 53.0% 52.4% 36.8% 35.5%
   Estimated 2004 return on equity (4) (5) 11.2% 5.2% 11.4% 6.6% 9.4%
Rate base included in estimated 2004 return of equity(6) (7) (in millions) $1,120 $397 $325 $125 $94

	Atlanta Gas Light	Elizabethtown Gas	Virginia Natural Gas	Florida City Gas	Chattanooga Gas
Operations
Average end-use customers (in thousands)	1,545	266	261	103	61
Daily capacity (1)	2.5	0.4	0.4	0.1	0.2
Storage capacity (1)	49.4	13.6	9.6	-	3.6
Annual distribution (1)	232	59	36	10	16
2005 peak day demand (1)	1.9	0.4	0.4	0.04	0.1
Peak storage capacity (1)	6.2	0.1	0.8	-	1.2
Average monthly throughput (1)	19.3	4.9	3.0	0.8	1.4
Miles of pipeline	30,427	4,948	5,106	3,162	1,521
Rates
Last decision on change in rates	Jun. 2005	Nov. 2002	Oct. 1996	Feb. 2004	Oct. 2004
Authorized return on rate base	8.53%	7.95%	9.24%	7.36%	7.43%
Estimated 2005 return on rate base (2) (3)	8.68%	6.54%	8.71%	6.25%	7.88%
Authorized return on equity	10.9%	10.0%	10.9%	11.25%	10.2%
Estimated 2005 return on equity (2) (3)	11.21%	6.37%	10.51%	8.32%	11.47%
Authorized rate base % of equity (4)	47.9%	53.0%	52.4%	36.8%	35.5%
Rate base included in 2005 return on equity (in millions) (3) (4)	$1,181	$433	$321	$118	$96

(1)	~~Represents an average for 2004 except Elizabethtown Gas and Florida gas, which are December 2004 amounts.~~

~~(2)~~

In millions of dekatherms.

~~(3)~~

~~The authorized return on rate base for Florida Gas includes a credit for deferred taxes that is considered a rate base deduction in all other jurisdictions.~~

~~(4)~~

The authorized returns on rate base and equity along with authorized rate base % of equity for Chattanooga Gas are currently under reconsideration by the Tennessee Regulatory Authority (Tennessee Authority). The estimated 2004 return on equity for Chattanooga Gas is calculated consistent with the Tennessee Authority order that is under reconsideration.

~~(5)~~(2)

Estimate based on principles consistent with utility ratemaking in each jurisdiction. Returns are not consistent with GAAP returns.

~~(6)~~ (3)

~~Based upon~~Estimated based on 13-month average.

~~(7)~~(4)

Rate base for Elizabethtown Gas is based ~~upon~~on amounts filed in a 2002 rate case; however, no specific ~~level of~~ rate base was authorized due to settlement by stipulation with ~~NJBPU.~~the New Jersey Board of Public Utilities. A 53% rate base of equity for Elizabethtown Gas was authorized in most recent rate case; however, 50% is used for rate of return calculation purposes based on estimated current regulatory capital structure.

In addition, ~~NUI is~~we are associated with ~~as many as 6~~ former sites in New Jersey, North Carolina and ~~10 former sites~~other states that we assumed with our acquisition of NUI in ~~other states.~~November 2004. Material cleanups of these sites have not been completed nor are precise estimates available for future cleanup costs. For the New Jersey sites, cleanup cost estimates range from ~~$30~~$57 million to ~~$116~~$104 million. Costs have been estimated for only ~~one~~1 of the ~~ten~~ non-New Jersey sites, for which current estimates range from $4$10 million to ~~$16~~$17 million.

~~The success of our telecommunications business strategy may be adversely affected by uncertain market conditions.~~

The current strategy of our telecommunications business is based upon our ability to lease telecommunications conduit and dark fiber in the Atlanta, Georgia and Phoenix, Arizona metropolitan areas. The market for these services, like the telecommunications industry in general, is very competitive, rapidly changing and currently suffering from lack of market commitments. We cannot be certain that growth in demand for these services will occur as expected. If the market for these services fails to grow as anticipated or becomes saturated with competitors, including competitors using alternative technologies, our investment in the telecommunications business may be adversely affected.

~~Future acquisitions and expansions, if any, may affect our business by increasing the level of our indebtedness and contingent liabilities and creating integration difficulties.~~

From time to time, we may evaluate and acquire assets or businesses or enter into joint venture arrangements that we believe complement our existing businesses and related assets. As a result, the relative makeup of our business is subject to change. These acquisitions and joint ventures may require substantial capital or the incurrence of additional indebtedness. Further, acquired operations or joint ventures may not achieve levels of revenues, operating income or productivity comparable to those of our existing operations or may not otherwise perform as expected. Realization of the anticipated benefits of acquisitions or other transactions could take longer than expected. Acquisitions or joint ventures may also involve a number of risks, including

·	~~our inability to integrate operations, systems and procedures~~

·	~~the assumption of unknown risks and liabilities~~

·	~~diversion of management’s attention and resources~~

·	~~difficulty retaining and training acquired key personnel~~

~~Our ability to successfully make strategic acquisitions and investments will depend on~~

·	~~the extent to which acquisitions and investment opportunities become available~~

·	~~our success in bidding for the opportunities that do become available~~

·	~~regulatory approval, if required, of the acquisitions on favorable terms~~

·	~~our access to capital and the terms upon which we obtain capital~~

·	~~if we are unable to make strategic investments and acquisitions, we may be unable to grow~~

Our growth may be restricted by the ~~capital intensive~~capital-intensive nature of our business.

~~In order to maintain our historic growth, we~~We must construct additions to our natural gas distribution system each ~~year.~~year to continue the expansion of our customer base. The cost of this construction may be affected by the cost of obtaining government approvals, development project delays or changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost of a project. Our cash flows are not fully adequate to finance the cost of this construction. As a result, we must fund a portion of our cash needs through borrowings and the issuance of common stock. ~~Our ability to finance the cost of constructing additions to our system depends on~~This may limit our ability to ~~borrow funds or sell~~increase infrastructure to connect customers due to limits on the amount we can economically invest, which shifts costs to potential customers. This may make it uneconomical for these potential customers to connect to our ~~common stock.~~distribution systems.

Table of Contents

Changes in weather conditions may affect our earnings.

Weather conditions and other natural phenomena can have a large impact on our earnings. Severe weather conditions can impact our suppliers and the pipelines that deliver gas to our distribution system. Extended mild weather, during either ~~during~~ the winter period or summer period, can have a significant impact on demand for and the cost of natural gas.

We have a WNA mechanism for Elizabethtown Gas, Chattanooga Gas and Virginia Natural Gas that partially offsets the impact ~~that~~of unusually cold or warm weather ~~has~~ on residential and commercial customer billings and margin. The WNA is most effective in a reasonable temperature range relative to normal weather using historical averages. The protection afforded by the WNA depends ~~upon~~on continued regulatory approval. The loss of this continued regulatory approval could make us more susceptible to weather-related earnings fluctuations.

Inflation and increased gas costs could adversely impact our customer base and customer collections and increase our level of indebtedness.

Inflation has caused increases in certain operating expenses and has required us to replace assets at higher costs. We have a process in place to continually review the adequacy of our utility gas rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those gas rates. Historically, we have been able to budget and control operating expenses and investments within the amounts authorized to be collected in rates and intend to continue to do so. The ability to control expenses is an important factor that will influence future results.

Rapid increases in the price of purchased gas ~~which occurred in some prior years,~~ cause us to experience a significant increase in short-term debt because we must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly customer bills for gas delivered. Increases in purchased gas costs also slow our utility collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher-than-normal accounts receivable. This situation also results in higher short-term debt levels and increased bad debt expense. Should the price of purchased gas increase significantly in the upcoming heating season, we would expect increases in our short-term debt, accounts receivable and bad debt expense during ~~2005.~~2006.

Finally, higher costs of natural gas in recent years have already caused many of our utility customers to conserve in the use of our gas services and could lead to even more customers utilizing such conservation ~~methods.~~methods or switching to other more efficient competing products. The higher costs have also allowed products utilizing energy sources other than natural gas for applications that have traditionally used natural gas to be in more competitive position, encouraging some customers to move away from natural gas fired equipment to equipment fueled by other energy sources.

A decrease in the availability of adequate pipeline transportation capacity could reduce our revenues and profits.

Our gas supply depends ~~upon~~on the availability of adequate pipeline transportation and storage capacity. We purchase a substantial portion of our gas supply from interstate sources. Interstate pipeline companies transport the gas to our system. A decrease in interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation and storage service could reduce our normal interstate supply of gas.

Risks Related to Our Corporate and Financial Structure

If we breach any of the material financial covenants under our various indentures, credit facilities or guarantees, our debt service obligations could be accelerated.

Our existing debt and the debt of certain of our subsidiaries contain a number of significant financial covenants. If we or any of these subsidiaries breach any of the financial covenants under these agreements, our debt repayment obligations under them could be accelerated. In such event, we may not be able to refinance or repay all our indebtedness, which would result in a material adverse effect on our business, results of operations and financial condition.

As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.

Our Credit Facility and the indenture under which Atlanta Gas Light’s outstanding ~~Medium-Term~~medium-term notes were issued contain cross-default provisions. Accordingly, should an event of default occur under some of our debt agreements, we face the prospect of being in default under other of our debt agreements, obliged in such instance to satisfy a large portion of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously.

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We depend on our ability to successfully access the capital markets. Any inability to access the capital or financial markets may limit our ability to execute our business plan or pursue improvements that we may rely on for future growth.

We rely on access to both short-term money markets (in the form of commercial ~~paper)~~paper and lines of credit) and long-term capital markets as a source of liquidity for capital and operating requirements not satisfied by the cash flow from our operations. If we are not able to access financial markets at competitive rates, our ability to implement our business plan and strategy will be affected. Certain market disruptions may increase our cost of borrowing or affect our ability to access one or more financial markets. Such market disruptions could result from

·	adverse economic conditions

·	adverse general capital market conditions

·	poor performance and health of the utility industry in general

·	bankruptcy or financial distress of unrelated energy companies or Marketers in Georgia

·	~~decreases~~significant decrease in the ~~market price of and~~ demand for natural gas

·	adverse regulatory actions that affect our local gas distribution companies

·	terrorist attacks on our facilities or our suppliers

~~Increases in our leverage could adversely affect our competitive position and financial condition.~~

~~An increase in our debt relative to our total capitalization could adversely affect us by~~

·	~~increasing the cost of future debt financing~~

·	~~limiting our ability to obtain additional financing, if we need it, for working capital, acquisitions, debt service requirements or other purposes~~

·	~~making it more difficult for us to satisfy our existing financial obligations~~

·	requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes

·	~~prohibiting the payment of dividends on our common stock or adversely impacting our ability to pay such dividends at the current rate~~

·	~~increasing our vulnerability to adverse economic and industry~~extreme weather conditions

·	~~limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete~~

~~Changing rating agency requirements could negatively affect our growth and business strategy, and a~~A downgrade in our credit rating could negatively affect our ability to access capital.

S&P, Moody’s and Fitch have recently implemented new requirements for various ratings levels. In order to maintain our current credit ratings in light of these or future new requirements, we may need to take steps or change our business plans in ways that may affect our growth and earnings per share. S&P, Moody’s and Fitch currently assign our senior unsecured debt a rating of BBB+, Baa1 and A,A-, respectively. Our commercial paper currently is rated A-2, P-2 and F-2 by S&P, Moody’s and Fitch, respectively. If the rating agencies downgrade our ratings, particularly below investment grade, it may significantly limit our access to the commercial paper market and our borrowing costs would increase. In addition, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources would likely decrease.

Additionally, if our credit rating by either S&P or Moody’s falls to non-investment grade status, we will be required to provide additional support for certain customers of our wholesale business. As of December 31, ~~2004,~~2005, if our credit rating had fallen below investment grade, we would have been required to provide collateral of approximately ~~$20~~$51 million to continue conducting our wholesale services business with certain counterparties.

The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.

We use derivatives, including futures, forwards and swaps, to manage our commodity and financial market risks. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could adversely affect the value of the reported fair value of these contracts.

We ~~depend on cash flow from our operations to pay dividends on our common stock.~~

We depend on dividends or other distributions of funds from our subsidiaries to pay dividends on our common stock. Payments of our dividends will depend on our subsidiaries’ earnings and other business considerations and may be subject to statutory or contractual obligations. Additionally, payment of dividends on our common stock is at the sole discretion of our Board of Directors.

We are vulnerable to interest rate risk with respect to our debt, which could lead to changes in interest expense.

We are subject to interest rate risk in connection with the issuance of fixed-rate and variable-rate debt. In order to maintain our desired mix of fixed-rate and variable-rate debt, we use interest rate swap agreements and exchange fixed-rate and variable-rate interest payment obligations over the life of the arrangements, without exchange of the underlying principal amounts. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.” We cannot ensure ~~you~~ that we will be successful in structuring such swap agreements to effectively manage our risks. If we are unable to do so, our earnings may be reduced. In addition, higher interest rates, all other things equal, reduce the earnings that we derive from transactions where we capture the difference between authorized returns and short-term borrowings.

~~Our tax rate may be increased and/or tax laws affecting us can change that may have an adverse impact on our cash flows and profitability.~~
50

Table of Contents

The rates of federal, state and local taxes applicable to the industries in which we operate, which often fluctuate, could be increased by the respective taxing authorities. In addition, the tax laws, rules and regulations that affect our business could change. Any such increase or change could adversely impact our cash flows and profitability.

Risks Related to Our Industry

Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.

Our gas distribution activities involve a variety of inherent hazards and operating risks, such as leaks, accidents and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, which in turn could lead to substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events not fully covered by insurance could adversely affect our financial position and results of operations.

Natural disasters, terrorist activities and the potential for military and other actions could adversely affect our businesses.

Natural disasters may damage our assets. The threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic and financial market instability and volatility in the price of natural gas that could affect our operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and companies in the energy industry may face a heightened risk of exposure to acts of terrorism. These developments have subjected our operations to increased risks. The insurance industry has also been disrupted by these events. As a result, the availability of insurance covering risks against which we and our competitors typically insure may be limited. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

Recent investigations and events involving the energy markets have resulted in an increased level of public and regulatory scrutiny in the energy industry and in the capital markets, resulting in increased regulation and new accounting standards.

As a result of the bankruptcy and adverse financial condition affecting several entities, particularly the bankruptcy filing by Enron, recently discovered accounting irregularities of various public companies and investigations by governmental authorities into energy trading activities, public companies, including particularly those in the energy industry, have been under an increased amount of public and regulatory scrutiny. Recently discovered practices and accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. New laws, such as the Sarbanes-Oxley Act of 2002, and regulations to address these concerns have been and continue to be adopted, and capital markets and rating agencies have increased their level of scrutiny. Costs related to increased scrutiny may have an adverse effect on our business, financial condition and access to capital markets. In addition, the FASB or the SEC could enact new accounting standards that could impact the way we are required to record revenues, assets and liabilities. These changes in accounting standards could lead to negative impacts on our reported earnings or increases in our liabilities.

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to risks associated with commodity prices, interest rates and credit. Commodity price risk is defined as the potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity. Interest rate risk results from our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business. Credit risk results from the extension of credit throughout all aspects of our business but is particularly concentrated at Atlanta Gas Light in distribution operations and in wholesale services.

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

Commodity Price Risk

~~Wholesale Services~~Retail Energy Operations ~~This segment routinely utilizes various types~~SouthStar’s use of ~~financial and other instruments to mitigate certain commodity price risks inherent in the natural gas industry. These instruments include~~derivatives is governed by a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, option contracts and financial swap agreements. The following table includes the fair values and average values of our energy marketing and risk management ~~assets~~policy, created and ~~liabilities as of December 31, 2004 and 2003. We base the average values on monthly averages for the 12 months ended December 31, 2004 and 2003.~~

Asset

Average 12-Month Values

Value at:

In millions

2004

2003

Dec. 31, 2004

Dec. 31, 2003

Natural gas contracts
$
28

$
14

$
36

$
13

Liability

Average 12-Month Values

Value at:

In millions

2004

2003

Dec. 31, 2004

Dec. 31, 2003

Natural gas contracts $ 21 $ 14 $ 19 $ 18

~~We employ a systematic approach to the evaluation and management of the risks associated with our contracts related to wholesale marketing and~~monitored by its risk management ~~including VaR. VaR is defined as~~committee, which prohibits the ~~maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree~~use of ~~probability. We use a 1-day and a 10-day holding period and a~~derivatives for speculative purposes. A 95% confidence interval is used to evaluate ~~our~~ VaR exposure. A 95% confidence interval means there is a 5% probability that the actual change in portfolio value will be greater than the calculated VaR value over the holding period. We calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price volatility, confidence interval and holding period. Our VaR may not be comparable to a similarly titled measure of another company because, although VaR is a common metric in the energy industry, there is no established industry standard for calculating VaR or for the assumptions underlying such calculations. The following table provides more information on SouthStar’s 1-day and 10-day holding period VaR.

~~Our~~
In millions

1-day

10-day

2005 period end $ 0.3 $ 0.8

2004 period end

0.2

0.5

SouthStar generates operating margin from the active management of storage positions through a variety of hedging transactions and derivative instruments aimed at managing exposures arising from changing commodity prices. SouthStar uses these hedging instruments to lock in economic margins (as spreads between wholesale and retail commodity prices widen between periods) and thereby minimize its exposure to declining operating margins.

Table of Contents

Wholesale Services This segment routinely utilizes various types of financial and other instruments to mitigate certain commodity price risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts and financial swap agreements. The following table includes the fair values and average values of our energy marketing and risk management assets and liabilities as of December 31, 2005 and 2004. We base the average values on monthly averages for the 12 months ended December 31, 2005 and 2004.

Average values at December 31,

In millions

2005

2004

Asset $ 83 $ 28
Liability 102 21 ��

Value at December 31,

In millions

2005

2004

Asset $ 97 $ 36
Liability 110 19

We employ a systematic approach to evaluating and managing the risks associated with our contracts related to wholesale marketing and risk management, including VaR. Similar to SouthStar, Sequent uses a 1-day and a 10-day holding period and a 95% confidence interval to evaluate its VaR exposure.

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

~~Our~~Sequent’s management actively monitors open commodity positions and the resulting VaR. ~~We continue~~Sequent continues to maintain a relatively matched book, where ~~our~~its total buy volume is close to sell volume, with minimal open commodity risk. Based on a 95% confidence interval and employing a 1-day and a 10-day holding period for all positions, ~~our~~Sequent’s portfolio of positions for the 12 months ended December 31, 2005, 2004 and 2003 had the following 1-day and 10-day holding period ~~VaRs:~~VaRs.

2004
In millions	1-day		10-day		1-day		10-day
2005
Period end	$	0.1	$	0.2	$	0.6	$	1.9
12-month average		0.1		0.3		0.4		1.2
High		0.4		1.3		1.1		3.5
Low(1)		0.0		0.0
Low (1)						0.0		0.0

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

			Commitments due before Dec. 31, 2007 &
			Commitments due before Dec. 31, 2007 &
In millions	Total		2006		thereafter
Standby letters of credit, performance / surety bonds	$	21	$	21	$	-

Rental ~~expense and sublease income~~Expense

~~The following table illustrates our total~~We incurred $26 million, $22 million, and $22 million in rental ~~lease expenses~~expense in 2005, 2004, and ~~sublease credits incurred for property and equipment:~~

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

Litigation

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

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

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

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

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

> Note 11

Fair Value of Financial Instruments

The following table shows the carrying amounts and fair values of ~~financial instruments~~our long-term debt including any current portions included in our consolidated balance ~~sheets:~~sheets.

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

In millions	Carrying Amount		Estimated Fair Value
As of December 31, 2005	$	1,615	$	1,784
As of December 31, 2004		1,623		1,816

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

Considerable judgment is required to develop the fair value estimates; therefore, the values are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair value estimates are based on information available to management as of December 31, ~~2004.~~2005. We are not aware of any subsequent factors that would significantly affect the estimated fair value amounts. For more information about the fair values of our interest rate swaps, see Note 4.

> Note 12

Income Taxes

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

Investment Tax Credits

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

In millions
2004 2003 2002
Included in expenses:

Current income taxes
Federal $ 25 $ 20 ($19 )
State 1 13 (4 )
Deferred income taxes
Federal 60 52 79
State 5 3 3
Amortization of investment tax credits (1 ) (1 ) (1 )
Total $ 90 $ 87 $ 58

In millions	2005			2004			2003
Current income taxes
Federal	$	84		$	25		$	20
State		18			1			13
Deferred income taxes
Federal		17			60			52
State		-			5			3
Amortization of investment tax credits		(2	)		(1	)		(1	)
Total	$	117		$	90		$	87

The reconciliations between the statutory federal income tax rate, the effective rate and the related amount of tax for the years ended December 31, 2005, 2004 ~~2003~~ and ~~2002~~2003 are presented ~~below:~~below.

2005
Dollars in millions	Amount			% of Pretax Income
Computed tax expense at statutory rate	$	109			35.0	%
State income tax, net of federal income tax benefit		11			3.7
Amortization of investment tax credits		(2	)		(0.6	)
Flexible dividend deduction		(2	)		(0.6	)
Other -- net		1			0.2
Total income tax expense at effective rate	$	117			37.7	%

2004
Dollars in millions		Amount			% of Pretax Income
Computed tax expense at statutory rate	$	85			35.0	%
State income tax, net of federal income tax benefit		9			3.5
Amortization of investment tax credits		(1	)		(0.6	)
Flexible dividend deduction		(2	)		(0.6	)
Other - net		(1	)		(0.2	)
Total income tax expense at effective rate	$	90			37.1	%

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

Table of Contents

2003
Dollars in millions	Amount			% of Pretax Income
Computed tax expense at statutory rate	$	78			35.0	%
State income tax, net of federal income tax benefit		8			3.8
Amortization of investment tax credits		(1	)		(0.6	)
Flexible dividend deduction		(1	)		(0.6	)
Other - net		3			1.4
Total income tax expense at effective rate	$	87			39.0	%

Accumulated Deferred Income Tax Assets and Liabilities

We report some of our assets and liabilities differently for financial accounting purposes than we do for income tax purposes. ~~The~~We report the tax effects of the differences in those items ~~are reported~~ as deferred income tax assets or liabilities in our consolidated balance sheets. ~~The~~We measure the assets and liabilities ~~are measured utilizing~~using income tax rates that are currently in effect. Because of the regulated nature of the utilities’ business, we recorded a regulatory tax liability ~~has been recorded~~ in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS 109)~~. The regulatory tax liability is being amortized~~, which we are amortizing over approximately 30 years(see Note 5). Our deferred tax ~~asset includes~~assets include an additional pension liability of ~~$33~~$37 million, which increased $7$3 million from ~~2003~~2004 in accordance with SFAS 109 (see Note 6).

As indicated in the table below, our deferred tax assets and liabilities include certain items we acquired from NUI. We have provided a valuation allowance for some of these items that ~~reduces~~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:~~

follows.

As of:
In millions
Dec. 31, 2004 Dec. 31, 2003
Accumulated deferred income tax liabilities

Property-accelerated depreciation and other property-related items $ 323 $ 294
Other 238 125
Total accumulated deferred income tax liabilities 561 419
Accumulated deferred income tax assets

Deferred investment tax credits 8 7
Deferred pension additional minimum liability 34 27
Net operating loss - NUI (1) 31 -
Net operating loss - Virginia Gas Company (2) 6 -
Capital loss carryforward 5 -
Alternative minimum tax credit (3) 7 -
Other 41 9
Total accumulated deferred income tax assets 132 43
Valuation allowances (8 ) -
Total accumulated deferred income tax assets, net of valuation allowance 124 43
Net accumulated deferred tax liability $ 437 $ 376

	As of:
In millions	Dec. 31, 2005			Dec. 31, 2004
Accumulated deferred income tax liabilities
Property - accelerated depreciation and other property-related items	$	494		$	323
Other		39			238
Total accumulated deferred income tax liabilities		533			561
Accumulated deferred income tax assets
Deferred investment tax credits		7			8
Deferred pension additional minimum liability		37			34
Net operating loss - NUI (1)		26			31
Net operating loss - Virginia Gas Distribution Company (2)		0			6
Capital loss carryforward (3)		4			5
Alternative minimum tax credit (4)		8			7
Other		37			41
Total accumulated deferred income tax assets		119			132
Valuation allowances (5)		(9	)		(8	)
Total accumulated deferred income tax assets, net of valuation allowance		110			124
Net accumulated deferred tax liability	$	423		$	437

(1)	Includes NUI’s federal net operating loss carryforwards of approximately ~~$79~~$62 million that expire in ~~2024~~2024.

(2)

Includes Virginia Gas ~~Company’s $18 million pre-acquisition net operating losses,~~Distribution Company which ~~are subject to a Internal Revenue Service Section 382 limitation (or reduced amount available for deduction as a result of change~~was sold in ~~control) and expire in 2016 through 2020.~~December 2005.

(3)	~~Was generated~~Expires December 31, 2007.

(4)	Generated by NUI and can be carried forward indefinitely to reduce ~~our~~ future tax liability.

(5)	Increase to valuation allowance is primarily due to increase in net operating losses on NUI headquarters that are not usable in New Jersey.

>Note 13

Related Party Transactions

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

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

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

FORM 10-K

(Mark One)

[ü] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2004~~2005

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-14174

AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)

Georgia	58-2210952
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Ten Peachtree Place NE,	404-584-4000
Atlanta, Georgia 30309
(Address and zip code of principal executive offices)	(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Class	Name of each exchange on which registered
Common Stock, $5 Par Value	New York Stock Exchange
Preferred Share Purchase Rights	New York Stock Exchange
8% Trust Preferred Securities	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 under the Securities Act. Yes [ü] No [ ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Act. Yes [ ] No [ü ]

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes [ü] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 under the Exchange Act. Large accelerated filer [ ü] Accelerated filer [ ] Non-accelerated filer [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes [ ] No [ü] ~~No [ ]~~

The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant, computed by reference to the price at which the registrant’s common ~~equity~~stock was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter, was ~~$1,879,590,369~~$2,989,393,874

The number of shares of ~~Common Stock~~the registrant’s common stock outstanding as of ~~February 11, 2005~~January 31, 2006 was ~~76,953,218.~~77,849,574.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Proxy Statement for the ~~2005~~2006 Annual Meeting of Shareholders (“Proxy Statement”) to be held ~~April 27, 2005,~~May 3, 2006, are incorporated by reference in Part III.

		Page(s)
Glossary of Key Terms		4
& Referenced Accounting Standards		54

Part I
Item 1.	Business	5
Item 1A.	Risk Factors	5
Item 1B.	Unresolved Staff Comments	5
Item 2.	Properties	5-6
Item 3.	Legal Proceedings	6
Item 2.	~~Properties~~	7
~~Item 3.~~	~~Legal Proceedings~~	8
~~Item~~ 4.	Submission of Matters to a Vote of Security Holders	96
Item 4A.	Executive Officers of the Registrant	97
Part II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	8-9
Item 6.	Selected Financial Data	10
Item 6.	~~Selected Financial Data~~	11
~~Item~~ 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1211-51
	Cautionary Statement Regarding Forward-Looking Information	1211
	Overview	1311-14
	Results of Operations	15-34
	AGL Resources	1915-19
	Distribution Operations	2520-25
	~~Wholesale Services~~ Retail Energy Operations	3325-27
	~~Energy Investments~~ Wholesale Services	3927-31
	~~Corporate~~ Energy Investments	4231-33
	Corporate	33-34
	Liquidity and Capital Resources	4335-40
	Critical Accounting Policies	4940-45
	Accounting Developments	5445
	Risk Factors	5545-51
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	6451-54
Item 8.	Financial Statements and Supplementary Data	55-94
	Consolidated Balance Sheets	6855-56
	Statements of Consolidated Income	7057
	Statements of Consolidated Common Shareholders’ Equity	7158
	Statements of Consolidated Cash Flows	7259
	Note 1 - Accounting Policies and Methods of Application	7360-65
	Note 2 - ~~Acquisitions~~Acquisition of NUI	7865
	Note 3 - Recent Accounting Pronouncements	7966-67
	Note 4 - Risk Management	8167-68
	Note 5 - Regulatory Assets and Liabilities	8468-71
	Note 6 - Employee Benefit Plans	8872-78
	Note 7 - Stock-based and Other Incentive Compensation Plans	9478-81
	Note 8 - ~~Financing~~ Common Shareholders’ Equity	9881-82
	Note 9 - ~~Common Shareholders’ Equity~~Debt	~~101~~83-85
	Note 10 - Commitments and Contingencies	~~102~~86-87
	Note 11 - Fair Value of Financial Instruments	~~104~~87
	Note 12 - Income Taxes	~~104~~87-88
	Note 13 - Related Party Transactions	~~106~~88
	Note 14 - Segment Information	~~106~~89-91
	Note 15 - Quarterly Financial Information (Unaudited)	~~109~~92
	Reports of Independent Auditors	~~110~~93-94
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~114~~94
Item 9A.	Controls and Procedures	~~114~~95
Item 9B.	Other Information	~~116~~95

Part III
Item 10.	Directors and Executive Officers of the Registrant	~~117~~95-96
Item 11.	Executive Compensation	~~117~~96
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~117~~96
Item 13.	Certain Relationships and Related Transactions	~~117~~96
Item 14.	Principal Accountant Fees and Services	~~117~~96
Part IV
Item 15.	Exhibits and Financial Statement Schedules	~~118~~96-101
Signatures		~~124~~102
Schedule II		~~137~~103

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

APB 2520	Accounting Principles Board (APB) Opinion No. 20, “Accounting Changes”
APB 25	APB Opinion No. 25, “Accounting for Stock Issued to Employees”
EITF 98-10	Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”
EITF 99-02	~~Emerging Issues Task Force~~EITF Issue No. 99-02, “Accounting for Weather Derivatives”
EITF 02-03	~~Emerging Issues Task Force~~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 46 & FIN 46R	FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities”
~~FSP 106-1~~FIN 47	FIN 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB ~~Staff Position (FSP)~~Statement No. ~~106-1, “Accounting and Disclosure Requirements Related to~~ ~~the Medicare Prescription Drug, Improvement and Modernization Act of 2003”~~ 143”
SFAS 5	~~SFAS~~Statement of Financial Accounting Standards (SFAS) No. 5, “Accounting for Contingencies”
SFAS 13	SFAS No. 13, “Accounting for Leases”
~~SFAS 66~~	~~SFAS No. 66, “Accounting for Sales of Real Estate”~~
SFAS 71	SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS ~~106~~	~~SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions”~~
~~SFAS~~ 109	SFAS No. 109, “Accounting for Income Taxes”
~~SFAS 121~~	~~SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of”~~
SFAS 123 & SFAS 123R	SFAS No. 123, “Accounting for Stock-Based Compensation”
SFAS ~~132~~131	SFAS No. ~~132, “Employers’ Disclosures~~131, “Disclosures about ~~Pensions~~Segments of an Enterprise and ~~Other Postretirement Benefits-an~~ ~~amendment of FASB Statements No. 87, 88 and 106”~~Related Information”
SFAS 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141	SFAS No. 141, “Business Combinations”
SFAS 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS ~~143~~	~~SFAS No. 143, “Accounting for Asset Retirement Obligations”~~
~~SFAS 144~~	~~SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”~~
~~SFAS 148~~	~~SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure-an~~ ~~amendment of FASB Statement No. 123”~~
~~SFAS~~ 149	SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”
SFAS 154	SFAS No. 154, “Accounting Changes and Error Corrections”

	Affiliated subsidiary	Approximate # of ~~Employees~~employees	Date of ~~Contract Expiration~~contract expiration
Teamsters (Local ~~769 and 385)~~	~~Florida Gas~~	82	~~March 2005~~
~~International Brotherhood of Electrical Workers (Local 50)~~	~~Virginia Natural Gas~~	~~147~~	~~May 2005~~
~~Utility Workers Union of America (Local 424)~~	~~Elizabethtown Gas~~	~~246~~	~~November 2005~~
~~Teamsters (Local~~No. 528)	Atlanta Gas Light	~~322~~302	March 2006
Communications Workers of America (Local No. 1023)	Elizabethtown Gas	5510	April 2006
International Brotherhood of Electrical Workers (Local No. 50)	Virginia Natural Gas	146	May 2006
Utility Workers Union of America (Local No. 461)	Chattanooga Gas	3120	April 2007
International Union of Operating Engineers (Local No. 474)	Atlanta Gas Light	3524	August 2007
Teamsters (Local Nos. 769 and 385)	Florida City Gas	53	March 2008
Utility Workers Union of America (Local No. 424)	Elizabethtown Gas	166	November 2009
Total		~~918~~721

Name, ~~Age~~age and ~~Position~~position with the Company	~~Dates Elected or Appointed~~ Periods served

~~Paula Rosput Reynolds,~~D. Raymond Riddle, Age 4872
Interim Chairman ~~President~~ and Chief Executive Officer	~~February 2002~~January 2006 - Present
~~President and Chief Executive Officer~~Director	May 1978 - Present
Chairman	August 2000 - February 2002
~~President and Chief Operating Officer of Atlanta Gas Light~~	~~September 1998 - November 2000~~

Kevin P. Madden, Age 5253 (1)
Executive Vice President, External Affairs	November 2005 - Present
Executive Vice President, Distribution and Pipeline Operations	April 2002 - November 2005
Executive Vice President, Legal, Regulatory and Governmental Strategy	September 2001 - April 2002

~~Richard T. O’Brien,~~R. Eric Martinez, Age ~~50 (2)~~37
Executive Vice President, Utility Operations	November 2005 - Present
Senior Vice President, Business Process Initiatives	August 2005 - November 2005
Vice President and General Manager of Elizabethtown Gas	December 2004 - August 2005
Senior Vice President, Engineering & Construction of Pivotal Energy Development	August 2003 - December 2004
Chief Operating Officer of AGL Networks, LLC	December 2002 - August 2003
Executive Vice President and General Manager of AGL Networks, LLC	June 2002 - December 2002
Vice President, Business Development	October 2000 - June 2002

Andrew W. Evans, Age 39 (2)
Senior Vice President and Chief Financial Officer	September 2005 - Present
Vice President and Treasurer	April ~~2001~~2002 - September 2005

Melanie M. Platt,Age 5051
Senior Vice President, Human Resources	September 2004 - Present
Senior Vice President ~~Business Support~~and Chief Adminstrative Officer	October 2000 - September 2004
Vice President of Investor Relations	May 1998 - November 2002
Vice President and Corporate Secretary ~~of Atlanta Gas Light~~	January 1995 - June 2002

Paul R. Shlanta,Age 4748
Executive Vice President, General Counsel and Chief Ethics and Compliance Officer	September 2005 - Present
Senior Vice President, General Counsel and Chief Corporate Compliance Officer	September 2002 - September 2005
Senior Vice President, General Counsel and Corporate Secretary	July 2002 - September 2002
Senior Vice President and General Counsel	September 1998 - July 2002

Bryan E. Seas, Age 45 (3)
Vice President, Controller and Chief Accounting Officer	September 2005 - Present
Vice President and Controller	July 2003 - September 2005

2004
	Sales Price of Common Stock		Cash Dividend per Common Share
Quarter ended:	High	Low	Cash Dividend per Common Share
March 31, 2004	$30.63	$27.87	$0.28
June 30, 2004	29.41	26.50	0.29
September 30, 2004	31.27	28.60	0.29
December 31, 2004	33.65	30.11	0.29


	Sales price of common stock				Cash Dividend Per Common
Quarter ended:	High		Low		Share
2005
March 31, 2005	$	36.09	$	32.00	$	0.31
June 30, 2005		38.89		33.37		0.31
September 30, 2005		39.32		35.29		0.31
December 31, 2005		37.54		32.23		0.37
2004
March 31, 2004	$	30.63	$	27.87	$	0.28
June 30, 2004		29.41		26.50		0.29
September 30, 2004		31.27		28.60		0.29
December 31, 2004		33.65		30.11		0.29

Period	Total Number of Shares Purchased	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs
October 2004	-	-	-	479,071
November 2004	45,000	$32.97	45,000	434,071
December 2004	6,667	$33.13	6,667	427,404
Total fourth quarter	51,667	$32.99	51,667	427,404

Dollars and shares in millions, except per share amounts	2004			2003			2002			Transition Period			2001			2000			2005			2004			2003			2002			Transition period			2001
Income statement
Income statement data
Operating revenues	$	1,832		$	983		$	877		$	204		$	946		$	608		$	2,718		$	1,832		$	983		$	877		$	204		$	946
Cost of gas																				1,626			995			339			268			49			327
Operating margin																				1,092			837			644			609			155			619
Operating expenses
Cost of gas		994			339			268			49			327			112
Operation and maintenance		377			283			274			68			267			248			477			377			283			274			68			267
Depreciation and amortization		99			91			89			23			100			83			133			99			91			89			23			100
Taxes other than income taxes		30			28			29			6			33			27			40			29			28			29			6			33
Total operating expenses		1,500			741			660			146			727			470			650			505			402			392			97			400
Gain on sale of Caroline Street campus		-			16			-			-			-			-			-			-			16			-			-			-
Operating income		332			258			217			58			219			138			442			332			258			217			58			219
Equity in earnings of SouthStar		-			46			27			4			14			6
Gain on sale of Utilipro Inc.		-			-			-			-			11			-
Gain on propane transaction		-			-			-			-			-			13
Other income (loss)		-			2			3			1			(7	)		9
Donation to private foundation		-			(8	)		-			-			-			-
Equity in earnings of SouthStar Energy Services LLC																				-			-			46			27			4			14
Other (loss) income																				(1	)		-			(6	)		3			1			4
Minority interest		(18	)		-			-			-			-			-			(22	)		(18	)		-			-			-			-
Interest expense		(71	)		(75	)		(86	)		(24	)		(98	)		(58	)		(109	)		(71	)		(75	)		(86	)		(24	)		(98	)
Earnings before income taxes		243			223			161			39			139			108			310			243			223			161			39			139
Income taxes		90			87			58			14			50			37			117			90			87			58			14			50
Income before cumulative effect of change in accounting principle		153			136			103			25			89			71			193			153			136			103			25			89
Cumulative effect of change in accounting principle, net of $5 in income taxes		-			(8	)		-			-			-			-			-			-			(8	)		-			-			-
Net income	$	153		$	128		$	103		$	25		$	89		$	71		$	193		$	153		$	128		$	103		$	25		$	89
Common stock data
Weighted average shares outstanding-basic		66.3			63.1			56.1			55.3			54.5			55.2			77.3			66.3			63.1			56.1			55.3			54.5
Weighted average shares outstanding-fully diluted		67.0			63.7			56.6			55.6			54.9			55.2			77.8			67.0			63.7			56.6			55.6			54.9
Total shares outstanding (1)																				77.8			76.7			64.5			56.7			55.6			55.1
Earnings per share-basic	$	2.30		$	2.03		$	1.84		$	0.45		$	1.63		$	1.29		$	2.50		$	2.30		$	2.03		$	1.84		$	0.45		$	1.63
Earnings per share-fully diluted	$	2.28		$	2.01		$	1.82		$	0.45		$	1.62		$	1.29		$	2.48		$	2.28		$	2.01		$	1.82		$	0.45		$	1.62
Dividends per share	$	1.15		$	1.11		$	1.08		$	0.27		$	1.08		$	1.08		$	1.30		$	1.15		$	1.11		$	1.08		$	0.27		$	1.08
Dividend payout ratio		50	%		55	%		59	%		60	%		66	%		84	%		52	%		50	%		55	%		59	%		60	%		66	%
Book value per share(1) (2)	$	18.04		$	14.66		$	12.52		$	12.41		$	12.20		$	11.49
Market value per share(1)	$	33.24		$	29.10		$	24.30		$	23.02		$	19.97		$	20.08
Book value per share (2)																			$	19.27		$	18.04		$	14.66		$	12.52		$	12.41		$	12.20
Market value per share (3)																			$	34.81		$	33.24		$	29.10		$	24.30		$	23.02		$	19.97
Balance sheet data(1)
Total assets	$	5,640		$	3,972		$	3,742		$	3,454		$	3,368		$	2,588		$	6,251		$	5,637		$	3,972		$	3,742		$	3,454		$	3,368
Long-term liabilities and deferred credits		682			647			702			671			711			768
Long-term liabilities																				737			682			647			702			671			711
Minority interest																				38			36			-			-			-			-
Capitalization
Long-term debt (excluding current portion)		1,623			956			994			1,015			1,065			664			1,615			1,623			956			994			1,015			1,065
Common shareholders’ equity		1,385			945			710			690			671			621			1,499			1,385			945			710			690			671
Total capitalization	$	3,008		$	1,901		$	1,704		$	1,705		$	1,736		$	1,285		$	3,114		$	3,008		$	1,901		$	1,704		$	1,705		$	1,736
Financial ratios(1)
Capitalization
Long-term debt		54	%		50	%		58	%		60	%		61	%		52	%		52	%		54	%		50	%		58	%		60	%		61	%
Common shareholders’ equity		46			50			42			40			39			48			48			46			50			42			40			39
Total		100	%		100	%		100	%		100	%		100	%		100	%		100	%		100	%		100	%		100	%		100	%		100	%
Return on average common shareholders’ equity		13.1	%		15.5	%		14.7	%		14.6	%		13.8	%		11.1	%		13.4	%		13.1	%		15.5	%		14.7	%		14.6	%		13.8	%

In millions	Increase (Decrease) in 2004 Operating Income (Before Taxes)
Accelerated recognition of margins associated with Sequent storage positions originally were anticipated to be liquidated in the first quarter of 2005	$	5
Asset sales in the second quarter of 2004 for a residential and retail property in Savannah, Georgia which resulted in a $2 million contribution to EBIT and the sale of our remaining investment units in U.S. Propane LP		3
Change in Atlanta Gas Light’s property taxes as a result of revised estimates and intangible property tax assessment		3
Contributions to the AGL Resources Private Foundation Inc. and for energy assistance by our subsidiary SouthStar		(3	)

In millions	Distribution Operations			Corporate			Consolidated
Gain (loss) on sale of Caroline Street campus	$	21			($5	)	$	16
Donation to private foundation		(8	)		-			(8	)
EBIT		13			(5	)		8
Income taxes								(3	)
Net income							$	5

Dollars in millions	2003			2002			2003 vs. 2002
Total interest expense	$	75		$	86			($11	)
Average debt outstanding(1)		1,255			1,412			(157	)
Average rate		6.0	%		6.1	%		(0.1	%)

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

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

Current liabilities	$	1,048	$	75	($11	)	$	1,112
Accumulated deferred income taxes		376		-	-			376
Long-term liabilities		569		-	-			569
Deferred credits		78		-	-			78
Minority interest(2)		-		-	30			30
Capitalization		1,901		101	(101	)		1,901
Total liabilities and capitalization	$	3,972	$	176	($82	)	$	4,066

AGL Resources Inc. and Subsidiaries
Pro-forma condensed consolidated statement of income
for the year ended December 31, 2003

In millions	As Reported			SouthStar(1)		Eliminations			(Unaudited) Pro-forma
Operating revenues	$	983		$	746		($169	)	$	1,560
Operating expenses
Cost of gas		339			622		(169	)		792
Operation and maintenance expenses		283			60		-			343
Depreciation and amortization		91			1		-			92
Taxes other than income		28			-		-			28
Total operating expenses		741			683		(169	)		1,255
Gain on sale of Caroline Street campus		16			-		-			16
Operating income		258			63		-			321
Equity earnings from SouthStar		46			-		(46	)		-
Donation to private foundation		(8	)		-		-			(8	)
Other income		2			-		-			2
Interest expense		(75	)		-		-			(75	)
Minority interest in income of consolidated subsidiary(2)		-			-		(17	)		(17	)
Earnings before income taxes		223			63		(63	)		223
Income taxes		(87	)		-		-			(87	)
Income before cumulative effect of change in accounting principle	$	136		$	63		($63	)	$	136

AGL Resources Inc. and Subsidiaries
Pro-forma condensed consolidated statement of income
for the year ended December 31, 2002

In millions	As Reported			SouthStar(1)		Eliminations			(Unaudited) Pro-forma
Operating revenues	$	877		$	630		($171	)	$	1,336
Operating expenses
Cost of gas		268			515		(171	)		612
Operation and maintenance expenses		274			72		-			346
Depreciation and amortization		89			2		-			91
Taxes other than income		29			-		-			29
Total operating expenses		660			589		(171	)		1,078
Operating income		217			41		-			258
Equity earnings from SouthStar		27			-		(27	)		-
Other income		3			1		-			4
Interest expense		(86	)		-		-			(86	)
Minority interest in income of consolidated subsidiary(2)		-			-		(15	)		(15	)
Earnings before income taxes		161			42		(42	)		161
Income taxes		(58	)		-		-			(58	)
Net income	$	103		$	42		($42	)	$	103

2004(*in millions)*	Operating revenues			Operating margin			EBIT
Distribution operations	$	1,111		$	641		$	247
Wholesale services		54			53			24
Energy investments		852			145			59
Corporate (1)		(185	)		(1	)		(16	)
Consolidated	$	1,832		$	838		$	314
2003
Distribution operations	$	936		$	599		$	247
Wholesale services		41			40			20
Energy investments		6			5			43
Corporate		-			-			(12	)
Consolidated	$	983		$	644		$	298
2002
Distribution operations	$	852		$	585		$	225
Wholesale services		23			23			9
Energy investments		2			1			24
Corporate		-			-			(11	)
Consolidated	$	877		$	609		$	247

	Duration of	Expiration	Type of fee	% Shared or	Profit sharing / fees payments
Dollars in millions	contract (in years)	date	structure	annual fee	2005	2004	2003
Elkton Gas	2	Mar 2007	Fixed-fee	(A)	$-	$-	$-
Chattanooga Gas	3	Mar 2007	Profit -sharing	50%	2	1	-
Atlanta Gas Light	2	Mar 2008	Profit -sharing	60%	4	4	3
Elizabethtown Gas	3	Mar 2008	Fixed -fee	$4	-	-	-
Florida City Gas	3	Mar 2008	Profit -sharing	50%	-	-	-
Virginia Natural Gas	3	Mar 2009	Profit -sharing	(B)	5	3	5
(A) Annual fixed fee is less than $1 million
(B) Sharing is based on a tiered sharing structure

In millions	Contract From NUI Acquisition		Other		Total
2005	$	5	$	8	$	13
2006		5		2		7
2007 and thereafter		107		9		116

In millions	Maturity Less Than 1 Year		Maturity 1-3 Years		Maturity 4-5 Years		Maturity in Excess of 5 Years		Total Net Fair Value
Prices actively quoted	$	6	$	1	$	-	$	-	$	7
Prices provided by other external sources	$	10	$	-	$	-	$	-	$	10

In millions	Prices actively quoted			Prices provided by other external sources
Mature through 2006		($3	)		($14	)
Mature 2007 - 2008		3			-
Mature 2009 - 2011		-			1
Mature after 2011		-			-
Total net fair value	$	-			($13	)

	NYMEX forward natural gas prices as of
	Sep 2005		Dec 2005		$ Change			% Change
Jan-06	$	14.77	$	11.43	$	(3.34	)		(23	%)
Feb-06		14.51		11.23		(3.28	)		(23	%)
Mar-06		14.04		11.36		(2.68	)		(19	%)
Avg.		14.44		11.34		(3.10	)		(21	%)

	Withdrawal schedule (in MMBtu)				Expected
	Physical salt dome		Physical reservoir		gross margin (in millions) (1)
Jan-06		119		92	$	5
Feb-06		149		212		6
Mar-06		16		252		5
Total		284		556	$	16

												Total
(A)	(21)	(105)	(286)	-	-	-	-	-	(2)	(10)	-	(424)

(B)	4	-	-	-	-	-	-	-	-	-	-	4
(C)	17	105	286	-	-	-	-	-	2	10	-	420
	21	105	286	-	-	-	-	-	2	10	-	424
(D)	$0.1	$0.2	$0.8	$-	$-	$-	$-	$-	$-	$-	$-	$1.1

In millions	Jan. 2005			Feb. 2005		Mar. 2005		Apr. 2005		May 2005		June 2005			July 2005			Total
Park and (loan) volumes (MMBtu)		(15	)		12		6		-		15		(12	)		(6	)		-

Expected gross margin from park and (loans)		($0.3	)	$	0.3	$	0.1		-		-		-			-		$	0.1

In millions	Dec. 31, 2004		Dec. 31, 2003
Unused availability under the Credit Facility	$	750	$	500
Cash and cash equivalents		49		17
Total cash and available liquidity under the Credit Facility	$	799	$	517

			Payments Due Before December 31,
					2006		2008		2010
					&		&		&
In millions	Total		2005		2007		2009		Thereafter
Long-term debt(1) (2)	$	1,623	$	-	$	2	$	2	$	1,619
Pipeline charges, storage capacity and gas supply(3) (4)		1,051		258		262		179		352
Short-term debt (2)		334		334		-		-		-
PRP costs(5)		327		85		162		80		-
Operating leases (6)		170		27		39		29		75
ERC(5)		90		27		10		12		41
Commodity and transportation charges		20		19		1		-		-
Total	$	3,615	$	750	$	476	$	302	$	2,087

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

			Commitments due before Dec. 31,
			Commitments due before Dec. 31,
In millions	Total		2006		2007 & thereafter
Standby letters of credit, performance / surety bonds	$	21	$	21	$	-

In millions	2005 (1)		2004		2003		2002		2004 vs. 2003			2003 vs. 2002
Construction of distribution facilities	$	87	$	64	$	60	$	62	$	4			($2	)
Pipeline replacement program		85		95		45		48		50			(3	)
Pivotal propane plant		2		29		-		-		29			-
Telecommunications		5		5		8		28		(3	)		(20	)
Other		97		71		45		49		26			(4	)
Total PP&E expenditures	$	276	$	264	$	158	$	187	$	106			($29	)

In millions	2006 (1)		2005		2004		2003
Construction or preservation of distribution facilities	$	110	$	135	$	64	$	60
SNG pipeline		-		32		-		-
PRP		30		48		95		45
Pivotal Propane plant		-		-		29		-
Pivotal Jefferson Island		36		8		2		-
Telecommunications		3		1		5		8
Other (2)		54		43		69		45
Total	$	233	$	267	$	264	$	158

Year	Miles of Pipe to be Replaced		Expenditures (in millions)
2006		95	$	30
2007		107		35
2008		150		37
2009		154		45
2010-2013		333		118
Totals		839	$	265

Dollars in millions	Dec. 31, 2004
Short-term debt	$	334	10	%
Long-term debt (1)		1,623	49
Total debt		1,957	59
Common shareholders’ equity		1,385	41
Total capitalization	$	3,342	100	%