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AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Three and Six Months Ended June 30, 2003

TABLE OF CONTENTS

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GLOSSARY OF KEY TERMS AND REFERENCED ACCOUNTING STANDARDS

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See Notes to Condensed Consolidated Financial Statements (Unaudited).

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See Notes to Condensed Consolidated Financial Statements (Unaudited).

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See Notes to Condensed Consolidated Financial Statements (Unaudited).

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See Notes to Condensed Consolidated Financial Statements (Unaudited).

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See Notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Significant Accounting Policies

General

Unless the context requires otherwise, references to “we”, “us”, “our” or the “company” are intended to mean consolidated AGL Resources Inc. and its subsidiaries (AGL Resources). We have prepared the accompanying unaudited consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). We believe, however, that our disclosures are adequate to make the information presented not misleading. The consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of our financial results for the interim periods. You should read these condensed consolidated financial statements in c onjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2002, filed with the SEC on March 19, 2003. Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 2003 are not necessarily indicative of our results of operations to be expected for any other interim period or for the year ending December 31, 2003. For a glossary of key terms and referenced accounting standards, see the glossary on page three of this filing.

Basis of Presentation

Our consolidated financial statements include our accounts and those of our majority-owned and controlled subsidiaries. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior periods have been reclassified to conform to the current presentation.

Accounting for Asset Retirement Obligations

In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 143, “Accounting for Obligations Associated with the Retirement of Long-Lived Assets,” (SFAS 143), which is effective for fiscal years beginning after June 15, 2002. SFAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be recognized as an obligation and capitalized as part of the related long-lived asset. We adopted SFAS 143 on January 1, 2003, and it did not have a material impact on our financial position or results of operations because no legally enforceable retirement obligations were identified.

Our regulated entities currently accrue removal costs on many of our regulated, long-lived assets through depreciation expense, with a corresponding charge to accumulated depreciation, in accordance with rates approved by their state jurisdictions.  As of June 30, 2003, we included accumulated removal costs of $103.9 million in our total accumulated depreciation.

Stock-based Compensation

We have several stock-based employee compensation plans and account for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25) and related interpretations. For our stock option plans, we generally do not reflect stock-based employee compensation cost in net income, as options for those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. However, if we subsequently modify the terms of the option granted we re-measure the intrinsic value of the options and record compensation expense in accordance with FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation,” when the market value of the underlying stock on the modification date is greater than the market value of the underlying stock on the original measurement date or grant date.

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In December 2002, the FASB issued SFAS 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an amendment of FASB Statement No. 123” (SFAS 148). SFAS 148 provides alternative methods of transition for a voluntary change from other methods of accounting to the fair value based method of accounting for stock-based employee compensation. Under the fair value based method, compensation cost for stock options is measured when options are granted. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 “Accounting for Stock-Based Compensation” (SFAS 123), which requires more prominent and more frequent disclosures in financial statements of the effects of stock-based compensation.

As of December 31, 2002, we adopted SFAS 148 through continued application of the intrinsic value method of accounting under APB 25, and we disclosed the effect on our net income and earnings per share of total stock-based employee compensation expense determined under the fair value based method. The following table illustrates the effect on our net income and earnings per share if we had instead applied the fair value recognition provisions of SFAS 123.

Comprehensive Income

Our comprehensive income includes net income and other gains and losses affecting shareholders’ equity that GAAP excludes from net income. Such items consist primarily of unrealized gains and losses on certain derivatives and minimum pension liability adjustments. There were no such items during the six months ended June 30, 2003 and 2002, and as a result, our total comprehensive income was equal to net income.

Earnings per Common Share

We compute basic earnings per common share by dividing our income available to common shareholders by the weighted-average number of common shares outstanding daily. Diluted earnings per common share reflect the potential dilution that could occur when potential diluted common shares are added to common shares outstanding.  

We derive our potential diluted common shares from performance units and stock options. The future issuance of the performance units depends on the satisfaction of certain performance criteria. The future issuance of outstanding stock options depends upon the exercise prices of the stock options, which are less than the average market price of the common shares for the respective periods. The following table shows our calculation of our diluted earnings per share.

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Common Shareholders’ Equity

On February 14, 2003, we announced the completion of our public offering of 6.4 million shares of common stock under our shelf registration statement. We priced the offering at $22.00 per share, and generated net proceeds of approximately $136.7 million, which we used to repay outstanding short-term debt and for general corporate purposes.

The following table provides details of our authorized, issued and outstanding common stock as of December 31, 2002 and June 30, 2003 and our common share activity during the six months ended June 30, 2003:

On April 16, 2003, we announced a 4% increase in our common stock dividend, raising the quarterly dividend from $0.27 per share to $0.28 per share, for an indicated annual dividend of $1.12 per share. Our new quarterly dividend became effective with the June 1, 2003 dividend that we paid to our shareholders of record as of the close of business on May 16, 2003.

The following table depicts the 6.4 million shares of common stock issued and the average price received as a result of our equity offering and the average issuance price of our stock out of treasury shares, under ResourcesDirect, our direct stock purchase and dividend reinvestment plan; our Retirement Savings Plus Plan; our Long-Term Stock Incentive Plan; our Long-Term Incentive Plan; and our Directors Plan.

Other Income

Our other income consists of the following:

(1)

SouthStar Energy Services, LLC

(2)

US Propane, L.L.C.

Recent Accounting Developments

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149). This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS 133. Our adoption of SFAS 149 had no impact on our condensed consolidated financial statements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS 150). This statement revises the accounting for certain financial instruments that, under previous guidance, issuers could account for as equity in a “mezzanine” section of the balance sheet between debt and equity. We adopted the provisions of SFAS 150 effective March 31, 2003, which required us to classify our Trust Preferred Securities initially at fair value as long-term liabilities in our Condensed Consolidated Balance Sheet.

Financial Instruments, Derivatives and Hedging Activities

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) established accounting and reporting standards requiring that every derivative financial instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. However, if the derivative transaction qualifies for and is designated as a normal purchase and sale, it is exempted from the fair value accounting requirements of SFAS 133 and is accounted for using traditional accrual accounting.

SFAS 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, SFAS 133 allows a derivative's gains and losses to offset related results on the hedged item in the income statement in the case of a fair value hedge, or to record the gains and losses in other comprehensive income until maturity in the case of a cash flow hedge, and requires that a company formally designate a derivative as a hedge as well as document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting.

Interest Rate Swaps

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. We have entered into interest rate swap agreements through our wholly-owned subsidiary, AGL Capital Corporation (AGL Capital), for the purpose of hedging the interest rate risk associated with our fixed and variable rate debt obligations. As of June 30, 2003, a notional principal amount of $175.0 million of these agreements effectively converts the interest expense associated with a portion of our Senior Notes and Trust Preferred Securities from fixed rates to variable rates based on an interest rate equal to the London Interbank Offered Rate (LIBOR), plus a spread determined at the swap date. As of June 30, 2003, our interest rate swaps are:

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$100.0 million principal amount of our 7.125% Senior Notes due 2011, we pay floating interest each January 14 and July 14 at six-month LIBOR plus 3.4%. For the three and six months ended June 30, 2003, the effective variable interest rate was 4.7%. These interest rate swaps expire January 14, 2011, unless terminated earlier.

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$75.0 million principal amount of our 8.0% Trust Preferred Securities due 2041, we pay floating interest rates each February 15, May 15, August 15 and November 15 at three-month LIBOR plus 1.315%. The effective interest rate for the three months ended June 30, 2003 was 2.6% and for the six months ended June 30, 2003 was 2.7%. These interest rate swaps expire May 15, 2041, unless terminated earlier.

These interest rate swaps have been designated as fair value hedges as defined by SFAS 133, which allows us to designate derivatives that hedge a recognized asset’s or liability's exposure to changes in their fair value. We recognize the gain or loss on fair value hedges in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The effect of that accounting is to reflect in earnings only that portion of the hedge that is not effective in achieving offsetting changes in fair value.

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Our interest rate swaps meet the conditions required to assume no ineffectiveness under SFAS 133, and therefore, we have accounted for them using the "shortcut" method prescribed for fair value hedges by SFAS 133. Accordingly, we adjust the carrying value of each interest rate swap to its fair value each quarter, with an offsetting and equal adjustment to the carrying value of the debt securities whose fair value is being hedged. Consequently, our earnings are not affected negatively or positively with changes in fair value of the interest rate swaps each quarter. The aggregate fair value of these interest rate swaps at June 30, 2003 was $9.0 million and at December 31, 2002 was $6.1 million.

Derivative Instruments

We are exposed to risks associated with changes in the market price of natural gas. Through Sequent Energy Management, LP, (Sequent) we use derivative financial instruments to reduce our exposure to the risk of changes in the prices of natural gas as discussed below. Additionally, SouthStar manages a portion of its commodity price risks through hedging activities using derivative financial instruments and physical commodity contracts. The fair value of these derivative financial instruments reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of the financial instruments we utilize.

Under our risk management policy, we attempt to mitigate substantially all of our commodity price risk associated with Sequent’s storage gas portfolio to lock in the economic margin at the time we enter into gas purchase transactions for our storage gas. We purchase gas for storage when the difference in the current market price we pay to buy gas plus the cost to store the gas is less than the market price we could receive in the future, resulting in a positive net profit margin. We use contracts to sell gas at that future price to substantially lock-in the profit margin we will ultimately realize when the stored gas is actually sold. These contracts meet the definition of a derivative under SFAS 133. The purchase, storage and sale of natural gas 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 ne t income, even though the economic margin is essentially unchanged from when the transactions were consummated. We do not currently use hedge accounting under SFAS 133 to account for this activity.   

Gas that we purchase and inject into storage is accounted for at the lower of average cost or market as inventory in our condensed consolidated balance sheet, and is no longer marked to market following our implementation of the accounting guidance in EITF 02-03, which is discussed in greater detail later in this note. Under EITF 02-03 we would recognize a loss in any period when the market price for gas is lower than our carrying amount for our purchased gas inventory. Costs to store the gas are recognized in the period the costs are incurred. We recognize revenues and cost of gas sold in our condensed statements of consolidated income in the period we sell gas and it is delivered out of the storage facility. The derivatives we use to mitigate commodity price risk and to substantially lock in the margin upon sale of storage gas are accounted for at fair value and marked to market each period, with changes in fair value recognized as gains or losses in the period of change. This difference in accounting, the accrual basis for our storage gas inventory versus mark to market accounting for the derivatives used to mitigate commodity price risk, can result in volatility in our reported net income. Over time, gains or losses on the sale of storage gas inventory will be offset by losses or gains on the derivatives, resulting in our realization of the economic profit margin we expected when we entered into the transactions. This accounting difference causes Sequent’s earnings on its storage gas positions to be affected by natural gas price changes, even though the economic profits remain essentially unchanged.

Commodity-related activities of our wholesale services segment, which includes Sequent, are monitored by our Risk Management Committee, which is charged with the review and enforcement of our risk management policy. Our risk management policy limits our risk management activities to hedging against price volatility to protect profit margins. Our policy explicitly prohibits the use of speculative trading. We use the following derivative financial instruments and physical transactions to manage such risks:

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forward contracts;

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futures contracts;

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options contracts;

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price and basis swaps; and

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storage and transportation capacity transactions.

Our risk management policy limits the use of these derivative financial instruments and physical transactions to hedge only those price risks associated with:

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pre-existing or anticipated physical natural gas sales;

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pre-existing or anticipated physical natural gas purchases; and

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system use and storage

During 2002, our wholesale services segment accounted for transactions in connection with energy marketing and risk management activities under the fair value, or mark-to-market method of accounting, in accordance with SFAS 133 and with Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10).  Under these methods, we recorded energy commodity contracts, including both physical transactions and financial instruments, at fair value, and reflected unrealized gains and/or losses in earnings in the period of change.  

Effective January 1, 2003, we adopted  EITF Issue No. 02-03 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-03).  EITF 02-03 rescinded the provisions of EITF 98-10 and reached two general conclusions:

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contracts that do not meet the definition of a derivative under SFAS 133 should not be marked to fair market value; and

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revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled

We recorded the following as a result of our adoption of EITF 02-03:  

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adjusted the carrying value of our non-derivative trading instruments (principally storage capacity contracts) to zero and now account for them using the accrual method of accounting;

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adjusted the value of our natural gas inventories used in our wholesale services segment to the lower of average  cost or market, which were previously recorded at fair value. This resulted in a cumulative effect of a change in accounting principle in our condensed consolidated income statement of $12.6 million ($7.8 million net of taxes), that resulted in a decrease of $12.6 million to our energy marketing and risk management assets and a decrease to accumulated deferred income taxes of $4.8 million in our condensed consolidated balance sheets, and

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began reporting our trading activity on a net basis (revenues net of associated costs) effective July 1, 2002, and applied guidance from EITF 02-03 to all prior periods resulting in costs totaling approximately $435.9 million for the three months ended June 30, 2002 and $676.8 million for the six months ended June 30, 2002 being reclassified as a component of our revenues. This reclassification had no impact on our previously reported net income or shareholders’ equity

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Our derivative financial instruments have a weighted average maturity of one to three years, except for our interest rate swaps discussed earlier.  Our derivative financial instruments for the three months ended June 30, 2003 and six months ended June 30, 2003 represented purchases (long) of 179.8 billion cubic feet and 411.3 billion cubic feet and sales (short) of 200.5 billion cubic feet and 382.4 billion cubic feet.

We recorded unrealized losses of $3.6 million for the three months ended June 30, 2003 and unrealized gains of $1.1 million for the three months ended June 30, 2002 as a result of our energy marketing and risk management activities. Excluding the cumulative effect of a change in accounting principle, our unrealized gains during the six months ended June 30, 2003 were $6.0 million and we recorded unrealized losses of $1.0 million for the six months ended June 30, 2002.

The following table includes the fair values and average values of Sequent's energy marketing and risk management assets and liabilities at June 30, 2003. We based the average values on a monthly average for the three months ended and the six months ended June 30, 2003.

Concentration of Credit Risk

Concentration of credit risk occurs at AGLC, where costs for distribution operations are charged out and collected from both Georgia Public Service Commission (GPSC) Certificated Marketers (Marketers) selling retail natural gas in Georgia and poolers. For the six months ended June 30, 2003, the four largest Marketers based on customer count, one of which is our partially owned affiliate, accounted for approximately 55.1% of the Company’s and 61.5% of distribution operations' operating margin.

Several factors are designed to mitigate our risks from the increased concentration of credit that has resulted from deregulation. The provisions of AGLC's tariff allow AGLC to obtain credit support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from AGLC. In addition, AGLC bills intrastate delivery service to the Marketers in advance rather than in arrears. We accept credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers and corporate guarantees from investment grade entities. Our risk management committee reviews the adequacy of credit support coverage, credit rating profiles of credit support providers and payment status of each Marketer on a monthly basis. We believe that adequate policies and procedures have been put in place to properly quantify, manage and report on AGLC's credit risk exposure to Marketers.

Sequent, which provides services to Marketers, utility and industrial customers, also has a concentration of credit risk measured by 60-day receivable exposure. By this measure, Sequent’s top 20 counterparties represent approximately 76% of our total exposure of $242 million. All of Sequent’s counterparties are assigned internal ratings determined from the counterparty’s external ratings with Standard & Poor’s and Moody’s. The internal rating is multiplied by the counterparty’s credit exposure with Sequent and divided by our total counterparty credit exposure. As of June 30, 2003, Sequent’s counterparties or the counterparty’s guarantor have a weighted average Standard & Poor’s equivalent credit rating of BBB.

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2. Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our condensed consolidated balance sheets in accordance with SFAS 71, “Accounting for the Effects of Certain Types of Regulation,” excluding regulatory assets of approximately $1.0 million at Virginia Natural Gas (VNG), which are subject to reduction to the extent that VNG’s return on pro-forma equity exceeds 10% as included in VNG’s weather normalization adjustment program order. These regulatory assets are recoverable either through a rate rider or through base rates specifically authorized by a state commission. Our regulatory assets and liabilities, and associated liabilities for our unrecovered pipeline replacement program costs and unrecovered environmental response costs are summarized in the table below:

Pipeline Replacement

Atlanta Gas Light Company (AGLC) recorded a long-term liability of $364.5 million as of June 30, 2003 and $444.0 million as of December 31, 2002, which represent engineering estimates for remaining capital expenditure costs in the pipeline replacement program.  The pipeline replacement program represents an approved settlement between AGLC and the GPSC that detailed a 10-year replacement of 2,300 miles of cast iron and bare steel pipe. AGLC recovers the costs through a combination of a straight fixed variable rate design, which spreads AGLC’s delivery service revenue evenly throughout the year, and a pipeline replacement revenue rider. As of June 30, 2003, AGLC had recorded a current liability of $67.1 million representing expected pipeline replacement program expenditures for the next 12 months.

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Environmental Matters

Before natural gas was widely available in the Southeast AGLC or its predecessor companies manufactured gas from coal and other fuels. Those manufacturing facilities were known as manufactured gas plants (MGPs), which AGLC ceased operating in the 1950’s. AGLC identified 13 sites in Georgia and Florida where AGLC or its predecessors operated MGPs. In connection with these operations, AGLC is aware of the presence of coal tar and certain other by-products of the gas manufacturing process at or near some of these former sites. Based on investigations to date, AGLC believes that some cleanup is likely at most of these sites. AGLC has active environmental remediation or monitoring programs in effect at 11 sites in Georgia. There is no active remediation or monitoring program at two sites in Georgia.

As of June 30, 2003, our MGP remediation program was approximately 67% complete. Where the soil remediation is required at our Georgia sites, the work is targeted to be complete by January 2005. Two of the three sites in Florida are currently in the preliminary investigation or engineering design phase.

AGLC has historically reported estimates of future remediation costs for MGPs based on probabilistic models of potential costs. As cleanup options and plans mature and cleanup contracts are entered into, AGLC is increasingly able to provide conventional engineering estimates of the likely costs of many elements of its MGP program. These estimates contain various engineering uncertainties, and AGLC continuously attempts to refine and update these engineering estimates. In addition, AGLC continues to review technologies available for the cleanup of AGLC’s two largest sites, Savannah and Augusta, which, if proven, could have the effect of reducing AGLC’s total future expenditures.

Our last engineering estimate was as of March 31, 2003. This estimate projected costs associated with AGLC’s engineering estimates and in-place contracts to be $85.2 million. For those remaining elements of the MGP program where AGLC is unable to perform engineering cost estimates at the current state of investigation, there remains considerable variability in the estimates for future remediation costs. For these elements, the estimates for the remaining cost of future actions at the MGP sites range from $7.5 million to $28.2 million. AGLC cannot estimate any single number within this range as a better estimate of its likely future costs. As a result, AGLC accrued the lower end of the range, or $7.5 million for these remaining elements in our environmental response costs. Finally, AGLC has estimates of certain other costs related to administering the MGP program. Through January 2005, AGLC estimates those costs to be $2.6 million; at this time AGLC generally cannot estimate expenses beyond this period.

As of June 30, 2003 and December 31, 2002, AGLC’s environmental response cost liability is comprised of:

The environmental response cost liability is included in a corresponding regulatory asset. As of June 30, 2003, the regulatory asset was $179.1 million, which is a combination of the accrued environmental response costs and unrecovered cash expenditures. The liability does not include other potential expenses, such as unasserted property damage claims, personal injury or natural resource damage claims, unbudgeted legal expenses, or other costs for which AGLC may be held liable but with respect to which we cannot reasonably estimate the amount. The liability also does not include certain potential cost savings as described above.

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AGLC has two ways of recovering investigation and cleanup costs. First, the GPSC has approved an environmental response cost recovery rider. It allows the recovery of costs of investigation, testing, cleanup and litigation. Because of that rider, these actual and projected future costs related to investigation and cleanup to be recovered from customers in future years are included in our regulatory asset. During the three and six months ended June 30, 2003, AGLC recovered $5.5 million and $11.1 million through its environmental response cost recovery rider. The second way AGLC can recover costs is by exercising the legal rights AGLC believes it has to recover a share of its costs from other potentially responsible parties, typically former owners or operators of the MGP sites. There were no material recoveries from potentially responsible parties during the six months ended June 30, 2003.

The significant years for spending for this program are 2003 and 2004. The environmental response cost recovery mechanism allows for recovery of expenditures over a five-year period subsequent to the period in which the expenditures were incurred. As of June 30, 2003, the MGP expenditures expected to be incurred over the next twelve months are reflected as a current liability of $48.4 million. In addition, AGLC expects to collect $23.8 million in revenues over the next twelve months under the environmental response cost recovery rider, which is reflected as a current asset.

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3. Financing

(1)

The daily weighted average rate was 1.5% for the six months ended June 30, 2003 and 2.2% for the twelve months ended December 31, 2002.

(2)

On July 2, 2003, we issued $225.0 million in Senior Notes. The proceeds were used to repay approximately $110.0 million of commercial paper and $65.3 million of long-term debt. Additionally, we entered into interest rate swaps of $100.0 million to effectively convert a portion of the fixed rate obligation on the $225.0 million Senior Notes to variable rate obligations. For more information see Note 8, “Subsequent Events.”

(3)

The daily weighted average rate was 1.8% for the six months ended June 30, 2003 and 2.3% for the twelve months ended December 31, 2002.

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4. Commitments and Contingencies

The following table illustrates our expected future contractual cash obligations as of June 30, 2003.

In January 2003, the FASB released FASB Interpretation No. 45, “Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). For many of the guarantees or indemnification agreements we issue, FIN 45 requires disclosure of the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The table below illustrates our other expected commercial commitments that are outstanding as of June 30, 2003 and meet the disclosure criteria required by FIN 45.

Caroline Street Campus

We have entered into an agreement to sell our 34-acre Caroline Street campus, where the majority of our Atlanta-based employees were located prior to our move to Ten Peachtree Place, our new corporate headquarters. This transaction, previously expected to close no later than December 31, 2003 is now expected to close before September 30, 2003. We anticipate that, upon closing, the estimated net gain will be approximately $10.0 million.

Litigation

We are involved in litigation arising in the normal course of business. We believe the ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial position, results of operations and cash flows.

On July 1, 2003, the city of Augusta, Georgia served AGLC with a complaint that was filed in the Superior Court of Richmond County, Georgia against AGLC. Augusta’s allegations include fraud and deceit and damages to realty. The allegations arise from negotiations between the city and AGLC regarding our environmental cleanup obligations connected with AGLC’s former manufactured gas plant operations in Augusta. The city of Augusta seeks relief in the form of damages including an amount to be determined by a jury for the alleged fraud and deceit, together with attorney fees and punitive damages. We believe the claims asserted in this complaint are without merit, and we have remained in active settlement negotiations with the City. For more information about the manufactured gas plants and our environmental cleanup obligations, please see Item 1, Financial Statements, Note 2 “Regulatory Assets and Liabilities – Environmental Matters. 8;

5. Related Party Transactions

We recognized revenue and had accounts receivable from SouthStar of the following:

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6. Investments in Equity Interests

We use the equity method to account for our equity interests where we hold a 20% to 50% voting interest, unless control can be exercised over the entity. Under the equity method, our ownership interest in the entity is reported as an investment within our condensed consolidated balance sheets. Additionally, our percentage ownership in our equity interest’s earnings or losses is reported in our condensed statements of consolidated income under other income.

In January 2003, the FASB released FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). Companies with unconsolidated entities subject to FIN 46, or referred to as variable interest entities and issuing financial statements on or after January 31, 2003 are required to disclose the nature, purpose, size and activities of the variable interest entity as well as the company’s maximum exposure to a loss as a result of its involvement with the variable interest entity. FIN 46 separates unconsolidated entities, including special purpose entities and investments in equity interests and partnerships, into two categories:

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entities for which the consolidation decision should be based on voting interests; and

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entities for which the consolidation decision should be based on variable interests and therefore are subject to FIN 46.

We have determined that our consolidation decision should be based on voting interests in reporting our investments in equity interests in SouthStar and US Propane, L.L.C. (US Propane).

Our investment in US Propane did not have a material effect on our financial position, results of operations and cash flows for the three and six months ended June 30, 2003 and 2002. Our investment in SouthStar, in which we currently hold a non-controlling 70% financial interest, had a material effect on our financial position and results of operations for the three and six months ended June 30, of 2003 and 2002.  The unaudited amounts below represent 100% of the results of SouthStar. The results are not comparable with SouthStar’s earnings or losses reported as other income in our condensed consolidated statements of income, since those amounts are reported based on our percentage ownership. SouthStar’s net income from continuing operations and net income is equal as they do not incur income tax expenses.

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7. Segment Information

Our business is organized into three operating segments:

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Distribution operations consists of AGLC, VNG and Chattanooga Gas Company (CGC).

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Wholesale services consists primarily of Sequent.

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Energy investments consists of SouthStar, AGL Networks, LLC (AGL Networks), US Propane and several other nonregulated, energy-related subsidiaries.

We treat our corporate segment as a nonoperating business segment, which includes AGL Resources Inc., AGL Services Company, nonregulated financing and captive insurance subsidiaries, and the effect of intercompany eliminations. We eliminated intersegment sales for the three and six months ended June 30, 2003 and 2002 from our condensed consolidated statements of income.

Management evaluates segment performance based on a non-GAAP measure of earnings before interest and taxes (EBIT), which includes the effects of corporate expense allocations. Items that we do not include in EBIT are financing costs, including interest and debt expense, income taxes and the cumulative effect of change in accounting principle, each of which we evaluate on a consolidated level. We believe EBIT is a useful measurement of our performance for you 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 are directly relevant to the efficiency of those operations.

EBIT should not be considered an alternative to, or more meaningful an indicator of our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company.

The reconciliations of our EBIT to operating income and net income are presented below for the three and six months ended June 30, 2003 and 2002:

(1)

Identifiable assets are those assets used in each segment’s operations. Our corporate segment’s assets consist primarily of intercompany eliminations, cash and cash equivalents and property, plant and equipment.

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Includes intercompany eliminations.

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(1)

Intersegment revenues – We record our wholesale services segment’s energy marketing and risk management revenues on a net basis. The following table provides detail of our wholesale services segments’ total gross revenues and gross sales to our distribution operations segment:

(1)

Includes intercompany eliminations.

8. Subsequent Events

On July 2, 2003, AGL Capital issued $225.0 million in Senior Notes with a maturity date of April 15, 2013. The Senior Notes have an interest rate of 4.45% payable on April 15 and October 15 of each year, beginning October 15, 2003. Interest will accrue from July 2, 2003. On July 10, 2003, we exercised our option to redeem $65.3 million of Medium-Term notes at a call premium. These notes were scheduled to mature in 2013 and 2023 bearing various interest rates ranging from 7.5% to 8.25%. We used the net proceeds from the Senior Notes to repay these Medium-Term notes and approximately $110.0 million of short-term debt and for general corporate purposes.

Additionally, we entered into interest rate swaps of $100.0 million to effectively convert a portion of the fixed rate interest obligation on the $225.0 million in Senior Notes due 2013 to a variable rate obligation. We pay floating interest on the interest rate swaps on April 15 and October 15 at six month LIBOR plus 0.615%. These interest rate swaps expire April 15, 2013, unless terminated earlier, and have been designated as fair value hedges under SFAS 133.

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Our reports, filings and other public announcements often include statements reflecting assumptions, expectations, projections, intentions or beliefs about future events. These statements, which may relate to such matters as future earnings, growth, supply and demand, costs, subsidiary performance, new technologies and strategic initiatives, are "forward-looking statements" within the meaning of the federal securities laws. These statements do not relate strictly to historical or current facts, and you can identify certain of these statements, but not necessarily all, by the use of the words “anticipate,” “assume,” “indicate,” “estimate,” “believe,” “predict,” “forecast,” “rely,” “expect,” “continue,” “grow” and other words of similar meaning. Although we believe that the expectations and assumptions reflected in these statements are r easonable in view of the information currently available, we cannot assure you that these expectations will prove to be correct. These forward-looking statements involve a number of risks and uncertainties.  Actual results may differ materially from the results discussed in the forward-looking statements. Please reference our website at aglresources.com for current information. Our electronic filings with the Securities and Exchange Commission (SEC) are available at no cost on our website. In addition to the risks set forth in the prospectus supplement filed with the SEC on February 12, 2003 and incorporated herein by reference, the following are among the important factors that could cause actual results to differ materially from the forward-looking statements:

•

changes in industrial, commercial and residential growth in our service territories

•

changes in price, supply and demand for natural gas and related products

•

impact of changes in state and federal legislation and regulation, including orders of various state public service commissions and of the Federal Energy Regulatory Commission (FERC) on the gas and electric industries and on us, including AGLC’s performance-based rate plan (PBR)

•

the ultimate impact of the Sarbanes-Oxley Act of 2002 and any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically

•

the enactment of new accounting standards by the Financial Accounting Standards Board (FASB) or the SEC that could impact the way we record revenues, assets and liabilities, which could lead to impacts on reported earnings or increases in liabilities, which in turn could affect our reported results of operations

•

market changes due to Georgia’s Natural Gas Consumers’ Relief Act of 2002

•

effects and uncertainties of deregulation and competition, particularly in markets where prices and providers historically have been regulated, unknown issues following deregulation such as the stability of Georgia Public Service Commission (GPSC) Certificated Marketers (Marketers) selling natural gas in Georgia and unknown risks related to nonregulated businesses, including risks related to energy marketing and risk management

•

concentration of credit risk in Marketers and our wholesale services  segment’s counterparties

•

excess high-speed network capacity, and demand for dark fiber in metro network areas

•

market acceptance of new technologies and products, as well as the adoption of new networking standards

•

our ability to negotiate new fiber optic contracts with telecommunications providers for the provision of AGL Networks' dark fiber services

•

utility and energy industry consolidation

•

performance of equity and bond markets and the impact on pension and post-retirement funding costs

•

impact of acquisitions and divestitures

•

direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit rating or the credit rating of our counterparties or competitors

•

interest rate fluctuations, financial market conditions and general economic conditions

•

uncertainties about environmental issues and the related impact of such issues

•

impact of changes in weather upon the temperature-sensitive portions of our business

•

impact of litigation

•

impact of changes in prices on the margins achievable in the unregulated retail gas marketing business

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Overview

We are an energy services holding company, headquartered in Atlanta, Georgia, whose principal business is the distribution of natural gas in Georgia, Virginia and Tennessee.  We operate three utilities, which combined, serve approximately 1.8 million end-users, making us the largest gas utility in the southeastern United States, and the second-largest pure gas distribution utility in the United States.  We are also involved in various non-utility businesses, including natural gas asset management and producer services; last-mile telecommunications infrastructure; retail gas marketing; and propane services.   We manage our business in three operating segments: distribution operations, wholesale services and energy investments and one nonoperating segment: corporate.

We are focused on a business strategy centered around effective management of our gas distribution operations, optimization of returns on our assets, and selective growth of our portfolio of closely related, unregulated businesses with an emphasis on risk management and earnings visibility.  

Highlights

•

For the three months ended June 30, 2003, our net income was $18.9 million or $0.29 per diluted common share, an increase of $6.6 million or $0.07 per diluted common share for the same period last year.

•

For the six months ended June 30, 2003, our net income was $70.7 million or $1.13 per diluted common share, an increase of $8.3 million or $0.02 per diluted common share for the same period last year. Our income before cumulative effect of change in accounting principle increased $16.1 million or $0.15 per diluted common share.

•

On April 16, 2003, we increased our dividends from $0.27 to $0.28 per common share, or an indicated annual rate of $1.12 per common share. The new quarterly dividend was paid June 1, 2003, to our shareholders of record as of the close of business May 16, 2003.

•

On June 5, 2003, our market price per share reached an all-time high of $26.98 per share an 11.0% increase from our year-end closing price.

•

On June 16, 2003, we renewed until June 16, 2004 our $200.0 million 364-Day Credit Facility with a one year term-out option that was scheduled to expire on August 7, 2003.

•

On July 2, 2003, AGL Capital Corporation issued $225 million in Senior Notes at an interest rate of 4.45%. We used the net proceeds to repay approximately $110.0 million of short-term debt and $65.3 million of long-term debt, as well as for general corporate purposes. Additionally we entered into interest rate swaps of $100.0 million to effectively convert a portion of the fixed-rate obligation on these Senior Notes to variable rate obligation at an effective interest rate at six month LIBOR plus 0.615%.

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Results of Operations

Our management evaluates segment performance based on Earnings Before Interest and Taxes (EBIT), which includes the effects of corporate expense allocations. Items that are not included in EBIT are financing costs, including interest and debt expense, income taxes and the cumulative effect of changes in accounting principle. We evaluate each of these items on a consolidated level. We believe EBIT is a useful measurement of our performance for you 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 are directly relevant to the efficiency of those operations.

You should not consider EBIT an alternative to, or a more meaningful indicator of our operating performance than operating income or net income as determined in accordance with accounting principles generally accepted in the United States of America (GAAP). In addition, our EBIT may not be comparable to a similarly titled measure of another company. The following is a reconciliation of our operating results to EBIT for the three and six months ended June 30, 2003 and 2002:

As a result of our equity issuance on February 14, 2003, we experienced a dilution of our basic and diluted earnings per share of approximately $0.03 for the three months ended June 30, 2003 and $0.09 per share for the six months ended June 30, 2003. This was primarily due to our issuance of an additional 6.4 million shares partially offset by a decrease of $0.3 million in interest expense, net of income taxes, for the three months ended June 30, 2003 and $0.4 million, net of income taxes, for the six months ended June 30, 2003.

Results of Operations

Below are the results of our segments operations as measured by EBIT, for the three and six months ended June 30, 2003 and 2002:

Income Taxes

The increase in our income tax expense of $5.4 million for the three months ended June 30, 2003 as compared to the three months ended June 30, 2002 was due primarily to the increase in earnings before income taxes of $12.0 million and the increase in our effective tax rate from 35.3% in 2002 to 39.0% in 2003. The increase in the effective tax rate was primarily due to higher projected state income taxes.

The increase in income tax expense of $16.0 million for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002 was due primarily to the increase in earnings before income taxes of $32.1 million and an increase in our effective tax rate from 35.4% in 2002 to 39.0% in 2003. The increase in the effective tax rate was primarily due to higher projected state income taxes.

Interest Expense and Preferred Securities Dividends

(1)

Includes Trust Preferred Securities

The decrease in our interest expense of $3.0 million and $5.8 million for the three and six months ended June 30, 2003 as compared to the same periods last year was a result of lower average debt balances due to the proceeds generated from the equity offering and lower working capital needs partially offset by higher average rates.

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Distribution Operations

Our distribution operations segment includes the results of operations and financial condition of our three natural gas local distribution companies: Atlanta Gas Light Company (AGLC), Virginia Natural Gas (VNG) and Chattanooga Gas Company (CGC).

•

AGLC is a natural gas local distribution utility with distribution systems and related facilities serving 237 cities throughout Georgia, including Atlanta, Athens, Augusta, Brunswick, Macon, Rome, Savannah and Valdosta. AGLC has approximately 6.0 billion cubic feet or Bcf, of liquefied natural gas (LNG) storage capacity in three LNG plants to supplement the supply of natural gas during peak usage periods.

•

VNG is a natural gas local distribution utility with distribution systems and related facilities serving 8 cities in the Hampton Roads region of southeastern Virginia. VNG owns and operates approximately 155 miles of a separate high-pressure pipeline that provides delivery of gas to customers under firm transportation agreements within the state of Virginia. VNG also has approximately 5.0 million gallons of propane storage capacity in its two propane facilities to supplement the supply of natural gas during peak usage periods.

•

CGC is a natural gas local distribution utility with distribution systems and related facilities serving 12 cities and surrounding areas, including the Chattanooga and Cleveland areas of Tennessee. CGC also has approximately 1.2 Bcf of LNG storage capacity in its LNG plant.

The Georgia Public Service Commission (GPSC) regulates AGLC; the Virginia State Corporation Commission (VSCC) regulates VNG; and the Tennessee Regulatory Authority (TRA) regulates CGC, with respect to rates, maintenance of accounting records and various other service and safety matters.

The results of operations of our distribution operations segment are as follows:

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The decrease in EBIT of $3.6 million for the three months ended June 30, 2003 as compared to the three months ended June 30, 2002 was due to:

•

an increase in operating margin of $0.5 million primarily as a result of :

•

a $1.5 million increase in VNG’s margin caused by higher usage per degree day and increased customer growth.

•

a $0.4 million decrease in AGLC’s margin primarily due to:

•

a $1.8 million increase in pipeline replacement program rider revenue

•

a $0.8 million decrease from the performance based rate settlement with the GPSC that was effective beginning May 1, 2002

•

a $0.8 million decrease due to lower carrying charges on natural gas stored underground on behalf of AGLC’s Marketers, and

•

$0.6 million decrease in other service revenues.

•

a $0.5 million decrease in CGC’s margin due primarily to a decrease in industrial volumes, and

•

an increase in operation and maintenance expenses of $4.1 million due to higher service company overhead and increased bad debt expenses resulting from higher revenue.

The increase in EBIT of $5.9 million for six months ended June 30, 2003 as compared to the six months ended June 30, 2002 was due to:

•

an increase in operating margin of $7.0 million which was primarily a result of:

•

a $10.4 million increase in VNG’s operating margin caused primarily by the effects of WNA and warmer than normal weather in 2002, higher usage per degree day and an increase in customer growth.

•

a $2.9 million decrease in AGLC’s operating margin caused primarily by:

•

a $3.3 million decrease from the performance based rate settlement with the GPSC

•

a $2.2 million decrease due to lower carrying charges on natural gas stored underground on behalf of Marketers.

•

a $1.6 million decrease in services fees and other revenues; these decreases were offset by

•

a $3.2 million increase in pipeline replacement program rider revenue and

•

a $1.0 million increase resulting from customer growth.

•

a $0.5 million decrease in CGC operating margin caused primarily by a decrease in industrial volumes.

•

higher operation and maintenance expenses of $2.2 million due to higher service company overhead  and increased bad debt expenses, and

•

a decrease in depreciation expense of $1.6 million due to a change in AGLC’s depreciation rates resulting from the performance based rate settlement with the GPSC.

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Wholesale Services

Our wholesale services segment includes the results of operations and financial condition of Sequent Energy Management, LP (Sequent), our asset optimization, gas supply services, and wholesale marketing and risk management subsidiary. Our asset optimization activities focus on capturing the value from idle or underutilized natural gas assets, typically by participating in transactions that balance the needs of varying markets and time horizons. These assets include rights to pipeline capacity, underground storage, and natural gas peaking services and facilities. Sequent also aggregates gas from other marketers and producers and sells it to third parties. In addition, Sequent bundles this commodity with transportation and storage service and redelivers short-term and long-term transported commodity.

Although Sequent is a nonregulated business, under varying agreements, Sequent acts as asset manager for our regulated utilities. In its capacity as asset manager, Sequent captures value from idle or underutilized assets of our utilities by arbitraging price differentials across different locations and over time. We worked with each of our state regulatory commissions to clarify Sequent’s role as asset manager for our regulated utilities, and have reached the following agreements:  

•

In November 2000, the VSCC approved an asset management agreement, which provides for a sharing of profits between Sequent and VNG's customers.  

•

In June 2003, CGC’s tariff was amended effective January 1, 2003 to require all net margin earned from CGC assets to be shared equally with CGC ratepayers.

•

Various Georgia statutes require Sequent, as asset manager for AGLC, to share 90% of its earnings from capacity release transactions with Georgia's Universal Service Fund (USF).  Sequent is also required by a December 2002 GPSC order to equally share net margin earned by Sequent, for transactions involving AGLC assets, other than capacity release, with Georgia’s USF.

During 2002, our wholesale services segment accounted for transactions in connection with energy marketing  in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) and accounted for risk management activities in accordance with Emerging Issues Task Force (EITF) Issue No. 98-10 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10).  Under these methods, we recorded energy commodity contracts, including both physical transactions and financial instruments at fair value, with unrealized gains and/or losses reflected in our earnings in the period of change.  

Effective January 1, 2003, we adopted EITF Issue No. 02-03, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-03).  EITF 02-03 rescinded EITF 98-10 and reached two general conclusions:

•

contracts that do not meet the definition of a derivative under SFAS 133 should not be marked to fair market value, and

•

revenues should be shown in the income statement net of costs associated with trading activities, whether or not the trades are physically settled.

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We recorded the following as a result of our adoption of EITF 02-03 we:

•

adjusted the carrying value of our non-derivative trading instruments (principally our storage capacity contracts) to zero and now account for them using the accrual method of accounting;  

•

adjusted the value of our natural gas inventories used in our wholesale services segment to the lower of average cost or market, which were previously recorded at fair value. This resulted in a cumulative effect of change in accounting principle in our condensed consolidated statements of income for the three months ended March 31, 2003 of $12.6 million ($7.8 million net of taxes), that resulted in a decrease of $12.6 million to energy marketing and risk management assets and a decrease in accumulated deferred income taxes of $4.8 million in our accompanying condensed consolidated balance sheets, and

•

began reporting our trading activity on a net basis (revenues net of costs) effective July 1, 2002, as a result of consensus one of EITF 02-03. We applied this guidance to all periods, resulting in costs totaling approximately $435.9 million for the three months ended June 30, 2002 and $676.8 million for the six months ended June 30, 2002 being reclassified as a component of revenues. This reclassification had no impact on our previously reported net income or shareholders’ equity

The results of operations for our wholesale services segment are as follows:

(1)

New York Mercantile Exchange, Inc.

(2)

The average settlement of the April through June and January through June futures contracts for each year, respectively.

The increase in EBIT of $2.7 million for the three months ended June 30, 2003 as compared to the three months ended June 30, 2002 was primarily due to a 27% increase in volume sold as a result of Sequent’s efforts to gain additional new business with local distribution companies, electric utilities and large industrial customers as well as an increase in the purchase of direct gas supply from producers. This was offset by an increase in operation and maintenance expenses resulting from the increased staffing levels required to support the growth in our business.

Sequent recorded unrealized losses of $3.6 million during the three months ended June 30, 2003, and unrealized gains of $1.1 million during the three months ended June 30, 2002 related to derivative instruments as a result of energy marketing and risk management activities.

The increase in EBIT of $17.5 million for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002 was primarily due to the items mentioned above, along with optimization of various transportation and storage assets that Sequent utilized, mainly in the first quarter when natural gas prices were highly volatile. Also, during the three months ended March 31, 2003, Sequent sold substantially all of its entire inventory, which was previously recorded on a mark-to-market basis under the now rescinded EITF 98-10. This resulted in $12.6 million in realized income, offset by sharing with our affiliated local distribution companies, for transactions that were recorded on a mark-to-market basis in prior periods.  

Sequent’s physical sales volumes for the six months ended June 30, 2003 increased 50% as compared to the same period last year. This increase is attributable to Sequent’s successful efforts to gain additional new business as detailed above. Additionally, a number of market factors, including colder temperatures in market areas served by Sequent, coupled with reduced amounts of gas in storage as the winter progressed, resulted in increased volatility in Sequent’s markets. The volatility in natural gas market prices as compared to the first quarter of 2003 has decreased by over 50%. Although actual prices continue to trade in a higher range as compared to the average price of the last several years, the volatility in the second quarter has declined to approximately the 2002 calendar year average.

Sequent recorded unrealized gains of $6.0 million, excluding the cumulative effect of change in accounting principle during the six months ended June 30, 2003, and unrealized losses of $1.0 million during the six months ended June 30, 2002 related to derivative instruments as a result of energy marketing and risk management activities.

We recorded the derivative instruments that Sequent utilized in its energy marketing and risk management activities on a mark-to-market basis in both the three and six months ended June 30, of 2003 and 2002. We also recorded energy-trading contracts as defined under EITF 98-10 on a mark-to-market basis for the six months ended June 30, 2002. The tables below illustrate the change in the net fair value of the derivative instruments and energy-trading contracts during the three and six months ended June 30, 2003 and 2002, as well as provides details of the net fair value of contracts outstanding as of June 30, 2003. Sequent’s storage positions are affected by price sensitivity in the NYMEX average price.

The "prices actively quoted" category represents Sequent’s positions in natural gas, which are valued using a combination of NYMEX futures prices and basis spreads. The basis spreads represent the cost to transport the commodity from a NYMEX delivery point such as Henry Hub to the contract delivery point. Our basis spreads are based on broker quotes obtained either directly or through electronic trading platforms.

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Energy Investments

Our energy investments segment includes our investments in SouthStar Energy Services, LLC (SouthStar) and US Propane L.L.C. (US Propane) as well as the results of operations and financial condition of AGL Networks LLC (AGL Networks).

•

SouthStar is a joint venture formed in 1998 by subsidiaries of AGL Resources, Piedmont Natural Gas Company (Piedmont) and Dynegy Inc. (Dynegy) to market natural gas and related services to retail customers, principally in Georgia. SouthStar is the largest retail marketer of natural gas in Georgia with a market share of 38% and operates under the trade name Georgia Natural Gas. Initially, our subsidiary owned a 50% interest, Piedmont’s subsidiary owned a 30% interest and Dynegy’s subsidiary owned the remaining 20% in SouthStar. On January 24, 2003, we announced that our wholly owned subsidiary, Georgia Natural Gas Company, reached an agreement to purchase Dynegy’s 20% ownership interest of SouthStar. The transaction closed March 11, 2003 and for accounting purposes had an effective date of February 18, 2003. Upon closing, our subsidiary owned a non-controlling 70% financial interest in SouthStar and Piedmon t’s subsidiary owned the remaining 30%. Although we own 70% of SouthStar, we do not have a controlling interest as matters of significance require the unanimous vote of Piedmont’s representative and our representative to the governing board of SouthStar.

SouthStar’s operating policy contains a provision for the disproportionate sharing of earnings between Piedmont and us when SouthStar’s annual earnings before taxes are above an annual threshold. The annual threshold is calculated each year based on a cumulative and annual 17% return on contributed capital. SouthStar’s operating policy requires that earnings above the threshold be allocated at various percentages based on actual margin generated in the four defined service areas of the operating policy, and distributed annually to each owner as a mandatory distribution.  Disproportionate sharing is only applicable to our original 50% financial interest in SouthStar.

We estimate that SouthStar’s earnings before taxes for the twelve months ended December 31, 2002, 2001 and 2000 were above the threshold. We estimate our increased portion of SouthStar’s equity earnings, previously attributed to Piedmont, for the twelve months ended December 31, 2002 to be $2.3 million to $4.4 million pre-tax. This reflects our estimate that our actual earnings from SouthStar were at a level of approximately 55.7% to 60.7% of total earnings, rather than our equity ownership of 50% of total earnings. We estimate our increased portion of equity earnings from SouthStar for the twelve months ending December 31, 2001 and 2000 to be up to $2.6 million pre-tax. Because the partners have not historically agreed on the annual earnings threshold, no disproportionate distributions have occurred to date.

Our estimated increased portion of equity earnings for the twelve months ended December 31, 2002 is based on our interpretation of SouthStar’s operating policy. Because the estimate is still subject to change we will not record our increased portion of equity earnings until our increased portion of equity earnings is received. The earnings test is based on SouthStar’s fiscal year ending December 31. Therefore, we have estimated the disproportionate sharing only through December 31, 2002, however, based on current estimates we expect that disproportionate sharing on our original 50% interest in SouthStar will occur again in 2003.

•

US Propane is a joint venture formed in 2000 by subsidiaries of AGL Resources, Atmos Energy Corporation, Piedmont Natural Gas Company and TECO Energy, Inc. We own 22.36% of the limited partnership interest in US Propane. US Propane owns all of the general partnership interests, directly or indirectly, and approximately 25% of the limited partnership interests in Heritage, a publicly traded marketer of propane. Heritage is the fourth largest retail marketer of propane in the United States, delivering approximately 350 million gallons per year to approximately 650,000 customers in 29 states.

•

AGL Networks, our wholly owned subsidiary, is a carrier-neutral provider of last-mile infrastructure and dark fiber solutions to a variety of customers in the Atlanta, Georgia and Phoenix, Arizona metropolitan areas. Its customers include local, regional and national telecommunication companies, wireless service providers, educational institutions and other commercial entities. AGL Networks typically provides conduit and dark fiber to its customers under long-term lease arrangements with terms that vary from three to twenty years. In addition to conduit and dark fiber leasing, AGL Networks also provides turnkey telecommunications network construction services.

The results of operations for our energy investments segment are as follows:

The increase in EBIT of $9.9 million for the three months ended June 30, 2003 as compared to the three months ended June 30, 2002 was due to:

•

a $10.3 million increase in other income from SouthStar, primarily as a result of increased volume on a per customer basis and an increase in our ownership from 50% to 70%, this was offset by

•

a $1.0 million decrease in EBIT from AGL Networks, resulting from increased operating expenses due to additional personnel necessary to support business growth, partially offset by an increase in monthly recurring contract revenues.

The increase in EBIT of $1.3 million for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002 was due to:

•

a $0.6 million increase in EBIT from AGL Networks that reflects an increase in monthly recurring contract revenues of $1.2 million and $2.3 million from a sales-type lease which were partially offset by increased operating expenses of $2.5 million due to additional personnel necessary to support business growth.

•

a $1.0 million increase in other income from US Propane due to colder than normal weather, offset by

•

a $1.1 million decrease in other income from SouthStar, primarily as a result of lower margins from higher gas prices in the first quarter of 2003 and a $7.0 million inventory adjustment recorded in the first quarter of 2002, offset by increased volume on a per customer basis in the second quarter of 2003, lower bad debt and customer care expense and an increase from our ownership from 50% to 70% effective in mid-February 2003.

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Corporate

Our corporate segment includes the results of operations and financial condition of our nonoperating business units, including AGL Services Company and AGL Capital Corporation (AGL Capital). AGL Services Company 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. We allocate AGL Services Company’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.

The results of operations for our corporate segment are as follows:

The increase in EBIT of $1.6 million for the six months ended June 30, 2003 as compared to the six months ended June 30, 2002 was due to prior year accrued expenses that were not allocated.

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Liquidity and Capital Resources

We rely upon operating cash flow along with borrowings under our commercial paper program, which are backed by our supporting credit agreement, or our Credit Facility, for our short-term liquidity and capital resource requirements. Our availability of borrowings under the Credit Facility is subject to conditions specified within the Credit Facility, which we currently meet. These conditions include our compliance with the financial covenants required by the Credit Facility and the continued accuracy of representations and warranties contained in the agreements.

We believe our operating cash flow, borrowings from the commercial paper program and other credit availability will be sufficient to meet our working capital needs. We may seek additional financing through debt or equity offerings in the private or public markets at any time. Although we currently have no borrowings outstanding under our Credit Facility, unused availability is limited by our total debt to capital ratios, as represented in the following table.

As a result of our equity offering and increased operating cash flow, our total cash and available liquidity under our Credit Facility at June 30, 2003 increased $250.9 million from December 31, 2002. As of June 30, 2003 Sequent’s unsecured line of credit had approximately $7.5 million available for the posting of margin deposits.

Our cash from operations, credit capacity and the amount of our unused borrowing capacity may change in the future due to a number of factors, some of which we cannot control. These factors include:

•

The seasonal nature of the natural gas business and our short-term borrowing requirements that typically peak during colder months;

•

Increased gas supplies required to meet our customers’ needs during cold weather;

•

Regulatory changes;

•

Changes in the wholesale prices and our customers’ demand for our products and services;

•

Margin requirements resulting from significant increases or decreases in our commodity prices; and

•

Operational risks.

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Cash Flows

Our cash and cash equivalents were $3.3 million as of June 30, 2003, a decrease of $5.1 million from December 31, 2002. As of June 30, 2002, our cash and cash equivalents were $4.3 million, a decrease of $3.0 million from December 31, 2001. Our principal sources and uses of cash during the six months ended June 30, 2003 and six months ended June 30, 2002 are summarized below.

Six Months Ended June 30, 2003:

Sources

•

We generated $204.7 million in cash, primarily through cash from our operations, plus decreases in our receivables and increases in our payables. This was offset by increases in our inventories

•

We received $136.7 million from our equity offering

•

We received $10.0 million from our sale of treasury stock

•

We received $7.0 million from our investments in equity  interests

•

We received $6.6 million from our other investing and financing activities

Uses

•

We paid $241.1 million (net of borrowings) to reduce our outstanding short-term debt from the commercial paper program

•

We invested $77.2 million in property, plant and equipment

•

We invested $20.0 million in our investments in equity interests

•

We paid $31.8 million in cash dividends on our common stock

Six Months Ended June 30, 2002:

Sources

•

We generated $201.3 million in cash, primarily through cash from our operations, plus increases in payables and decreases in inventories. This was offset by increases in receivables

•

We received $9.9 million from our sale of treasury stock

•

We received $4.1 million from our investments in equity interests

•

We received $0.7 million from our other investing and financing activities

Uses

•

We invested $87.4 million in property, plant and equipment

•

We paid $60.2 million (net of borrowings) to reduce our outstanding short-term debt from the commercial paper program

•

We paid $45.0 million in scheduled payments on our Medium-Term notes

•

We paid $26.4 million in cash dividends on our common stock

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Financing

 Ratios Our Credit Facility financial covenants and PUHCA require us to maintain a ratio of total debt to total capitalization of no greater than 70.0%. As of June 30, 2003, we were in compliance with this leverage ratio requirement.  The components of our capital structure, as of the dates indicated, are summarized in the following table.

(1)

Net of interest rate swaps of $2.3 million as of June 30, 2003.

(2)

Net of interest rate swaps of $6.7 million, $6.1 million, and ($0.1) million respectively.

Short-term Debt. Our short-term debt is comprised of borrowings under our commercial paper program and Sequent’s line of credit. The commercial paper program is supported by our Credit Facility which consists of:  

•

a $200 million 364-day Credit Facility with a one year term-out option that was originally scheduled to expire on August 7, 2003 but was renewed until June 16, 2004.

•

a $300 million 3 year Credit Facility that terminates on August 7, 2005.

As of July 25, 2003, we had no outstanding borrowings under the Credit Facility. The following table provides details on AGL Capital’s commercial paper program.

Sequent has a $15.0 million unsecured line of credit, which is used solely for the posting of margin deposits and is unconditionally guaranteed by AGL Resources. This line of credit was renewed on July 3, 2003, expires on July 2, 2004, and bears interest at the federal funds effective rate plus 0.5%. As of June 30, 2003, the line of credit had an outstanding balance of $7.5 million. The following table provides details on Sequent’s line of credit.

Long-term Debt. We have $30.0 million in scheduled Medium-Term note payments due in October 2003, with an interest rate of 5.90%. We expect to utilize the availability of working capital and liquidity under the commercial paper program to fund these scheduled payments. During the six months ended June 30, 2003, we did not issue any long-term debt.

On April 1, 2003, we exercised our option to call at par two Medium-Term notes totaling $7.2 million before their scheduled maturity dates. A note of $5.0 million bearing interest of 7.4% was scheduled to mature in March 2013, and a note of $2.2 million bearing interest of 7.5% was scheduled to mature in March 2014. We redeemed these notes using proceeds from the issuance of commercial paper.

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On July 2, 2003, we issued $225.0 million in Senior Notes due April 15, 2013. The Senior Notes have an interest rate of 4.45% payable on April 15 and October 15 of each year, beginning October 15, 2003. Interest will accrue from July 2, 2003. We used the net proceeds from the Senior Notes to repay $65.3 million of our Medium-Term notes, discussed below, and approximately $110.0 million of short-term debt and for general corporate purposes.

On July 2, 2003, we also entered into interest rate swaps of $100.0 million to effectively convert $100 million of the fixed rate obligation on the $225.0 million in Senior Notes due 2013 issued on July 2, 2003, to variable rate obligations. We pay floating interest on the interest rate swaps on April 15 and October 15 at six month LIBOR plus 0.615%. These interest rate swaps expire April 15, 2013, unless terminated earlier and we have designated the swaps as fair value hedges under SFAS 133.

On July 10, 2003, we exercised our option to redeem $65.3 million of Medium-Term notes at a call premium. These notes were scheduled to mature in 2013 and 2023 bearing various interest rates ranging from 7.5% to 8.25%.

Interest Rate Swaps. For a discussion of our interest rate swaps, see Item 1, Financial Statements, Note 1 “Significant Accounting Policies” which is incorporated herein by reference.  

Available Capacity Under Shelf Registration.  We have a shelf registration statement registered with the SEC for up to $750 million of various capital securities. Including the effect of the recent equity and Senior Note offerings, as of July 25, 2003, we had approximately $383 million remaining capacity under this shelf registration statement.

Credit Rating.  Credit ratings impact our ability to obtain short-term and long-term financing and the cost of such financing. In determining our credit ratings, the rating agencies consider a number of factors. Quantitative factors that appear to be given significant weight include, among other things:

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earnings before interest, taxes, depreciation and amortization

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operating cash flow

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total debt outstanding

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total equity outstanding

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pension liabilities and funding status

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other commitments

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fixed charges such as interest expense, rent or lease payments

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payments to preferred stockholders

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liquidity needs and availability

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potential legislation on deregulation

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total debt to total capitalization ratios

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various ratios calculated from these factors

Qualitative factors appear to include, among other things, stability of regulation in each jurisdiction, risks and controls inherent with wholesale services, predictability of cash flows, business strategy, management, industry position and contingencies.

Our credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization and you should evaluate each rating independently of any other rating. We cannot assure you 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. For the six months ended June 30, 2003 no fundamental adverse shift occurred in our business or ratings profile.

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The following table presents, as of July 25, 2003, the credit ratings on our unsecured debt issues from the three major rating agencies. The ratings are all investment-grade status and the outlooks for all credit ratings are stable.

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:

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A maximum leverage ratio.

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Minimum net worth.

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Insolvency events and nonpayment of scheduled principal or interest payments.

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Acceleration of other financial obligations.

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Change of control provisions.

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 requires us to issue equity based on credit rating or other trigger events. We are currently in compliance with all existing debt provisions.

Sequent has certain trade and/or credit contracts that have explicit credit rating trigger events in case of a credit rating downgrade. These rating triggers typically would give counterparties the right to suspend or terminate credit if our credit ratings were 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 was not posted, our ability to continue transacting business with these counterparties would be impaired. At June 30, 2003, such agreements between Sequent and its counterparties totaled $12 million. We believe the existing cash and available liquidity under our Credit Facility is adequate to fund these potential liquidity requirements.

Capital Requirements

Environmental Matters

We expect the manufactured gas plants remediation program to be complete with respect to the significant cleanup by January 2005. The significant years for spending for this program are 2003 and 2004. The remaining liability for the environmental response cost program as of June 30, 2003 is estimated to be $85.9 million.

For a discussion on our contractual cash obligations and other commercial commitments, see Item 1, Financial Statements, Note 4 “Commitments and Contingencies” which is incorporated herein by reference.

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Critical Accounting Policies

The selection and application of critical accounting policies is an important process that has progressed as our business activities have evolved and as a result of new accounting pronouncements. Accounting rules generally do not involve a selection among alternatives, but rather involve an implementation and interpretation of existing rules and the use of judgment as to the specific set of circumstances existing in our business. Each of the critical accounting policies involves complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements.

Regulatory Accounting

We account for transactions within our distribution operations segment according to the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation.” Applying this accounting policy allows us to defer expenses and income in the consolidated balance sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the statements of consolidated income of an unregulated company. We then recognize these deferred regulatory assets and liabilities in our statement of consolidated income in the period in which we reflect the same amounts in rates.

If any portion of our distribution operations segment ceased to continue to meet the criteria for application of regulatory accounting treatment for all or part of its operations, we would eliminate the regulatory assets and liabilities related to those portions ceasing to meet such criteria from our consolidated balance sheet and include them in our statement of consolidated income for the period in which the discontinuance of regulatory accounting treatment occurred.

Pipeline Replacement

AGLC has recorded a long-term liability of $364.5 million as of June 30, 2003 and $444.0 million as of December 31, 2002, that represent engineering estimates for remaining capital expenditure costs in the pipeline replacement program (PRP).  The PRP represents an approved settlement between AGLC and the staff of the GPSC that details a 10-year replacement of 2,300 miles of cast iron and bare steel pipe. We recover the costs through a combination of a straight fixed variable rate that spreads AGLC’s delivery service revenue evenly throughout the year and a pipeline replacement revenue rider. As of June 30, 2003, AGLC had recorded a current liability of $67.1 million representing the expected expenditures of the program for the next 12 months.

Environmental Matters

AGLC historically reported estimates of future remediation costs based on probabilistic models of potential costs. As we continue to develop cleanup options and plans and we continue to enter cleanup contracts, AGLC is increasingly able to provide conventional engineering estimates of the likely costs of many elements of its manufactured gas plant (MGP) program. These estimates contain various engineering uncertainties, and AGLC continuously attempts to refine and update these engineering estimates.

In addition, AGLC continues to review technologies available for the cleanup of AGLC’s two largest sites, Savannah and Augusta, which, if proven, could have the effect of reducing AGLC’s total future expenditures. Our latest estimate, as of March 31, 2003, projects costs associated with AGLC’s engineering estimates and in-place contracts to be $85.2 million. For those remaining elements of the MGP program where AGLC still cannot perform engineering cost estimates, there remains considerable variability in available future cost estimates. For these elements, the remaining cost of future actions at the MGP sites is $7.5 million to $28.2 million. AGLC cannot estimate any single number within this range as a better estimate of its likely future costs. As a result, AGLC accrued the lower end of the range of $7.5 million for these remaining elements in our environmental response costs. Finally, AGLC has estimates of certain other costs paid dir ectly by AGLC related to administering the MGP program. Through January 2005, AGLC estimates those costs to be $2.6 million; at this time AGLC generally cannot estimate expenses beyond this period. Consequently, as of June 30, 2003 and December 31, 2002,

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AGLC’s environmental response cost liability is comprised of:

The environmental response cost liability is included in a corresponding regulatory asset. As of June 30, 2003, the regulatory asset was $179.1 million, which is a combination of the accrued environmental response costs and unrecovered cash expenditures. AGLC’s estimate does not include other potential expenses, such as unasserted property damage, personal injury or natural resource damage claims, unbudgeted legal expenses, or other costs for which AGLC may be held liable but with respect to which the amount cannot be reasonably forecast. AGLC’s estimate also does not include certain potential cost savings as described above.

Revenue Recognition

Distribution Operations

VNG and CGC employ rate structures that include volumetric rate designs that allow recovery of costs through gas usage. VNG and CGC recognize revenues from sales of natural gas and transportation services in the same period in which they deliver the related volumes to customers. VNG and CGC bill and recognize sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. In addition, VNG and CGC record revenues for estimated deliveries of gas, not yet billed to these customers, from the meter reading date to the end of the accounting period. We include these revenues in our consolidated balance sheets as unbilled revenue. Included in the rates charged by VNG and CGC is a weather normalization adjustment factor, which offsets the impact of unusually cold or warm weather on our operating margin. Beginning in November 2002, VNG's rates include a two-year experimental weather normalization adjustmen t program. For certain commercial and industrial customers and all wholesale customers, VNG and CGC recognize revenues based upon actual deliveries during the accounting period.

Wholesale Services

We record our wholesale services segment’s revenues when physical sales of natural gas and natural gas storage volumes are delivered to the specified delivery point based on contracted or market prices.  We reflect revenues from commodities sold as part of wholesale services’ trading and derivative activities that are not designated as hedges net of the cost of these sales.  We record derivative transactions at their fair value.  

Our wholesale services segment accounts for derivative instruments under SFAS 133, which requires us to reflect all derivatives, as defined therein in our balance sheet at their fair value as risk management activities. The market prices or fair values used in determining the value of these contracts are Sequent’s best estimates utilizing information such as commodity exchange prices, over-the-counter quotes, volatility and time value, counterparty credit and the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions. When the portfolio market value changes, primarily due to newly originated transactions and the effect of price changes, our wholesale services segment recognizes the change of derivative instruments as a gain or loss in the period of change. We recognize cash inflows and outflows associated with settlement of these risk management activities in operating cash flows, and we report any receivables and payables resulting from these activities resulting from these settlements separately from risk management activities in the balance sheet as energy marketing receivables and payables.  

We adopted the net presentation provisions of the June 2002 consensus for EITF 02-03 on July 1, 2002. As required under that consensus, we present gains and losses from energy-trading activities on a net basis. This results in costs totaling approximately $435.9 million for the three months ended June 30, 2002 and $676.8 million for the six months ended June 30, 2002 being reclassified as a component of our revenues. This reclassification had no impact on our previously reported net income or shareholders’ equity.

During 2002, our wholesale services segment accounted for transactions in connection with energy marketing and risk management activities under the fair value or mark-to-market methods of accounting, in accordance with SFAS 133 and EITF 98-10. Under these methods, we recorded energy commodity contracts, including both physical transactions and financial instruments at fair value, with unrealized gains and/or losses reflected in earnings in the period of change.  Effective January 1, 2003, we adopted the final provisions of EITF 02-03, which rescinded EITF 98-10. Prior to EITF 02-03, wholesales services accounted for non-derivative energy instruments, such as contracts for storage capacity and physical natural gas inventory, at their fair value under EITF 98-10.

As a result of the adoption, wholesale services adjusted the fair value of its non-derivative trading instruments to zero and now accounts for them under the accrual method of accounting.  In addition, wholesale services’ natural gas inventories are now recorded at the lower of cost or market.  The cumulative effect of the change in accounting principle resulted in a $12.6 million pre-tax reduction to income before cumulative effect of change in accounting principle ($7.8 million net of taxes) and a decrease of $12.6 million to energy marketing and risk management assets and a $4.8 million decrease to accumulated deferred income taxes in our accompanying condensed consolidated balance sheets.

Energy Investments

SouthStar

SouthStar recognizes revenues from sales of natural gas and transportation services in the same period in which they deliver the related volumes to customers. SouthStar bills and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. In addition, SouthStar records revenues for estimated deliveries of gas, not yet billed to these customers, from the meter reading date to the end of the accounting period. For certain commercial and industrial customers and all wholesale customers, SouthStar recognizes revenues based upon actual deliveries during the accounting period.

AGL Networks

We recognize revenues attributable to leases of dark fiber pursuant to indefeasible rights-of-use (IRU) agreements as services are provided. Dark fiber IRU agreements generally require the customer to make a down payment upon execution of the agreement; however, in some cases AGL Networks receives up to the entire lease payment at the inception of the lease and recognizes revenue ratably over the lease term. As a result, we record deferred revenue in our condensed consolidated balance sheet. In addition, AGL Networks recognizes sales revenues upon the execution of certain sales-type agreements for dark fiber when the agreements provide for the transfer of the legal title to dark fiber to the customer at the end of the agreement’s term. This sales-type accounting treatment is in accordance with EITF Issue No. 00-11 “Lessors’ Evaluation of Whether Leases of Certain Integral Equipment Meet the Ownership Transfer Requirements of FASB Statemen t No. 13 Accounting for Leases, for leases of Real Estate” and FAS No. 66 “Accounting for Sales of Real Estate”, which provides that such transactions meet the criteria for sales-type lease accounting if the agreement obligates the lessor to deliver documents that convey ownership of the underlying asset to the lessee by the end of the lease term.

AGL Networks is obligated, under the dark fiber IRUs, to maintain the network in efficient working order and in accordance with industry standards. Customers contract with AGL Networks to provide maintenance services for the network. AGL Networks recognizes this maintenance revenue as services are provided.

AGL Networks also engages in construction projects on behalf of customers. Projects are considered substantially complete upon customer acceptance and the revenue and associated expenses are recorded at that time.  

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Accounting for Contingencies

Our accounting policies for contingencies cover a variety of business activities, including contingencies for potentially uncollectible receivables, rate matters, and legal and environmental exposures. We accrue for these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated in accordance with SFAS No. 5 “Accounting for Contingencies.” We base our estimates for these liabilities on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future. Actual results may differ from estimates, and estimates can be, and often are, revised either negatively or positively, depending upon actual outcomes or expectations based on the facts surrounding each potential exposure.

Accounting for Pension Benefits

We have a defined benefit pension plan for the benefit of substantially all full-time employees and qualified retirees. We use several statistical and other factors that attempt to anticipate future events and to calculate the expense and liability related to the plan. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as determined by us. In addition, our actuarial consultants use subjective factors such as withdrawal and mortality rates to estimate the projected benefit obligation. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, or longer or shorter life spans of participants. These differences may result in a significant impact on the amount of pension expense recorded in future periods.

The combination of poor equity market performance and historically low corporate bond rates has created a divergence in the estimated value of the pension liability and the actual value of the pension assets. These conditions resulted in an increase in our unfunded accumulated benefit obligation (ABO) and future pension expenses and could impact our future contributions. The primary factors that drive the value of our unfunded ABO are the discount rate and the market value of plan assets as of year end.

As of December 31, 2002, we recorded an additional minimum pension liability of $79.9 million, which resulted in an after tax charge to other comprehensive income of $48.5 million. To the extent that our future expenses and contributions increase as a result of the additional minimum pension liability, we believe that such increases are recoverable in all or in part, under our future rate proceedings or mechanisms.

Equity market performance and corporate bond rates have a significant effect on our reported unfunded ABO as the primary assumptions that drive the value of our unfunded ABO are the discount rate and expected return on plan assets. A one-percentage point increase or decrease in the assumed discount rate could have a negative or positive impact to the ABO of approximately $40.0 million. Additionally, a one-percentage point increase or decrease in the assumed expected return on assets would decrease or increase our pension expense by approximately $2.5 million.

As of June 30, 2003, the market value of the pension assets was $225.3 million as compared to a market value of $207.8 million as of December 31, 2002. The net increase of $17.5 million from December 31, 2002 to June 30, 2003 results from our contribution of $6.5 million on February 14, 2003 and our actual return on plan assets of $20.9 million less benefits paid of $9.9 million. Our $6.5 million contribution is expected to reduce pension expense approximately $0.5 million for the twelve months ended December 31, 2003.

The actual return on plan assets of $20.9 million as compared to the expected return on plan assets could have an impact on our benefit obligation as of December 31, 2003 and our pension expense for 2004. We are unable to determine how this actual return on plan assets will affect future benefit obligation and pension expense; as actuarial assumptions and differences between actual and expected returns on plan assets are determined at the time we complete our actuarial evaluation as of December 31, 2003. Our actual returns may also be positively or negatively impacted as a result of future performance in the equity and bond markets.

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Regulatory and Legislative Overview

Federal Activity

The Pipeline Safety Improvement Act of 2002, enacted on December 17, 2002, addresses improved safety and integrity of the industry’s large diameter transmission pipeline systems.  This Act requires that the Office of Pipeline Safety (OPS) establish new regulations on the inspection of transmission pipelines by December 2003.  If OPS fails to do that, then there are identified requirements within the Act which will require us to inspect all of our transmission lines in high consequence areas over the next 10 years and to take appropriate remedial action. OPS issued a Notice of Proposed Rulemaking that was open for comments through the end of April 2003. OPS rules are scheduled to be issued no later than December 17, 2003. Based on initial estimates, the bill will require our three utility subsidiaries to inspect and take remedial action on approximately 350 miles of large diameter pipelines with an estimated cost over that 10 year period o f $22 million. We believe that since the efforts that require these expenditures are federally mandated, the costs are recoverable in state regulatory proceedings.

State Activity

None of the three state jurisdictions in which we operate passed any legislation that would significantly impact our businesses during their most recent legislative sessions.

Since 1998, there have been a number of federal and state proceedings regarding the role of AGLC and its administration and assignment of interstate assets to Marketers pursuant to the provisions of the Natural Gas Competition and Deregulation Act of Georgia. As part of those proceedings, AGLC has entered into a stipulation with the GPSC staff, industrial customers, the Governor’s Office of Consumer Affairs and all but one of the Marketers on its systems, regarding the assignment of its interstate capacity assets.  A hearing to approve the settlement has been conducted and by a vote of 5-0 on July 24, 2003 the GPSC approved the stipulation. Under the terms of that authorization, AGLC is authorized to:  

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offer two additional sales services pursuant to GPSC approved tariffs, and

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acquire and continue managing the interstate transportation and storage contracts which underlie the sales services provided to the Marketers on its distribution system under GPSC approved tariffs.  

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Item 3. Quantitative and Qualitative Disclosure About Market Risk

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

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 the delegation of approval and authorization 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. Our 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. Sequent is exposed to certain commodity price risks inherent in the natural gas industry or inherent in transactions entered in the normal course of business. In executing risk management strategies to mitigate these risks, our wholesale services segment routinely utilizes various types of financial and other instruments. 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 financial and other derivative instruments that we use require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual arrangements. Sequent does not designate its derivative instruments to manage risk exposure to energy prices as hedges under SFAS 133. Our determination of fair value considers various factors, including closing exchange or over-the-counter market price quotations, time value and volatility factors underlying options and contractual commitments. The maturities of these financial instruments are less than two years and represent purchases (long) of 411.3 billion cubic feet and sales (short) of 382.4 billion cubic feet.

The following table includes the fair values and average values of Sequent's energy marketing and risk management assets and liabilities as of June 30, 2003. We base the average values on a monthly average for the six months ended June 30, 2003.