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AGL RESOURCES INC.

Form 10-Q

For the Quarterly Period Ended June 30, 2004

TABLE OF CONTENTS

GLOSSARY OF KEY TERMS

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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)

Note 1

Accounting Policies and Methods of Application

General

AGL Resources Inc. is an energy services holding company that conducts substantially all of its operations through its subsidiaries. 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 condensed 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 and the information presented is not misleading.

The condensed 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 conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2003, filed with the SEC on February 6, 2004.

Due to the seasonal nature of our business, the results of operations for the three and six months ended June 30, 2004 and the June 30, 2004, December 31, 2003 and June 30, 2003 balance sheets are not necessarily indicative of the results of operations to be expected for any other interim period or for the year ending December 31, 2004. For a glossary of key terms and referenced accounting standards, see pages three and four of this filing.

Basis of Presentation

Our condensed consolidated financial statements as of and for the periods ended June 30, 2004 include our accounts, the accounts of our majority-owned and controlled subsidiaries and the accounts of variable interest entities for which we are the primary beneficiary. All significant intercompany items have been eliminated in consolidation. Certain amounts from prior periods have been reclassified to conform to the current period presentation. The December 31, 2003 balance sheet amounts are derived from our audited financial statements.

Our condensed consolidated financial statements include the accounts of SouthStar Energy Services LLC (SouthStar), a variable interest entity of which we are the primary beneficiary. Previously, we accounted for our 70% non-controlling financial ownership interest in SouthStar using the equity method of accounting. Under the equity method, our ownership interest in SouthStar was reported as an investment within our consolidated balance sheet, and our share of SouthStar’s earnings was reported in our condensed consolidated statement of income as a component of other income. We utilize the equity method to account for and report investments where we exercise significant influence but not control and where we are not the primary beneficiary as defined by FIN 46. Our equity method investments generally include entities where we have a 20% to 50% voting interest.

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), which was effective for our December 31, 2003 consolidated financial statements. FIN 46 was subsequently revised in December 2003 (FIN 46R). FIN 46R clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to certain entities in which equity investors do not have the characteristics of a controlling financial interest. FIN 46R also defines a variable interest entity, and provides guidance for determining when a business enterprise should consolidate the results of a variable interest entity.

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During the first quarter effective January 1, 2004, we adopted FIN 46R resulting in the consolidation of SouthStar’s accounts in our condensed consolidated financial statements; and the deconsolidation of the accounts related to our Trust Preferred Securities. For more discussion on FIN 46R and the impact of its adoption on our condensed consolidated financial statements, see Note 2, Recent Accounting Pronouncements.

Stock-based Compensation

We have several stock-based employee compensation plans and we 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 Statement of Financial Accounting Standard No. 123, “Accounting for Stock-Based Compensation” (SFAS 123). For our stock option plans, we generally do not reflect stock-based employee compensation cost in net income, as options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. For our stock appreciation rights, we reflect stock-based employee compensation cost based on the fair value of our common stock at the balance sheet date, since these awards constitute a variable plan under APB 25.

The following table illustrates the effect on our net income and earnings per share for the three and six months ended June 30, 2004 and 2003 as if we had applied the optional fair value recognition provisions of SFAS 123:

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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. For the six months ended June 30, 2004 our comprehensive income increased as a result of the fair value of derivatives at SouthStar in the amount of $1 million and a similar offsetting decrease due to the sale of our remaining investment units related to US Propane LP. As a result, our comprehensive income for June 30, 2004 was equal to net income. For the six months ended June 30, 2003 our 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 reduction in earnings per common share that could occur when potential dilutive common shares are added to common shares outstanding.  

We derive our potential dilutive common shares by calculating the number of shares issuable under performance units and stock options. The future issuance of shares underlying the performance units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends upon whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. There were no anti-dilutive items. The following table shows the calculation of our diluted shares for the three and six months ended June 30, 2004 and 2003, assuming performance units currently earned under the plan ultimately vest, and stock options currently exercisable at prices below the average market prices are exercised:

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Note 2

Recent Accounting Pronouncements

FIN 46

FIN 46 requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities.

In December 2003, the FASB revised FIN 46, delaying the effective dates for certain entities created before February 1, 2003, and making other amendments to clarify application of the guidance. For potential variable interest entities other than any special purpose entities, FIN 46R was required to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004.   

FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46R also requires certain disclosures of an entity’s relationship with variable interest entities. We adopted FIN 46R as of March 31, 2004.

Notes payable to Trusts and Trust Preferred Securities In June 1997 and March 2001, we established AGL Capital Trust I and AGL Capital Trust II (Trusts) to issue our Trust Preferred Securities. The Trusts are considered to be special purpose entities under FIN 46 and FIN 46R since our equity in the Trusts is not considered to be sufficient to allow the Trusts to finance their own activities and our equity investment is not considered to be at risk since the equity amounts were financed by the Trusts.

Under FIN 46 (prior to the revision in FIN 46R), we concluded that we were the primary beneficiary of the Trusts because the Trust Preferred Securities are publicly traded, widely held, and no one party would absorb a majority of any expected losses of the Trusts. In addition, our loan agreements with the Trusts include call options allowing us to capture the benefits of declining interest rates since the options enable us to call the preferred securities at par, giving us the ability to capture the majority of the residual returns in the Trusts. Accordingly, at December 31, 2003, the accounts of the Trusts were included in our consolidated financial statements.  

The revisions in FIN 46R included specific guidance that instruments such as the call options included in our loan agreements with the Trusts do not constitute variable interests, and should not be considered in the determination of the primary beneficiary. As a result, as of January 1, 2004 we were required to exclude the accounts of the Trusts from our consolidated financial statements upon our adoption of FIN 46R and to classify amounts payable to the Trusts as “Notes Payable to Trusts” within capitalization in our condensed consolidated balance sheets as of June 30, 2004.

The impact of deconsolidation of the Trusts is that we have included in our condensed consolidated balance sheets at June 30, 2004, an asset of approximately $10 million representing our investment in the Trusts, and a note payable to the Trusts totaling approximately $232 million, which is net of an interest rate swap of $2 million, and removed $222 million related to the Trust Preferred Securities issued by the Trusts. The notes payable represent the loan payable to fund our investments in the Trusts of $10 million and the amounts due to the Trusts from the proceeds received from their issuances of Trust Preferred Securities of $222 million.

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SouthStar SouthStar is a joint venture formed in 1998 by our subsidiary, Georgia Natural Gas Company, Piedmont Natural Gas Company, Inc. (Piedmont) and Dynegy Inc. (Dynegy) to market natural gas and related services to retail customers, principally in Georgia. On March 11, 2003, we purchased Dynegy’s 20% ownership interest in a transaction that for accounting purposes had an effective date of February 18, 2003. We currently own a non-controlling 70% financial interest in SouthStar and Piedmont owns the remaining 30%. Our 70% interest is non-controlling because all significant management decisions require approval by both owners.  

On March 29, 2004 we executed an amended and restated partnership agreement with Piedmont. This amended and restated partnership agreement calls for SouthStar’s future earnings starting in 2004 to be allocated 75% to our subsidiary and 25% to Piedmont. For all periods prior to February 18, 2003, SouthStar’s earnings have been allocated to us based upon our ownership interests in those periods of 50%. SouthStar, which operates under the trade name Georgia Natural Gas, competes with other energy marketers, including Marketers in Georgia, to provide natural gas and related services to customers in Georgia and the Southeast.

As of December 31, 2003, we did not consolidate SouthStar in our financial statements because it did not meet the definition of a variable interest entity under FIN 46. FIN 46R added the following conditions for determining whether an entity was a variable interest entity:

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the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both, and

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substantially all of the entity’s activities (for example purchasing products and additional capital) either involve or are conducted on behalf of an investor that has disproportionately fewer voting rights.

We determined that SouthStar is a variable interest entity as defined in FIN 46R because:

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our equal voting rights with Piedmont are not proportional to our economic obligation to absorb 75% of any losses or residual returns from SouthStar, and

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SouthStar obtains substantially all of its transportation capacity for delivery of natural gas through our wholly owned subsidiary, Atlanta Gas Light Company (AGLC).

Consequently, as of January 1, 2004, we consolidated all of SouthStar’s accounts with our subsidiaries’ accounts and eliminated any intercompany balances between segments. We recorded Piedmont’s portion of SouthStar’s earnings as a minority interest in our condensed consolidated statements of income, and we recorded Piedmont’s portion of SouthStar’s capital as a minority interest on our condensed consolidated balance sheet.

FASB Staff Position 106-2 On May 19, 2004, the FASB issued FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” (FSP 106-2) which supersedes FSP 106-1 and is effective for the first interim or annual reporting period beginning after June 15, 2004, or July 1, 2004 for us.  The guidance in FSP 106-2 related to the accounting for the federal subsidy applies only to the sponsor of a single-employer defined benefit postretirement health care plan for which (a) the employer has concluded that prescription drug benefits available under the plan to some or all participants for some or all future years are "actuarially equivalent" to Medicare Part D and thus qualify for the subsidy under the Medicare Prescription Drug Act and (b) the expected federal subsidy will offset or reduce the employer’s share of the cost o f the underlying postretirement prescription drug coverage on which the federal subsidy is based.  FSP 106-2 also provides guidance for the disclosures about the effects of the subsidy for an employer that sponsors a postretirement health care benefit plan that provides prescription drug coverage but for which the employer has not yet been able to determine actuarial equivalency.

Effective July 2, 2004 we amended our Defined Benefit Health Care and Life Insurance Plan (Defined Plan) to no longer offer prescription drug benefits to retirees age 65 and older after January 1, 2006. As a result, FSP 106-2 will not have an impact on our accounting for our Defined Plan.

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Note 3

Risk Management

Our risk management activities are monitored by the Risk Management Committee (RMC). The RMC is comprised of senior officers charged with the review and enforcement of our risk management policies. Our risk management policies limit the use of derivative financial instruments and physical transactions within pre-defined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following derivative financial instruments and physical transactions to manage commodity price risks:

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Forward contracts

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Futures contracts

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Options contracts

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Financial swaps

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Storage and transportation capacity transactions

Interest Rate Swaps

To maintain an effective capital structure, it is our policy to borrow funds using a mix of fixed-rate 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-rate and variable-rate debt obligations. We designated these interest rate swaps as fair value hedges and accounted for them using the “shortcut’ method prescribed by Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), which allows us to designate derivatives that hedge exposure to changes in the fair value of a recognized asset or liability. We record 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 t o the risk being hedged. The effect of this accounting is to reflect in earnings only that portion of the hedge that is ineffective in achieving offsetting changes in fair value.

Accordingly, we adjust the carrying value of each interest rate swap to its fair value at the end of each period, 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 swaps each quarter.

In March 2004 we adjusted our fixed to variable-rate debt obligations and terminated an interest rate swap on $100 million of the principal amount of our 4.45% Senior Notes due 2013. Additionally, as of March 31, 2004 and in connection with the deconsolidation of the Trusts, we re-designated the interest rate swaps on the Trust Preferred Securities as a fair value hedge of our notes payable to the Trusts.

As of June 30, 2004, a notional principal amount of $175 million of these interest rate swap agreements effectively converted the interest expense associated with a portion of our Senior Notes and notes payable to the Trusts 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. Our interest rate swaps consist of the following:

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$100 million principal amount of 7.125% Senior Notes due 2011. We pay floating interest each January 14 and July 14 at six-month LIBOR plus 3.4%. The effective variable interest rate at June 30, 2004 was 4.6%, an increase of 0.1% from December 31, 2003. These interest rate swaps expire January 14, 2011, unless terminated earlier.

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$75 million principal amount of 8.0% notes payable to Trusts 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 at June 30, 2004 was 2.6%, an increase of 0.1% from December 31, 2003. These interest rate swaps expire May 15, 2041, unless terminated earlier.

The aggregate fair value of these interest rate swaps was recorded as a liability of $3 million at June 30, 2004 and $4 million at December 31, 2003 and an asset of $9 million at June 30, 2003.

Commodity-related derivative instruments

Sequent We are exposed to risks associated with changes in the market price of natural gas. Sequent Energy Management, L.P. (Sequent) uses derivative financial instruments to reduce our exposure to the risk of changes in the prices of natural gas. 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 the financial instruments we utilize.

We attempt to mitigate substantially all the commodity price risk associated with Sequent’s natural gas portfolio to lock in the economic margin at the time we enter into natural gas purchase transactions for our stored natural gas. We purchase natural gas for storage when the difference in the current market price we pay to buy natural gas plus the cost to store the natural gas is less than the market price we can receive in the future, resulting in a positive net profit margin. We use New York Mercantile Exchange (NYMEX) futures contracts to sell natural gas at that future price to substantially lock in the profit margin we will ultimately realize when the stored gas is actually sold. Those NYMEX futures contracts meet the definition of a derivative under SFAS 133 and are recorded at fair value in our condensed consolidated balance sheet, with changes in fair value recorded in earnings in the period of change. The pur chase, storage and sale of natural gas are accounted for on an accrual basis rather than on the mark-to-market basis we utilize for the derivatives used to mitigate the commodity price risk associated with our storage portfolio. This difference in accounting will result in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated. We do not currently use hedge accounting under SFAS 133 to account for this activity.

Our commodity-related derivative financial instruments, which exclude interest rate swaps, had a weighted average maturity of 8 months based on volumes.  At June 30, 2004, our commodity-related derivative financial instruments represented purchases (long) of 540 billion cubic feet (Bcf) with approximately 99% of these scheduled to mature in less than 2 years. In addition, our financial instruments included sales (short) of 555 Bcf with approximately 96% of these scheduled to mature in less than 2 years and the remaining 4% in 3-9 years. For the six months ended June 30, 2004 and 2003, excluding the cumulative effect of a change in an accounting principle in 2003 for the adoption of EITF 02-03, our unrealized gains were $15 million in 2004 and $6 million in 2003.

SouthStar The commodity-related derivative financial instruments (futures, options and swaps) used by SouthStar manage exposures arising from changing commodity prices. SouthStar’s objective for holding these derivatives is to minimize this risk using the most effective methods to reduce or eliminate the impacts of these exposures. A significant portion of SouthStar’s derivative transactions are designated as cash flow hedges under SFAS 133. Derivative gains or losses arising from cash flow hedges are recorded in other comprehensive income (OCI) and are reclassified into earnings in the same period as the settlement of the underlying hedged item. Any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not perfectly offset the losses or gains on the hedged item, is recorded into earnings in the period in which it occurs. SouthStar currently has no hedge ineffectiveness. The remainder of SouthStar’s derivative instruments does not meet the hedge criteria under SFAS 133. Therefore, changes in their fair value are recorded in earnings in the period of change.

At June 30, 2004, the fair value of these derivatives was reflected in our condensed consolidated financial statements as an asset of $2 million with a corresponding increase to OCI of $1 million.  For the six months ended June 30, 2004, a loss of $1 million was reclassified to earnings from OCI related to instruments designated as hedges under SFAS 133 and a loss of $1 million was recognized on instruments not designated as hedges under SFAS 133 representing the change in fair value of those instruments during the period.  No amounts were recorded to earnings related to hedge ineffectiveness. The maximum maturity of open positions is less than 2 years and represent purchases of 2 Bcf and sales of 3 Bcf, with approximately 97% scheduled to mature in less than one year.

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Weather derivative contracts

SouthStar routinely enters into weather derivative contracts for hedging purposes in order to preserve margins in the event of warmer-than-normal weather in the winter months. SouthStar accounts for these contracts using the intrinsic value method under the guidelines of EITF 99-02, “Accounting for Weather Derivatives”.

Concentration of Credit Risk

Distribution Operations AGLC has a concentration of credit risk for amounts billed for services and other costs to its customers, ten Marketers and poolers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. These retail functions include customer service, billing, collections, and the purchase and sale of natural gas. The provisions of AGLC’s tariff allow AGLC to obtain security support in an amount equal to a minimum of two times a Marketer’s highest monthly bill.

Wholesale Services Sequent provides services to marketers, utility and industrial customers has a concentration of credit risk measured by 30-day receivable exposure plus forward exposure, which is highly concentrated in 20 of its counterparties. At June 30, 2004, Sequent’s top 20 counterparties represented approximately 55% of the total counterparty credit exposure of $238 million, derived by adding the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures.

Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. When we are engaged in more than one outstanding derivative transaction with the same counterparty and we also have a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of our credit risk. Sequent also uses other netting agreements with certain counterparties with whom we conduct significant transactions.

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Note 4

Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our consolidated balance sheets in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Our regulatory assets and liabilities, and associated liabilities for our unrecovered pipeline replacement program (PRP) costs and unrecovered environmental response costs (ERC), are summarized in the table below:

(1) Presented in other current assets in our condensed consolidated balance sheets.

(2) Presented in other deferred debits and other assets in our condensed consolidated balance sheets.

(3) Presented in other deferred debits and other assets, other current liabilities and accrued postretirement benefit costs in our condensed consolidated balance sheets.

(4) Presented in other current liabilities in our condensed consolidated balance sheets.

(5) Presented in deferred credits in our condensed consolidated balance sheets.

Our regulatory assets and liabilities are described in our Annual Report on Form 10-K for the year ended December 31, 2003. The following represent significant changes to our regulatory assets and liabilities during the six months ended June 30, 2004:

Environmental Response Costs

Our latest engineering estimate for the costs to remediate certain former manufactured gas plant (MGP) sites was $50 million, a reduction of $17 million from the estimate as of December 31, 2003.  The decrease was primarily a result of actual expenditures in 2004. For those remaining elements of the MGP program where AGLC is unable to perform engineering cost estimates at the current state of investigation, considerable variability remains in the estimates for future remediation costs. For these elements, the estimate for the remaining cost of future actions at MGP sites is $15 million.  AGLC estimates certain other costs related to administering the MGP program and remediation of sites currently in the investigation phase. Through January 2005, AGLC estimates the administrative costs to be $3 million. Beyond January 2005, these costs are not estimable. As of June 30, 2004, our MGP program was approximately 70% com plete.

For those sites currently in the investigation phase, our estimate is $9 million. This estimate is based upon preliminary data received during 2003 with respect to the existence of contamination at those sites. Our range of estimates for these sites is from $9 million to $15 million. We have accrued the low end of our range, or $9 million, as this is our best estimate at this phase of the remediation process. AGLC’s ERC liability is composed of the elements in the following table:

(1) As of March 31, 2004, September 30, 2003 and March 31, 2003.

(2) Expenditures during the three months ended June 30, 2004, December 31, 2003 and June 30, 2003.

The ERC liability is included in a corresponding regulatory asset. As of June 30, 2004, the regulatory asset was $167 million, which is a combination of accrued ERC 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 an amount.

AGLC has three ways of recovering investigation and cleanup costs. The GPSC has approved an ERC recovery rider. It allows recovery of the costs of investigation, testing, cleanup and litigation. Because of this 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 assets. AGLC recovered $12 million during the six months ended June 30, 2004, through its ERC 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 was no material recoveries from potentially responsible parties during the six months ended June 30, 2004. The remaining way AGLC can recover costs is from the receipt of net profits from the sale of remediated property.  On June 30, 2004, a residential and retail development located in Savannah, Georgia and adjacent to a former MGP site was sold resulting in a gross gain of $6 million.  All gains on sales of MGP property are required by the ERC recovery rider to be shared 70% with ratepayers. As a result, approximately $4 million was credited to the MGP program as a reduction to the regulatory asset.

2004 is expected to be the last significant year of spending for this program. The ERC recovery mechanism allows for recovery of expenditures over a five-year period subsequent to the period in which the expenditures are incurred. As of June 30, 2004, the MGP expenditures expected to be incurred over the next 12 months are reflected as a current liability of $37 million. In addition, AGLC expects to collect $26 million in revenues over the next 12 months under the ERC recovery rider, which is reflected as a current asset.

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Note 5

Pension and Other Postretirement Benefits

Accounting for Pension Benefits

The measurement date for our pension and other postretirement benefit plans is December 31. The following are the costs components of our pension and other postretirement benefit plans for the second quarter ended June 30, 2004 and 2003.

The following are the cost components for the six months ended June 30, 2004 and 2003.

Employer Contributions

In April of 2004, we made a $13 million contribution to our pension plan. We do not anticipate making any additional contributions in 2004.

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Note 6

Financing

(1)

The daily weighted average rate was 1.2% for the six months ended June 30, 2004.

(2)

The daily weighted average rate was 1.5% for the six months ended June 30, 2004.

(3)

Weighted average interest rate, including interest rate swaps if applicable.

(4)

Interest rates exclude debt issuance and other financing related costs.

Short-term Debt

Our short-term debt is composed of borrowings under our commercial paper program which consists of short-term unsecured promissory notes with maturities ranging from 14 to 57 days, maturities within one year of our Medium-Term notes, Sequent’s line of credit and SouthStar’s non-recourse debt. The commercial paper program is supported by our Credit Facility.

On May 26, 2004, we closed on a new $500 million three-year Credit Facility. This new Credit Facility replaces our previous $200 million 364-day Credit Facility that was scheduled to expire on June 16, 2004 and our previous $300 million three-year Credit Facility that was scheduled to terminate on August 7, 2005. Under our new Credit Facility, one time each calendar year we can request from lenders an increase in credit commitments up to an additional $200 million.

On April 19, 2004, SouthStar amended its $75 million revolving line of credit which provides working capital needs to meet seasonal demands. The line of credit is scheduled to expire on April 19, 2007 and is not guaranteed by us. SouthStar’s line of credit provides for its working capital needs and meets its seasonal demands. On June 14, 2004, Sequent extended its $25 million line of credit until July 1, 2005, which is used solely for the posting of exchange deposits and is unconditionally guaranteed by us.

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 Note 7

Commitments and Contingencies

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. There have not been any significant changes to our contractual obligations which were described in our Annual Report on Form 10-K for the year ended December 31, 2003.

Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. The following tables illustrate our expected financial commitments as of June 30, 2004:

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

In the first quarter of 2004, we settled a lawsuit with the city of Augusta, Georgia who had served AGLC with a complaint that was filed in the Superior Court of Richmond County, Georgia on July 1, 2003. The City of Augusta’s allegations included fraud and deceit and damages to realty. The allegations arose from negotiations between the city and AGLC regarding the environmental cleanup obligations connected with AGLC’s former MGP operations in Augusta.

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Note 8

Segment Information

Our business is organized into three operating segments:

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

o

Wholesale services consists primarily of Sequent.

o

Energy investments consists primarily of SouthStar, AGL Networks, LLC and US Propane LP through the date of its sale in January 2004.

We treat corporate, our fourth segment, as a non-operating business segment, and it includes AGL Resources Inc., AGL Services Company, Pivotal Energy Development, nonregulated financing and the effect of intercompany eliminations. We eliminated intersegment sales for the three and six months ended June 30, 2004 and 2003 from our statements of consolidated income.

We evaluate segment performance based on the 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 a change in accounting principle, each of which we evaluate on a consolidated level. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our business from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

EBIT should not be considered an alternative to, or a more meaningful indicator of our operating performance than, operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income, earnings before income taxes and net income for the three and six months ended June 30, 2004 and 2003 are presented below.

(1)

Identifiable assets are those assets used in each segment’s operations.

(2)

Our corporate segment’s assets consist primarily of intercompany eliminations, cash and cash equivalents and property, plant and equipment.

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(1)

Intersegment revenues – Wholesale services records its energy marketing and risk management revenue on a net basis.  The following table provides detail of wholesale services’ total gross revenues and gross sales to distribution operations:

(2)

Includes intercompany eliminations; assets consist primarily of cash and cash equivalents and property, plant and equipment.

(3)

Identifiable assets are those assets used in each segment’s operations.

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Note 9

Subsequent Events

NUI Corporation Acquisition On July 15, 2004, we announced that our board of directors approved a definitive merger agreement under which we will acquire all of the outstanding shares of NUI Corporation (NUI) for $13.70 per share in cash, or $220 million in the aggregate based on approximately 16 million shares outstanding, and the assumption of NUI’s outstanding debt at closing. At March 31, 2004, NUI had approximately $607 million in debt and $136 million of cash on its balance sheet, bringing the estimated net value of the acquisition to $691 million.

At closing we expect to fund the purchase of NUI’s shares primarily through the issuance of equity or debt securities.   We expect to refinance a portion of NUI’s outstanding debt and expect to finance at least $220 million of the purchase through the issuance of equity securities. The transaction is subject to approval of NUI’s shareholders, the SEC, state regulatory agencies of New Jersey, Florida, Maryland and Virginia and various other closing conditions. We are seeking expedited treatment from the various state and federal regulatory agencies for approval of our proposed merger agreement with NUI. The merger agreement provides that the closing must occur on or prior to April 11, 2005, but the closing may be extended for an additional 90 days until July 11, 2005, in the event the parties have not obtained the required consents for the acquisition.

Postretirement Plan We amended the Defined Benefit Postretirement Health Care and Life Insurance Plan (Defined Plan) due to the Medicare Prescription Drug Improvement and Modernization Act of 2003, which was signed into law December 8, 2003, and which resulted in Medicare offering prescription drug coverage beginning January 1, 2006 to all Medicare-eligible retirees. As a result of this law, effective July 2, 2004 we amended our Defined Plan to discontinue prescription drug benefits to retirees age 65 and older after January 1, 2006.

Treasury Securities From time to time we enter into transactions designed as a hedge against market interest rate fluctuations. On July 2, 2004 we entered into a forward contract transaction involving $100 million of U.S. Treasury securities in order to minimize such fluctuations. The transaction partially hedges an anticipated debt offering in the third or fourth quarter of 2004, and the locked-in Treasury rate was 4.57% with an October 1, 2004 settlement date.

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ITEM 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operation

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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).  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,” “fo recast,” “rely,” “expect,” “continue,” “grow” and other words of similar meaning.  Although we believe that the expectations and assumptions reflected in these statements are reasonable 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, including those set forth below and in our Form 10-K filed with the Securities and Exchange Commission on February 6, 2004 under Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Risk Factors.” The following are among the important factors that could cause actual results to differ materially from the results discussed in the forward-looking statements:

o

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

o

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

o

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

o

actions taken by government agencies, including decisions on base rate increase requests by state regulators

o

the ultimate impact of the Sarbanes-Oxley Act of 2003 and any future changes in accounting regulations or practices in general with respect to public companies, the energy industry or our operations specifically

o

the enactment of new accounting standards by the Financial Accounting Standards Board (FASB) or the Securities and Exchange Commission (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

o

effects and uncertainties of deregulation and competition, particularly in markets where prices and providers historically have been regulated and unknown issues following deregulation such as the stability of the Georgia retail gas market, including risks related to energy marketing and risk management

o

concentration of credit risk in Marketers – that is, marketers who are certificated by the Georgia Public Service Commission (GPSC) to sell retail natural gas in Georgia – and customers of our wholesale services segment

o

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

o

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

o

our ability to negotiate new fiber optic contracts with telecommunications providers for the provision of AGL Networks, LLC’s dark fiber services

o

utility and energy industry consolidation

o

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

o

impact of acquisitions and divestitures, including:

o

the risk that our business and NUI Corporation (NUI) will not be integrated successfully or such integration may be more difficult, time-consuming or costly than expected

o

expected revenue synergies and cost savings from the merger may not be fully realized or realized within the expected time frame

o

revenues following the merger may be lower than expected

o

the ability to obtain governmental approvals of the merger on the proposed terms and schedule

o

the failure of NUI’s shareholders to approve the merger

o

the risk that we may be unable to obtain financing necessary to consummate the acquisition, or that the terms of such financing may be onerous

o

the risk that any financing plan may have the effect of diluting our shareholder value in the near term

o

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

o

interest rate fluctuations, financial market conditions and general economic conditions

o

uncertainties about environmental issues and the related impact of such issues

o

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

o

impact of litigation

o

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

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Summary

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.  Our executive offices are located at Ten Peachtree Place NE, Atlanta, Georgia 30309. The telephone number at that address is (404) 584-4000. As shown in the following chart, we conduct substantially all our operations through our significant subsidiaries, which we manage as three operating segments - distribution operations, wholesale services and energy investments - and one non-operating segment, corporate, which includes our intercompany eliminations.

Distribution operations includes our three regulated utilities that construct, manage and maintain gas pipeline in Georgia, Tennessee and Virginia and serve more than 1.8 million end-use customers. Approximately 83% of our customers are located in Georgia, 14% are located in Virginia and 3% are located in Tennessee.  Our wholesale services segment includes our nonutility business engaged in natural gas asset management and optimization, producer services and wholesale marketing, and risk management activities. Our energy investments segment includes our nonutility businesses engaged in retail natural gas marketing and operating telecommunications conduit and fiber infrastructure within select metropolitan areas.

Our overall business strategy is to operate and grow our gas distribution business efficiently and effectively, optimize returns on our assets, and selectively grow our portfolio of closely related businesses while remaining focused on risk management and earnings visibility.

NUI Acquisition On July 15, 2004, we announced that our board of directors approved a definitive merger agreement under which we will acquire all the outstanding shares of NUI for $13.70 per share in cash or approximately $220 million, based on approximately 16 million shares outstanding, and the assumption of NUI’s outstanding debt. NUI is a diversified energy company that operates natural gas utilities and natural gas storage and pipeline businesses. NUI provides natural gas to approximately 367,000 residential, commercial and industrial customers in New Jersey, Virginia, Florida and Maryland. This transaction will increase our customer base by 20 percent to approximately 2.2 million.

The total value of the acquisition is $691 million, which includes the assumption of approximately $607 million of NUI’s debt and $136 million of cash on its March 31, 2004 balance sheet. We expect to fund the purchase of NUI’s shares primarily through the issuance of equity or debt securities, and we also expect to refinance a portion of NUI’s outstanding debt upon closing. We ultimately expect to finance at least $220 million of the purchase through the issuance of equity securities. The transaction is subject to approval of NUI’s shareholders, the SEC, state regulatory agencies of New Jersey, Florida, Maryland and Virginia and other various closing conditions. We are seeking expedited treatment from the various state and federal regulatory agencies for approval of our proposed merger agreement with NUI. The merger agreement provides that the closing must occur on or prior to April 11, 2005, but the clo sing may be extended for an additional 90 days until July 11, 2005, in the event the parties have not obtained the required consents for the acquisition.

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Natural gas demand, supply and pricing As a result of comparatively milder weather and other industry factors, natural gas prices have declined in the second quarter of 2004. As July and August typically contain the bulk of summer cooling-degree days, industry analysts expect that increased electricity demand will be met by natural gas-fired generation, as high crude oil prices and a tight coal market make those fuels less attractive generation sources. The increased demand will determine the levels of natural gas storage supplies going into the 2004 – 2005 heating season.

In recent weeks, the natural gas market has been driven by storage injections, as local distribution companies, electric utilities, and others who have a requirement to inject gas during the period of April through October have been doing so in substantial quantities. The declining natural gas prices in April, May and June have resulted in these companies injecting 100 percent of all available injection capacity.

Industry dynamics Although natural gas prices have declined in recent months, recent industry information illustrate that domestic production of natural gas has failed to keep pace with demand, creating substantial price volatility in the natural gas markets. The vast majority of North America’s gas supply comes from mature producing areas, such as western Canada and the Gulf of Mexico, which have experienced yearly declines in output since 1997. New and supplemental sources of supply will need to be identified in the future to meet the expected increased demand for natural gas and more particularly to dampen volatility and to maintain competitive pricing.  Imported liquefied natural gas (LNG) is the one incremental supply source to the United States, but currently comprises only about 2 percent of the total domestic natural gas supply and cannot grow appreciably without new terminals being sited, licensed a nd constructed.

We are undertaking a strategy to diversify our natural gas supply portfolio by exploring a variety of options related to LNG supplies and natural gas assets in the southeastern region. Our strategy includes, but is not limited to, taking advantage of existing LNG import terminals or proposed new terminals to route incremental supplies to our storage and distribution facilities. To do so will likely require expansion of some of our natural gas delivery infrastructure to improve both the capacity and reliability of our system. In addition, we are exploring enhanced access to underdeveloped Appalachian natural gas supplies, a strategy which we believe will be enhanced by our proposed acquisition of NUI. We believe that efforts to enhance access to new natural gas supplies will be beneficial in moderating the price of natural gas to our markets over time.  

The industry continues to be characterized by significant regional differentials in the delivered price of natural gas. As such, our subsidiary, Sequent Energy Management (Sequent), uses the assets of our utilities and others to take advantage of these differentials, which are highly seasonal and sporadic in nature. In addition, the value of natural gas continues to vary over time and hence our storage capacity can be deployed in part to take advantage of such differences. Through the second quarter of 2004, the curve of forward prices did not exhibit as much differentiation over time as it did last year. As such, the arbitrage value of our storage decreased.  As discussed above, the natural gas resource conditions in the market are likely to create price volatility, so we believe the current softness of arbitrage value is unlikely to be a prolonged event. Furthermore, there is a need for some storage for load balancing in the supply area, which is generally unaffected by the forward curve, and hence we expect rapid deliverability storage services, which we offer, to remain in demand.

Competition The principal competition for our distribution operations businesses and SouthStar Energy Services, LLC (SouthStar) are the electric utilities serving the residential and small commercial markets throughout our service areas and the potential displacement or replacement of natural gas appliances with electric appliances. The primary competitive factors are the price of energy and the comfort of natural gas heating compared to electric heating and other energy sources. The increase in wholesale natural gas prices has resulted in increases in the costs of natural gas billed to our customers, and has affected, to some extent, our ability to retain customers, which remains one of our larger challenges in 2004.

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Our customers’ demand for natural gas and the level of business of our natural gas assets could be affected by numerous factors, including:

o

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

o

general economic conditions

o

energy conservation

o

legislation and regulations

o

the capability to convert from natural gas to alternative fuels and

o

weather

Sequent competes for asset management business with other energy wholesalers, often through a competitive bidding process. Sequent has historically been successful in obtaining new asset management business by placing bids that were based primarily on the intrinsic value of the transaction, which is the difference in commodity prices between time periods or locations at the inception of the transaction. In recent months, energy wholesalers have become increasingly willing to place bids for asset management transactions that are priced to include extrinsic value which is the additional value for the margins the wholesaler may be able to capture over the term of the asset management deal. We expect this trend to continue in the near term, and the increasing competition for asset management deals could result in downward pressure on the volume of transactions, and the related margins available in this portion of Sequent’s business.

Sarbanes-Oxley Act Section 404 We are currently working on our compliance with the Sarbanes-Oxley Act Section 404. This project involves defining and documenting our internal controls processes, evaluating the effectiveness of these controls and establishing the appropriate monitoring and reporting systems. We have started testing our key controls and identifying any potential areas requiring improvement. Our external auditor has started their review of our documentation and controls and we believe that we are on track for certification of our 2004 controls by year-end.

Revenues and Cash flow We generate nearly all of our operating revenues and cash flow through the sale, distribution and storage of natural gas. Distribution operations and energy investments comprise a significant portion of our consolidated revenues for the six months ended June 30, 2004 and 2003.

An estimate of the amount of natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period is also recognized in revenues and recorded as unbilled revenues on our condensed consolidated balance sheet.  A significant portion of our operations is subject to variability associated with changes in commodity prices and seasonal fluctuations. During the heating season, which is primarily from November through March, net revenues are higher since generally more customers will be connected in periods of colder weather than in periods of warmer weather.

Our non-utility businesses use physical and financial arrangements to hedge this price risk. Certain hedging and trading activities may require cash deposits to satisfy margin requirements. In addition, reported earnings for the wholesale services and energy investment segments reflect changes in the fair value of certain derivatives; these values may change significantly from period to period.

Operating margin and EBIT We evaluate the performance of our operating segments using the measures of earnings before interest and taxes (EBIT) and operating margin. Our EBIT and operating margin are not measures that are considered to be calculated in accordance with accounting principles generally accepted in the United States of America (GAAP). EBIT is a non-GAAP measure that includes operating income, other income, equity in SouthStar’s income in 2003, donations, minority interest in 2004 and gain on sales of assets.  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 principles, each of which are evaluated on a consolidated level.

We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

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Our operating margin is a non-GAAP measure of income, calculated as revenues minus cost of gas and cost of sales, excluding operation and maintenance expense, depreciation and amortization and taxes other than income taxes. These items are included in our calculation of operating income. We believe operating margin is a better indicator than revenues of the top line contribution resulting from customer growth in our distribution operations segment since the cost of gas is generally passed directly to our customers. We also consider operating margin to be a better indicator in our wholesale services and energy investments segments since it is a direct measure of gross profit before overhead costs.

The following are reconciliations of our operating margin and EBIT to operating income and net income for the three and six months ended June 30, 2004 and 2003 and solely for purposes of comparison reconciliations on a pro-forma basis to adjust the three and six months ended June 30, 2003 as if we had consolidated SouthStar’s accounts. This pro-forma presentation is a non-GAAP presentation; however we believe this pro-forma presentation is useful to users of our financial statements since it presents prior year revenues and expenses on the same basis as 2004 following our consolidation of SouthStar pursuant to our adoption of FIN 46R.

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

(1)

Includes 100% of SouthStar’s revenues and expenses for comparisons among 2003 and 2004 quarters adjusted for SouthStar’s consolidation in 2004.

(2)

Minority interest adjusts our earnings to reflect our 75% share of SouthStar’s earnings in 2004 and our 70% share in 2003 (less Dynegy Inc.’s 20% share of SouthStar’s income prior to February 18, 2003).  

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Second quarter 2004 earnings Our second quarter results reflect an increase in distribution operation’s EBIT as compared to last year. This reflects higher pipeline replacement revenues, increased customer growth and higher carrying charges for Marketer’s stored gas. This was offset partially by Sequent’s decreased operating margin. The decrease in operating margin was due to lower volatility in the natural gas market primarily associated with narrowing storage spreads, resulting in fewer positive price differences in storage opportunities.

Six month 2004 earnings The increase in earnings for the six months ended June 30, 2004 was due in large part to SouthStar’s strong performance. Despite higher energy prices, lower volatility in the second quarter of 2004 affected Sequent’s performance. Compared to the prior year, Sequent’s operating margins were lower as we experienced reduced volatility and price movements across geography and spreads in the forward curve over time, despite 17 percent higher trading volumes.

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Interest expense The decrease in interest expense for the three and six months ended June 30, 2004 as compared to the same periods in 2003 was a result of lower interest rates on commercial paper borrowings, lower average debt balances, the repayment of Medium-Term notes in 2003 and interest rate swap transactions. As shown in the following table, our average debt balances were lower as compared to last year, due to the proceeds generated from the equity offering, which occurred on February 14, 2003, approximately $76 million of cash distributions from SouthStar from December 2003 through June 2004 and lower working capital needs.

(1)

Daily average of all outstanding debt including our note payable to Trusts in 2004 and Trust Preferred Securities in 2003.

As of June 30, 2004, $34 million of long-term fixed-rate obligations are scheduled to mature within the next 12 months. Any new debt obtained to refinance this obligation will be exposed to changes in interest rates. For the six months ended June 30, 2004, had market interest rates been 100 basis points higher, representing a 3.6% interest rate on our variable rate debt versus our actual 2.6% interest rate we incurred, our year-to-date pretax interest expense would have increased by $3 million.

Income tax expense The increase in income tax expense of $2 million and $5 million for the three and six months ended June 30, 2004 was primarily due to the increase in earnings before income taxes, offset by a decrease in the effective tax rate. The decrease in the effective tax rate was primarily due to a decrease in state taxes, which was partially offset by additional tax expense due to recognition of a tax gain from our sale of our general and limited partnership interest in US Propane.

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Results of Operations

Distribution Operations

Distribution operations include the results of operations and financial condition of our three natural gas local distribution utility companies: Atlanta Gas Light Company (AGLC), Virginia Natural Gas (VNG) and Chattanooga Gas Company (CGC). Each utility operates subject to regulations provided by the state regulatory agencies in its service territories. 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 charged to our customers, maintenance of accounting records and various other service and safety matters.

Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. Rates are set at levels that allow for the recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return on common equity.  Rate base consists generally of the original cost of utility plant in service, working capital, inventories and certain other assets; less accumulated depreciation on utility plant in service, net deferred income tax liabilities and certain other deductions.  We continuously monitor the performance of our utilities to determine whether rates need to be adjusted by making a rate case filing.

o

AGLC is a natural gas local distribution utility with distribution systems and related facilities throughout Georgia. AGLC has approximately six Bcf of LNG storage capacity in three LNG plants to supplement the supply of natural gas during peak usage periods.  Pursuant to the Georgia Natural Gas Competition and Deregulation Act, AGLC is designated as an “electing distribution company,” which means that AGLC is required to offer LNG peaking services to Marketers—that is, marketers who are certificated by the GPSC to sell retail natural gas in Georgia--at rates and on terms approved by the GPSC. On October 1, 2004 we will file with the GPSC the information necessary to determine if AGLC’s current performance based rates will be extended, modified, or terminated subsequent to April 30, 2005.

AGLC has executed an agreement with Southern Natural Gas (SNG), a subsidiary of El Paso Corporation, to acquire a portion of SNG’s interstate pipeline that runs from Macon, Georgia to Atlanta, Georgia.  The transaction is valued at approximately $32 million.  As part of the agreement, AGLC will extend the existing SNG transportation and storage contracts to ensure reliable delivery of natural gas into Georgia in return for the right to expand AGLC’s system off of the purchased facilities. We expect the SNG transaction to close by April 30, 2005, subject to securing regulatory approvals.

In May 2004, AGLC and 8 of the 10 Marketers entered into a settlement which resolved matters related to the capacity supply plan that was required to be filed by AGLC on July 1, 2004.  As a result of the settlement, the parties filed with the GPSC a three year capacity supply plan for the Georgia market. A hearing is scheduled in early September 2004, with the final GPSC decision and order expected on September 29, 2004.  The plan includes, among other things:

o

calculation of the design (peak) day requirements for the next three years;

o

purchase by AGLC of certain SNG facilities and the recovery of those costs through the Pipeline Replacement Program;

o

construction of a line from the Macon LNG facility to those SNG facilities;

o

extension of the Sequent peaking contract; and

o

other tariff provisions.  

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o

VNG is a natural gas local distribution utility with distribution systems and related facilities serving 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 five million gallons of propane storage capacity in its two propane facilities to supplement the supply of natural gas during peak usage periods.

In 2004, Pivotal Propane of Virginia, Inc., (Pivotal Propane) our wholly owned subsidiary intends to complete the construction of a propane air facility in the VNG service area to provide VNG with 28,800 dekatherms of propane air per day on a 10-day-per-year basis to serve its peaking needs.  VNG has received approval from the VSCC for the $27 million propane air plant to improve the reliability of its system in Virginia. The propane-air facility is currently under construction, and we expect to have the facility completed in time for the beginning of the winter heating season.

In June 2004, the VSCC issued its final order authorizing the recovery of all charges for this service through VNG’s gas cost recovery mechanism. The approval is for an initial 10-year term, with the possibility of renewal thereafter for terms of two years subject to VSCC approval. VNG has the right to purchase the facility at the end of the initial term or any renewal term. We expect the facility to become operational by the end of 2004.

In June 2004, VNG filed for a 3-year extension of its weather normalization adjustment program. This filing included a fully adjusted cost of service study along with the same schedules required for a general rate case.

o

CGC is a natural gas local distribution utility with distribution systems and related facilities serving the Chattanooga and Cleveland areas of Tennessee. CGC has approximately 1.2 Bcf of LNG storage capacity in its LNG plant. Included in the rates charged by CGC is a WNA factor, which offsets the impact of unusually cold or warm weather on operating margin.

In January 2004, CGC filed a rate plan request with the TRA for a total rate increase of $4.5 million annually. The rate plan was filed to cover CGC’s rising cost of providing natural gas to its customers. In May 2004 the TRA suspended the increase until July 28, 2004. Since its initial filing, CGC reduced its rate plan increase to $3.9 million, as a result of the February 2004 TRA ruling discussed below. On September 1, 2004, new rates will become effective, subject to a final authority by the TRA, which we expect by December 2004.

In March 2003, CGC filed a joint petition with other Tennessee distribution companies requesting the TRA issue a declaratory ruling that the portion of uncollectible accounts directly related to the cost of its natural gas is recoverable through a Purchased Gas Adjustment (PGA) mechanism. The PGA mechanism allows the local distribution companies to automatically adjust their rates to reflect changes in the wholesale cost of natural gas and to insure the utilities recover 100% of the cost incurred in purchasing gas for their customers. On February 9, 2004 the TRA ruled that the gas portion of accounts written-off as uncollectible after March 10, 2004 could be recovered through the PGA.

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Results of Operations for the three and six months ended June 30, 2004 and 2003 are as follows:

(1)

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

2^nd Quarter 2004 compared to 2^nd Quarter 2003 The increase in EBIT of $5 million was primarily the result of increased operating margin at AGLC of $4 million, which was due mainly to the following:

o

$2 million increase due to customer growth

o

$1 million increase in pipeline replacement program (PRP) revenue due to continued PRP capital spending; and

o

$1 million in additional carrying charges for marketers’ gas storage due to higher storage volumes combined with higher weighted average cost of gas.

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6 months 2004 compared to 6 months 2003 The increase in EBIT of $6 million was primarily the result of increased operating margin of $11 million, partially offset by increased operating expenses.  The increase in operating margin was due primarily to the following:

o

AGLC’s operating margin increased $8 million resulting from an increase of $2 million in pipeline replacement program (PRP) revenue due to continued PRP capital spending; $2 million in additional carrying charges for gas stored for marketers due to higher storage volumes combined with higher weighted average cost of gas, $1 million in other revenue, primarily from contracts to provide maintenance services to non-traditional customers, and; $3 million increase due to increased customer growth.

o

VNG’s and CGC’s operating margin increased $3 million due primarily to increased customer growth.

Operating expenses for the six months was $190 million, up from $184 million in the same period last year.  The increase of $6 million was primarily a result of:

o

$5 million increase in operations and maintenance expense as a result of increases in information services and technology costs due to software maintenance; costs for locating gas infrastructure due to increased customer requests; and marketing expenses for a gas appliance program

o

$1 million additional pension expense

o

$2 million increase in depreciation expense primarily from new depreciation rates at VNG and increased assets at each utility

o

Partly offset by a $2 million reduction in expenses from reduced AGLC property taxes and reductions in bad debt primarily due to a TRA ruling that allows for recovery of the gas portion of accounts written off as uncollectible at CGC and increased collection efforts at VNG

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Wholesale Services

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

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

Regulatory Agreements We have reached the following agreements with state regulatory commissions related to Sequent’s role as asset manager for our regulated utilities. Failure to renew these agreements would have a significant impact on Sequent’s EBIT.  

o

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).  A December 2002 GPSC order requires net margin earned by Sequent, for transactions involving AGLC assets other than capacity release, to be shared equally with the USF. For the six months ended June 30, 2004, we contributed $1.3 million to the USF based upon profits earned in 2003.

o

In November 2000, the VSCC approved an asset management agreement that provides for a sharing of profits between Sequent and VNG’s customers.  This agreement expires in October 2005, unless Sequent, VNG and the VSCC agree to extend the contract. In December 2003, we contributed $4.7 million to VNG’s customers for the contract year November 2002 through October 2003. This contribution will be reflected as a reduction to customer gas cost in 2004. We will contribute profits earned in the contract year November 2003 through October 2004 in December 2004.

o

In June 2003, CGC’s tariff was amended effective January 1, 2003 to require net margin earned by Sequent for transactions involving CGC assets to be shared equally with CGC ratepayers. This agreement expires in April 2006 and is subject to automatic extensions unless specifically terminated by either party. In 2004, Sequent contributed $1.3 million to CGC based upon profits earned during 2003. This contribution is being reflected as a reduction to customer gas cost in 2004.

Peaking Services Wholesale services generates operating margin through, among other things, the sale of peaking services, which includes receiving a fee from customers that guarantees that they will receive gas under peak conditions. Sequent recorded gross revenues of $7 million in the six months ended June 30, 2004 under these peaking services and $6 million during the same period in 2003. Wholesale services incurs costs to support its obligations under these agreements, which will be reduced in whole or in part as the matching obligations expire. Wholesale services’ affiliated peaking arrangement expired March 31, 2004. In July 2004, AGLC submitted a capacity supply plan to the GPSC that includes a request for the extension of the Sequent peaking services agreement.

In addition, we renewed and extended for 5 years a separate non-affiliated peaking service agreement that begins in November 2004 and ends in March 2009. If these arrangements, including those with AGLC, are renewed, it is likely that future fees may not be reset at current levels.  We will continue to seek new peaking transactions as well as work toward extending those that are set, or have expired.

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Energy Marketing and Risk Management Activities For the six months ended June 30 in each year, Sequent recorded unrealized gains of $15 million in 2004 and $6 million in 2003, excluding the cumulative effect of a change in accounting principle, related to changes in the fair value of derivative instruments utilized in our energy marketing and risk management activities. 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, 2004 and 2003 and provide details of the net fair value of contracts outstanding as of June 30, 2004. Sequent’s storage positions are affected by price sensitivity in the New York Mercantile Exchange, Inc. (NYMEX) average price.

The sources of our net fair value at June 30, 2004 are as follows:

(1)

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

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Storage Inventory Outlook The NYMEX forward curve graph set forth below reflects the NYMEX natural gas prices as of June 30, 2004 through June 2005, and reflects the prices we could buy natural gas at the Henry Hub for delivery in the same time period. July 2004 futures expired on June 28, 2004, however they are included as they coincide with the July storage withdrawals. The Henry Hub, located in Louisiana, is the largest centralized point for natural gas spot and futures trading in the United States. NYMEX uses the Henry Hub as the point of delivery for its natural gas futures contracts. Many natural gas marketers also use the Henry Hub as their physical contract delivery point or their price benchmark for spot trades of natural gas.

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As shown in the following table, “Open futures NYMEX contracts” represents the volume in contract equivalents of the transactions we executed to hedge our storage inventory. As of June 30, 2004, the expected withdrawal schedule of this inventory and its weighted average costs are reflected in the category “physical withdrawal schedule as of June 30, 2004 (NYMEX contract equivalents.)”  Our futures contracts qualify as derivatives under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) and are accounted for at fair value (mark-to-market). However, the storage inventory is accounted for under the accrual method, at the lower of average cost or market, resulting in a timing mismatch in earnings recognition.

We recognize the gains or losses on the futures contracts in the period the price changes; we recognize the gains or losses on the storage inventory as the gas is withdrawn from storage. The schedule also reflects that our storage inventory is fully hedged with futures, which results in an overall locked-in margin, timing notwithstanding. “Expected gross margin after regulatory sharing” reflects the gross margin we would generate in future periods based on the forward curve and inventory withdrawal schedule at June 30, 2004. This gross margin could change in the future as we adjust our daily injection and withdrawal plans due to changes in market conditions.

(1)

July futures expired on June 28, 2004; however, they are included herein as they coincide with the July storage withdrawals.

(2)

WACOG = Weighted average cost of gas

(3)

At June 30, 2004, as a result of our positions, a $0.10 parallel change in future NYMEX prices would impact our EBIT by $0.6 million. As shown, our net position is flat, and price movements should only affect timing of earnings between periods as futures contracts are marked to market but inventory is recorded at the lower of average cost or market.

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Park and Loan Outlook Additionally, we have entered into park and loan transactions with various pipelines. A park and loan transaction is a tariff transaction offered by pipelines, where the pipeline allows the customer to park natural gas on or borrow natural gas from the pipeline in one period and reclaim natural gas from or repay natural gas to the pipeline in a subsequent period. The economics of these transactions are evaluated and managed similar to the way traditional reservoir and salt dome storage transactions are evaluated. However, these transactions have elements that qualify as derivatives in accordance with SFAS 133.

Under SFAS 133, the transactions are considered financing arrangements when the contracts contain fixed volumes that are payable or repaid at determinable dates and at a specific point in time to third parties. Because these park and loan transactions have fixed volumes, they contain price risk for the change in market prices from the date the transaction is initiated to the time the natural gas is repaid. As a result, these transactions qualify as derivatives under SFAS 133 and must be recorded at their fair value. Certain park and loan transactions that we execute meet this definition.

As such, we account for these transactions at fair value once the transaction has started (either the natural gas is originally parked on or borrowed from the pipeline). “Park and (loan) volumes” represents the contract equivalent for the volumes of our park and loan transactions as of June 30, 2004 that is not already accounted for at fair value. “Expected gross margin from park and loans” represents the gross margin from those transactions expected to be recognized in future periods based on the NYMEX forward curves at June 30, 2004.   

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Results of Operations for the three and six months ended June 30, 2004 and 2003 are as follows:

2^nd Quarter 2004 compared to 2^nd Quarter 2003 The $5 million decline in EBIT was the result of decreased operating margin. The decrease was due to lower volatility in the natural gas market primarily associated with narrowing storage spreads. The net result is that we had fewer storage arbitrage opportunities in 2004 compared to 2003. Despite reduced volatility during 2004, Sequent’s sales volumes increased 17% from 1.71 billion cubic feet (Bcf) per day in 2003 to 2.00 Bcf per day in 2004. We experienced increased volumes predominantly due to customer growth in the producer services and end-user areas of our business.

During the second quarter 2004, Sequent recognized an expense of $0.7 million associated with the reduction of a portion of our natural gas inventory to market prices that were below the average carrying cost of the inventory. Our adjusted weighted average cost of gas stored in inventory was $5.90 per millions of British thermal units (MMBtu) at the end of the second quarter of 2004, compared to $5.56 per MMBtu during the same period in 2003.

6 months 2004 compared to 6 months 2003 The decrease in EBIT of $14 million was the result of decreased operating margin and increased operating expenses. The decrease in operating margin was due primarily to lower volatility in natural gas in 2004. The dampening effect of region-to-region volatility compressed Sequent’s trading and marketing activities and the expected margins within its transportation portfolio.

During the first quarter of 2004, the weighted average cost of natural gas stored in inventory that was sold was $5.06 per MMBtu. This was substantially higher than the $2.20 per MMBtu during the same period last year, thus yielding reduced margins during early 2004 compared to 2003. Sequent’s operating expenses increased modestly compared to 2003 due to additional payroll expenses associated with an increase in the number of employees, and additional costs for outside services attributable to consultants and contractors due in part to our Sarbanes-Oxley Act compliance activities.  

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Energy Investments

Our energy investments segment includes the consolidated results of operations and financial condition of SouthStar in 2004, our equity investment in SouthStar in 2003, the results of operations and financial condition of AGL Networks, LLC (AGL Networks), and our equity investment in US Propane LP (US Propane), through the date of its sale in January 2004.

On January 20, 2004, we executed an agreement to sell our general and limited partnership interests in US Propane. The aggregate transaction was valued at $130 million. Upon closing, we received $29 million for the sale of our interests. We recognized a gain of $1.1 million on this transaction in 2004, which we recorded in other income.

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SouthStar is a joint venture formed in 1998 by our subsidiary, Georgia Natural Gas Company, Piedmont and Dynegy Inc. (Dynegy) to market natural gas and related services to retail customers, principally in Georgia. On March 11, 2003, we purchased Dynegy’s 20% ownership interest in a transaction that for accounting purposes had an effective date of February 18, 2003.  

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

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AGL Networks, our wholly owned subsidiary, is a provider of telecommunications conduit and un-used fiber optic cable or dark fiber. AGL Networks leases and sells its fiber to a variety of customers in the Atlanta, Georgia and Phoenix, Arizona metropolitan areas, with a small presence in other cities in the United States. Its customers include local, regional and national telecommunications companies, internet service providers, educational institutions and other commercial entities.  

AGL Networks typically provides underground conduit and dark fiber to its customers under leasing arrangements with terms that vary from 1 to 20 years. In addition, AGL Networks offers telecommunications construction services to companies. Our primary goals for this business in the next 12 to 15 months are to:

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increase revenues through our sales efforts,

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maintain control of capital costs for connecting customers to the network,

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and maintain control of sales and operating expenses.

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Results of operations for energy investments for the three and six months ended June 30, 2004 and 2003 are shown in the following tables. We have also included pro-forma results as if SouthStar’s accounts were consolidated with our subsidiaries’ accounts for the three and six months ended June 30, 2003. These unaudited pro-forma results are presented for comparative purposes only.