Edgar Filing: AGL RESOURCES INC

Form 8-K

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

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934


Date of Report (Date of earliest event reported): January 26, 2006


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

Georgia	1-14174	58-2210952
(State or other jurisdiction of incorporation)	(Commission File No.)	(I.R.S. Employer Identification No.)


Ten Peachtree Place NE, Atlanta, Georgia 30309
(Address and zip code of principal executive offices)


404-584-4000
(Registrant's telephone number, including area code)


Not Applicable
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

[ ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[ ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[ ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[ ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01 Regulation FD Disclosure

On January 26, 2006 at 9:00 a.m. (EST) AGL Resources Inc. plans to hold its 2005 earnings conference call. The Company is filing this Form 8-K to provide selected discussion of financial results, liquidity and market risks for the year ended December 31, 2005.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

Forward-looking statements involve matters that are not historical facts, and because these statements involve anticipated events or conditions, forward-looking statements often include words such as "anticipate," "assume," "can," "could," "estimate," "expect," "forecast," "future," "indicate," "intend," "may," “outlook,” "plan," "predict," "project,” "seek," "should," "target," "will," "would," or similar expressions. Our expectations are not guarantees and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations are reasonable in view of the currently available information, our expectations are subject to future events, risks and uncertainties, and there are several factors - many beyond our control - that could cause results to differ significantly from our expectations.

Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact of acquisitions and divestitures; direct or indirect effects on AGL Resources' business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions and general economic conditions; uncertainties about environmental issues and the related impact of such issues; the impact of changes in weather on the temperature-sensitive portions of the business; the impact of natural disasters such as hurricanes on the supply and price of natural gas; acts of war or terrorism; and other factors which are provided in detail in our filings with the SEC.

We caution readers that the important factors described elsewhere in this report could cause our business, results of operations or financial condition in 2006 and thereafter to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or describe in this report that could cause results to differ significantly from our expectations.

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

Overview

We are a Fortune 1000 energy services holding company whose principal business is the distribution of natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. Our six utilities serve more than 2.2 million end-use customers, making us the largest distributor of natural gas in the southeastern and mid-Atlantic regions of the United States based on customer count. We also are involved in various related businesses, including retail natural gas marketing to end-use customers primarily in Georgia; natural gas asset management and related logistics activities for our own utilities as well as for other nonaffiliated companies; natural gas storage arbitrage and related activities; operation of high-deliverability underground natural gas storage assets; and construction and operation of telecommunications conduit and fiber infrastructure within selected metropolitan areas. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services and energy investments - and a nonoperating corporate segment.

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

During the year ended December 31, 2005, we derived approximately 86% of our earnings before interest and taxes (EBIT) from our regulated natural gas distribution business and the sale of natural gas to end-use customers primarily in Georgia through SouthStar. This statistic is significant because it represents the portion of our earnings that directly results from the underlying business of supplying natural gas to retail customers. Although SouthStar is not subject to the same regulatory framework as our utilities, it is an integral part of the retail framework for providing gas service to end-use customers in the state of Georgia. For more information regarding our measurement of EBIT which excludes interest expenses from operating income and net income, see Results of Operations - AGL Resources.

The remaining 14% of our EBIT was principally derived from businesses that are complementary to our natural gas distribution business. We engage in natural gas asset management and the operation of high-deliverability natural gas underground storage as ancillary activities to our utility franchises. These businesses allow us to be opportunistic in capturing incremental value at the wholesale level, provide us with deepened business insight about natural gas market dynamics and facilitate our ability, in the case of asset management, to provide transparency to regulators as to how that value can be captured to benefit our utility customers through profit sharing arrangements. Given the volatile and changing nature of the natural gas resource base in North America and globally, we believe that participation in these related businesses strengthens our business.

Our Competitive Strengths

We believe our competitive strengths have enabled us to grow our business profitably and create significant shareholder value. These strengths include:

Regulated distribution assets located in growing geographic regions Our operations are primarily concentrated along the east coast of the United States, from Florida to New Jersey. We operate primarily urban utility franchises in growing metropolitan areas where we can more effectively deploy technology to improve service delivery and manage costs. We believe the population growth and resulting expansion in business and construction activity in many of the areas we serve should result in increased demand for natural gas and related infrastructure for the foreseeable future.

Demonstrated track record of performance through superior execution We continue to focus our efforts on generating significant incremental earnings improvements from each of our businesses. We have been successful in achieving this goal in the past through a combination of business growth, opportunistic franchise acquisition and controlling or reducing our operating expenses. We achieved these improvements to our operations in part through the implementation of best practices in our businesses, including increased investments in enterprise technology, workforce automation and business process modernization. Our goal is a single operational platform that eliminates duplicate systems and disparate processes among our various companies.

Demonstrated ability to acquire and integrate natural gas assets that add significant incremental earnings We take a disciplined approach to identifying strategic natural gas assets that support our long-term business plan. For example, our 2004 acquisition of natural gas distribution operations in New Jersey, Florida, and Maryland, provided us an opportunity to leverage and strengthen one of our core competencies - the efficient, low-cost operation of natural gas franchises. The disparity between these utilities’ pre-acquisition utility operating metrics and cost structure and those of our other utilities provided us an opportunity to achieve significant improvements in these businesses, which we have been able to do. We will continue to seek and implement better methods of operating in order to improve our service delivery and reduce costs. In addition, our acquisition of a natural gas storage facility in Louisiana in 2004 added immediate incremental earnings to our business and, given the possibilities for expansion, will likely provide prospective earnings growth.

Business Accomplishments in 2005

We believe the results of our efforts are clear. We not only delivered solid results to our shareholders again in 2005 but also provided customers with improved service.

In 2005, we increased net income 26% over the prior year to $193 million and increased fully diluted earnings per share 8% to $2.48 despite increased average outstanding debt of $549 million and 11 million additional shares outstanding in 2005 due to our equity share issuance in November 2004, both of which were related to acquisitions in the fourth quarter of 2004. Our board of directors raised our annual dividend 19% in November 2005, to an annual rate of $1.48 per share. The increase marked the fourth time in three years our board has raised the dividend bringing our payout ratio more in line with other publicly traded energy holding companies and local distribution companies and ensuring a competitive dividend yield relative to alternative investments.

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

We continued business process improvement actions, including the deployment of substantial technology resources, in each of our business units. Additionally, through asset management, producer services and storage arbitrage activities at Sequent, we captured and recognized incremental net income from opportunities in the marketplace as we provided services during and after hurricanes Katrina and Rita. Our operational platform was tested, when during hurricane Rita, Sequent relocated its trading floor from Houston to Dallas, with virtually no service interruptions, in order to keep our commitments to customers and provide continuity in a market where service disruptions were prevalent.

Lastly, we worked cooperatively with our regulators during the year. In Georgia, we negotiated a settlement in the Atlanta Gas Light rate case whereby rates billed to customers will not change for a five-year period but Atlanta Gas Light will recognize reduced operating revenues of $5 million per year for a total of $25 million over the five-year period.

We also extended our asset agreement for Sequent to manage Atlanta Gas Light’s natural gas and transportation assets. Sequent also extended its asset agreement with Virginia Natural Gas for an additional three years. For additional information on Sequent’s asset management agreements with our affiliated utilities, see “Results of Operations - Wholesale Services.”

2006 Goals

The fundamentals of our business goals do not significantly change from one year to the next. Instead, we continue to refine our goals, taking into consideration our prior financial and operational performance and those external factors impacting not only us and the natural gas industry but also the global marketplace. We are focused on delivering earnings and income growth by effectively managing our gas distribution operations, optimizing returns on assets, selectively growing our gas distribution businesses through acquisitions and developing our portfolio of closely related unregulated businesses with an emphasis on risk management and earnings visibility. Key elements of our goals for 2006 include:

§	continuing our discipline around capital deployment as well as our intensive due diligence and valuation process in connection with potential acquisition or development projects;

§	driving a process oriented culture that supports economies of scale and efficiencies;

§	providing superior retail and wholesale logistics to further elevate and improve the overall delivery of seamless and competitively priced services to our customers by continuing to modernize our gas system, rationalize our gas supply, and leverage our technology platforms; and

§	renewing our focus on and further invest in our high-performance employee culture to make people our competitive edge in sustaining enterprise excellence.

Impact of Hurricanes on AGL Resources and Our Industry

The natural gas production, processing and pipeline infrastructure in the Gulf of Mexico was significantly affected by hurricanes Katrina and Rita in the months of August and September 2005. This resulted in higher and more volatile natural gas prices, which we and the Energy Information Administration expected to significantly increase the cost to heat a home during the current heating season. Natural gas prices moderated at the end of 2005 and early 2006, and weather has been warmer than normal thus far in 2006, but we still expect the cost to heat a home to be significantly higher in the first quarter of 2006 compared to prior years.

The impact of hurricanes Katrina and Rita on natural gas prices and transportation costs created diverse offsetting effects on our business. Increased energy and transportation prices are expected to represent a significantly larger portion of consumer household incomes during the remaining winter heating season (first quarter of 2006), raising the possibility that we will experience some additional bad debt expense, as well as some margin erosion from increased consumer conservation. These higher prices have thus far been mitigated in part by significantly warmer than normal temperatures in the eastern United States during the first half of the heating season. While we expect these factors to have some impact on our financial results, primarily in the first half of 2006, we have regulatory and operational mechanisms in place in most of our jurisdictions that we expect will help mitigate our exposures to high natural gas prices.

The market dynamics brought on by the two hurricanes presented opportunities for Sequent and for our own utilities through Sequent’s affiliate asset management agreements. Sequent drew upon its knowledge of the natural gas grid to move gas from supply sources and deliver it to its customers, which involved moving gas over less traditional routes due to Gulf Coast infrastructure limitations. For additional information regarding the impacts of these hurricanes on our business, see “Results of Operations - Distribution Operations” and “Results of 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 seek 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 Energy Policy Act of 2005 (Energy Act) was enacted. The Energy Act authorized many broad energy policy provisions including significant funding for consumers and business 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 that existed on the ownership of public utilities and eliminates certain regulatory burdens. Some of the reporting requirements, financing authorizations and affiliate relationship approvals that were previously required by the SEC under the PUHCA were replaced by the requirements of the Energy Act.

In addition, the Energy Act requires a public utility holding company to maintain its books and records and make them available to the FERC and 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 January 2006, we requested an exemption from the Energy Act oversight of our local distribution companies which have previously been exempt from regulation by the FERC. Our filing request provided us with a temporary exemption. If the FERC has not taken action within 60 days of our request, the exemption shall be deemed to have been granted. We expect to qualify for an exemption of these reporting requirements. We also expect that the state regulatory agencies in each of our jurisdictions will require the filing of some of the data that was previously required to be filed with the SEC under the PUHCA.

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

Results of Operations

AGL Resources

Our results of operations for 2004 included three months of the acquired operations of Jefferson Island and one month of the acquired operations of NUI.

Pursuant to Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidations of Variable Interest Entities” as revised, which we adopted in January 2004, we consolidated SouthStar’s accounts with our subsidiaries’ accounts as of January 1, 2004. For the years ended December 31, 2005 and 2004, we recorded 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 portion of SouthStar’s contributed capital as a minority interest in our consolidated balance 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, natural gas usage and operating revenues are higher since generally more customers are connected to our distribution systems, and 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 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 and interest expense, 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.

Hedging In addition to seasonality, changes 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 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 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 in our consolidated balance sheet.

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

The following table sets forth a reconciliation of our operating margin and EBIT to our operating income and net income, together with other consolidated financial information for the years ended December 31, 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 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 2004. In 2003, we recognized our portion of SouthStar’s earnings of $46 million as equity earnings.

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 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

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

(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. The amounts presented for SouthStar represent 100% of its revenues and expenses for 2003. The amounts presented for minority interest adjusts our earnings to reflect our 80% share of SouthStar’s earnings, less Dynegy Inc.’s 20% share of SouthStar’s earnings prior to February 18, 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			63		(63	)		298
Interest expense		75			-		-			75
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

Discussion of Consolidated Results

2005 compared to 2004 Our earnings per share and net income for 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 businesses. Consolidated EBIT for the year ended December 31, 2005 increased by $105 million or 33% from the previous year, of which $56 million related to EBIT contributions from the acquisitions of NUI and Pivotal Jefferson Island and from Pivotal Propane of Virginia, Inc. (Pivotal Propane) which became operational in 2005. The increase further reflected increased contributions from Atlanta Gas Light in distribution operations of $8 million, retail energy operations of $11 million and AGL Networks, LLC (AGL Networks) in energy investments of $3 million. 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, 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. Sequent’s operating margins 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 margins at AGL Networks of $4 million.

Operating expenses increased $145 million, 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 and by $13 million at wholesale services 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 which were 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 as 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 ended 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 2004 was higher than the prior year due to stronger contributions from our wholesale services business, SouthStar and the acquisitions of NUI and Jefferson Island. Consolidated EBIT for the year ended December 31, 2004 increased $16 million or 5% as compared to 2004, 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, distribution operations’ EBIT in 2004 increased by $13 million after excluding the effect of a net $13 million pretax gain on the sale of company property and a related charitable contribution in 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 sale of Heritage Propane and of a residential development property in Savannah, Georgia. These increases were partially offset by lower contributions of $4 million from 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.

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’ 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.

Operating expenses increased $42 million on a pro-forma basis 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 salary expense, increased outside service costs related to our ETRM and SOX 404 compliance projects, and increased depreciation. Excluding the effects of our acquisition of NUI, distribution operations expenses increased $10 million as a result of increased costs related to information technology projects, SOX 404 compliance and depreciation expense, offset by decreased bad debt expense.

Our corporate segment also had a $6 million increase in operating expenses primarily from increased outside service costs associated with software maintenance, licensing and implementation projects, as well as for SOX 404 compliance efforts and merger and acquisition activities.

Interest expense for 2004 was $71 million or $4 million lower than in 2003. As 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
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

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, 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 filed tax returns to related income tax accruals.

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 66.3 million, while 2003 results were based on weighted average shares outstanding of 63.1 million.

Distribution Operations

Distribution operations includes our natural gas local distribution utility companies that construct, manage and maintain natural gas pipelines and distribution facilities and serve more than 2.2 million end-use customers. Each utility operates subject to regulations provided by the state regulatory agency in its service territories with respect to rates charged to our customers, maintenance of accounting records, and various other service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. Rates are set at levels that allow recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return on common equity. Rate base consists generally of the original cost of utility plant in service, working capital, inventories and certain other assets; less accumulated depreciation on utility plant in service, net deferred income tax liabilities and certain other deductions. Our utilities are authorized to use a purchased gas adjustment (PGA) mechanism, which allows them to automatically adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure the utilities recover 100% of costs incurred in purchasing gas for their customers. We continuously monitor the performance of our utilities to determine whether rates need to be further adjusted by making a rate case filing.

Increased Natural Gas Prices, Bad Debt and Conservation Increased prices of natural gas are being driven by increased demand that is exceeding the growth in available supply. The hurricanes in the Gulf Coast region during the late summer and early fall of 2005 impacted the availability of natural gas supply, causing a dramatic rise in natural gas prices. These higher prices have thus far been mitigated in part by significantly warmer than normal temperatures in the eastern United States during the first half of the heating season. We expect our customers will incur increases in their bills during the remainder of the current winter heating season.

An increase in the cost of gas due to higher natural gas commodity costs generally has no direct effect on our utility’s net revenues and net income due to the PGA mechanisms at our utilities. However, net income may be reduced primarily due to higher expenses that may be incurred for bad debt, as well as lower volumes of natural gas deliveries to customers that may result from lower natural gas consumption caused by customer conservation.

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

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

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

Competition Our distribution operations businesses face competition based on customer preferences for natural gas compared to other energy products and the comparative prices of those products. Our principal competition relates to electric utilities and oil and propane providers serving the residential and small commercial markets throughout our service areas and the potential displacement or replacement of natural gas appliances with electric appliances. The primary competitive factors are the price of energy and the desirability of natural gas heating versus alternative heating sources.

Competition for space heating and general household and small commercial energy needs generally occurs at the initial installation phase when the customer/builder makes decisions as to which types of equipment to install. Customers will generally continue to use the chosen energy source for the life of the equipment. Customer demand for natural gas could be affected by numerous factors, including

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

·	general economic conditions

·	energy conservation

·	legislation and regulations

·	the capability to convert from natural gas to alternative fuels

weather

In some of our service areas net growth continues to be slowed due to the number of customers who leave our systems due to higher gas prices, incentives offered by the local electric utilities to switch to electric heat alternatives and competition from alternative fuel sources.

We expect customer growth to improve in the future through our efforts in new business and retention. These efforts include working to add residential customers with three or more appliances, multi-family complexes and high-value commercial customers that use natural gas for purposes other than space heating. In addition, we partner with numerous entities to market the benefits of gas appliances and to identify potential retention options early in the process for those customers who might consider leaving our franchise by converting to alternative fuels.

Our distribution operation utilities consist of:

Atlanta Gas Light This natural gas local distribution utility operates distribution systems and related facilities throughout Georgia. Atlanta Gas Light is regulated by the Georgia Public Service Commission (Georgia Commission).

Prior to Georgia’s 1997 Natural Gas Competition and Deregulation Act (Deregulation Act), which deregulated Georgia’s natural gas market, Atlanta Gas Light was the supplier and seller of natural gas to its customers. Today, Marketers—that is, marketers who are certificated by the Georgia Commission to sell retail natural gas in Georgia at rates and on terms approved by the Georgia Commission — sell natural gas to the end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light's role includes

·	distributing natural gas for Marketers

·	constructing, operating and maintaining the gas system infrastructure, including responding to customer service calls and leaks

·	reading meters and maintaining underlying customer premise information for Marketers

Since 1998, a number of federal and state proceedings have addressed the role of Atlanta Gas Light in administering and assigning interstate assets to Marketers pursuant to the provisions of the Deregulation Act. In this role, Atlanta Gas Light is authorized to offer additional sales services pursuant to Georgia Commission-approved tariffs and to acquire and continue managing the interstate transportation and storage contracts that underlie the sales services provided to Marketers on its distribution system under Georgia Commission-approved tariffs.

Rate Settlement Agreement In June 2005, the Georgia Commission approved a Settlement Agreement with Atlanta Gas Light that froze Atlanta Gas Light’s base rates billed to customers as of April 30, 2005 through April 30, 2010. The Settlement Agreement also requires Atlanta Gas Light to recognize reduced revenues of $25 million in total over the same period, to spend $2 million annually on energy conservation programs and to spend an additional $2 million for social responsibility programs. The Settlement Agreement was effective for rates as of May 1, 2005. Atlanta Gas Light had identified and implemented along with increased operating margins from net customer growth in Georgia during 2005, reductions in its operating costs, which offset the impact of the Settlement Agreement on its 2005 EBIT.

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

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

The Settlement Agreement extends Atlanta Gas Light’s Pipeline Replacement Program (PRP) by five years to require that all replacements be completed by December 2013 and sets the per customer PRP rate to be billed at $1.29 per customer per month from 2005 through 2007 and at $1.95 from 2008 through 2013. Atlanta Gas Light will apply the five-year total reduction in recognized base rate revenues of $25 million to the amount of costs incurred to replace pipe, reducing the amount recovered from customers under the PRP. The timing of replacements was subsequently specified in an amendment to the PRP stipulation.

This amendment, which was approved by the Georgia Commission on December 20, 2005, requires Atlanta Gas Light to replace the remaining 152 miles of cast iron pipe and 70% of the remaining 687 miles of bare steel pipe by December 2010. The remaining 30% of bare steel pipe is required to be replaced by December 2013. The amendment requires an evaluation by Atlanta Gas Light and the Georgia Commission staff of 22 miles of 24-inch pipe in Atlanta by December 2010 to determine if such pipe requires replacement. If replacement of this pipe is required, the pipe must be replaced by December 2013. The additional cost to replace this pipe is projected to be approximately $37 million.

The Settlement Agreement includes a provision that allows for a true-up of any over- or under-recovery of PRP revenues that may result from a difference between PRP charges collected through fixed rates and actual PRP revenues recognized through the remainder of the program.

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

Straight-Fixed-Variable Rates Atlanta Gas Light’s revenue is recognized under a straight-fixed-variable rate design, whereby Atlanta Gas Light charges rates to its customers based primarily on monthly fixed charges. This mechanism minimizes the seasonality of revenues since the fixed charge is not volumetric and the monthly charges are not set to be directly weather dependent. Weather indirectly influences the number of customers that have active accounts during the heating season, and this has a seasonal impact on Atlanta Gas Light’s revenues since generally more customers are connected in periods of colder weather than in periods of warmer weather.

Elizabethtown Gas This natural gas local distribution utility operates distribution systems and related facilities in central and northwestern New Jersey. Most Elizabethtown Gas customers are located in densely populated central New Jersey, where increases in the number of customers primarily result from conversions to gas heating from alternative forms of heating. In the northwestern region of the state, customer additions are driven primarily by new construction. Elizabethtown Gas is regulated by the New Jersey Board of Public Utilities (NJBPU).

Weather Normalization The Elizabethtown Gas tariff contains a weather normalization clause that is designed to help stabilize Elizabethtown Gas results by increasing base rate amounts charged to customers when weather is warmer than normal and decreasing amounts charged when weather is colder than normal. The weather normalization clause was renewed in October 2004 and is based on a 20-year average of weather conditions.

Pipeline Replacement In April 2005, Elizabethtown Gas presented the NJBPU with a proposal to accelerate the replacement of approximately 88 miles of 8” to 12” diameter elevated-pressure cast iron pipe. Under the proposal, approximately $42 million in estimated capital costs incurred over a three year period would be recovered through a pipeline replacement rider similar to the program in effect at Atlanta Gas Light. If the program as proposed is approved, cost recovery would occur on a one-year lag basis, with collections starting on October 1, 2006 and extending through December 31, 2009, after which time the program would be rolled into base rates. On December 7, 2005, Elizabethtown Gas filed testimony in support of its proposal. The proposal and related testimony will be considered in the following timeframe:

·	the New Jersey Rate Payer Advocate will file testimony on February 28, 2006

·	Elizabethtown Gas will file rebuttal testimony on March 17, 2006

·	public hearings will convene on March 30, 2006

Virginia Natural Gas This natural gas local distribution utility operates distribution systems and related facilities in southeastern Virginia. Virginia Natural Gas is regulated by the Virginia State Corporation Commission (Virginia Commission).

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

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

In July 2005, Virginia Natural Gas filed a performance-based rate (PBR) plan with the Virginia Commission and included the schedules required for a general rate case in support of its proposal. Under the PBR plan, Virginia Natural Gas proposes to freeze base rates at their 1996 levels for 5 additional years. This would provide Virginia Natural Gas customers an additional 5 years of rate stability, for a total of 14 years without a rate increase. If the Virginia Commission approves the proposal, Virginia Natural Gas will become the first Virginia natural gas utility to operate under a 1996 state law that authorized PBR plans for natural gas utilities. Consistent with state law, Virginia Natural Gas has proposed two exceptions that allow for adjustments to frozen base rates. Virginia Natural Gas could request a rate adjustment in connection with (1) any changes in taxation of gas utility revenues by the Commonwealth and (2) any financial distress of Virginia Natural Gas beyond its control.

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

·	Virginia Commission staff will file its testimony and exhibits on or before January 24, 2006;

·	Virginia Natural Gas will file rebuttal testimony and exhibits on or before February 7, 2006; and

·	public evidentiary hearings will convene on February 21, 2006.

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

On January 12, 2006, Virginia Natural Gas filed with the Virginia Commission a proposed motion for approval of Virginia Natural Gas’ PBR plan. If the proposed motion is approved, the PBR plan would be implemented as filed and Virginia Natural Gas would commit to certain actions, primarily to construct a pipeline that would connect Virginia Natural Gas’ northern system to its southern system. Participants and supporters of the proposed motion include Virginia Natural Gas, AGL Resources, and the Virginia Office of the Attorney General, Division of Consumer Counsel and the Virginia Industrial Gas Users’ Association.

Weather Normalization Adjustment (WNA) In September 2002, the Virginia Commission approved a WNA program as a two-year experiment involving the use of special rates. The WNA program’s purpose is to reduce the effect of weather on customer bills by reducing bills when winter weather is colder than normal and increasing bills when winter weather is warmer than normal. In September 2004, Virginia Natural Gas received approval from the Virginia Commission to extend the WNA program for an additional two years with certain modifications to the existing program. The significant modifications include removal of the commercial class of customers from the WNA program and the use of a rolling 30-year average to calculate the weather factor that is updated annually.

Florida City Gas This natural gas local distribution utility operates distribution systems and related facilities in central and southern Florida. Florida City Gas customers purchase gas primarily for heating water, drying clothes and cooking. Some customers, mainly in central Florida, also purchase gas to provide space heating during the winter season. Florida City Gas is regulated by the Florida Public Service Commission.

Chattanooga Gas This natural gas local distribution utility operates distribution systems and related facilities in the Chattanooga and Cleveland areas of southeastern Tennessee. Included in the base rates charged by Chattanooga Gas is a weather normalization clause that allows for revenue to be recognized based on a factor derived from average temperatures over a 30-year period, which offsets the impact of unusually cold or warm weather on its operating income. Chattanooga Gas is regulated by the Tennessee Regulatory Authority (Tennessee Authority).

Base Rate Increase In June 2005, the Tennessee Authority upheld its previous October 2004 order denying Chattanooga Gas a $4 million rate increase. The October 2004 order approved an increase of approximately $1 million based on a 10.2% return on equity and a capital structure of 35.5% common equity.

Elkton Gas This natural gas local distribution utility operates distribution systems and related facilities serving approximately 5,800 customers in Cecil County, Maryland. Elkton Gas customers are approximately 93% commercial and industrial and 7% residential. Elkton Gas is regulated by the Maryland Public Service Commission.

Results of Operations The following table presents results of operations for distribution operations for the years ended December 31, 2005, 2004 and 2003.

In millions	2005		2004		2003
Operating revenues	$	1,753	$	1,111	$	936
Cost of gas		939		471		337
Operating margin		814		640		599
Operation and maintenance		372		286		261
Depreciation and amortization		114		85		81
Taxes other than income taxes		32		23		24
Total operating expenses		518		394		366
Gain on sale of Caroline Street campus		-		-		21
Operating income		296		246		254
Donation to private foundation		-		-		(8	)
Other income		3		1		1
EBIT	$	299	$	247	$	247

Metrics
Average end-use customers (in thousands) (1)		2,242		1,880		1,838
Operation and maintenance expenses per customer	$	166	$	152	$	142
EBIT per customer (2)	$	133	$	131	$	127
Throughput (in millions of Dth) (1)
Firm		234		194		190
Interruptible		120		105		109
Total		354		299		299
Heating degree days (3):
Florida (1)		698		239		-
Georgia		2,726		2,589		2,654
Maryland (1)		5,004		860		-
New Jersey (1)		5,017		873		-
Tennessee		3,115		3,010		3,168
Virginia		3,465		3,214		3,264

(1)	2004 metrics include only December for the utilities acquired from NUI.

(2)	Excludes the gain on the sale of our Caroline Street campus in 2003.

(3)

We measure effects of weather on our businesses using “degree days.” The measure of degree days for a given day is the difference between average daily actual temperature and a baseline temperature of 65 degrees Fahrenheit. Heating degree days result when the average daily actual temperature is less than the 65-degree baseline. Generally, increased heating degree days result in greater demand for gas on our distribution systems.

2005 compared to 2004 EBIT increased $52 million or 21% reflecting an increase in operating margin of $174 million, partially offset by increased operating expenses of $124 million. The utilities and appliance businesses acquired from NUI on November 30, 2004 contributed approximately $50 million of EBIT in 2005 as compared to $7 million in 2004. This was due to the full year inclusion of the results in 2005 compared to one month in 2004.

The $174 million increase or 27% in operating margin was primarily due to the addition of NUI’s operations, which contributed $167 million. The remainder was primarily due to $8 million of higher operating margin at Atlanta Gas Light. The increase at Atlanta Gas Light resulted primarily from higher PRP revenues of $6 million and higher revenue of $3 million related to additional carrying charges for gas stored for Marketers primarily due to higher gas prices. Further, Atlanta Gas Light had approximately $3 million of increased operating margin from net customer growth which offset a $3 million decrease in operating revenues pursuant to the June 2005 rate settlement agreement with the Georgia Commission. Operating margin at Virginia Natural Gas and Chattanooga Gas Company remained relatively flat as compared to last year.

The $124 million or 31% increase in operating expenses primarily reflected the addition of NUI’s operations, which resulted in an increase in operating expenses of $125 million.

2004 compared to 2003 There was no change in distribution operations’ EBIT from 2003; however, the 2003 results included a pre-tax gain of $21 million on the sale of our Caroline Street campus, offset by an $8 million donation to AGL Resources Private Foundation, Inc. Exclusive of the gain and donation, EBIT in 2004 increased $13 million or 5% due to increased operating margin that was partially offset by increased operating expenses.

Distribution operations increase in operating margin of $41 million or 7% from 2003 included $17 million in combined increases at Atlanta Gas Light and Virginia Natural Gas. The increase in Atlanta Gas Light’s operating margin was primarily due to higher PRP revenue as a result of continued PRP capital spending, customer growth, higher customer usage and additional carrying charges from gas stored for Marketers due to a higher average cost of gas. The increase in operating margin at Virginia Natural Gas was primarily due to customer growth. The acquisition of NUI added $24 million of operating margin primarily from NUI’s December operations of Elizabethtown Gas and Florida City Gas.

Operating expenses increased $28 million or 8% from 2003. This was due primarily to the addition of NUI operations for the month of December of $17 million. The remaining increase of $11 million was due to increases in the cost of outside services related to increased information technology services as a result of our ongoing implementation of a work management system; increased legal services due to increased regulatory activity; and increased accounting services related to our implementation of SOX 404. Employee benefit and compensation expenses also increased primarily as a result of higher health care insurance costs and increased long-term compensation expenses. In addition, depreciation expenses increased primarily from new depreciation rates implemented for Virginia Natural Gas and increased assets at each utility. These increases were partially offset by a reduction in bad debt expense, which was primarily due to a Tennessee Authority ruling that allowed for recovery of the gas portion of accounts written off as uncollectible at Chattanooga Gas and increased collection efforts at both Chattanooga Gas and Virginia Natural Gas.

Retail Energy Operations

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

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

Beginning January 1, 2004, we consolidated the accounts of SouthStar and eliminated all intercompany balances in the consolidation. We recorded the portion of SouthStar’s earnings that are attributable to our joint venture partner, Piedmont, as a minority interest in our statements of consolidated income, and we recorded Piedmont’s portion of SouthStar’s capital as a minority interest in our consolidated balance sheets.

Competition SouthStar competes with other energy marketers, including Marketers in Georgia, to provide natural gas and related services to customers in Georgia and the Southeast. Based on its market share, SouthStar is the Marketer of natural gas in Georgia, with average customers in 2003 - 2005 in excess of 530,000.

In addition, similar to distribution operations, SouthStar faces competition based on customer preferences for natural gas compared to other energy products and the comparative prices of those products. SouthStar’s principal competition relates to electric utilities and the potential displacement or replacement of natural gas appliances with electric appliances. This competition with other energy products has been exacerbated by price volatility in the wholesale natural gas commodity market which has resulted in significant increases in the cost of natural gas billed to SouthStar’s customers.

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

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

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

Impact of High Gas Prices SouthStar’s operating margin and EBIT from the sales of natural gas to retail customers could be impacted by conservation and bad debt trends as a result of higher natural gas prices in the 2005 - 2006 winter heating season. SouthStar’s bad debt expense as a percentage of operating revenues of approximately 1% for 2005 has remained consistent with 2004. We believe SouthStar’s higher-quality customer base and the unregulated pricing structure in Georgia mitigates its exposure to higher bad debt expenses.

Results of Operations The following table presents results of operations for retail energy operations for the years ended December 31, 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 in 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 the revenues and expenses for 2003 on the same basis as 2005 and 2004. In 2003, we recognized our portion of SouthStar’s earnings of $46 million as equity earnings.

In millions	2005			2004			Pro-forma 2003
Operating revenues	$	996		$	827		$	743
Cost of gas		850			695			619
Operating margin		146			132			124
Operation and maintenance		58			60			60
Depreciation and amortization		2			2			1
Taxes other than income		1			-			-
Total operating expenses		61			62			61
Operating income		85			70			63
Minority interest		(22	)		(18	)		(17	)
EBIT	$	63		$	52		$	46

Metrics
Average customers (in thousands)		531			533			558
Market share in Georgia		35	%		36	%		38	%
Natural gas volumes (Bcf)		44			45			49

2005 compared to 2004 The $11 million or 21% increase in EBIT for the year ended December 31, 2005 was driven by a $14 million increase in operating margin and a $1 million decrease in total operating expenses, offset by a $4 million increase in minority interest due to higher earnings.

The $14 million or 11% increase in operating margin was primarily the result of higher commodity margins, offset by lower asset management margins and lower late payment fees relative to last year.

There was a slight decrease in operating expenses in 2005 as compared to 2004. The decrease was due to lower bad debt expense resulting from the application of ongoing active customer collection process improvements. Minority interest increased $4 million or 22% as a direct result of increased operating income in 2005 as compared to 2004.

2004 compared to 2003 The increase in EBIT of $6 million or 13% for the year ended December 31, 2004 was primarily the result of higher commodity margins and decreased bad debt expense during the year.

Operating margin for the year increased $8 million or 6% primarily as a result of a $9 million increase due primarily to a lower commodity cost structure resulting from continued refinement of SouthStar’s hedging strategies and a $3 million increase due to a full year of higher customer service charges from third party providers. These increases were partially offset by a decrease of $2 million related to a one-time sale of stored gas in 2003 and a $2 million decrease in late payment fees due to an improved customer base.

Operating expenses increased by $1 million or 2% primarily due to a $5 million increase in costs related to SOX 404 implementation and corporate overhead allocations, offset by lower bad debt expense resulting from active customer collection process improvements and increased quality of customer base. There was also a $1 million increase in minority interest as a result of higher SouthStar earnings in 2004 as compared to 2003.

Wholesale Services

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

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

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

In April 2005, Sequent commenced asset management responsibilities for Elizabethtown Gas, Florida City Gas and Elkton Gas. In October 2005, the agreement between Sequent and Virginia Natural Gas was renewed for an additional three years. The agreement was scheduled to expire in October 2005. In January 2006, the Georgia Commission extended the asset management agreement between Sequent and Atlanta Gas Light for two additional years. The agreement was scheduled to expire in March 2006. Under the terms of the extended agreement, Sequent will increase its aggregate net sharing percentage paid to Atlanta Gas Light from 50% to 60% on the majority of transactions Sequent will initiate going forward in its role as asset manager. The following table provides additional information on Sequent’s asset management agreements with its affiliated utilities.

	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 structure

Transportation and Storage Transactions In our wholesale marketing and risk management business, Sequent also contracts for natural gas transportation and storage services. We participate in transactions to manage the natural gas commodity and transportation costs that result in the lowest cost to serve our various markets. We seek to optimize this process on a daily basis, as market conditions change, by evaluating all the natural gas supplies, transportation alternatives and markets to which we have access and identifying the least-cost alternatives to serve our various markets. This enables us to capture geographic pricing differences across these various markets as delivered gas prices change.

In a similar manner, we participate in natural gas storage transactions where we seek to identify pricing differences that occur over time with regard to future delivery periods at multiple locations. We capture margin by locking in the price differential between purchasing natural gas at the lowest future price and, in a related transaction, selling that gas at the highest future price, all within the constraints of our contracts. Through the use of transportation and storage services, we are able to capture margin through the arbitrage of geographical pricing differences that occur over time.

Producer Services Our producer services business primarily focuses on aggregating natural gas supply from various small and medium-sized producers located throughout the natural gas production areas of the United States, principally in the Gulf Coast region. We provide producers with certain logistical and risk management services that offer them attractive options to move their supply into the pipeline grid. Aggregating volumes of natural gas from these producers allows us to provide markets to producers who seek a reliable outlet for their natural gas production.

Peaking Services Sequent generates operating margin through, among other things, the sale of peaking services, which includes receiving a fee from affiliated and nonaffiliated customers that guarantees those customers will receive gas under peak conditions. Sequent incurs costs to support our obligations under these agreements, which are reduced in whole or in part as the matching obligations expire. We will continue to seek new peaking transactions as well as work toward extending those that are set to expire.

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

There has been significant consolidation of energy wholesale operations, particularly among major gas producers. Financial institutions have also entered the marketplace. As a result, energy wholesalers have become increasingly willing to place bids for asset management transactions that are priced to capture market share. We expect this trend to continue in the near term, which could result in downward pressure on the volume of transactions and the related margins available in this portion of Sequent’s business.

Seasonality Fixed cost commitments are generally incurred evenly over the year, while margins generated through the use of these assets are generally greatest in the winter heating season and occasionally in the summer due to peak usage by power generators in meeting air conditioning load. This increases the seasonality of our business, generally resulting in higher margins in the first and fourth quarters.

Energy Marketing and Risk Management Activities We account for derivative transactions in connection with our energy marketing activities on a fair value basis in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). We record derivative energy commodity contracts (including both physical transactions and financial instruments) at fair value, with unrealized gains or losses from changes in fair value reflected in our earnings in the period of change.

Sequent’s energy-trading contracts are recorded on an accrual basis as required under the 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” (EITF 02-03) rescission of EITF 98-10, unless they are derivatives that must be recorded at fair value under SFAS 133.

As shown in the table below, Sequent recorded net unrealized losses related to changes in the fair value of derivative instruments utilized in its energy marketing and risk management activities of $13 million during 2005 and unrealized gains related to changes in the fair value of derivative instruments of $22 million during 2004 and $1 million during 2003. The tables below illustrate the change in the net fair value of the derivative instruments and energy-trading contracts during 2005, 2004 and 2003 and provide details of the net fair value of contracts outstanding as of December 31, 2005.

In millions	2005			2004			2003
Net fair value of contracts outstanding at beginning of period	$	17			($5	)	$	7
Cumulative effect of change in accounting principle		-			-			(13	)
Net fair value of contracts outstanding at beginning of period, as adjusted		17			(5	)		(6	)
Contracts realized or otherwise settled during period		(47	)		11			2
Change in net fair value of contract gains (losses)		17			11			(1	)
Net fair value of new contracts entered into during period		-			-			-
Net fair value of contracts outstanding at end of period		(13	)		17			(5	)
Less net fair value of contracts outstanding at beginning of period, as adjusted for cumulative effect of change in accounting principle		-			(5	)		(6	)
Unrealized (loss) gain related to changes in the fair value of derivative instruments	$	(13	)	$	22		$	1

The sources of our net fair value at December 31, 2005 are as follows. The “prices actively quoted” category represents Sequent’s positions in natural gas, which are valued exclusively using NYMEX futures prices. “Prices provided by other external sources” are basis transactions that represent the cost to transport the commodity from a NYMEX delivery point to the contract delivery point. Our basis spreads are primarily based on quotes obtained either directly from brokers or through electronic trading platforms.

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	)

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

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

Earnings Volatility and Price Sensitivity The market dynamics created by the two gulf coast hurricanes significantly impacted natural gas prices, primarily in the last five months of this year. From June 30, 2005 to September 30, 2005, the forward NYMEX prices through March 2006 increased on average approximately $6.10, or 75%, and from October 1, 2005 to December 31, 2005 the same prices decreased on average approximately $3.10, or 21%. These market dynamics created significant market opportunities for Sequent, as its storage and transportation activities created increased economic value as compared to 2004.

The accounting differences described above also impact the comparability of Sequent’s period-over-period results as changes in forward NYMEX prices do not increase and decrease on a consistent basis from year to year. During most of 2005, Sequent’s reported results were negatively impacted by increases in forward NYMEX prices which resulted in the recognition of unrealized losses. In comparison, the reported results during 2004 were not as significantly impacted by changes in forward NYMEX prices. As a result, a comparison of the 2005 and 2004 reported results yielded an unfavorable variance during the first nine months of 2005; however, the majority of these unrealized losses were recovered during the fourth quarter of this year. Based on Sequent’s storage positions at December 31, 2005, a $1.00 change in the forward NYMEX prices would result in a $7 million impact to Sequent’s EBIT after sharing of profits with Sequent’s affiliated utilities.

Storage Inventory Outlook The following table presents the NYMEX forward natural gas prices as of September 30, 2005 and December 31, 2005 for the period of January 2006 through March 2006, and reflects the prices at which Sequent could buy natural gas at the Henry Hub for delivery in the same time period. January 2006 futures expired on December 28, 2005; however they are included in the table below as they coincide with the January 2006 storage withdrawals. The Henry Hub, located in Louisiana, is the largest centralized point for natural gas spot and futures trading in the United States. NYMEX uses the Henry Hub as the point of delivery for its natural gas futures contracts. Many natural gas marketers also use the Henry Hub as their physical contract delivery point or their price benchmark for spot trades of natural gas.

	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	%)

The forward NYMEX prices decreased on average by 21% in the fourth quarter of 2005 due to warmer than normal weather in late December 2005 and the diminishing effects of hurricanes Rita and Katrina in the fall of 2005. Sequent’s original economic profit margin was unaffected by these changes in the NYMEX forward natural gas prices, due to the hedging instruments that it has in place. However, the decline in NYMEX prices during the fourth quarter of 2005 resulted in the recovery of previously reported unrealized losses associated with Sequent’s NYMEX contracts.

Sequent’s expected withdrawals from physical salt dome and reservoir storage are presented in the table below along with its expected gross margin. Sequent’s expected gross margin is net of the impact of regulatory sharing and reflects the amounts that we would expect to realize in future periods based on the inventory withdrawal schedule and forward natural gas prices at December 31, 2005. Sequent’s storage inventory is fully hedged with futures as its NYMEX short positions are equal to the physical long positions, which results in an overall locked-in margin, timing notwithstanding. Sequent’s physical salt dome and reservoir volumes are presented in increments of 10,000 million British thermal units (MMBtu).

	Withdrawal schedule (in MMBtu)				Expected
	Physical salt dome		Physical reservoir		gross margin (in millions) (1)
WACOG (2)	$	9.76	$	8.98		N/A
Jan-06		119		92	$	5
Feb-06		149		212		6
Mar-06		16		252		5
Total		284		556	$	16

(1)	After regulatory sharing

(2)	Weighted average cost of gas in inventory

As noted above, Sequent’s inventory level and pricing as of December 31, 2005 should result in gross margin of approximately $16 million through March 2006 if all factors remained the same, but could change if Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months.

Credit Rating Sequent has certain trade and credit contracts that have explicit credit rating trigger events in case of a credit rating downgrade. These rating triggers typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting with some of our counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, our ability to continue transacting with these counterparties would be impaired. If at December 31, 2005, our credit ratings had been downgraded to non-investment grade, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $51 million.

Results of Operations The following table presents results of operations for wholesale services for the years ended December 31, 2005, 2004 and 2003.

In millions	2005			2004		2003
Operating revenues	$	95		$	54	$	41
Cost of sales		3			1		1
Operating margin		92			53		40
Operation and maintenance		39			27		20
Depreciation and amortization		2			1		-
Taxes other than income		1			1		-
Total operating expenses		42			29		20
Operating income		50			24		20
Other loss		(1	)		-		-
EBIT	$	49		$	24	$	20

Metrics
Physical sales volumes (Bcf/day)		2.17			2.10		1.75

2005 compared to 2004 The increase in EBIT of $25 million or 104% in 2005 as compared to 2004 was due to an increase in operating margin of $39 million partially offset by an increase in operating expenses of $13 million.

Sequent’s operating margin increased by $39 million or 74% primarily due to the significant impacts of the Gulf Coast hurricanes during the third quarter of 2005 and the lingering market disruptions and price volatility throughout the fourth quarter. For the first nine months of the year, reported operating margin was similar to that of the prior year, with quarterly decreases being offset by quarterly increases. However, during the third quarter of 2005, while we created substantial economic value by serving our customers during the storms, our reported operating margin was negatively impacted by accounting losses associated with our storage hedges as a result of increases in forward natural gas prices of approximately $6 per MMBtu. During the fourth quarter, natural gas prices continued to be volatile in the aftermath of the hurricanes and we were able to further optimize our storage and transportation positions at levels in excess of the prior year. In addition, our previously reported hedge losses were partially recovered during the fourth quarter as forward natural gas prices decreased approximately $3 per MMBtu.

Operating expenses increased by $13 million or 45% due to additional payroll associated with increased headcount and increased employee incentive compensation costs driven by Sequent’s operational and financial growth and depreciation expense in connection with Sequent’s new energy trading and risk management (ETRM) system which was implemented during the fourth quarter of the prior year.

2004 compared to 2003 EBIT increased $4 million or 20% from 2003 to 2004 due to a $13 million increase in operating margin, partially offset by a $9 million increase in operating expenses.

Operating margin increased by $13 million or 33% primarily due to increased volatility during the fourth quarter of 2004 which provided Sequent with seasonal trading, marketing, origination and asset management opportunities in excess of those experienced during the prior year. Also contributing to the increase were advantageous transportation values to the Northeast and new peaking and third-party asset management transactions. Sequent’s sales volumes for 2004 averaged 2.10 Bcf/day, a 20% increase from the prior year. This increase resulted primarily from the addition of new counterparties, increased presence in the midwestern and northeastern markets and continued growth in origination and asset management activities, as well as business generated due to the market volatility experienced during the fourth quarter.

As a result of a decline in forward NYMEX prices, the 2004 results reflected the recognition of unrealized gains associated with the financial instruments used to economically hedge Sequent’s inventory held in storage. If the forward NYMEX price in effect at December 1, 2004 had also been in effect at December 31, 2004, based on Sequent’s storage positions at December 31, 2004, Sequent’s reported EBIT would have been $19 million. At December 31, 2003, an increase in forward NYMEX prices resulted in the recognition of modest unrealized losses associated with inventory hedges.

Partially offsetting the improved fourth-quarter results was lower volatility during the second quarter of 2004 compared to the same period in 2003, which compressed Sequent's trading and marketing activities and the related margins within its transportation portfolio. In addition, Sequent's weighted average cost of natural gas stored in inventory was $5.06 per MMBtu during the first quarter of 2004 compared to $2.20 per MMBtu during the same period in 2003. This significant difference in cost resulted in reduced operating margins period over period.

Operating expenses increased by $9 million or 45% due primarily to additional salary expense as a result of an increase in the number of employees; additional costs for outside services related to the development and implementation of Sequent’s ETRM system; the implementation of SOX 404;and increased corporate costs. In addition, 2004 operating expenses reflected depreciation associated with the recently implemented ETRM system.

Energy Investments

Our energy investments segment consists of

Pivotal Jefferson Island This wholly owned subsidiary operates a salt dome storage and hub facility in Louisiana, approximately eight miles from the Henry Hub. The storage facility is regulated by the Louisiana Public Service Commission and by the Federal Energy Regulatory Commission (FERC), which has limited regulatory authority over the storage and transportation services. The facility consists of two salt dome gas storage caverns with 10 million Dth of total capacity and about 7.2 million Dth (MMDth) of working gas capacity. The facility has approximately 720,000 Dth/day withdrawal capacity and 360,000 Dth/day injection capacity. Pivotal Jefferson Island provides for storage and hub services through its direct connection to the Henry Hub via the Sabine Pipeline and its interconnection with 7 other pipelines in the area. Our subsidiary, Pivotal Energy Development (Pivotal Development) is responsible for the day-to-day operation of the facility. Pivotal Jefferson Island is fully subscribed for the 2005-2006 winter period.

In October 2005, Pivotal Jefferson Island announced that it was soliciting bids for current firm natural gas storage contracts that will expire at the end of the first quarter of 2006. In December 2005, Pivotal Jefferson Island executed an agreement for 1.0 MDth for the expiring capacity. Pivotal Jefferson Island is negotiating a contract for an additional 300 MDth of storage capacity available beginning July 1, 2006. Pivotal Jefferson Island expects to complete the contract for the balance of the expiring capacity in the first quarter of 2006. Additionally, in December 2005, Pivotal Jefferson Island substantially completed a capital project to improve its compression capabilities, which increased the daily injection capability to 360,000 Dth.

In October 2005, Pivotal Jefferson Island also announced that it is soliciting customer interest, in the form of nonbinding bids for capacity, in a project that would expand Pivotal Jefferson Island’s salt-dome storage facility by 175% from its current capacity of 7.2 MDth to as much as 19.8 MDth. The expansion under consideration includes the development of a third and a fourth storage cavern at the facility, with each cavern having a working gas capacity of 6 MDth. If there is sufficient customer interest in the project, construction would begin in early 2006. We would expect to complete the third cavern by mid-2008 and would expect the fourth cavern to be operational by mid-2010. The expansion project also includes expanding the number of pipeline interconnections in order to enhance Pivotal Jefferson Island’s flexibility with regard to storage capacity and deliverability. Final construction plans, as well as the total projected capital cost of the project, will be determined during the first quarter of 2006.

Pivotal Jefferson Island’s competition is limited to other saltdome caverns in the Gulf Coast. We believe that Pivotal Jefferson Island is uniquely situated with its direct connection to the Henry Hub and its connection to seven other pipelines. For those reasons we believe that Pivotal Jefferson Island will be subscribed ahead of most of its competitors.

Pivotal Propane In 2005, this wholly owned subsidiary completed the construction of a propane air facility in the Virginia Natural Gas service area that provides up to 28,800 Dth of propane air per day on a 10-day-per-year basis to serve Virginia Natural Gas’ peaking needs.

AGL Networks This wholly owned subsidiary is a provider of telecommunications conduit and dark fiber. AGL Networks leases and sells its fiber to a variety of customers in the Atlanta, Georgia and Phoenix, Arizona metropolitan areas, with a small presence in other cities in the United States. Its customers include local, regional and national telecommunications companies, internet service providers, educational institutions and other commercial entities. AGL Networks typically provides underground conduit and dark fiber to its customers under leasing arrangements with terms that vary from 1 to 20 years. In addition, AGL Networks offers telecommunications construction services to companies. AGL Networks’ competitors are any entities that have or will lay conduit and fiber on the same route as AGL Networks in the respective metropolitan areas.

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

Results of Operations The following table presents results of operations for energy investments for the years ended December 31, 2005, 2004 and 2003.

In millions	2005		2004		2003
Operating revenues	$	56	$	25	$	6
Cost of sales		16		12		1
Operating margin		40		13		5
Operation and maintenance		17		5		9
Depreciation and amortization		5		2		1
Taxes other than income		1		1		-
Total operating expenses		23		8		10
Operating income		17		5		(5	)
Other income		2		2		2
EBIT	$	19	$	7	$	(3	)

2005 compared to 2004 The $12 million or 171% increase in EBIT was primarily the result of increased operating margin of $27 million, offset by $15 million in higher operating expenses.

Of the $27 million or 208% increase in operating margin, $13 million resulted from Pivotal Jefferson Island, NUI’s nonutility businesses, which contributed $8 million and Pivotal Propane which contributed $3 million. AGL Networks contributed $4 million primarily from growth in both recurring revenues from fiber leasing activities of $1 million and from construction and new business activities of $3 million.

Of the $15 million or 188% increase in operating expenses, $8 million resulted from NUI’s nonutility businesses, $3 million resulted from Pivotal Jefferson Island, and a $1 million increase related to Pivotal Propane. AGL Networks’ operating expenses were relatively flat in 2005 as compared to 2004.

2004 compared to 2003 The increase in EBIT of $10 million was primarily the result of $3 million from Pivotal Jefferson Island and $3 million from AGL Networks. The remaining increase of $4 million was from the sale of Heritage Propane Partners, L.P. and the sale of a residential and retail development property in Savannah, Georgia in the second quarter of 2004.

Operating margin for the year increased $8 million primarily as a result of the addition of Pivotal Jefferson Island’s $4 million of operating margin and an operating margin increase at AGL Networks of $4 million due to increased revenue from a variety of customers.

Operating expenses decreased by $2 million or 20% primarily due to decreased headcount at AGL Networks.

Corporate

Our corporate segment includes our nonoperating business units, including AGL Services Company (AGSC), AGL Capital Corporation (AGL Capital) and Pivotal Development. AGSC is a service company established in accordance with PUHCA. AGL Capital provides for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities, and other financing arrangements.

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

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

AGSC Restructuring As a result of the NUI acquisition, the associated centralization of certain administrative and operational functions and our ongoing desire to operate as efficiently as possible, we began, during the first quarter of 2005, a review of certain functions within our AGSC subsidiary. We expect this process to be part of an ongoing effort to optimize staffing levels and work processes across our entire company.

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

Results of Operations The following table presents results of operations for our corporate segment for the years ended December 31, 2005, 2004 and 2003.

In millions	2005			2004			2003
Payroll	$	57		$	48		$	48
Benefits and incentives		34			32			32
Outside services		43			29			19
Taxes other than income		5			4			2
Other		52			46			44
Total operating expenses before allocations		191			159			145
Allocation to operating segments		(185	)		(147	)		(139	)
Operating expenses		6			12			6
Loss on asset disposed of Caroline Street campus		-			-			(5	)
Operating loss		(6	)		(12	)		(11	)
Other losses		(5	)		(4	)		(1	)
EBIT	$	(11	)	$	(16	)	$	(12	)

The corporate segment is a nonoperating segment, and as such, changes in EBIT amounts for the indicated periods reflect the relative changes in various general and administrative expenses, such as payroll, benefits and incentives and outside services.

2005 compared to 2004 The $5 million or 31% increase in EBIT for 2005 compared to 2004 was primarily due to decreased operating expenses of $6 million. These decreased costs were primarily due to merger and acquisition related costs incurred in 2004 but not in 2005. With respect to total operating expenses before allocations, payroll expenses in 2005 increased due to headcount in the corporate segment resulting from the acquisition of NUI in November of 2004 and the realignment of certain corporate functions to AGSC.

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

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

2004 compared to 2003 The decrease in EBIT of $4 million or 33% for the year ended December 31, 2004 as compared to the same period in 2003 primarily was due to an increase in operating expenses of $6 million. The increase in operating expenses was primarily due to increased outside services costs associated with software maintenance; licensing and implementation of our work management system project; higher costs due to our SOX 404 compliance efforts; merger- and acquisition-related expenses; and expenses related to Pivotal Development’s activities in 2004. The increase in operating expenses was offset by a loss of $5 million on the sale of our Caroline Street campus in 2003.

Liquidity

To meet our capital and liquidity requirements we rely on operating cash flow, short-term borrowings under our commercial paper program, which is backed by our supporting credit agreement (Credit Facility), borrowings under Sequent’s and SouthStar’s lines of credit, and borrowings or stock issuances in the long-term capital markets. Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and through February 8, 2006, the SEC. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. The availability of borrowings under our Credit Facility is limited and subject to a total-debt-to-capital ratio financial covenant specified within the Credit Facility, which we currently meet.

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

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

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

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

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

·	regulatory changes and changes in ratemaking policies of regulatory commissions

·	contractual cash obligations and other commercial commitments

·	interest rate changes

·	pension and postretirement funding requirements

·	changes in income tax laws

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

·	operational risks

·	the impact of natural disasters, including weather

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

We also work to maintain or improve our credit ratings on our debt to effectively manage our existing financing costs and enhance our ability to raise additional capital on favorable terms. Factors we consider important in assessing our credit ratings include our balance sheet leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that would require us to issue equity based on credit ratings or other trigger events. As of January 2006, our senior unsecured debt ratings are BBB+ from Standard & Poor’s Ratings Services (S&P), Baa1 from Moody’s Investors Service and A- from Fitch Ratings (Fitch).

During 2005, no change occurred in our ratings profile; however, upon the announcement of our proposed acquisition of NUI, S&P placed our credit ratings on CreditWatch with negative implications, Moody’s affirmed our ratings but changed its rating outlook to negative from stable, and Fitch placed our credit ratings on Rating Watch Negative. Since the closing of the acquisition on November 30, 2004, S&P removed us from CreditWatch and changed our outlook to negative; Fitch took us off Rating Watch Negative and affirmed our ratings with a stable outlook; and Moody’s changed our outlook to stable. S&P has indicated that the negative outlook is the result of the execution risks in integrating the NUI acquisition.

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

Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. Our most important default events include maintaining covenants with respect to maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, and acceleration of other financial obligations and change of control provisions. Our Credit Facility’s financial covenant require us to maintain a ratio of total debt to total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60% of debt to total capitalization. We are currently in compliance with all existing debt provisions and covenants.

We believe that accomplishing these capitalization objectives and maintaining sufficient cash flow are necessary to maintain our investment-grade credit ratings and to allow us access to capital at reasonable costs.

Short-term debt Our short-term debt is composed of borrowings under our commercial paper program, Sequent’s lines of credit, SouthStar’s line of credit, and the current portion of our capital leases. Our short-term debt financing generally increases between June and December because our payments for natural gas and pipeline capacity are generally made to suppliers prior to the collection of accounts receivable from our customers. We typically reduce short-term debt balances in the spring because a significant portion of our current assets are converted into cash at the end of the winter heating season.

Our Credit Facility was amended in August 2005. Under the terms of the amendment, the term of the Credit Facility was extended to August 31, 2010. The aggregate principal amount available under the amended Credit Facility was increased to $850 million, and our option to increase the aggregate cumulative principal amount available for borrowing to $1.1 billion on not more than three occasions during each calendar year. The increased capacity under our Credit Facility increases our ability to borrow under our commercial paper program. Our total cash and available liquidity under our Credit Facility as of the dates indicated are represented in the table below.

In millions	Dec. 31, 2005		Dec. 31, 2004
Unused availability under the Credit Facility	$	850	$	750
Cash and cash equivalents		27		49
Total cash and available liquidity under the Credit Facility	$	877	$	799

As of December 31, 2005 and 2004, we had no outstanding borrowings under the Credit Facility. However, the availability of borrowings and unused availability under our Credit Facility is limited and subject to conditions specified within the Credit Facility, which we currently meet. These conditions include

·	maintain a ratio of total debt to total capitalization of no greater than 70%

·	the continued accuracy of representations and warranties contained in the agreement

In June 2005, Sequent’s existing $25 million unsecured line of credit was extended to July 2006. In September 2005, Sequent entered into an additional $20 million unsecured line of credit scheduled to expire in September 2006. These unsecured lines of credit, which total $45 million, are used solely for the posting of margin deposits for NYMEX transactions, and are unconditionally guaranteed by us. At December 31, 2005, there were no outstanding amounts under these lines of credit, which is an $18 million decrease from the same time in 2004.

In September 2005, Pivotal Utility Holdings, Inc entered into a $20 million unsecured line of credit to be used solely for the posting of margin deposits for its natural gas hedging program. The line expires in September 2006 and is unconditionally guaranteed by us. There were no amounts outstanding under this line of credit at December 31, 2005.

SouthStar’s $75 million line of credit provides the additional working capital needed to meet seasonal demands and is not guaranteed by us. The line of credit is secured by various percentages of its accounts receivable, unbilled revenue and inventory. The line of credit expires in April 2007 and bears interest at the prime rate and/or LIBOR plus a margin based on certain financial measures. At December 31, 2005, the line of credit had an outstanding balance of $36 million. There were no amounts outstanding under this facility at the same time in 2004.

In 2004, we repaid $500 million outstanding under NUI’s credit facility. Upon the repayment of the outstanding amounts, we terminated NUI’s credit facility.

Long-term Debt In 2004, AGL Capital issued $250 million of 6% Senior Notes Due October 2034 and $200 million of 4.95% senior notes due January 2015. We fully and unconditionally guarantee the senior notes. The proceeds from the issuance were used to refinance a portion of our outstanding short-term debt under our commercial paper program. During 2004, we also made $82 million in medium-term note payments using proceeds from the borrowings under our commercial paper program.

Interest Rate Swaps To maintain an effective capital structure, it is our policy to borrow funds using a mix of fixed-rate debt and variable-rate debt. We have entered into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our fixed-rate and variable-rate debt obligation. At December 31, 2005, including the effects of $100 million of interest rate swaps, 66% of our total short-term and long-term debt was fixed.

Refinancing of Gas Facility Revenue Bonds In April and May 2005 we refinanced $67 million of our gas facility revenue bonds.

Minority Interest As a result of our consolidation of SouthStar’s accounts effective January 1, 2004, we recorded Piedmont’s portion of SouthStar’s contributed capital as a minority interest in our consolidated balance sheets and included it as a component of our total capitalization. We recorded a cash distribution of $19 million in 2005 and $14 million in 2004 for SouthStar’s dividend distribution to Piedmont in our consolidated statement of cash flows as a financing activity.

Common stock In November 2004, we completed our public offering of 11.04 million shares of common stock, generating net proceeds of approximately $332 million. We used the proceeds to purchase the outstanding capital stock of NUI and to repay short-term debt incurred to fund our purchase of Jefferson Island.

Dividends on Common Stock In 2005 we made $101 million in common stock dividend payments. This was an increase of $26 million or 35% from 2004. The increase was due to our 11 million share common stock offering in November 2004 which increased the number of shares outstanding and the increases in the amount of our quarterly common stock dividends per share.

In 2004, we made $75 million in common stock dividend payments. This was an increase of $5 million or 7% from 2003. The increase was due to the 6.4 million common stock offering in February 2003, which increased the number of shares outstanding and the increases in our quarterly common stock dividends per share.

For the three most recent fiscal years, we have made the following increases of dividends on our common stock.

Date of change	% increase			Quarterly dividend		Indicated annual dividend
Nov 2005		19	%	$	0.37	$	1.48
Feb 2005		7			0.31		1.24
Apr 2004		4			0.29		1.16
Apr 2003		4			0.28		1.12

Shelf Registration We currently have remaining capacity under an October 2004 shelf registration statement of approximately $957 million. We may seek additional financing through debt or equity offerings in the private or public markets at any time.

MARKET RISKS

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 risk management policies and monitoring 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. 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.

Commodity Price Risk

Retail Energy Operations SouthStar’s use of derivatives is governed by a risk management policy, created and monitored by its risk management committee, which prohibits the use of derivatives for speculative purposes. A 95% confidence interval is used to evaluate 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. VaR is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. We 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.

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 opportunistically to lock in economic margins (as spreads between wholesale and retail commodity prices widen between periods) and thereby minimize retail price exposure, but SouthStar does not hold speculative positions. In the event that natural gas prices continue to increase and remain higher than historical levels and volatility of natural gas prices diminishes, the operating margin from SouthStar’s storage business could be negatively impacted.

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. Similarly 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 Sequent generally manage physical gas assets and economically protect its positions by hedging in the futures markets, its open exposure is generally minimal, permitting Sequent to operate within relatively low VaR limits. Sequent employs daily risk testing, using both VaR and stress testing, to evaluate the risks of its open positions.

Sequent’s management actively monitors open commodity positions and the resulting VaR. Sequent continues to maintain a relatively matched book, where 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, 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:

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

2004
Period end	$	0.1	$	0.2
12-month average		0.1		0.3
High		0.4		1.3
Low (1)		0.0		0.0

2003
Period end	$	0.3	$	1.0
12-month average		0.1		0.3
High		2.5		4.7
Low (1)		0.0		0.0

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

During 2005 Sequent experienced increases in its “high”, “12-month average” and “period end” 1-day and 10-day VaR amounts. These increases were directly associated with the market impacts and related price volatility created by the Gulf Coast hurricanes during the third quarter and the lingering effects through year-end.

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. To facilitate the achievement of desired fixed-rate to variable-rate debt ratios, AGL Capital entered into interest rate swaps whereby it agreed to exchange, at specified intervals, the difference between fixed and variable amounts calculated by reference to agreed-upon notional principal amounts. These swaps are designated to hedge the fair values of $100 million of the $300 million Senior Notes due 2011, and $75 million of the $150 million principal amount of notes payable to Trusts due in 2041. In March 2004, we adjusted our fixed-rate to variable-rate debt obligations and terminated an interest rate swap on $100 million of the $225 million principal amount of Senior Notes Due 2013.

In September 2005, we also executed five treasury-lock agreements totaling $125 million to hedge the interest rate risk associated with an anticipated 2006 financing. The agreements will result in a 4.11% interest rate on the 10-year United States Treasury bond and were designated as cash flow hedges against the future interest payments on the anticipated financing.

Credit Risk

Distribution Operations Atlanta Gas Light has a concentration of credit risk because it bills only 10 Marketers in Georgia for its services. The credit risk exposure to Marketers varies with the time of the year, with exposure at its lowest in the nonpeak summer months and highest in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. These retail functions include customer service, billing, collections, and the purchase and sale of the natural gas commodity. These Marketers, in turn, bill end-use customers. The provisions of Atlanta Gas Light’s tariff allow Atlanta Gas Light to obtain security support in an amount equal to a minimum of two times a Marketer’s highest month’s estimated bill from Atlanta Gas Light.

Several factors are designed to mitigate our risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. We accept credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers and corporate guarantees from investment-grade entities. The RMC reviews the adequacy of credit support coverage, credit rating profiles of credit support providers and payment status of each Marketer on a monthly basis. We believe that adequate policies and procedures have been put in place to properly quantify, manage and report on Atlanta Gas Light’s credit risk exposure to Marketers.

Atlanta Gas Light also faces potential credit risk in connection with assignments to Marketers of interstate pipeline transportation and storage capacity. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would in all likelihood seek repayment from Atlanta Gas Light. The fact that some of the interstate pipelines require Marketers to maintain security for their obligations to the interstate pipelines arising out of the assigned capacity somewhat mitigates this risk.

Retail Energy Operations SouthStar credit-scores firm residential and small commercial customers using a national credit reporting agency and enrolls, without security, only those customers that meet or exceed SouthStar’s credit threshold. The average credit score of SouthStar’s Georgia customers has increased 9% since 2003.

SouthStar investigates potential interruptible and large commercial customers through reference checks, review of publicly available financial statements and review of commercially available credit reports. SouthStar also assigns physical wholesale counterparties an internal credit rating and credit limit prior to entering into a physical transaction based on their Moody’s, S&P and Fitch ratings, commercially available credit reports and audited financial statements.

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

Master netting agreements enable Sequent to net certain assets and liabilities by counterparty. Sequent also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. Additionally, Sequent may require counterparties to pledge additional collateral when deemed necessary. Sequent conducts credit evaluations and obtain appropriate internal approvals for its counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, Sequent requires credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not meet the minimum ratings threshold.

Sequent, which provides services to Marketers and utility and industrial customers, also has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. As of December 31, 2005, Sequent’s top 20 counterparties represented approximately 52% of the total counterparty exposure of $554 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures.

As of December 31, 2005, Sequent’s counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of A- which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty.

To arrive at the weighted average credit rating, each counterparty’s assigned internal rating is multiplied by the counterparty’s credit exposure and summed for all counterparties. That sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. The following tables show Sequent’s commodity receivable and payable positions as of December 31, 2005 and 2004:

	As of:
	December 31,
In millions	2005		2004
Gross receivables
Receivables with netting agreements in place:
Counterparty is investment grade	$	462	$378
Counterparty is non-investment grade		66	36
Counterparty has no external rating		113	78
Receivables without netting agreements in place:
Counterparty is investment grade		34	16
Counterparty is non-investment grade		-	6
Counterparty has no external rating		-	-
Amount recorded on balance sheet	$	675	$514

Gross payables
Payables with netting agreements in place:
Counterparty is investment grade	$	456	$	291
Counterparty is non-investment grade		56		45
Counterparty has no external rating		255		139
Payables without netting agreements in place:
Counterparty is investment grade		4		40
Counterparty is non-investment grade		-		6
Counterparty has no external rating		4		-
Amount recorded on balance sheet	$	775	$	521

Sequent has certain trade and credit contracts that have explicit rating trigger events in case of a credit rating downgrade. These rating triggers typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, Sequent would need to post collateral to continue transacting business with some of its counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If at December 31, 2005, Sequent’s credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $51 million.

Item 9.01 Financial Statements and Exhibits

(c)

Exhibits

Exhibit No.	Description

99.1	AGL Resources’ Press Release announcing financial results and other information.

SIGNATURE

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

	AGL RESOURCES INC.
	(Registrant)
Date: January 26, 2006	/s/ Andrew W. Evans
	Senior Vice President and Chief Financial Officer