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): February 1, 2007


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 2.02 Results of Operations and Financial Condition

On February 1, 2007, AGL Resources Inc. issued a press release announcing the Company’s financial results for the fourth quarter and year ended December 31, 2006. A copy of the press release is attached hereto as Exhibit 99.1 and incorporated by reference herein.

The information in the preceding paragraph, as well as Exhibit 99.1 referenced therein, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 nor incorporated by reference in any filing under the Securities Act of 1933 unless AGL Resources Inc. expressly so incorporates such information by reference.

Item 7.01 Regulation FD Disclosure

On February 1, 2007 at 9:00 a.m. (EST) AGL Resources Inc. plans to hold its 2006 earnings conference call. The Company is filing this Form 8-K to provide selected discussion of financial results for the year ended December 31, 2006.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain expectations and projections regarding our future performance referenced in this report, in other materials we file with the Securities and Exchange Commission (SEC), or otherwise release to the public and on our website are forward-looking statements. Senior officers 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 regarding our future operations, prospects, strategies, financial condition, economic performance (including growth and earnings), industry conditions and demand for our products and services. We have tried, whenever possible, to identify these statements by using words such as "anticipate," "assume," “believe,” "can," "could," "estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” "seek," "should," "target," "will," "would," and similar expressions.

You are cautioned not to place undue reliance on our forward-looking statements. Our forward-looking statements are not guarantees of future performance and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations for the future are reasonable in view of the currently available information, our expectations are subject to future events, risks and inherent uncertainties, as well as potentially inaccurate assumptions, and there are numerous 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 those set forth below and in the other documents that we file with the SEC. We note these factors for investors as permitted by the Private Securities Litigation Reform Act of 1995. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not perceive them to be material, 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. You are advised, however, to review any further disclosures we make on related subjects in our Form 10-K, Form 10-Q and Form 8-K reports to the SEC.

Overview

We are an energy services holding company whose principal business is the distribution of natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. 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 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 nonaffiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability underground natural gas storage assets. We also own and operate a small telecommunications business that constructs and operates conduit and fiber infrastructure within select 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. As of December 31, 2006, we employed a total of 2,364 employees across these five segments.

The distribution operations segment is the largest component of our business and is subject to regulation and oversight by agencies in each of the six states we serve. These agencies approve natural gas 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, our largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions and price levels for natural gas. Our non-Georgia jurisdictions have various regulatory mechanisms to provide us with a reasonable opportunity to recover our costs, but these methods of recovery are not direct offsets to the potential impacts on earnings. Atlanta Gas Light charges rates to its customers primarily as monthly fixed charges. Our retail energy operations segment, which consists of SouthStar, also is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. Our Sequent subsidiary within our wholesale services segment is weather sensitive, with increased earnings opportunities, as well as increased loss potential, during periods of extreme weather conditions, which typically produce greater price volatility. Our energy investments segment’s primary business is our natural gas storage, which develops, acquires and operates high-deliverability salt-dome storage assets in the Gulf Coast region of the United States. While this business also can generate additional revenue during times of peak market demand for natural gas storage services, the majority of our storage services are covered under medium to long-term contracts at a fixed market rate.

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.

Operating Margin and EBIT

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

Our operating margin and EBIT are not measures that are considered to be calculated in accordance with 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 similarly titled measures of other companies

2006 Business Highlights

We achieved several significant milestones during 2006 that position us well for future growth and for providing long-term value to our shareholders.

We completed our rate proceeding in Virginia, which resulted in a five-year rate freeze for customers under the first performance-based rate plan approved in that state for a natural gas utility. As part of the settlement reached with the parties in the case, we have committed to spend approximately $48 million to $60 million to build a new pipeline that will improve access to natural gas in certain areas we serve in Virginia, particularly during critical peak periods. Also, the Virginia Commission approved a permanent weather normalization adjustment (WNA) for residential customers as part of the settlement.

We successfully resolved our rate proceeding in Tennessee, which resulted in a $3 million base rate increase effective January 1, 2007 to offset higher costs and lower natural gas consumption. Additionally, the rate proceeding improved our authorized return and improved our capital structure (55% debt and 45% equity) that is more consistent with our utilities and other non-affiliated utilities.

·	We continued to grow our asset management business at Sequent which enables them to generate greater levels of economic value during periods of market volatility.

·	We expanded, through SouthStar, our retail footprint into the Ohio and Florida markets.

We announced our intention to develop a 12 Bcf natural gas salt-dome storage facility, known as Golden Triangle Storage, in Beaumont, Texas, at a capital cost of up to $180 million. The project will provide high-deliverability Gulf Coast storage at a key market point, with the first phase scheduled to be in commercial operation in 2010.

2006 Business Results

In 2006, we earned $212 million in net income or $2.72 per diluted share, compared with net income of $193 million, or $2.48 per diluted share, in 2005. The 10% increase in net income was the result of a variety of factors:

Our distribution operations segment’s EBIT improved by $11 million, or 4% in 2006 as compared to 2005. We continued to benefit from the improved operating metrics of the utilities we acquired in 2004. These results were offset, however, by customer consumption declines due to warmer-than-normal weather throughout the year and high natural gas prices, particularly during the first quarter of 2006.

Our retail energy operations segment provided stable year-over-year earnings contributions despite the effects of declining customer consumption, warmer weather and a lower of weighted average cost or current market price (LOCOM) adjustment to inventory. This segment’s marketing efforts during the year also resulted in a slight increase in customer count.

Our wholesale services segment captured significant arbitrage opportunities due to price volatility and periods of extreme weather conditions. As a result, this segment’s EBIT contribution of $90 million was $41 million higher than in 2005, primarily as a result of additional commercial activity and storage arbitrage opportunities throughout the year, as well as the recognition of hedge gains as forward NYMEX prices declined.

Our energy investments segment made progress on the evaluation and development of several projects during 2006. While these projects are expected to provide future earnings contributions, the business development expenses associated with developing them resulted in a lower year-over-year performance in this segment as well as the disposition in the second half of 2005 of certain non-strategic assets acquired as part of the acquisition of NUI in December 2004.

·	Our interest expense for 2006 increased $14 million as compared to 2005. The increase reflects higher carrying costs associated with higher inventory storage balances, as well as higher short-term interest rates, relative to the prior year.

Results of Operations

AGL Resources

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, 2006, 2005 and 2004.

In millions	2006			2005			2004
Operating revenues	$	2,621		$	2,718		$	1,832
Cost of gas		1,482			1,626			995
Operating margin		1,139			1,092			837
Operating expenses
Operation and maintenance		473			477			377
Depreciation and amortization		138			133			99
Taxes other than income		40			40			29
Total operating expenses		651			650			505
Operating income		488			442			332
Other expenses		(1	)		(1	)		-
Minority interest		(23	)		(22	)		(18	)
EBIT		464			419			314
Interest expense		123			109			71
Earnings before income taxes		341			310			243
Income taxes		129			117			90
Net income	$	212		$	193		$	153
Earnings per common share:
Basic	$	2.73		$	2.50		$	2.30
Diluted	$	2.72		$	2.48		$	2.28
Weighted average number of common shares outstanding:
Basic		77.6			77.3			66.3
Diluted		78.0			77.8			67.0

Segment information Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are presented in the following table for the years ended December 31, 2006, 2005 and 2004:

In millions	Operating revenues			Operating margin (1)			Operating expenses		EBIT (1)
2006
Distribution operations	$	1,624		$	807		$	499	$	310
Retail energy operations		930			156			68		63
Wholesale services		182			139			49		90
Energy investments		41			36			26		10
Corporate (2)		(156	)		1			9		(9	)
Consolidated	$	2,621		$	1,139		$	651	$	464
2005
Distribution operations	$	1,753		$	814		$	518	$	299
Retail energy operations		996			146			61		63
Wholesale services		95			92			42		49
Energy investments		56			40			23		19
Corporate (2)		(182	)		-			6		(11	)
Consolidated	$	2,718		$	1,092		$	650	$	419
2004
Distribution operations	$	1,111		$	640		$	394	$	247
Retail energy operations		827			132			62		52
Wholesale services		54			53			29		24
Energy investments		25			13			8		7
Corporate (2)		(185	)		(1	)		12		(16	)
Consolidated	$	1,832		$	837		$	505	$	314

(1)	These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained Results of Operations - AGL Resources.

(2)	Includes the elimination of intercompany revenues and cost of gas.

Discussion of Consolidated Results

2006 compared to 2005 The increase in EBIT of $45 million or 11% in 2006 was primarily the result of increases at the distribution operations and wholesale services segments. Wholesale services’ EBIT improvement of $41 million primarily reflected the recognition of hedge gains during 2006, as forward NYMEX prices declined significantly. In contrast, NYMEX price increases experienced during 2005 had the opposite effect, but to a lesser extent. In the distribution operations segment, EBIT improved by $11 million, and operating margin declined $7 million offset primarily by reduced operating expenses of $19 million. Our retail energy operations segment’s EBIT was flat compared to 2005. The energy investments segment’s EBIT was down $9 million primarily due to the loss of EBIT contributions as the result of the sale in 2005 of certain assets that were originally acquired with the 2004 acquisition of NUI Corporation (NUI).

Our operating margin increased $47 million or 4% from 2005. The following table indicates the significant changes in our operating margin:

In millions
Operating margin for 2005		$1,092
Net change in the fair value of hedges at wholesale services		60
Wholesale services commercial activities		5
Wholesale services inventory LOCOM adjustments (net of hedging recoveries)		(18)
Retail energy operations inventory LOCOM adjustments		(6)
Improved operating margins at retail energy operations		16
Lower operating margins at distribution operations utilities		(7)
Loss of margin from energy investment assets sold in 2005		(9)
Other		6
Operating margin for 2006		$1,139

Changes in commodity prices subject a significant portion of our operations to earnings variability. Our nonutility businesses principally use physical and financial arrangements to economically hedge the risks associated with both weather-related 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 and are reflected as gains or losses within our operating margin or our other comprehensive income (OCI) for those derivative instruments that qualify and are designated as accounting hedges.

Forward NYMEX prices decreased during 2006, especially during the third and fourth quarters. This resulted in the wholesale services segment recognizing $41 million of storage hedge gains in 2006, compared to the recognition of $7 million of storage hedge losses in 2005. In addition, wholesale services recognized $12 million in gains associated with the financial instruments used to hedge its transportation capacity. Consequently, wholesale services experienced a net change of $60 million from its hedging activities for 2006 compared to 2005.

The results of the wholesale services segment also reflect improved commercial activities of approximately $5 million. Sequent was able to capture higher seasonal storage margins in 2006 and additional operating margin opportunities brought on by higher temperatures during the late summer months. This offset the lower operating margins that resulted from milder weather earlier in the year.

As a result of decreasing NYMEX prices, the wholesale services segment evaluated the weighted average cost of its natural gas inventory and recorded LOCOM adjustments totaling $43 million during 2006; however, as inventory was physically withdrawn from storage during the year, $22 million of the 2006 adjustments were recovered and reflected in 2006 operating revenues when the original economic results were realized as the related hedging derivatives were settled.

We experienced increased operating margins at our retail energy operations segment of $10 million driven by improved retail margins of $6 million and slightly higher storage and commercial margins of $4 million. Storage and commercial margins were driven by improved optimization of storage and transportation assets and effective commodity risk management, including net gains on weather derivatives offset by a $6 million adjustment in 2006 to reduce inventory to market for which no LOCOM adjustment was recorded in 2005. Retail operating margins increased due to improved retail price spreads and an increase in the average number of customers offset by lower customer consumption and weather that was more than 10% warmer than the previous year and lower late payment fees of $1 million due to an increase in the number of customers utilizing payment arrangements.

Operating margin for the distribution operations segment decreased $7 million primarily from warmer weather affecting customer usage and from our exiting the New Jersey and Florida appliance businesses. The margin at Elizabethtown Gas decreased $3 million with 18% warmer weather than in 2005. Virginia Natural Gas’ margin decreased $4 million with 17% warmer weather, and the margin at Florida City Gas decreased $2 million with 16% warmer weather. Further, the exiting of the New Jersey and Florida appliance businesses reduced margin by $3 million. This margin reduction was partially offset by increased margin at Atlanta Gas Light of $6 million primarily from gas storage carrying costs from higher average inventory balances and pipeline replacement program revenues from the continuing expenditures under the program.

Our energy investments segment operating margin decreased $4 million due to the loss of contributions from certain assets we acquired with the 2004 acquisition of NUI, but later sold in 2005.

Our operating expenses increased $1 million or 0.2% from the same period in 2005. The following table sets forth the significant components of operating expenses:

In millions
Operating expenses for 2005	$	650
Increased depreciation and amortization		5
Increased payroll, incentive compensation and corporate overhead allocated costs at wholesale services		6
Increased bad debt expenses at retail energy operations and distribution operations		4
Lower expenses resulting from energy investment assets sold in 2005		(8	)
Lower expenses at distribution operations related to workforce and facilities restructurings in 2005 and 2006		(15	)
Other		9
Operating expenses for 2006	$	651

The wholesale services segment recorded $6 million of additional costs associated with payroll due to an increased number of employees to support growth and increased incentive compensation, which is generally based on Sequent’s operating performance and higher corporate overhead allocated costs. Bad debt expense for 2006 increased over 2005 primarily in our retail energy operations segment. The retail energy operation’s bad debt for 2006 was $13 million, a $3 million increase from the same period in 2005, driven by an increase in the number of accounts receivable balances past due more than 60 days due to higher natural gas bills.

These increases were offset by $15 million in lower costs primarily related to a 2005 restructuring at the distribution operations segment, as a result of a reduction in the workforce and elimination of unnecessary facilities following the 2004 acquisition of NUI. An additional $8 million decrease in operating expenses was related to the operation of assets, primarily in the energy investments segment, that were originally acquired in the 2004 acquisition of NUI and later sold in 2005.

Interest expense for 2006 increased by $14 million or 13% as compared to 2005. As indicated in the following table, higher short-term interest rates and higher debt outstanding combined to increase our interest expense in 2006 relative to the previous year. The increase of $200 million in average debt outstanding for 2006 compared to 2005 was due to additional debt incurred as a result of higher working capital requirements.

Dollars in millions	2006			2005
Total interest expense	$	123		$	109
Average debt outstanding (1)		2,023			1,823
Average interest rate		6.1	%		6.0	%

(1)	Daily average of all outstanding debt

Based on $733 million of variable-rate debt, which includes $527 million of variable-rate short-term debt, $100 million of variable-rate senior notes and $106 million of variable-rate gas facility revenue bonds outstanding at December 31, 2006, a 100 basis point change in market interest rates from 5% to 6% would result in an increase in annual pretax interest expense of $7 million.

The increase in income tax expense of $12 million or 10% for 2006 compared to 2005 reflected additional income taxes primarily due to higher corporate earnings year over year. We expect our effective tax rate for the year ending December 31, 2007, to be similar to the effective rate for the year ended December 31, 2006.

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

Our operating margin in 2005 increased $255 million or 30% from 2004. The following table indicates the significant changes in our operating margin:

In millions
Operating margin in 2004	$	837
Increased operating margin at distribution operations from acquired utilities		167
Wholesale services commercial activities		53
Increased operating margins at retail energy operations		14
Increased operating margins at Jefferson Island		13
Operating margin from energy investment assets acquired from NUI Corp.		8
Increased operating margin at distribution operations, primarily Atlanta Gas Light		7
Increased operating margins at Pivotal Propane and AGL Networks		7
Inventory LOCOM adjustments at wholesale services		(2	)
Net change in the fair value of hedges at wholesale services		(12	)
Operating margin in 2005	$	1,092

The increase primarily reflects the NUI and 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 $7 million mainly as a result of higher pipeline replacement revenues and additional carrying costs charged to Marketers for gas storage. Retail energy operations’ margins increased $14 million, due primarily to higher commodity margins. Wholesale services’ operating margin increased $39 million year over year, primarily due to significant market volatility following the hurricane activity during the third quarter and the continuing volatile market conditions during the fourth quarter of 2005. Energy investments’ margins were up $27 million, primarily as a result of the acquisition of Jefferson Island that contributed $13 million, contributions from NUI’s nonutility businesses of $8 million, contribution from Pivotal Propane of $3 million and improved operating margin at AGL Networks of $4 million.

Our operating expenses increased $145 million or 29% from 2004. The following table sets forth the significant changes in our operating expenses:

In millions
Operating expenses in 2004	$	505
Operating expenses at distribution operations from NUI utilities acquired December 2004		125
Increased operating expenses at wholesale services, primarily payroll, incentive compensation and depreciation		13
Operating expenses at energy investments from NUI acquired assets		8
Operating expenses at Jefferson Island		3
Operating expenses at energy investments from Pivotal Propane		3
Other		(7	)
Operating expenses in 2005	$	650

The increase was primarily a result of $125 million in higher expenses at distribution operations due to the addition of NUI. In addition, operating expenses at energy investments increased $15 million primarily due to the addition of Jefferson Island, the NUI nonutility assets and Pivotal Propane. Operating expenses at wholesale services increased $13 million due to increased payroll and employee incentive compensation costs resulting from its operational and financial growth and depreciation on a trading and risk management system placed in service during 2004. The increased operating expenses were offset by lower corporate operating expenses primarily due to prior-year costs incurred with merger and acquisition activities.

Interest expense for 2005 increased by $38 million or 54% as compared to 2004. As indicated in the table below, higher short-term interest rates and higher average 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 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.

The increase in income tax expense of $27 million or 30% for 2005 compared to 2004 reflected additional income taxes of $25 million due to higher corporate earnings year over year and $2 million due to a slightly higher effective tax rate of 38% for 2005 as compared to 37% in 2004.

Distribution Operations

Distribution operations includes our six natural gas local distribution utility companies that construct, manage and maintain intrastate natural gas pipelines and distribution facilities and serve more than 2.2 million end-use customers.

Atlanta Gas Light This natural gas local distribution utility operates distribution systems and related facilities throughout Georgia serving approximately 1.5 million end-use customers. Atlanta Gas Light customer counts are approximately 94% residential and 6% commercial or industrial. Atlanta Gas Light is regulated by the Georgia Public Service Commission (Georgia Commission) and its rates are frozen until 2010.

Atlanta Gas Light’s natural gas market was deregulated in 1997 with Georgia’s Natural Gas Competition and Deregulation Act (Deregulation Act). Prior to this act, 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 on terms approved by the Georgia Commission — sell natural gas to end-use customers in Georgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia Commission. 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

Elizabethtown Gas This natural gas local distribution utility operates distribution systems and related facilities serving approximately 269,000 customers 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 customer counts are approximately 92% residential and 8% commercial or industrial. Elizabethtown Gas is regulated by the New Jersey Board of Public Utilities (New Jersey Commission) and its rates are frozen until 2010.

Virginia Natural Gas This natural gas local distribution utility operates distribution systems and related facilities serving approximately 264,000 customers in southeastern Virginia. Virginia Natural Gas customer counts are approximately 92% residential and 8% commercial or industrial. Virginia Natural Gas is regulated by the Virginia State Corporation Commssion (Virginia Commission) and its rates are frozen until 2011.

Florida City Gas This natural gas local distribution utility operates distribution systems and related facilities serving approximately 104,000 customers 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 customer counts are approximately 94% residential and 6% commercial or industrial. Florida City Gas is regulated by the Florida Public Service Commission (Florida Commission).

Chattanooga Gas This natural gas local distribution utility operates distribution systems and related facilities serving approximately 61,000 customers in the Chattanooga and Cleveland areas of southeastern Tennessee. Chattanooga Gas customer counts are approximately 86% residential and 14% commercial or industrial. Chattanooga Gas is regulated by the Tennessee Regulatory Authority (Tennessee Commission).

Elkton Gas This natural gas local distribution utility operates distribution systems and related facilities serving approximately 6,000 customers in Cecil County, Maryland. Elkton Gas customer counts are approximately 92% residential and 8% commercial or industrial. Elkton Gas is regulated by the Maryland Public Service Commission (Maryland Commission).

The following table provides operational information for our five largest utilities. The daily capacity represents total system capability, and the storage capacity includes on-system LNG and propane volumes.

	Atlanta Gas Light			Elizabethtown Gas			Virginia Natural Gas			Florida City Gas			Chattanooga Gas
Operations
2006 avg. end-use customers (in thousands)		1,546			269			264			104		61
2005 avg. end-use customers (in thousands)		1,545			266			261			103		61
2004 avg. end-use customers (in thousands) (6)		1,533			263			256			103		60
Daily capacity (1)		2.53			0.45			0.48			0.05		0.19
Storage capacity (1)		48.44			12.96			9.55			-		3.61
Annual distribution -- 2006 (1)		211			46			33			9		15
Annual distribution -- 2005 (1)		232			59			36			10		16
Annual distribution -- 2004 (1) (6)		233			65			34			9		16
2006 peak day demand (1)		1.6			0.3			0.3			0.04		0.1
Peak storage capacity (1)		7.80			0.77			1.64			-		1.21
Average monthly throughput (1)		17.6			3.8			2.8			0.8		1.3
Miles of main (7)		30,284			3,030			5,235			3,207		1,521
Heating degree days -- 2006 (2)		2,466			4,110			2,869			696		2,898
2006 % (warmer) colder than 2005		(10	%)		(18	%)		(17	%)		(16	%)	(7%)
Heating degree days -- 2005 (2)		2,726			5,017			3,465			829		3,115
2005 % colder than 2004		5	%		2	%		8	%		3	%	3%
Heating degree days -- 2004 (2) (6)		2,589			4,918			3,214			802		3,010
Rates
Last decision on change in rates		Jun. 2005			Nov. 2002			Oct. 1996			Feb. 2004		Dec. 2006
Authorized return on rate base (5)		8.53	%		7.95	%		9.24	%		7.36	%	7.43%
Estimated 2006 return on rate base (3)		8.45	%		7.83	%		7.65	%		7.41	%	7.00%
Authorized return on equity		10.9	%		10.0	%		10.9	%		11.25	%	10.2%
Estimated 2006 return on equity (3)		10.73	%		9.4	%		8.49	%		10.67	%	9.01%
Authorized rate base % of equity		47.9	%		53.0	%		52.4	%		36.8	%	35.5%
Rate base included in 2006 return on equity (in millions) (1)	$	1,238		$	417		$	351		$	120		$102

(1)

In Bcf

(2)

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

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

(4)	Estimated based on 13-month average.

(5)

The authorized return on rate base, return on equity, and percentage of equity reflected above were those authorized as of December 31, 2006. Effective January 1, 2007, Chattanooga Gas’ authorized return on rate base, return on equity and percentage of equity are 7.89%, 10.2% and 44.8%, respectively, due to the results of its base rate case settled in December 2006.

(6)

Includes amounts for the full year of 2004; however, we acquired these utilities in December 2004. The December 2004 end-use customers for Elizabethtown Gas was 266 and 103 for Florida City Gas, December 2004 distribution for Elizabethtown Gas was 8.2 and 0.9 for Florida City Gas; and December 2004 heating degree days for Elizabethtown Gas was 873 and 239 for Florida City Gas.

(7)	Includes distribution and transmission main only

Regulatory Environment Each utility operates subject to regulations provided by the state regulatory agency in its service territories with respect to rates charged to our customers and various 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 generally consists 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 that 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 the 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 through a rate case filing.

Straight-Fixed-Variable Rates Atlanta Gas Light recognizes revenue under a straight-fixed-variable rate design whereby Atlanta Gas Light charges rates to its customers based primarily on monthly fixed charges, however the Marketers bill these charges directly to their customers. This mechanism minimizes the seasonality of revenues since the monthly fixed charge is not volumetric and the monthly charge is 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.

Weather Normalization The tariffs of Elizabethtown Gas, Virginia Natural Gas, and Chattanooga Gas contain WNA provisions that are designed to help stabilize operating margin 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 WNA is most effective in a reasonable temperature range relative to normal weather using historical averages. For Elizabethtown Gas, the weather normalization provision was renewed in October 2004 and is based on a 20-year average of weather conditions.

Virginia Natural Gas received from the Virginia Commission approval of a weather normalization program in September 2002 as a two-year experiment involving the use of special rates. 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 modifications included 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. The residential WNA program was made permanent in a rate settlement agreement in July 2006.

Chattanooga Gas’ base rates include a weather normalization provision 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.

Rate Settlement Agreements On July 24, 2006, the Virginia Commission issued an order approving Virginia Natural Gas’ performance based rate (PBR) plan with modifications. Under the PBR rate plan, Virginia Natural Gas’ rates were frozen as an incentive for it to promote cost containment, productivity and rate stability without traditional rate proceedings that set rates based on investment, return and cost of service. These modifications include a requirement to construct and report on the progress of a pipeline connecting Virginia Natural Gas’ northern and southern systems and reporting requirements to monitor compliance with the terms of the PBR plan. Virginia Natural Gas accepted the terms of the PBR plan as modified by the Virginia Commission in August 2006. The modified PBR plan was effective August 1, 2006 with base rates frozen at current levels for five years. The estimated cost to construct the pipeline is between $48 million and $60 million, and the pipeline is expected to be completed in 2009.

On June 30, 2006, we filed a general rate case with the Tennessee Commission seeking approximately $6 million in increased annual base rates to cover the rising cost of service at Chattanooga Gas. Our rate case included a proposal for comprehensive rate design, including an energy conservation program (ECP) and a conservation and usage adjustment (CUA). The ECP would provide incentives for customers to reduce their natural gas consumption by offering rebates for more energy-efficient appliances and to help customers better manage their energy costs. The CUA is designed to mitigate the financial impact on Chattanooga Gas of expected increased energy conservation by customers through rate adjustments.

The Tennessee Commission divided the case into two phases: one phase to examine the revenue requirements and traditional rate design issues and a second phase to review the CUA and ECP. Approximately $5 million of our base rate request was related to the revenue requirement. In December 2006, the Tennessee Commission approved a settlement agreement between Chattanooga Gas, the Consumer Advocate and Protection Division of the Attorney General’s Office (Consumer Advocate) and the Chattanooga Manufacturers Association settling the revenue requirements and traditional rate design issues of the case. The settlement agreement was effective January 1, 2007 and provides for a base rate increase of approximately $3 million of which $2 million will be an increase in operating margin and the remaining will be a $1 million shift from WNA to base rates and have no overall impact on operating margin.

The settlement agreement establishes and authorized return on equity of 10.2% for Chattanooga Gas, resulting in an overall authorized rate of return of 7.89%. Prior to the settlement agreement, Chattanooga Gas’ authorized return on equity was 10.2% and its overall authorized rate of return was set at 7.43%. The second phase of the case is scheduled to begin in February 2007 with a final ruling expected by September 30, 2007.

Customer Demand 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 commercial markets throughout our service areas primarily through the potential displacement or replacement of natural gas appliances with electric appliances. The primary competitive factors are the prices for competing sources 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 or builder makes decisions as to which types of equipment to install. Customers 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

·	new housing starts

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

We expect customer growth to improve in the future through our efforts to obtain new customers and retain existing customers. These efforts include working to add residential customers, multifamily 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 converting to alternative fuels.

Collective Bargaining Agreements In 2006, a collective bargaining agreement representing approximately 300 Atlanta Gas Light employees by Teamsters Local 528 was not renewed. As a result, these employees are no longer represented by a bargaining unit and now fall under our standard human resources pay and benefit plans and policies. The following table provides information about the collective bargaining agreements to which our natural gas local distribution utilities are parties:

	Affiliated subsidiary		Approximate # of employees		Date of contract expiration
Communications Workers of America (Local No. 1023)		Elizabethtown Gas		8		April 2007
Utility Workers Union of America (Local No. 461)		Chattanooga Gas		21		April 2007
International Union of Operating Engineers (Local No. 474)		Atlanta Gas Light		26		August 2007
Teamsters (Local Nos. 769 and 385)		Florida City Gas		50		March 2008
Utility Workers Union of America (Local No. 424)		Elizabethtown Gas		160		November 2009
International Brotherhood of Electrical Workers (Local No. 50)		Virginia Natural Gas		141		May 2010
Total				406

Results of Operations The following table presents results of operations for distribution operations for the years ended December 31, 2006, 2005 and 2004.

In millions	2006		2005		2004
Operating revenues	$	1,624	$	1,753	$	1,111
Cost of gas		817		939		471
Operating margin (1)		807		814		640
Operating expenses		499		518		394
Operating income		308		296		246
Other income		2		3		1
EBIT (1)	$	310	$	299	$	247

Metrics (2)
Average end-use customers (in thousands)		2,250		2,242		1,880
Operation and maintenance expenses per customer	$	156	$	166	$	152
EBIT per customer	$	138	$	133	$	131

(1)	These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in “Results of Operations - AGL Resources.”

(2)	2004 metrics include only December for Florida City Gas, Elizabethtown Gas and Elkton Gas.

2006 compared to 2005 EBIT increased $11 million or 4% in 2006 reflecting a decrease in operating expenses of $19 million, partially offset by decreased operating margin of $7 million.

The operating margin decrease of $7 million or 1% in 2006 was primarily the result of lower usage resulting from customer conservation and warmer weather. Operating margins decreased $4 million at Virginia Natural Gas, $3 million at Elizabethtown Gas and $2 million at Florida City Gas. Also contributing to the decrease was a $3 million decrease from our exit of the New Jersey and Florida appliance business operations in 2005. These decreases were offset by a net increase in Atlanta Gas Light’s operating margin of $6 million consisting of $5 million in gas storage carrying costs and $2 million in pipeline replacement program (PRP) revenues, offset primarily by $2 million as a result of the effect of the Georgia Commission’s June 2005 Rate Order.

Operating expenses decreased $19 million or 4% in 2006 compared to the same period in 2005, primarily due to lower compensation and facilities expense of $10 million, resulting from a workforce and facilities restructuring in 2005, $5 million of reduced outside services and $3 million in lower costs due to our exiting the appliance businesses acquired with our purchase of NUI. These decreases were offset by a $1 million increase in bad debt expense primarily at Elizabethtown Gas due to higher gas prices in 2006. Operating expenses also reflect a $2 million net gain compared to 2005 primarily due to the sale of properties in Georgia in 2006.

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 businesses acquired from NUI on November 30, 2004 contributed approximately $50 million of EBIT in 2005 compared to $7 million in 2004. This was due to the inclusion of the full-year NUI results in 2005 as compared to the inclusion of one month in 2004.

The $174 million or 27% increase 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 from additional carrying charges to Marketers for gas stored, primarily due to higher gas prices. Atlanta Gas Light also had approximately $3 million of increased operating margin from net customer growth, which offset a $3 million decrease in operating revenues that resulted from the June 2005 Settlement Agreement with the Georgia Commission. Operating margin at Virginia Natural Gas and Chattanooga Gas remained relatively flat compared to 2004.

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

Retail Energy Operations

Our retail energy operations segment consists of SouthStar, a joint venture owned 70% by our subsidiary, Georgia Natural Gas Company, and 30% by Piedmont Natural Gas (Piedmont). SouthStar markets natural gas and related services to retail customers on an unregulated basis, principally in Georgia as well as to commercial and industrial customers in Tennessee, North Carolina, South Carolina and Alabama. During 2006, SouthStar entered into agreements with customers in Ohio and Florida to supply natural gas starting in the fourth quarter of 2006.

The SouthStar executive committee, which acts as the governing board, is comprised of six members, three representatives from AGL Resources 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. Earnings related to customers in Ohio and Florida are allocated 70% to us and 30% to Piedmont. We record the earnings allocated to Piedmont as a minority interest in our consolidated statements of income, and we record 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 largest Marketer of natural gas in Georgia, with average customers over the last three years 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 for other non-natural gas energy products 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 and related significant increases in the cost of natural gas billed to SouthStar’s customers, especially during the fourth quarter of 2005 and the first and second quarters of 2006.

Operating Margin SouthStar generates operating margin primarily in three ways. The first is through the sale of natural gas to retail customers in the residential, commercial and industrial sectors, primarily in Georgia where SouthStar captures a spread between wholesale and retail natural gas prices. The second way is through the collection of monthly service fees and customer late payment fees.

The combination of these two retail price components is evaluated by SouthStar to ensure such pricing is structured to cover related retail customer costs, such as bad debt expense, customer service and billing, and lost and unaccounted-for gas, and to provide a reasonable profit, as well as being competitive to attract new customers and maintain market share. SouthStar’s operating margins are impacted by seasonal weather, natural gas prices, customer growth and SouthStar’s related market share in Georgia, which has historically been approximately 35%. SouthStar employs strategies to attract and retain a higher credit-quality customer base. These strategies result not only in higher operating margin, as these customers tend to utilize higher volumes of natural gas, but also help to mitigate bad debt expense due to the higher credit-quality of customers.

The third way SouthStar generates margin is through its commercial operations of optimizing storage and transportation assets and effectively managing commodity risk, which enables SouthStar to maintain competitive retail prices and operating margins. SouthStar is allocated storage and pipeline capacity that is used to supply gas to its customers in Georgia. Through hedging transactions, SouthStar manages exposures arising from changing commodity prices using natural gas storage transactions to capture margin from natural gas pricing differences that occur over time. SouthStar’s risk management policies allow the use of derivative instruments for hedging and risk management purposes but prohibit the use of derivative instruments for speculative purposes.

SouthStar accounts for its natural gas inventories at the lower of weighted average cost or current market price (LOCOM). SouthStar evaluates the weighted average cost of its natural gas inventories against market prices and determines whether any declines in market prices below the weighted average cost are other than temporary. For declines considered to be other than temporary, SouthStar records adjustments to cost of gas in our consolidated statement of income to reduce the weighted average cost of the natural gas inventory to the current market price. As of December 31, 2006, SouthStar recorded a LOCOM adjustment of $6 million. SouthStar did not record a LOCOM adjustment in 2005 or 2004.

We have designated a portion of SouthStar’s derivative transactions as cash flow hedges under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period as the underlying hedged item occurs and is recorded in earnings. We record any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not offset and are greater than the losses or gains on the hedged item, in cost of gas in our consolidated statement of income in the period in which the ineffectiveness occurs. SouthStar currently has minimal hedge ineffectiveness. We have not designated the remainder of SouthStar’s derivative instruments as hedges under SFAS 133 and, accordingly, we record changes in their fair value in earnings in the period of change.

SouthStar also enters into weather derivative instruments in order to preserve margins in the event of warmer-than-normal weather in the winter months. These contracts are accounted for using the intrinsic value method under Emerging Issues Task Force (EITF) Issue No. 99-02, “Accounting for Weather Derivatives.” The weather derivative contracts contain settlement provisions based on cumulative heating degree days for the covered periods. In September 2006, SouthStar entered into weather derivatives (swaps and options) for the current winter heating season. During 2006, SouthStar recorded net gains on these weather derivatives of approximately $5 million. These gains were largely offset by a corresponding loss of operating margin due to the warm weather the hedge was designed to protect against.

Impact of Volatility in Natural Gas Prices SouthStar’s operating margin and EBIT from the sales of natural gas to retail customers were affected by lower average usage in part due to conservation and higher bad debt as a result of higher and more volatile natural gas prices during the 2005-2006 heating season. SouthStar was also affected when natural gas prices further declined at the end of 2006 resulting in a LOCOM adjustment to inventory.

SouthStar’s operating margin and EBIT associated with the optimization of storage and transportation assets and commodity risk management during 2006 were affected by the decline in wholesale natural gas prices. In 2005, natural gas prices were significantly higher in part due to gas supply disruptions brought on by hurricanes Katrina and Rita. For derivatives not designated as hedges under SFAS 133, SouthStar generally records fair value losses as natural gas prices decrease and fair value gains as natural gas prices increase.

SouthStar’s bad debt expense was $13 million for 2006, a $3 million increase from 2005. The increase in bad debt was impacted by an increase in the amount of accounts receivable balances past due more than 60 days and the expectation that a majority of these past due accounts will not be collected. In addition, $1 million of aged deposits were applied to SouthStar's bad debt on a one-time basis in 2005. SouthStar entered into payment arrangements with these customers in an effort to help customers pay their higher natural gas bills during the 2005-2006 heating season. We expect that SouthStar’s collection efforts will continue to help mitigate the overall impact of bad debt expense as a percentage of operating revenues, which were 1.4% for the year ended December 31, 2006 compared to approximately 1.1% (excluding the one-time application of aged deposits) for the same period in 2005. We further believe that SouthStar’s higher credit-quality customer base mitigates our exposure to higher bad debt expenses.

SouthStar also has experienced lower average usage per customer during 2006, compared to the same period in 2005 due to a number of factors including warmer weather and the effects of customer conservation. Though these two factors have contributed to a $16 million unfavorable impact on operating margin, net of gains on weather derivatives, relative to wholesale prices and normalized temperatures. SouthStar achieved a net increase in operating margin of $10 million for 2006 compared to 2005.

Ohio Retail Market In August 2006, SouthStar was awarded the right to supply approximately a total of 10 Bcf of natural gas to customers of Dominion East Ohio (Dominion Ohio) through August 2008 (approximately 5 Bcf/year). As part of this agreement, SouthStar will manage supply, transportation and storage of natural gas on behalf of Dominion Ohio. While we do not expect the Dominion Ohio agreement to materially impact our results of operations, SouthStar’s entrance into the Ohio market is part of its continued growth strategy.

Results of Operations The following table presents results of operations for retail energy operations for the years ended December 31, 2006, 2005, and 2004.

In millions	2006			2005			2004
Operating revenues	$	930		$	996		$	827
Cost of gas		774			850			695
Operating margin (1)		156			146			132
Operating expenses		68			61			62
Operating income		88			85			70
Other expense		(2	)		-			-
Minority interest		(23	)		(22	)		(18	)
EBIT (1)	$	63		$	63		$	52

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

(1)	These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in “Results of Operations - AGL Resources. “

2006 compared to 2005 EBIT for 2006 was relatively flat as compared to 2005, driven by a $10 million increase in operating margin which was offset by a $7 million increase in operating expenses, a $2 million increase in other expense and a $1 million increase in minority interest due to the slightly higher operating income.

Operating margin increased by $10 million or 7% driven by improved retail operating margins of $6 million and higher storage margin gains of $4 million. Retail operating margins increased due to improved retail spreads and an increase of approximately 2,000 average customers in 2006 compared to 2005, offset by lower customer consumption due to weather that was approximately 10% warmer than 2005 and conservation. Late payment fees were $1 million lower in 2006 as compared to 2005 due to more customers being on payment arrangements in 2006. Additionally, retail operating margins decreased compared to 2005 due to higher interruptible margins in 2005 driven by peaking sales during curtailments. Storage margins were driven by improved optimization of storage and transportation assets and effective commodity risk management including net gains on weather derivatives. Storage operating margins were impacted by an adjustment in 2006 of $6 million to reduce inventory to market for which no LOCOM adjustment was recorded in 2005.

Operating expenses increased $7 million or 11% primarily due to higher bad debt expense of $3 million, increased depreciation of $1 million due to the implementation of system enhancements, higher outside service costs of $1 million principally driven by the current-year implementation of a new energy trading and risk management (ETRM) system and $1 million from increases in other general corporate overhead costs.

The retail energy operations segment made a $2 million charitable contribution in 2006. Minority interest increased $1 million as a result of increased operating income in 2006 compared to 2005.

2005 compared to 2004 The $11 million or 21% increase in EBIT for 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 and positive margin captured with SouthStar’s storage assets, offset by lower customer usage and lower late payment fees relative to 2004.

There was a slight decrease in operating expenses in 2005 compared to 2004. The decrease was primarily due to $1 million in lower bad debt expense resulting from ongoing collection process improvements. Minority interest increased $4 million or 22% as a direct result of increased operating income in 2005 compared to 2004.

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 customers with natural gas from the major producing regions and market hubs primarily in the eastern and mid-continental United States. Sequent 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 customers. In 2006, Sequent entered into an agreement which should facilitate the expansion of its operations into the western United States and Canada and plans to pursue additional opportunities in these regions during 2007. Sequent continues to work on projects and transactions to extend its operating territory and is entering into agreements of longer duration, as well as evaluating opportunities to expand its business focus and models.

Seasonality Fixed cost commitments are generally incurred evenly over the year, while margins generated through the use of the 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 Sequent’s business, generally resulting in higher margins in the first and fourth quarters.

Competition Sequent competes for asset management business with other energy wholesalers, often through a competitive bidding process. 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.

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 capacity to meet their demands, and they typically contract for this capacity on a 365-day basis even though they may only need a portion of the capacity to meet their peak demands. Sequent enters into agreements with these customers, either through contract assignment or agency arrangement, whereby Sequent uses the customers’ rights to transportation and storage capacity during periods when customers do not need it. 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.

The following table provides additional information on Sequent’s asset management agreements with its affiliated utilities.

	Expiration		Timing of		Type of fee		% Shared or			Profit sharing / fees payments
Dollars in millions	date		payment		structure		annual fee			2006		2005		2004
Elkton Gas		Mar 2008		Monthly		Fixed-fee		(A	)	$	-	$	-	$	-
Chattanooga Gas		Mar 2008		Annually		Profit -sharing		50	%		4		2		1
Atlanta Gas Light		Mar 2008		Semi-Annually		Profit -sharing		60	%		6		4		4
Elizabethtown Gas		Mar 2008		Monthly		Fixed -fee	$	4			4		-		-
Florida City Gas		Mar 2008		Annually		Profit -sharing		50	%		-		-		-
Virginia Natural Gas		Mar 2009		Annually		Profit -sharing		(B	)		2		5		3
Total										$	16	$	11	$	8

(A)	Annual fixed fee is less than $1 million

(B)	Profit sharing is based on a tiered sharing structure

In January 2006, the Georgia Commission extended the asset management agreement between Sequent and Atlanta Gas Light for two additional years. In addition, Sequent’s asset management agreements with Chattanooga Gas and Elkton Gas were extended for an additional year through March 2008.

Transportation Transactions Sequent contracts for natural gas transportation capacity and participates in transactions that manage the natural gas commodity and transportation costs to result in the lowest cost to serve its various markets. Sequent seeks 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 it has access and identifying the least-cost alternatives to serve the various markets. This enables Sequent to capture geographic pricing differences across these various markets as delivered gas prices change.

As Sequent executes transactions to secure transportation capacity, it often enters into forward financial contracts to hedge its positions. The hedging instruments are derivatives, and Sequent reflects changes in the derivatives’ fair value in its reported operating results. During 2006, Sequent reported gains of $12 million associated with transportation capacity hedges. The majority of this amount will be reversed during 2007 as the positions are settled. Sequent did not report any significant gains or losses on these types of hedges during 2005 or 2004.

Producer Services Sequent’s 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. Sequent provides producers with certain logistical and risk management services that offer producers attractive options to move their supply into the pipeline grid. Aggregating volumes of natural gas from these producers allows Sequent 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 its obligations under these agreements, which are reduced in whole or in part as the matching obligations expire. Sequent will continue to seek new peaking transactions as well as work toward extending those that are set to expire.

Credit Rating Sequent has certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements 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 with some of its counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, Sequent’s ability to continue transacting with these counterparties would be impaired. If at December 31, 2006 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 $10 million.

Energy Marketing and Risk Management Activities We account for derivative transactions in connection with Sequent’s energy marketing activities on a fair value basis in accordance with 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 a net unrealized gain related to changes in the fair value of derivative instruments utilized in its energy marketing and risk management activities of $132 million during 2006, $30 million of unrealized losses during 2005 and unrealized gains of $22 million during 2004. The tables below illustrate the change in the net fair value of the derivative instruments and energy-trading contracts during 2006, 2005 and 2004 and provide details of the net fair value of contracts outstanding as of December 31, 2006.

In millions	2006			2005			2004
Net fair value of contracts outstanding at beginning of period	$	(13	)	$	17			($5	)
Contracts realized or otherwise settled during period		17			(47	)		11
Change in net fair value of contract gains		115			17			11
Net fair value of new contracts entered into during period		-			-			-
Net fair value of contracts outstanding at end of period		119			(13	)		17
Less net fair value of contracts outstanding at beginning of period		(13	)		17			(5	)
Unrealized gain (loss) related to changes in the fair value of derivative instruments	$	132		$	(30	)	$	22

The sources of Sequent’s net fair value at December 31, 2006 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. Sequent’s basis spreads are primarily based on quotes obtained either through electronic trading platforms or directly from brokers.

In millions	Prices actively quoted		Prices provided by other external sources
Mature through 2007	$	21	$	80
Mature 2008 - 2009		6		8
Mature 2010 - 2012		-		2
Mature after 2012		-		2
Total net fair value	$	27	$	92

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.

We view Sequent’s trading margins from two perspectives. First, our commercial decisions are based on economic value, which is defined as the locked-in gain to be realized in the statement of income at the time the physical gas is withdrawn from storage and ultimately sold and the derivative instrument used to hedge natural gas price risk on that physical storage is settled. Second is the GAAP reported value both prior to and at the point of physical withdrawal. The GAAP amount is impacted by the process of accounting for the financial hedging instruments in interim periods at fair value between the time the gas is injected into storage and when it is ultimately withdrawn and the financial instruments are settled. The change in the fair value of the hedging instruments is recognized in earnings in the period of change and is characterized as unrealized gains or losses.

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 current market value. The derivatives that Sequent uses to mitigate commodity price risk are accounted for at fair value and marked to market each period. This difference in accounting treatment 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. These accounting differences also affect the comparability of Sequent’s period-over-period results, since changes in forward NYMEX prices do not increase and decrease on a consistent basis from year to year. During most of 2006, Sequent’s reported results were positively impacted by decreases in forward NYMEX prices which resulted in the recognition of unrealized gains. In contrast, 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, although to a lesser extent. During 2004, the reported results were not as significantly affected by changes in forward NYMEX prices. As a result, unrealized gains during 2006 had a positive impact on the favorable variance between 2006 and 2005 and unrealized losses during 2005 had a negative impact on the favorable variance between 2005 and 2004.

Storage Inventory Outlook The following graph presents the NYMEX forward natural gas prices as of December 31, 2005, September 30, 2006, and December 31, 2006 for the period of January 2007 through March 2008, and reflects the prices at which Sequent could buy natural gas at the Henry Hub for delivery in the same time period.

Sequent’s expected withdrawals from physical salt dome and reservoir storage are presented in the table below along with the expected gross margin. Sequent’s expected gross margin is net of the impact of regulatory sharing and reflects the amounts that it would expect to realize in future periods based on the inventory withdrawal schedule and forward natural gas prices at December 31, 2006. Sequent’s storage inventory is hedged with futures, and as shown below, the 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 NYMEX equivalent contract units of 10,000 million British thermal units (MMBtu).

	Q1 2007		Q2 2007		Q3 2007		Q4 2007		Q1 2008		Total
Salt dome		412		-		-		-		7		419
Reservoir		850		1		-		96		116		1,063
Total volumes		1,262		1		-		96		123		1,482
Expected gross margin (in millions)	$	9	$	-	$	-	$	4	$	5	$	18

As of December 31, 2006, the weighted average cost of natural gas in inventory was $5.52 for physical salt dome storage and $5.18 for physical reservoir storage. These costs reflect adjustments that were recorded at the end of each quarter in 2006 in order to reduce the value of Sequent’s natural gas inventory to market value at certain locations. Sequent reduced the inventory value by $9 million after regulatory sharing for the quarter ended December 31 and by $43 million for the year ended December 31, 2006. These adjustments negatively impacted Sequent’s reported earnings. However, as the carrying value of the inventory was reduced, the expected gross margin in the table above increased by an equal and offsetting amount. Sequent recovered $22 million of the aggregate $43 million of gross margin reductions during 2006 and expects to recover the majority of the remainder during the first quarter of 2007, as both the inventory is withdrawn from storage and sold and the hedging instruments in place to lock in the original margins on the storage transactions are settled and recorded in our earnings.

Park and Loan Transactions Sequent routinely enters into park and loan transactions with various pipelines which allow it to park gas on or borrow gas from the pipeline in one period and reclaim gas from or repay gas to the pipeline in a subsequent period. The economics of these transactions are evaluated and price risks are managed in much the same way traditional reservoir and salt dome storage transactions are evaluated and managed.

During the spring and summer months of 2006, natural gas prices were significantly lower than the futures prices for the upcoming winter months. As a result, Sequent has entered into transactions to park natural gas with the pipelines during the summer and receive the natural gas back during the winter.

Sequent enters into forward NYMEX contracts to hedge its park and loan transactions. While the hedging instruments mitigate the price risk associated with the delivery and receipt of natural gas, they can also result in volatility in Sequent’s reported results during the period before the initial delivery or receipt of natural gas. During this period, if the forward NYMEX prices in the months of delivery and receipt do not change in equal amounts, Sequent will report a net unrealized gain or loss on the hedges.

Although Sequent’s quarterly results were modestly impacted by unrealized hedge losses during 2006, on an annual basis Sequent did not report any significant gains or losses on park and loan hedges during 2006, 2005, or 2004.

Results of Operations The following table presents results of operations for wholesale services for the years ended December 31, 2006, 2005, and 2004.

In millions	2006		2005			2004
Operating revenues	$	182	$	95		$	54
Cost of sales		43		3			1
Operating margin (1)		139		92			53
Operating expenses		49		42			29
Operating income		90		50			24
Other expenses		-		(1	)		-
EBIT (1)	$	90	$	49		$	24

Metrics
Physical sales volumes (Bcf / day)		2.20		2.17			2.10

(1)	These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in “Results of Operations - AGL Resources.”

The following table indicates the significant changes in operating margin for the years ended December 31, 2006, 2005 and 2004:


In millions	2006			2005			2004
Gain (loss) on storage hedges	$	41		$	(7	)	$	5
Gain on transportation hedges		12			-			-
Commercial activity		107			102			49
Inventory LOCOM, net of hedging recoveries		(21	)		(3	)		(1	)
Operating margin	$	139		$	92		$	53

2006 compared to 2005 The increase in EBIT of $41 million or 84% in 2006 compared to 2005 was primarily due to an increase in operating margin of $47 million partially offset by an increase in operating expenses of $7 million.

Sequent’s operating margin increased by $47 million or 51% primarily due to improved commercial opportunities associated with larger seasonal storage spreads during the first half of 2006 and above average temperatures during the late summer months. These conditions offset the impacts of mild weather during the winter and early summer and the lower level of market volatility that we experienced compared to the hurricane activity in the Gulf of Mexico in 2005.

Additionally, the 2006 reported results were positively impacted by forward NYMEX prices moving downward and the narrowing of future seasonal spreads which resulted in the recognition of $41 million of gains on Sequent’s economic storage hedges in contrast to the prior period when forward prices increased and resulted in the recognition of $7 million of hedge losses. During 2006, Sequent also recognized $12 million in gains associated with financial instruments used to hedge its transportation capacity. There were no significant gains or losses associated with transportation hedges recognized in the prior period.

The positive impact from the price movements in 2006 was partially offset by LOCOM adjustments that Sequent recorded at certain storage locations during the year in order to reduce the carrying value of its natural gas inventory to current market prices. In 2006, Sequent recorded a total of $43 million in LOCOM adjustments; however $22 million of the adjustments were recovered during the period as the affected inventory was withdrawn from storage and sold and the hedging instruments in place to lock in the original margins on the storage transactions were settled. In 2005, Sequent recorded LOCOM adjustments of $3 million.

Operating expenses increased by $7 million or 17% primarily due to higher costs associated with an increase in the number of employees to support Sequent’s growth and additional incentive compensation costs directly related to stronger financial performance in 2006, as well as a higher percentage of corporate overhead costs than in 2005, primarily due to Sequent’s growth. The increased expenses were partially offset by lower costs associated with outside services and other expenses.

2005 compared to 2004 The increase in EBIT of $25 million or 104% in 2005 compared to 2004 was primarily 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 effects of the Gulf Coast hurricanes during the third quarter of 2005 and lingering market disruptions and price volatility throughout the fourth quarter. For the first nine months of the year, reported operating margins were similar to that of the prior year, with quarterly decreases being offset by quarterly increases. However, during the third quarter of 2005, while Sequent created substantial economic value by serving its customers during the storms, the reported operating margin was negatively impacted by accounting losses associated with storage hedges as a result of increases in forward NYMEX prices of approximately $6 per MMBtu. During the fourth quarter, natural gas prices continued to be volatile in the aftermath of the hurricanes and Sequent was able to further optimize its storage and transportation positions at levels in excess of the prior year. In addition, previously reported hedge losses were partially recovered during the fourth quarter as NYMEX 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 a new ETRM system, which was implemented during the fourth quarter of the prior year.

Energy Investments

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 Department of Natural Resources (Louisiana DNR) and by the Federal Energy Regulatory Commssion (FERC) which has limited regulatory authority over the storage and transportation services. The facility consists of two salt dome gas storage caverns with approximately 9.72 Bcf of total capacity and about 7.23 Bcf of working gas capacity. The facility has approximately 0.72 Bcf/day withdrawal capacity and 0.36 Bcf/day injection capacity. Jefferson Island provides storage and hub services through its direct connection to the Henry Hub via the Sabine Pipeline and its interconnection with seven other pipelines in the area. Jefferson Island’s entire portfolio is under firm subscription for the 2006-2007 winter period.

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

In September 2006, Jefferson Island filed suit against the State of Louisiana to maintain its lease to complete an ongoing natural gas storage expansion project in Louisiana. The project would add two salt dome storage caverns under Lake Peigneur to the two caverns currently owned and operated by Jefferson Island. In its suit, Jefferson Island alleges that the Louisiana DNR accepted all leasehold payments without reservation and never provided Jefferson Island with notice and opportunity to cure, as required by state law. As to the second basis for termination, the suit contends that Jefferson Island’s lease with the State of Louisiana was amended in 2004 so that mining operations are no longer required to maintain the lease. While we continue to seek resolution of this dispute, it is not possible at this time to predict whether the dispute can be settled or, if not, what the results of the litigation would be. As of January 2007, our current estimate of costs incurred that would be considered unusable if the Louisiana DNR was successful in terminating our lease and causing us to cease the expansion project is approximately $8 million.

Golden Triangle Storage In December 2006, we announced plans to build a $180 million natural gas storage facility in the Beaumont, Texas area in the Spindletop salt dome. The project will consist of two underground salt dome storage caverns approximately a half-mile to a mile below ground that will hold about 12 Bcf of working natural gas, or 17 Bcf total storage capacity. Golden Triangle Storage expects to finalize engineering plans and obtain regulatory permits to begin construction in 2008. The first salt dome cavern is expected to begin operations in 2010, and the second cavern is expected to begin operations in 2012.

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 0.3 Bcf/day of propane air on a 10-day-per-year basis to serve Virginia Natural Gas’ peaking needs.

AGL Networks This wholly owned subsidiary provides 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 one to twenty years. In addition, AGL Networks offers telecommunications construction services to companies. AGL Networks’ competitors are any entities that have laid or will lay conduit and fiber on the same route as AGL Networks in the respective metropolitan areas.

Results of Operations The following table presents results of operations for energy investments for the years ended December 31, 2006, 2005 and 2004.

In millions	2006		2005		2004
Operating revenues	$	41	$	56	$	25
Cost of sales		5		16		12
Operating margin (1)		36		40		13
Operating expenses		26		23		8
Operating income		10		17		5
Other income		-		2		2
EBIT (1)	$	10	$	19	$	7

(1)	These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in “Results of Operations - AGL Resources.”

2006 compared to 2005 The $9 million or 47% decrease in EBIT is due primarily to the loss of operating margin and other income contributions from the 2005 sale of certain assets that we originally acquired with the 2004 acquisition of NUI, and an increase in operating expenses due to higher business development expense and increased costs at Jefferson Island, offset by lower expenses related to the sale of the former NUI assets.

Operating margin decreased $4 million or 10% largely due to the loss of $9 million of operating margin contributions from certain assets we acquired with the 2004 acquisition of NUI but sold in 2005. Jefferson Island’s operating margin increased by $1 million compared to the prior year, in part due to increases in both firm and interruptible margin opportunities. AGL Networks’ operating margin increased by $1 million due to a larger customer base. Pivotal Propane contributed a $2 million increase primarily in the first quarter of 2006 as it did not become operational until April 2005.

Operating expenses increased $3 million or 13% compared to 2005. Operating expenses at Pivotal Propane increased as it did not become operational until April 2005. Jefferson Island’s operating expenses increased by $2 million due to the installation of new compression equipment and higher legal costs and property taxes. Additionally, project and corporate development costs increased $9 million. These costs were offset by decreased operating expenses of $8 million resulting from the 2005 sale of certain assets that we originally acquired with the 2004 acquisition of NUI. Other income decreased by $2 million due to the loss of earnings contributions from certain assets we acquired with the 2004 acquisition of NUI but sold in 2005.

2005 compared to 2004 The $12 million or 171% increase in EBIT in 2005 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 Jefferson Island, $8 million resulted from NUI’s nonutility businesses and $3 million resulted from Pivotal Propane. AGL Networks contributed $4 million primarily as a result of recurring revenues from fiber leasing activities of $1 million and 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 Jefferson Island and $1 million resulted from Pivotal Propane. AGL Networks’ operating expenses were relatively flat in 2005 as compared to 2004.

Corporate

Our corporate segment includes our nonoperating business units, including AGL Services Company (AGSC), AGL Capital Corporation (AGL Capital) and Pivotal Development. 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 operating expenses and interest costs to our operating segments in accordance with various 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 Jefferson Island, typically enables 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.

Results of Operations The following table presents results of operations for our corporate segment for the years ended December 31, 2006, 2005 and 2004.

In millions	2006			2005			2004
Operating revenues		(156	)		(182	)		(185	)
Cost of sales		(157	)		(182	)		(184	)
Operating margin (1) (2)		1			-			(1	)
Operating expenses (3)		9			6			12
Operating loss		(8	)		(6	)		(13	)
Other expenses		(1	)		(5	)		(3	)
EBIT (2)	$	(9	)	$	(11	)	$	(16	)

(1)	Includes intercompany eliminations

(2)	These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in “Results of Operations - AGL Resources.”

(3)	The following table summarizes the major components of operating expenses.

In millions	2006			2005			2004
Payroll		55			57			48
Benefits and incentives		36			34			32
Outside services		41			43			29
All other expenses		50			57			50
Allocations		(173	)		(185	)		(147	)
Total operating expenses	$	9		$	6		$	12

The corporate segment is a nonoperating segment. 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.

Item 9.01 Financial Statements and Exhibits

(d)

Exhibits

Exhibit No.	Description

99.1	Press release dated February 1, 2007 announcing financial results for the fourth quarter and year ended December 31, 2006.

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 hereunto duly authorized.

	AGL RESOURCES INC.
	(Registrant)
Date: February 1, 2007	/s/ Andrew W. Evans
	Executive Vice President and Chief Financial Officer

Exhibit Index

Exhibit No.	Description

99.1	Press release dated February 1, 2007 announcing financial results for the fourth quarter and year ended December 31, 2006.