Edgar Filing: AGL RESOURCES INC

Form 8K

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): April 27, 2005


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 April 27, 2005, AGL Resources Inc. announced its financial results for the three months ended March 31, 2005 and certain other information. A copy of AGL Resources’ press release announcing such financial results and other information is attached as Exhibit 99.1 hereto 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 shall it be deemed incorporated by reference in any filing under the Securities Act of 1933.

Item 7.01 Regulation FD Disclosure

On April 27, 2005 at 4:30 p.m. (ET) AGL Resources Inc. plans to hold its first quarter 2005 earnings conference call. The Company is filing this Form 8-K to provide selected discussion of financial results, liquidity and market risks as of March 31, 2005.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Certain expectations and projections regarding our future performance referenced in this report, as well as in other reports and proxy statements we file with the Securities and Exchange Commission (SEC), are forward-looking statements. Officers and other key employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.

Forward-looking statements involve matters that are not historical facts, such as projections of our financial performance, management’s goals and strategies for our business and assumptions regarding the foregoing. Because these statements involve anticipated events or conditions, forward-looking statements often include words such as “anticipate,” “assume,” “believe,” “can,” “could,” “estimate,” “expect,” “forecast,” “indicate,” “intend,” “may,” “plan,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would” or similar expressions. For example, in this report, we have forward-looking statements regarding our expectations for various items, including:

·	revenue growth;

·	operating income growth;

·	cash flows from operations;

·	operating expense growth;

·	capital expenditures;

·	our business strategies and goals;

·	our potential for growth and profitability;

·	our ability to integrate our recent and future acquisitions;

·	trends in our business and industries, and

·	developments in accounting standards

Do not unduly rely on forward-looking statements. They represent our expectations about the future and are not guarantees. Our expectations are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations are reasonable in view of the currently available information, our expectations are subject to future events, risks and uncertainties, and there are several factors - many beyond our control - that could cause results to differ significantly from our expectations. We caution readers that, in addition to the important factors described elsewhere in this report, the factors set forth in our 2004 Annual Report on Form 10-K filed with the SEC on February 15, 2005 under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Risk Factors,” among others, could cause our business, results of operations or financial condition in 2005 and thereafter to differ significantly from those expressed in any forward-looking statements. There also may be other factors not described in this report that could cause results to differ significantly from our expectations.

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

Overview

We are a Fortune 1000 energy services holding company whose principal business is the distribution of natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. Our six utilities serve more than 2.3 million end-use customers, making us the largest distributor of natural gas in the Southeast and mid-Atlantic regions of the United States, based on customer count. We also are involved in various related businesses, including retail natural gas marketing to end-use customers in Georgia; natural gas asset management and related logistics activities for our own utilities as well as for other non-affiliated companies; natural gas storage arbitrage and related activities; operation of high-deliverability underground natural gas storage assets; and construction and operation of telecommunications conduit and fiber infrastructure within select metropolitan areas. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services and energy investments - and a non-operating corporate segment.

The distribution operations segment is the largest component of our business and is comprehensively regulated by regulatory agencies in six states. These agencies approve rates designed to provide us the opportunity to generate revenues; to recover the cost of natural gas delivered to our customers and our fixed and variable costs such as depreciation, interest, maintenance and overhead costs; and to earn a reasonable return for our shareholders. With the exception of Atlanta Gas Light Company (Atlanta Gas Light), our largest utility franchise, the earnings of our regulated utilities are weather-sensitive to varying degrees. Although various regulatory mechanisms provide a reasonable opportunity to recover our fixed costs regardless of volumes sold, the effect of weather manifests itself in terms of higher earnings during periods of colder weather and lower earnings with warmer weather. Our retail energy operations segment, which includes SouthStar Energy Services LLC (SouthStar), also is weather sensitive, and uses a variety of hedging strategies to mitigate potential weather impacts. Our utilities and SouthStar face competition in the residential and commercial customer markets based on customer preferences for natural gas compared with other energy products, as well as the price of those products relative to that of natural gas.

We derived approximately 96% of our earnings before interest and taxes (EBIT) during the three months ended March 31, 2005 from our regulated natural gas distribution business and from the sale of natural gas to end-use customers in Georgia by SouthStar. This statistic is significant because it represents the portion of our earnings that results directly from the underlying business of supplying natural gas to retail customers. Although SouthStar is not subject to the same regulatory framework as our utilities, it is an integral part of the retail framework for providing gas service to end-use customers in the state of Georgia. For more information regarding our measurement of EBIT and the items it excludes from operating income and net income, see “Results of Operations - AGL Resources.”

The remaining 4% of our EBIT was principally derived from businesses that are complementary to our natural gas distribution business. We engage in natural gas asset management and operation of high deliverability natural gas underground storage as subordinate activities to our utility franchises. These businesses allow us to be opportunistic in capturing incremental value at the wholesale level, provide us with deepened business insight about natural gas market dynamics and facilitate our ability, in the case of asset management, to provide transparency to regulators as to how that value can be captured to benefit our utility customers through sharing arrangements. Given the volatile and changing nature of the natural gas resource base in North America and globally, we believe that participation in these related businesses strengthens our business vitality.

Industry Dynamics and Competition The natural gas industry continues to face a number of challenges, most of which relate to the supply of, and demand for, natural gas across the United States. A confluence of factors - including higher peak demands across all customer classes; incremental demand for natural gas to fuel the production of electricity, declining continental supply, particularly in the Gulf of Mexico region, and sustained higher pricing levels relative to historical averages - have created a mismatch between demand and declining supply.

These factors continue to challenge our industry to unlock new sources of natural gas supply to serve the North American market. Liquefied natural gas (LNG) continues to grow in importance as an incremental supply source to meet the expected growth in demand for natural gas. Expansion of existing LNG terminals and construction of new facilities both point toward rapid import expansions throughout the rest of this decade. In addition to expansion of LNG supplies, access to previously restricted areas for natural gas drilling also will be critical in meeting future supply needs. The challenge is magnified by the time lags and capital expenditures required to bring new LNG facilities and new drilling rigs online and by the absence of a comprehensive national energy policy designed to facilitate the construction and expansion process.

The natural gas industry also continues to face significant competition from the electric utilities serving the residential and small commercial markets as the potential replacement of natural gas appliances with electric appliances becomes more prevalent. The primary competitive factors are the price of energy and the comfort of natural gas heating compared to electric heating and other energy sources. The increase in wholesale natural gas prices over the last several years has resulted in increases in the costs of natural gas billed to our customers and has affected, to some extent, our ability to retain customers, which remains one of our greater challenges in our southernmost utilities in 2005 and future years.

Integration of NUI Corporation We have made significant progress in integrating the assets and operations of NUI Corporation (NUI), which we acquired on November 30, 2004, into our business operations. In the first quarter of 2005, we consolidated a number of NUI’s business technology platforms into our enterprise-wide systems, including the accounting, payroll, human resources and supply chain functions. We also consolidated the call center operation that previously served the NUI utilities into our centralized call center. The combination of system integrations and the application of our best-practice operational model in managing the NUI assets already has resulted in improvements in the metrics we use to measure our business results. Such metrics include the productivity of our field personnel, the speed of our response to customers, personal and system safety and system reliability.

Internal Controls Section 404 of the Sarbanes-Oxley Act of 2002 (SOX 404) and related rules of the SEC require management of public companies to assess the effectiveness of the company’s internal controls over financial reporting as of the end of each fiscal year. In our 2004 Annual Report on Form 10-K filed with the SEC on February 15, 2005 we noted that, for 2004, the scope of our assessment of our internal controls over financial reporting included all our consolidated entities except those falling under NUI, which we acquired on November 30, 2004, and Jefferson Island Storage & Hub, LLC (Jefferson Island), which we acquired on October 1, 2004. In accordance with the SEC’s published guidance, we excluded these entities from our assessment as they were acquired late in the year, and it was not possible to conduct our assessment between the date of acquisition and the end of the year. SEC rules require that we complete our assessment of the internal control over financial reporting of these entities within one year from the date of acquisition.

We have initiated our efforts to assess the systems of internal control related to NUI’s and Jefferson Island’s businesses to comply with the SEC’s requirements under both Sections 302 and 404 of the Sarbanes-Oxley Act. During the first quarter of 2005, we converted and integrated substantially all of NUI’s accounting systems and internal control processes into our corporate accounting systems and internal control processes. As part of this process, we are addressing and resolving the material deficiencies in internal controls for the NUI business identified by NUI’s external and internal auditors during audits performed in fiscal years 2003 and 2004, as more fully described in our 2004 Annual Report on Form 10-K. While the conversion of financial systems is a key step toward remediation of the control deficiencies, we still are in the process of documenting the internal control process for the NUI business and we continue to remediate known deficiencies in internal controls.

Results of Operations

AGL Resources We acquired Jefferson Island and NUI in the fourth quarter of 2004. As a result, these acquired operations are included in our results of operations for the three months ended March 31, 2005 but are not included for the same period in 2004.

Beginning in 2005, we added an additional segment, Retail Energy Operations, which consists of the operations of SouthStar, our retail gas marketing subsidiary that conducts business primarily in Georgia. We added this segment due to our application of accounting guidance in SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information,” (“FAS 131”) in consideration of the impact of the NUI and Jefferson Island acquisitions and it is consistent with our desire to provide transparency and visibility to SouthStar on a standalone basis. Separating SouthStar into its own segment also provides additional visibility to the remaining businesses in the Energy Investments segment, principally Jefferson Island and Pivotal Propane of Virginia, Inc. (Pivotal Propane), which are more closely related in structure and operation. Additionally, we have restated the segment information for the three months ended March 31, 2004 in accordance with the guidance set forth in FAS 131.

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

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

Operating margin and EBIT We evaluate the performance of our operating segments using the measures of operating margin and EBIT. We believe operating margin is a better indicator than revenues for the contribution resulting from customer growth in our distribution operations and retail energy operations segments 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 wholesale services and energy investments segments since it is a direct measure of gross profit before overhead costs. Management believes EBIT is useful to investors as a measurement of our operating segments’ performance because it 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 affects the efficiency of the underlying operations.

Our operating margin and EBIT are not measures that are considered to be calculated in accordance with GAAP. You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our operating margin or EBIT measures may not be comparable to a similarly titled measure of another company. The following are reconciliations of our operating margin and EBIT to operating income and net income, together with other consolidated financial information for the three months ended March 31, 2005 and 2004.

	Three months ended March 31,
In millions	2005			2004			2005 vs. 2004
Operating revenues	$	912		$	651			40	%
Cost of gas		572			393			46
Operating margin		340			258			32
Operating expenses		159			125			27
Operating income		181			133			36
Other income		1			1			-
Minority interest		(13	)		(11	)		(18	)
EBIT		169			123			37
Interest expense		(26	)		(16	)		(63	)
Earnings before income taxes		143			107			34
Income taxes		(55	)		(41	)		(34	)
Net income	$	88		$	66			33	%

Basic earnings per common share	$	1.15	$	1.02	13	%
Fully diluted earnings per common share	$	1.14	$	1.00	14	%
Weighted average number of common shares outstanding
Basic		76.9		64.6	19	%
Fully diluted		77.6		65.5	19	%

Segment information Operating revenues, operating margin and EBIT information for each of our segments are contained in the following table for the three months ended March 31, 2005 and 2004:

2005 (*in millions)*	Operating revenues			Operating margin		EBIT
Distribution operations	$	634		$	253	$	123
Retail energy operations		314			66		40
Wholesale services		11			11		4
Energy investments		12			9		5
Corporate (1)		(59	)		1		(3	)
Consolidated	$	912		$	340	$	169
2004
Distribution operations	$	389		$	180	$	82
Retail energy operations		307			57		33
Wholesale services		20			20		12
Energy investments		1			1		1
Corporate (1)		(66	)		-		(5	)
Consolidated	$	651		$	258	$	123

(1)	Includes intercompany eliminations

First quarter 2005 compared to first quarter 2004

Operating Margin $73 million of the $82 million increase in operating margin resulted from distribution operations, of which approximately $70 million resulted from the acquisition of NUI. The remaining $12 million primarily reflects increased contributions from retail energy operations in the amount of $9 million, increased contributions of $8 million in the energy investments segment, and an increase of $1 million in the corporate segment, offset by a $9 million decrease in wholesale services.

Operating Expenses Operating expenses increased by $34 million, of which $32 million was from our distribution operations where $37 million was as a result of the NUI acquisition. The higher expenses from NUI were offset by $2 million of lower expenses at Virginia Natural Gas Company and $1 million of lower expenses related to favorable bad debt expense compared to last year. Wholesale services’ operating expenses were $1 million less than in 2004 because of costs related to Sequent’s Energy Trading and Risk Management system in the first quarter of 2004. Our energy investments expenses increased $4 million due primarily to the Jefferson Island acquisition. Operating expenses for the retail energy operations segment were essentially flat year-over-year.

Interest Expense Interest expense increased by $10 million from last year’s first quarter, primarily as a result of NUI and Jefferson Island acquisition debt ($8 million) and higher short-term interest rates ($2 million) as shown in the following table:

	Three months ended March 31,
Dollars in millions	2005			2004			2005 vs. 2004
Average debt outstanding (1)	$	1,820		$	1,214		$	606
Average rate		5.7	%		5.3	%		0.4	%

(1)	Daily average of all outstanding debt.

If, for the three months ended March 31, 2005, market interest rates on our variable rate debt had been 100 basis points higher, representing a 6.1% interest rate rather than our actual 5.1% interest rate, our year-to-date pretax interest expense would have increased by $4 million.

Income Taxes Income taxes increased by $14 million, primarily as a result of the higher pre-tax income for the first quarter of 2005.

Shares Outstanding Weighted average shares outstanding increased 12.3 million during the first quarter 2005, primarily as a result of our 11-million share equity offering completed in November 2004.

Distribution Operations

Distribution operations includes our natural gas local distribution utility companies, which construct, manage and maintain natural gas pipelines and distribution facilities and serve 2.3 million end-use customers. Our distribution utilities include:

·	Atlanta Gas Light

·	Elizabethtown Gas

·	Virginia Natural Gas Company, Inc. (Virginia Natural Gas)

·	Florida City Gas (Florida Gas)

·	Chattanooga Gas Company (Chattanooga Gas)

·	Elkton Gas

Each utility operates subject to regulations provided by the state regulatory agencies in its service territories with respect to rates charged to our customers, maintenance of accounting records and various other service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. Rates are set at levels that should generally allow for the recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return on common equity. Rate base consists generally of the original cost of utility plant in service, working capital, inventories and certain other assets; less accumulated depreciation on utility plant in service, net deferred income tax liabilities and certain other deductions. We continuously monitor the performance of our utilities to determine whether rates need to be adjusted through the regulatory process.

Updates The following is a summary of significant developments with regard to our distribution operations segment that have occurred since we filed our 2004 Annual Report on Form 10-K on February 15, 2005.

On October 15, 2004, Atlanta Gas Light filed a request for a $26 million rate increase from the Georgia Public Service Commission (Georgia Commission) which would continue its performance-based rate plan (PBR) and included a return on equity (ROE) band of 10.2% to 12.2% with an 11.2% midpoint. This filing was required by the PBR implemented for AGLC in 2001. On February 25, 2005, the Georgia Commission Adversary Staff and intervening parties filed rebuttal testimony. Adversary Staff put forth a case calling for a $55.6 million base rate reduction predicated on a 9.0% ROE.

In March 2005, the Virginia State Corporation Commission staff issued a report alleging that Virginia Natural Gas’ rates were excessive and that its rates should be adjusted to produce a $15 million reduction in revenue. The staff also filed a motion requesting that Virginia Natural Gas’ rates be declared interim and subject to refund. On April 11, 2005, Virginia Natural Gas responded to the staff’s report and motion and contested the allegations in the report and objected to the motion filed by the staff. Virginia Natural Gas also notified the Virginia State Corporation Commission that it would file a general rate case before December 31, 2005. As of April 27, 2005, the Virginia Commission has taken no action on the staff’s motions.

On April 26, 2005, Elizabethtown Gas presented the New Jersey Board of Public Utilities (NJBPU) with a proposal to accelerate the replacement of approximately 88 miles of 8” to 12” elevated pressure cast iron main. Under the proposal, approximately $42 million in estimated capital costs incurred over a three year period would be recovered through a pipeline replacement rider similar to the program in effect at Atlanta Gas Light. If the program as proposed is approved, cost recovery would occur on a one-year lag basis, with collections starting on October 1, 2006 and extending through December 31, 2009, after which time the program would be rolled into base rates.

In October 2004, the Tennessee Regulatory Authority (Tennessee Authority) denied Chattanooga Gas Company’s (CGC) request for a $4 million rate increase, instead approving an increase of approximately $1 million based on a 10.2% return on equity. In November 2004, the Tennessee Authority granted Chattanooga Gas’ motion for reconsideration of the rate increase and in December 2004 heard oral arguments on the issues of the appropriate capital structure and the return on equity to be used in setting Chattanooga Gas’ rates. In March 2005, CGC filed additional testimony and supporting documentation at the request of the Tennessee Authority. The Tennessee Authority has yet to issue a final ruling on our request for reconsideration.

Operations On March 1, 2005, Atlanta Gas Light completed its acquisition of 250 miles of interstate pipeline in central Georgia from Southern Natural Gas (SNG), a subsidiary of El Paso Corporation, for $32 million. The acquisition will improve deliverable capacity and reliability of the storage capacity from our LNG facility in Macon to our markets in Atlanta.

Results of Operations for our distribution operations segment for the three months ended March 31, 2005 and 2004 are as follows:

	Three months ended March 31,
In millions	2005		2004		2005 vs. 2004
Operating revenues	$	634	$	389	$	245
Cost of gas		381		209		172
Operating margin		253		180		73
Operating expenses
Operation and maintenance		93		71		22
Depreciation and amortization		28		21		7
Taxes other than income		9		6		3
Total operating expenses		130		98		32
Operating income		123		82		41
Other income		-		-		-
EBIT	$	123	$	82	$	41

Metrics (includes information only for 2005 for utilities acquired from NUI)
Average end-use customers (in thousands)		2,266		1,840		23	%
Operation and maintenance expenses per customer	$	42	$	38		11
EBIT per customer	$	53	$	45		18
Throughput (in millions of dekatherms)
Firm		106		90		18	%
Interruptible		33		28		18
Total		139		118		18	%
Heating degree days (1):						% Colder / (Warmer	)
Florida		490		-		-	%
Georgia		1,396		1,503		(7	)
Maryland		2,684		-		-
New Jersey		2,755		-		-
Tennessee		1,545		1,716		(10	)
Virginia		2,056		1,853		11

(1)

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

First quarter 2005 compared to first quarter 2004

Operating Margin The increase in operating margin of $73 million, or 41%, was primarily a result of the addition of NUI’s operations, which contributed $70 million. The remainder of the increase was the combination of higher operating margin at Atlanta Gas Light offset by lower operating margin at Virginia Natural Gas. The increase at Atlanta Gas Light was a result of higher PRP revenues, additional revenue from gas storage carrying charges billed to marketers and increased customer usage and growth. These results were offset by a reduction in operating margins at Virginia Natural Gas, resulting from lower use per heating degree day and a change in the weather normalization adjustment calculation resulting from a regulatory order.

Operating Expenses The increase in operating expenses of $32 million, or 33%, primarily was a result of the addition of NUI’s operations, which contributed $37 million. This increase was offset primarily by lower operating expenses at Virginia Natural Gas, largely in part to lower bad debt and payroll expenses.

EBIT The increase in EBIT of $41 million was primarily from the inclusion of NUI’s operations, which contributed approximately $34 million.

Retail Energy Operations

Our retail energy operations segment consists of SouthStar, a joint venture formed in 1998 by our subsidiary, Georgia Natural Gas Company, Piedmont Natural Gas and Dynegy Inc. (Dynegy). The purpose was to market natural gas and related services to retail customers on an unregulated basis, principally in Georgia. On March 11, 2003, we purchased Dynegy’s 20% ownership interest.

We currently own a non-controlling 70% financial interest in SouthStar, and Piedmont owns the remaining 30%. Our 70% interest is non-controlling because all significant management decisions require approval of both owners. On March 29, 2004, we executed an amended and restated partnership agreement with Piedmont. This amended and restated partnership agreement calls for SouthStar’s future earnings starting in 2004 to be allocated 75% to our subsidiary and 25% to Piedmont. In addition, we executed a services agreement which provided that AGL Services Company will provide and administer accounting, treasury, internal audit, human resources and information technology functions for SouthStar.

Results of operations for our retail energy operations segment for the three months ended March 31, 2005 and 2004 are shown in the following table.


	Three months ended March 31,
In millions	2005			2004			2005 vs. 2004
Operating revenues	$	314		$	307		$	7
Cost of sales		248			250			(2	)
Operating margin		66			57			9
Operating expenses
Operation and maintenance		13			13			-
Depreciation and amortization		-			-			-
Taxes other than income		-			-			-
Total operating expenses		13			13			-
Operating income		53			44			9
Minority interest (1)		(13	)		(11	)		(2	)
EBIT	$	40			33		$	7
Average customers (in thousands)		531			550			(4	%)
Market share in Georgia		36	%		37	%		(3	%)

(1) Minority interest adjusts our earnings to reflect our 75% share of SouthStar’s earnings.

First quarter 2005 compared to first quarter 2004

Operating Margin The $9 million increase in operating margin is primarily a result of higher commodity margins in 2005, partly offset by lower sales volumes due to 7% warmer weather in 2004. These margins resulted from larger storage spreads and favorable asset management activities during the quarter.

Operating Expenses Operating expenses were virtually flat year-over-year. Bad debt expense decreased $2 million in 2005 as a result of significantly lower write-offs. However, this was substantially offset by a one-time vendor performance credit and the timing of marketing expenses in 2005.

EBIT SouthStar’s EBIT contribution of $40 million in 2005 was $7 million higher than last year, reflecting higher commodity margins and favorable asset management results during the quarter.

Wholesale Services

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

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

The following is a summary of significant developments with regard to our wholesale services segment that have occurred since we filed our 2004 Annual Report on Form 10-K on February 15, 2005.

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

On April 1, 2005, in connection with the acquisition of NUI, Sequent commenced asset management responsibilities for Elizabethtown Gas, Florida Gas and Elkton Gas. The following table summarizes Sequent’s asset management transactions with our affiliated utilities.

Dollars in millions	Duration of contract (in years)	Expiration date	Frequency of payment	Profits shared / fees paid in 2005 (1)		Profits shared / fees paid in 2004 (2)
Virginia Natural Gas	5	Oct 2005	Annually	$-	$3
Atlanta Gas Light	3	Feb 2006	Semi-annually	3	4
Chattanooga Gas	3	Mar 2007	Annually	2	1
Elizabethtown Gas	3	Mar 2008	Monthly	-	-
Florida Gas	3	Mar 2008	Quarterly	-	-
Elkton Gas	2	Mar 2007	Monthly	-	-

(1)	For the three months ended March 31.

(2)	For the twelve months ended December 31.

Energy Marketing and Risk Management Activities The tables below illustrate the change in the net fair value of Sequent’s derivative instruments and energy-trading contracts during the three months ended March 31, 2005 and 2004, and provide details of the net fair value of contracts outstanding as of March 31, 2005. Sequent’s storage positions are affected by changes in the New York Mercantile Exchange, Inc. (NYMEX) average price.

	Three months ended March 31,
In millions	2005			2004
Net fair value of contracts outstanding at beginning of period	$	17			($5	)
Contracts realized or otherwise settled during period		9			4
Change in net fair value of contracts		(15	)		10
Net fair value of contracts outstanding at end of period		11			9
Less net fair value of contracts outstanding at beginning of period		17			(5	)
Unrealized (loss) gain related to changes in the fair value of derivative instruments		($6	)	$	14

The sources of our net fair value at March 31, 2005 are as follows:

In millions	Matures through March 2006			Matures through March 2009		Matures through March 2011		Matures after March 2012		Total net fair value
Prices actively quoted (1)	$	19			1		-		-	$	20
Prices provided by other external sources (1)		(13	)		3		1		-		(9	)

(1)

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

Mark-to-Market versus Lower of Average Cost or Market We purchase natural gas for storage when the current market price we pay plus the cost for storage is less than the market price we could receive in the future. We attempt to mitigate substantially all of our commodity price risk associated with our storage portfolio. We use derivative instruments to reduce the risk associated with future changes in the price of natural gas. We sell NYMEX futures contracts or other over-the-counter derivatives in forward months to substantially lock-in the profit margin we will ultimately realize when the stored gas is actually sold.

Natural gas stored in inventory is accounted for differently than the derivatives we use to mitigate the commodity price risk associated with our storage portfolio. The difference in accounting can result in volatility in our reported net income, even though the profit margin is essentially unchanged from the date the transactions were consummated. Natural gas that we purchase and inject into storage is accounted for at the lower of average cost or market. The derivatives we use to mitigate commodity price risk are accounted for at fair value and marked to market each period. These differences in our accounting treatment result in volatility in our reported net income.

Earnings Volatility And Price Sensitivity Over time, gains or losses on the sale of inventory will be offset by losses or gains on the derivatives used as hedges, resulting in the realization of the profit margin we expected when we entered into the transactions. Accounting differences cause Sequent’s earnings on its storage positions to be affected by natural gas price changes, even though the economic profits remain essentially unchanged. Based upon our storage positions at March 31, 2005, a $0.10 change in the forward NYMEX prices would result in a $0.5 million impact to Sequent’s EBIT.

Storage Inventory Outlook The NYMEX forward curve graph set forth below reflects the NYMEX natural gas prices as of December 31, 2004 and March 31, 2005 for the period of April 2005 through March 2006, and reflects the prices at which we could buy natural gas at the Henry Hub for delivery in the same time period. April 2005 futures expired on March 29, 2005; however they are included in the table below as they coincide with the April storage withdrawals. The Henry Hub, located in Louisiana, is the largest centralized point for natural gas spot and futures trading in the United States. NYMEX uses the Henry Hub as the point of delivery for its natural gas futures contracts. Many natural gas marketers also use the Henry Hub as their physical contract delivery point or their price benchmark for spot trades of natural gas.

The NYMEX forward curve graph also displays the significant increase in NYMEX prices experienced during the first quarter of 2005. As shown in the table following the graph, a significant portion of our inventory in storage as of March 31, 2005 is scheduled for withdrawal in July and August. Since we have these NYMEX contracts in place, our original economic profit margin is unaffected. However, the increase in NYMEX prices during the first quarter of 2005 resulted in unrealized losses associated with our NYMEX contracts. During the first quarter of 2004, we experienced the same phenomenon, albeit to a lesser degree. See further discussions in “Results of Operations” below.

As shown in the table below, “Open Futures NYMEX Contracts” represents the volume in contract equivalents of the transactions we executed to lock in our storage inventory margin. Each contract equivalent represents 10,000 million British thermal units (MMBtu’s). As of March 31, 2005, the expected withdrawal schedule of this inventory is reflected in items (B) and (C) of the table to the graph. At March 31, 2005, the weighted average cost of gas (WACOG) in salt dome storage was $6.74, and the WACOG for gas in reservoir storage was $6.33.

The table also reflects that our storage inventory is fully hedged with futures as evidenced by the NYMEX short positions (A) being equal to the physical long positions (B and C), which results in an overall locked-in margin, timing notwithstanding. Expected gross margin after regulatory sharing reflects the gross margin we would generate in future periods based on the forward curve and inventory withdrawal schedule at March 31, 2005. Our current inventory level and pricing should result in gross margin of approximately $7 million through March 2006. This gross margin will likely change as we adjust our daily injection and withdrawal plans in response to changes in market conditions in future months.

	Apr 05	May 05	Jun 05	Jul 05	Aug 05	Sep 05	Oct 05	Nov 05	Dec 05	Jan 06	Feb 06	Mar 06	Total
(A)	(114)	(89)	(66)	(165)	(225)	(21)	(68)	-	-	-	(41)	(46)	(835)

(B)	80	64	-	-	-	-	-	-	-	-	-	-	144
(C)	34	25	66	165	225	21	68	-	-	-	41	46	691
	114	89	66	165	225	21	68	-	-	-	41	46	835
(D)	$0.8	$0.7	$0.4	$1.1	$2.0	$0.3	$0.7	-	-	-	$0.6	$0.6	$7.2

(A) Open futures NYMEX contracts (short) long (in MMBtu)

(B) Physical salt dome withdrawal schedule (in MMBtu)

(D) Expected gross margin, in millions, after regulatory sharing for withdrawal activity

Credit Rating Sequent has certain trade and credit contracts that have explicit credit rating trigger events in case of a credit rating downgrade. These rating triggers typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with some of our counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If at March 31, 2005, our credit ratings had been downgraded to non-investment grade, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $15 million.

Results of Operations for our wholesale services segment for the three months ended March 31, 2005 and 2004 are as follows:

	Three months ended March 31,
In millions	2005		2004		2005 vs. 2004
Operating revenues	$	11	$	20		($9	)
Cost of sales		-		-
Operating margin		11		20		(9	)
Operating expenses
Operation and maintenance		7		8		(1	)
Depreciation and amortization		-		-		-
Taxes other than income		-		-		-
Total operating expenses		7		8		(1	)
Operating income		4		12		(8	)
Other income		-		-
EBIT	$	4	$	12		($8	)

Metrics
Physical sales volumes (Bcf/day)		2.3		2.1		10	%

First quarter 2005 compared to first quarter 2004

Operating Margin The $9 million reduction in operating margin reflects the negative impacts of changes in forward NYMEX prices during late 2004 and early 2005, partially offset by improved origination operations during the 2005 period. During December 2004, there was a significant decline in forward NYMEX prices which resulted in the recognition of gains associated with the financial instruments used to hedge Sequent’s inventory held in storage. The majority of this inventory was scheduled for withdrawal during the first quarter of 2005 and, as a result, $5 million of margin that was originally anticipated to be recognized during the first quarter of 2005 was recognized in 2004. The results for the first quarter of 2004 did not experience a similar impact. Also, as a result of an increase in forward NYMEX prices during the first quarter of 2005, the results for this period reflect the recognition of $8 million of losses associated with our inventory hedges. The results for the first quarter of 2004 were similarly affected; however, the earnings impact was less than $1 million. Partially offsetting the negative impacts of forward NYMEX price changes was a $5 million increase in origination results in the Northeast market due to higher transportation spreads.

Operating Expenses Operating expenses decreased $1 million as a result of lower outside services costs associated with the prior year implementation of our ETRM system and certain one-time SOX compliance costs incurred in 2004. The reduced expenses were partially offset by higher payroll costs related to increased headcount.

Energy Investments

Our energy investments segment includes:

·	Jefferson Island

·	Pivotal Propane of Virginia

·	Virginia Gas Company

·	50% ownership interset in Saltville Gas Storage Company, LLC (Saltville)

·	AGL Networks, LLC

On April 27, 2005, we announced our agreement to sell our 50 percent interest in Saltville and our wholly-owned subsidiaries in Virginia Gas Pipeline and Virginia Gas Storage to Duke Energy Corporation, the other 50 percent partner in Saltville LLC. We acquired these Virginia assets in November 2004 with our purchase of NUI. We will retain Virginia Gas Distribution Company, another NUI asset, which has 270 customers and annual throughput of 240,000 Dth.

When completed, the sale will make Duke Energy the sole owner of Saltville, which operates a storage facility that currently has approximately 2.0 Bcf of capacity. AGL Resources will receive, subject to working capital adjustments, $62 million in cash at closing and will utilize the proceeds to repay debt and for other general corporate purposes. The transaction is not expected to have a material impact on our earnings. Closing of the transaction, which is conditional upon regulatory approvals, including approval from the Virginia State Corporation Commission, is expected in the third quarter of 2005.

Results of operations for our energy investments segment for the three months ended March 31, 2005 and 2004 are shown in the following table.


	Three months ended March 31,
In millions	2005		2004		2005 vs. 2004
Operating revenues	$	12	$	1	$	11
Cost of sales		3		-		3
Operating margin		9		1		8
Operating expenses
Operation and maintenance		3		1		2
Depreciation and amortization		2		-		2
Taxes other than income		-		-		-
Total operating expenses		5		1		4
Operating income		4		-		4
Other income		1		1		-
EBIT	$	5	$	1	$	4

First quarter 2005 compared to first quarter 2004

Operating Margin Operating margin in the energy investments segment increased $8 million, primarily as a result of the addition of Jefferson Island (which contributed $4 million of the increase), the addition of Virginia Gas Company and Saltville obtained with the NUI acquisition (which contributed $2 million of the increase) and improved margins at AGL Networks (which contributed approximately $1 million of the increase) during the quarter.

Operating Expenses Operating expenses in the Energy Investments segment increased $4 million, primarily driven by the addition of Pivotal Jefferson Island, Virginia Gas Company and Saltville and additional expenses at AGL Networks associated with the projects in Phoenix and Atlanta.

EBIT The $4 million EBIT growth year-over-year is from the addition of Jefferson Island.

Corporate

Our corporate segment includes our nonoperating business units, including AGL Services Company (AGSC), AGL Capital Corporation (AGL Capital) and Pivotal Energy Development (Pivotal). AGSC is a service company established in accordance with the Public Utility Holding Company Act of 1935, as amended (PUHCA). AGL Capital provides for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities, and other financing arrangements.

Pivotal coordinates, among our related operating segments, the development, construction or acquisition of assets in the Southeast and Mid-Atlantic 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’s commercial activities is to improve the economics of system reliability and natural gas deliverability in these targeted regions.

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

Results of operations for our corporate segment for the three months ended March 31, 2005 and 2004 are as follows:

	Three months ended March 31,
In millions	2005			2004			2005 vs. 2004
Payroll	$	13		$	11		$	2
Benefits and incentives		8			10			(2	)
Outside services		8			6			2
Depreciation and amortization		3			3			-
Taxes other than income		2			2			-
Other		11			11			-
Total operating expenses before allocations		45			43			2
Allocation to operating segments		(42	)		(38	)		(4	)
Total operating expenses		3			5			(2	)
Other losses		-			-			-
EBIT		($3	)		($5	)		$2

First quarter 2005 compared to first quarter 2004 The corporate segment had a $2 million positive EBIT variance in the first quarter of 2005 relative to the same period last year. The key drivers of corporate operating expense are detailed in the above table and summarized below.

Payroll Expense Corporate payroll expenses were $2 million higher than last year. Approximately $1 million of the increase related to the acquisition of NUI. The remaining $1 million is the result of increased headcount.

Benefits and Incentives A $2 million reduction in benefits and incentive expenses was primarily the result of $1 million lower incentive pay and $1 million lower group insurance expense charged to AGSC.

Outside Services A $2 million increase in outside services resulted primarily from additional spending in the information technology area, including $2 million in projects related to NUI integration and $1 million related to customer solution projects.

Other Our corporate segment recorded a $2 million loss on the retirement of some information technology assets in the first quarter of 2004 that was absent from this year’s results.

Liquidity and Capital Resources

We rely on operating cash flow; short-term borrowings under our commercial paper program, which is backed by our supporting credit agreement (Credit Facility); and borrowings or stock issuances in the long-term capital markets to meet our capital and liquidity requirements. Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by state and federal regulatory bodies including state public service commissions and the SEC. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation.

The availability of borrowings and unused availability under our Credit Facility is limited and subject to conditions specified within the Credit Facility, which we currently meet. These conditions specified and defined within the Credit Facility include:

·	compliance with certain financial covenants

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

·	our total debt-to-capital ratio

Our total cash and available liquidity under our Credit Facility as of the dates indicated are represented in the table below.

In millions	March 31, 2005		Dec. 31, 2004
Unused availability under the Credit Facility	$	750	$	750
Cash and cash equivalents		24		49
Total cash and available liquidity under the Credit Facility	$	774	$	799

We believe these sources will be sufficient for our working capital needs, debt service obligations and scheduled capital expenditures for the foreseeable future. The relatively stable operating cash flows of our distribution operations businesses currently contribute most of our cash flow from operations, and we anticipate this to continue in the future. We will continue to evaluate our need to increase our available liquidity based upon our view of natural gas prices and liquidity requirements established by the rating agencies. We have historically had a working capital deficit, primarily as a result of our borrowings of short-term debt to finance the purchase of long-term assets, principally property, plant and equipment. However, our liquidity and capital resource requirements may change in the future due to a number of factors, some of which we cannot control. These factors include:

·	the impact of the integration of NUI

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

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

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

·	regulatory changes and changes in rate-making policies of regulatory commissions

·	contractual cash obligations and other commercial commitments

·	interest rate changes

·	pension and postretirement funding requirements

·	changes in income tax laws

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

·	operational risks

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. We calculate any expense pension contributions using an actuarial method called the projected unit credit cost method, and as a result of our calculations, we do not expect to make a pension contribution in 2005. The following table illustrates our expected future contractual obligations:

			Payments due before December 31,
					2006		2008		2010
					&		&		&
In millions	Total		2005		2007		2009		Thereafter
Long-term debt (1) (2)	$	1,618	$	1	$	2	$	2	$	1,613
Short-term debt (2)		38		38		-		-		-
Pipeline charges, storage capacity and gas supply (2)		1,756		208		502		423		623
Commodity and transportation charges		129		20		23		14		72
Pipeline replacement program costs (3)		346		76		178		92		-
ERC (3)		74		12		12		11		39
Operating leases (4)		146		14		32		28		72
Communication/network service and maintenance		12		5		7		-		-
Total	$	4,119	$	373	$	756	$	570	$	2,420

(1)	Includes $232 million of Notes Payable to Trusts, callable in 2006 and 2007.

(2)	Does not include the interest expense associated with the long-term and short-term debt.

(3)	Charges recoverable through a purchased gas adjustment mechanism or alternatively billed to Marketers. Also includes demand charges associated with Sequent.

(4)	Charges recoverable through rate rider mechanisms.

(5)

We have certain operating leases with provisions for step rent or escalation payments, or certain lease concessions. We account for these leases by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms in accordance with SFAS No. 13, “Accounting for Leases.” However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein.

SouthStar has natural gas purchase commitments related to the supply of minimum natural gas volumes to its customers. These commitments are priced on an index plus premium basis. At March 31, 2005, SouthStar had obligations under these arrangements for 11 Bcf through December 31, 2005.

We also have incurred various contingent financial commitments in the normal course of business. Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following table illustrates our expected contingent financial commitments as of March 31, 2005:

			Commitments due before December 31,
					2006		2008		2010
					&		&		&
In millions	Total		2005		2007		2009		Thereafter
Guarantees (1)	$	7	$	7	$	-	$	-	$	-
Standby letters of credit, performance/ surety bonds		15		12		3		-		-
Total other commercial commitments	$	22	$	19	$	3	$	-	$	-
(1) We provide guarantees on behalf of SouthStar. We guarantee 70% of SouthStar’s obligations to SNG under certain agreements between the parties up to a maximum of $7 million if SouthStar fails to make payment to SNG.

Investing activities Our cash used in investing activities consists primarily of property, plant and equipment expenditures. As shown in the following table, we made investments of $81 million in the three months ended March 31, 2005 and $45 million in the same period in 2004.

	Three months ended
	March 31,
In millions	2005		2004
Distribution operations	$	72	$	36
Retail energy operations		-		2
Wholesale services		-		3
Energy investments		3		4
Corporate		6		-
Total property, plant and equipment expenditures	$	81	$	45

The increase of $36 million is primarily from higher expenditures at our distribution operations segment, including $32 million for the acquisition of a 250-mile pipeline in Georgia from SNG and approximately $7 million in expenditures at Elizabethtown Gas and Florida Gas.

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

We also work to maintain or improve our credit ratings on our senior notes to effectively manage our existing financing costs and enhance our ability to raise additional capital on favorable terms. Factors we consider important in assessing our credit ratings include: our balance sheet leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any transaction that would require us to issue equity based on credit ratings or other trigger events. As of April 2005, our senior unsecured debt ratings are BBB+ from Standard & Poor’s Rating Services (S&P), Baa1 from Moody’s Investor Service and A- from Fitch Ratings (Fitch).

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

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

We believe that accomplishing these capitalization objectives and maintaining sufficient cash flow are necessary to maintain our investment-grade credit ratings and to allow us access to capital at reasonable costs. The components of our capital structure, as of the dates indicated, are summarized in the following table:

In millions	March 31, 2005				December 31, 2004				March 31, 2004
Short-term debt	$	38	1	%	$	334	10	%	$	100	5	%
Current portion of long-term debt		-	-			-	-			33	1
Long-term debt (1)		1,618	52			1,623	48			970	46
Total debt		1,656	53			1,957	58			1,103	52

Minority interest		30	1			36	1			27	1
Common equity		1,446	46			1,385	41			1,002	47
Total capitalization	$	3,132	100	%	$	3,378	100	%	$	2,132	100	%

(1)	Net of interest rate swaps

Short-term debt Our short-term debt is composed of borrowings under our commercial paper program, Sequent’s line of credit, the current portion of our capital lease obligation due within the next year and SouthStar’s line of credit. The decrease in our short-term debt of $295 million is primarily a result of payments on outstanding commercial paper from:

·	cash generated from strong operating results

·	positive working capital from lower inventory and receivable requirements

Refinancing of Gas Facility Revenue Bonds On April 19, 2005, our wholly-owned subsidiary, Pivotal Utility Holdings, Inc. completed the refinancing of $20 million in Gas Facility Revenue Bonds due October 1, 2024. These bonds which had a fixed interest rate of 6.4% were refunded with $20 million of adjustable rate Gas Facility Revenue Bonds. The maturity date of these bonds remains October 1, 2024. The bonds were issued at an initial interest rate of 2.8%, and initially have a 35-day auction period, where the interest rate will adjust every 35 days.

It is also our intent to refinance an additional $46 million in Gas Facility Revenue Bonds bearing interest at 6.35% with an adjustable rate 35-day auction period. Upon the completion of certain regulatory approvals, we anticipate the closing to be completed by May 2005.

Dividends on Common Stock In February 2005, we announced a 7% increase in our common stock dividend, raising the quarterly dividend from $0.29 per share to $0.31 per share, which equates to an indicated annual dividend of $1.24 per share. The increase in our common stock dividend of $5 million for the three months ended March 31, 2005 as compared to the same period last year was a result of our increased quarterly dividend and the increase in the number of shares outstanding as a result of our November 2004 equity offering.

Market Risks

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

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

Commodity Price Risk

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


Natural gas contracts	Average values				Value at:
*In millions*	Three months ended March 31, 2005		Twelve months ended Dec. 31, 2004		March 31, 2005		Dec. 31, 2004		March 31, 2004
Asset	$	54	$	28	$	73	$	36	$	30
Liability		38		21		61		19		21

We employ a systematic approach to the evaluation and management of the risks associated with our contracts related to wholesale marketing and risk management, including value-at-risk (VaR). VaR is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability.

We use a 1-day and a 10-day holding period and a 95% confidence interval to evaluate our VaR exposure. A 95% confidence interval means there is a 5% probability that the actual change in portfolio value will be greater than the calculated VaR value over the holding period. We calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price volatility, confidence interval and holding period. Our VaR may not be comparable to a similarly titled measure of another company because, although VaR is a common metric in the energy industry, there is no established industry standard for calculating VaR or for the assumptions underlying such calculations.

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

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

	Three months ended March 31, 2005
In millions	1-day		10-day
Period end (1)	$	0.0	$	0.1
Average		0.2		0.5
High		0.4		1.3
Low (1)		0.0		0.0

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

Retail Energy Operations SouthStar’s use of derivatives is governed by a risk management policy which prohibits the use of derivatives for speculative purposes. This policy also establishes VaR limits of $0.5 million on a 1-day holding period and $0.7 million on a 10-day holding period. A 95% confidence interval is used to evaluate VaR exposure. The maximum VaR experienced during the three months ended March 31, 2005 was less than $0.2 million for the 1-day holding period and $0.5 million for the 10-day holding period.

Credit Risk

Sequent may require its counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for our counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not meet the minimum ratings threshold.

Sequent evaluates its counterparties using the S&P equivalent credit rating which is determined by a process of converting the lower of the S&P or Moody’s rating to an internal rating ranging from 9.00 to 1.00, with 9.00 being equivalent to AAA/Aaa by S&P and Moody’s and 1.00 being equivalent to D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based a variety of financial metrics.

The weighted average credit rating is obtained by multiplying each counterparty’s assigned internal rating by the counterparty’s credit exposure and the individual results are then summed for all counterparties. That total is divided by the aggregate total counterparties’ exposure. This numeric value is converted to an S&P equivalent. Under the refined methodology, Sequent’s counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of BBB+ at March 31, 2005, compared with our previously reported rating of A- at December 31, 2004 and BBB+ at March 31, 2004. For more information on Sequent’s counterparties credit ratings, see the discussion in “Results of Operation - Wholesale Services.” The following tables show Sequent’s commodity receivable and payable positions as of the dates indicated:

Gross receivables
In millions	March 31, 2005		Dec. 31, 2004		March 31, 2004
Receivables with netting agreements in place:
Counterparty is investment grade	$	295	$	378	$	232
Counterparty is non-investment grade		28		36		8
Counterparty has no external rating		59		78		11

Receivables without netting agreements in place:
Counterparty is investment grade		12		16		17
Counterparty is non-investment grade		2		6		-
Counterparty has no external rating		-		-		-
Amount recorded on balance sheet	$	396	$	514	$	268

Gross payables
In millions	March 31, 2005		Dec. 31, 2004		March 31, 2004
Payables with netting agreements in place:
Counterparty is investment grade	$	215	$	291	$	189
Counterparty is non-investment grade		46		45		33
Counterparty has no external rating		141		139		50

Payables without netting agreements in place:
Counterparty is investment grade		37		40		43
Counterparty is non-investment grade		-		6		3
Counterparty has no external rating		-		-		-
Amount recorded on balance sheet	$	439	$	521	$	318

Item 9.01. Financial Statements and Exhibits.

(c)

Exhibits

Exhibit No.	Description

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

SIGNATURE

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

	AGL RESOURCES INC.
	(Registrant)
Date: April 27, 2005	/s/ Richard T. O’Brien
	Executive Vice President and Chief Financial Officer