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Retention – Partner with numerous entities, including appliance retailers, HVAC dealers, plumbers, realtors and natural gas marketers to market the benefits of gas appliances and to identify early in the process those customers who may opt to leave our franchise or convert to alternative fuels.

Results of Operations The results of operations for distribution operations are as follows:

(1)

2003 EBIT per customer excludes the gain on the sale of our Caroline Street campus.

(2)

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.

2003 compared to 2002 EBIT increased $22.4 million for 2003 as compared to 2002, primarily as a result of the gain of $21.5 million on the sale of the land from our Caroline Street campus, offset by the $8.0 million donation to AGL Resources Private Foundation, Inc.  Excluding the gain and donation, EBIT increased $8.9 million from improved operations as a result of increased operating margin, partially offset by increased operating expenses.

Operating margin increased $13.6 million from 2002. This was primarily from an increased number of customers and a higher usage per degree day, of which VNG contributed approximately $12.0 million. Pipeline replacement program (PRP) rider revenues increased $2.3 million, resulting from recovery of prior-year program expenses. Carrying costs charged to Marketers for gas stored underground also contributed $0.7 million due to higher storage volumes.  Offsetting the increases was a reduction in AGLC’s rates as compared to prior year of $3.3 million for the first four months of 2003 due to the PBR settlement agreement with the GPSC effective May 1, 2002. CGC’s operating margin for 2003 was not materially different from 2002.

Operating expenses increased $4.2 million from 2002 due primarily to a $2.0 million increase in corporate allocated costs related to an increase in corporate building lease costs and higher general business insurance premiums. Bad debt expenses increased $2.2 million, primarily as a result of colder-than-normal weather and higher natural gas prices. Additional increases in operating expenses were attributed to a $1.2 million VNG regulatory asset write-off in 2003.  These increases in operating expenses were partially offset by a $1.1 million decrease in depreciation expenses due to lower depreciation rates at AGLC for the first four months of 2003 as a result of the PBR settlement agreement with the GPSC.

2002 compared to fiscal 2001 The increase in EBIT of $11.2 million for 2002 compared to fiscal 2001 was primarily due to decreases in operating expenses of $24.4 million, partially offset by decreases in operating margin of $12.7 million.

Operating margin decreased $12.7 million primarily due to the following:

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VNG’s operating margin decreased $11.3 million, resulting from the impact of warmer-than-normal winter weather of $12.4 million, partially offset by a $1.1 million increase in customers and the positive impact of an experimental WNA program that went into effect for the billing cycle beginning November 2002.

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CGC’s operating margin decreased $1.2 million, primarily due to lower use per customer.

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AGLC’s operating margin decreased $0.1 million, primarily due to a $6.7 million decrease in AGLC’s rates as a result of the PBR settlement with the GPSC, and a decrease of $4.3 million as a result of a decline in the number of customers due to fewer end-use customers connecting to our system.  Additional decreases to AGLC margin were a $2.7 million one-time adjustment in 2001 to cost of gas as a result of inventory cost for natural gas stored underground.  These decreases were offset by an $11.0 million increase in AGLC’s PRP rider revenues resulting from recovery of prior-year program expenses, and an increase in carrying costs charged to Marketers for gas stored underground that contributed an additional $3.0 million.

Operating expenses decreased $24.4 million primarily due to the following:

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Operation and maintenance expenses decreased $12.7 million related to reductions in payroll and contract costs as a result of implementing cost efficiencies.

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Bad debt expenses decreased $6.0 million as a result of higher-than-normal bad debt expense in fiscal 2001 due to colder-than-normal weather and higher-than-normal gas prices, resulting in higher customer bills during the 2001 heating season.

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Goodwill amortization decreased $5.2 million from 2001 as a result of the adoption of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” (SFAS 142), effective October 1, 2001.

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Depreciation expense decreased $3.0 million in 2002 as compared to fiscal 2001, due to a decrease of $5.6 million caused by a decline in average depreciation rates (from 3.0% to 2.6%) as a result of AGLC’s PBR settlement with the GPSC effective May 1, 2002, partially offset by an increase in depreciation expenses of $3.3 million due to higher property, plant and equipment balances.

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.  

Asset management transactions Our asset management customers include our affiliated local distribution companies (LDCs), nonaffiliated utilities, municipal customers and industrial customers. These customers must contract for transportation and storage services to meet their peak-day demands, and typically contract for these services on a 365-day basis even though they may only need these services to meet their peak demands for a much shorter period.  We enter into agreements with these customers, either through contract assignment or agency arrangement, whereby we use their rights to transportation and storage services during off-peak periods.  We capture margin by optimizing the purchase, transportation, storage and sale of natural gas, and typically either share profits with customers or pay a fee for using utility assets.  

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

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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.

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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.

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In June 2003, CGC’s tariff was amended effective January 1, 2003 to require all 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. From May 2001 to December 2002, Sequent operated under a bailment agreement and annually paid $0.3 million to manage CGC’s assets.

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

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

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

Peaking services Wholesale services generates operating margin through the sale of peaking services, which includes receiving a fee from customers that guarantees that those customers will receive gas under peak conditions. The primary customer for these peaking services has historically been AGLC. Under these peaking services, wholesale services recorded gross revenues of $10.6 million in 2003, $11.4 million in 2002 and zero in fiscal 2001. All our peaking arrangements expire March 31, 2004. Wholesale services also incurs costs to support our obligations under these agreements, which will be reduced in whole or in part as the matching obligations expire. 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 aggressively enter into new peaking transactions as well as work toward extending those that are set to expire.

Competition Sequent, although regionally focused in the eastern half of the United States, competes for natural gas suppliers and customers with national and regional full-service energy providers, energy merchants, several large commercial and investment banks and natural gas producers. Due to the events in our industry in the last four years, the amount of competition has been significantly reduced. Our success is based on our ability to aggregate competitively priced commodities and services from our transportation and storage capacity and tailor our services to the customers’ needs. We believe that we will continue to provide the basic services many customers are seeking, and we should benefit from the reduction in the number of competitors.

Business Expansion Sequent has been focusing on expanding its business, both geographically and through added emphasis on the origination of new asset management transactions and growing the producer services businesses. Throughout 2003 we added personnel to focus specifically on these opportunities. Our business territory now extends from Texas to Chicago and all other areas of the United States east of the Mississippi River. In the fourth quarter of 2003, we executed four new nonaffiliated asset management transactions and have increased our producer services volumes.  This expansion, as well as our other business growth, has increased Sequent’s fixed cost commitments in the form of firm capacity charges for transportation and storage contracts, and lengthened the average tenure of our portfolio to seven months. At December 31, 2003, Sequent’s longest-dated contract in its portfolio was nine years, with contract terms ranging from one day to nine years. Sequent’s firm capacity commitments currently are

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$9.4 million in 2004

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$2.6 million in 2005

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$1.8 million in 2006

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

Business Outlook Continued growth of the nonaffiliated asset management and producer services business lines will be critical to Sequent’s success in 2004. Given the continued exit of Marketers due to business repositioning and credit limitations, Sequent should benefit through increased market share.  Additionally, although we manage our business with limited open positions and value at risk (VaR), the rescission of EITF 98-10 and our adoption of EITF 02-03 could increase earnings volatility in our reported results, as more fully discussed below under “Energy Marketing and Risk Management activities.”

Energy Marketing and Risk Management Activities During 2003, 2002 and fiscal 2001, we accounted for derivative transactions in connection with our energy marketing activities on a mark-to-market basis in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), and during 2002 and 2001 we accounted for nonderivative energy and energy-related activities in accordance with EITF 98-10.  

Under these methods, we recorded energy commodity contracts (including both physical transactions and financial instruments) at fair value, with unrealized gains or losses from changes in fair value reflected in our earnings in the period of change.  We also recorded energy-trading contracts, as defined under EITF 98-10, on a mark-to-market basis for transactions executed on or before October 25, 2002. Energy-trading contracts entered into after October 25, 2002 were recorded on an accrual basis as required under EITF 02-03’s rescission of EITF 98-10, unless they were derivatives that must be recorded at fair value under SFAS 133.

Effective January 1, 2003, we adopted EITF 02-03, which rescinded 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.

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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.

Our adoption of EITF 02-03 had the following impact:

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We recorded an adjustment to the carrying value of our nonderivative trading instruments (principally our storage capacity contracts) to zero, and now account for them using the accrual method of accounting.  

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

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We reclassified our trading activity on a net basis (revenues net of costs) effective July 1, 2002 as a result of the first consensus of EITF 02-03. This reclassification had no impact on our previously reported net income or shareholders’ equity. Revenues for 2002 and fiscal 2001 are shown net of costs associated with trading activities.

Sequent recorded unrealized gains of $0.7 million, excluding the cumulative effect of a change in accounting principle, during 2003, and unrealized gains of $4.1 million in 2002 and $2.9 million in fiscal 2001, 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 2003 and 2002 and provide details of the net fair value of contracts outstanding as of December 31, 2003. 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 December 31, 2003 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.

We had a net risk management liability at December 31, 2003 of $5.1 million compared to a net risk management asset of $6.8 million at December 31, 2002.  We determined the amounts for 2002 relating to gas storage inventory on a mark-to-market basis, which was the appropriate accounting method at that time.  We recorded the gas storage inventory in 2003 on an accrual basis, at the lower of average cost or market.  Therefore, these amounts are not directly comparable.  The fair value of our gas storage inventory position at December 31, 2003 was higher than average cost, but the fair value is not reflected in the financial statements due to the accounting rules now in effect. 

At December 31, 2003 the fair value of this inventory was in excess of average cost by approximately $5.3 million. We used a calculation to compare the forward value using market prices at the expected withdrawal period with the cost of inventory included in the balance sheet.  Additionally, $1.9 million of this value must be shared under our asset management agreements but would be recorded in accounts payable. This net $3.4 million incremental value would have been reflected in our earnings for the year under mark-to-market accounting. 

Storage Inventory Outlook The NYMEX forward curve graph reflects the NYMEX natural gas prices as of December 31, 2003, also known as the NYMEX forward curve, through November 2004. These are the prices on December 31, 2003 at which we could buy natural gas at the Henry Hub for delivery in the time period of January through November 2004.

“Open futures NYMEX contracts” represents the volume in contract equivalents of the transactions we executed to economically hedge our storage inventory. As of December 31, 2003, the expected withdrawal schedule of this inventory and its weighted average costs are reflected in the entry “physical withdrawal schedule.”  Our futures contracts qualify as derivatives under 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 December 31, 2003. This gross margin could change as we adjust our daily injection and withdrawal plans due to changes in market conditions.

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 gas on or borrow gas from the pipeline in one period and reclaim gas from or repay gas to the pipeline in a subsequent period. The economics of these transactions are evaluated and 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 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 gas is repaid. As a result, these transactions qualify as derivatives under SFAS 133 that 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 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 December 31, 2003 that are 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 forward curves at December 31, 2003.   

(1)

January futures expired on December 29, 2003; however, they are included herein as they coincide with the January storage withdrawals.

(2)

As a result of our positions, a $0.10 parallel change in future NYMEX prices would impact our EBIT by $0.3 million at December 31, 2003. A $0.10 change in the price of gas realized on the withdrawal of physical inventory would impact our EBIT by $0.3 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 lower of average cost or market.

Results of Operations The results of operations for wholesale services are as follows:

2003 compared to 2002 EBIT increased $10.5 million from 2002 primarily due to a $17.1 million increase in operating margin, offset by an increase of $6.3 million in operating expenses.

Operating margin increased $17.1 million due primarily to Sequent’s optimization of various transportation and storage assets, mainly in the first quarter when natural gas prices were highly volatile. In the first quarter, Sequent sold substantially all its inventory that 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 amounts shared with our affiliated LDCs for transactions that were recorded on a mark-to-market basis in prior periods. The increase in operating margin was partly offset by lower natural gas volatility created by unseasonably cool temperatures in the Southeast, Midwest and Upper Mid-Atlantic during the summer of 2003. As compared to the summer of 2002, when volatility was higher as a result of two hurricanes in the Gulf of Mexico and warmer-than-normal temperatures in the Northeast.

Operating expenses increased by $6.3 million, primarily due to a $3.1 million increase in corporate costs and a $3.2 million increase primarily due to personnel and outside consulting costs incurred while growing the business.

Sequent’s physical sales volumes for 2003 increased 26% to 1.75 Bcf/day as compared to 2002. This increase was partially attributable to Sequent’s successful efforts to gain additional new business in the Midwest and Northeast. Additionally, a number of market factors, including colder temperatures during the winter in market areas served by Sequent and reduced amounts of gas in storage as the winter progressed, resulted in increased volatility in Sequent’s markets during the first quarter of 2003 compared to the same period of 2002. The volatility in the second and third quarters returned to seasonal averages and increased slightly above average in the fourth quarter.

2002 compared to fiscal 2001 The increase in EBIT of $6.0 million for 2002 as compared to fiscal 2001 was due to increased operating margin of $11.3 million and a $2.2 million decrease in other loss, offset by a $7.5 million increase in operating expenses.

Operating margin increased $11.3 million, primarily from increased weather volatility from warmer-than-normal weather in the Northeast, two hurricanes during the late summer, colder weather in November and December, and an overall increase in volumes sold. These weather-related events caused interruption in the supply/demand equilibrium between the affected production and market areas, resulting in wide geographical pricing disparities.

Sequent used its access to contracted assets and its expertise in logistics to maximize the profit opportunity by flowing gas on the most economical path available. Additionally, operating margin was positively impacted by peaking services, which were not provided in fiscal 2001.  Physical gas sales volumes increased from 0.1 Bcf/day in fiscal 2001 to 1.39 Bcf/day in 2002.

Operating expenses increased $7.5 million, primarily from the addition of personnel to support growth in the business and a full year of operating expenses following Sequent’s formation in early 2001. Other loss decreased $2.2 million primarily due to the write-off in fiscal 2001 of our investment in Etowah LNG of $2.6 million, resulting from the termination of the joint venture partnership originally formed in 1998.

Energy Investments

Our energy investments segment includes our investments in SouthStar and US Propane LP (US Propane), the results of operations and financial condition of AGL Networks, LLC (AGL Networks), and Utilipro through the date of its sale in 2001.

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SouthStar is a joint venture formed in 1998 by our subsidiary, Georgia Natural Gas Company, Piedmont and Dynegy to market natural gas and related services to retail customers, principally in Georgia. Initially, we owned a 50% interest in SouthStar, Piedmont owned a 30% interest and Dynegy owned the remaining 20% interest.

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. Upon closing, we owned a noncontrolling 70% financial interest in SouthStar and Piedmont owned the remaining 30%. Our 70% interest is noncontrolling because all significant matters require approval by both owners. We recognize our equity in earnings of SouthStar based upon our ownership interest plus the amount recognized for disproportionate sharing, as discussed below.  For all periods prior to February 18, 2003, SouthStar’s earnings have been allocated to us based upon our ownership interests in those periods or 50%.

Competition 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. Based upon its market share, SouthStar is the largest retail marketer of natural gas in Georgia with a monthly year-to-date average of approximately 557,700 customers.  This represents a market share of approximately 37.5% as of December 31, 2003, which is relatively consistent with its market share of 38.2% in the prior year.

Disproportionate sharing SouthStar’s operating policy contains provisions for the disproportionate sharing of earnings with our partner in SouthStar, Piedmont, when SouthStar’s annual earnings before taxes exceed a certain threshold. The threshold is calculated each year based on a cumulative and annual 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. No disproportionate sharing of earnings had occurred prior to December 2003 because the owners had not reached an agreement on how disproportionate sharing should be calculated.

On December 31, 2003, the owners resolved their differences over the interpretation of the provisions in the operating policy that provided for the disproportionate sharing of earnings through an agreement that provides for SouthStar’s 2003 earnings to be allocated 80% to us and 20% to Piedmont, less income allocable to Dynegy prior to February 18, 2003. The agreement resulted in our recognition of $5.9 million of equity earnings for disproportionate sharing for the 12 months ended December 31, 2003.

The agreement also provided for a one-time cash distribution of $40 million to the owners on December 31, 2003, which was allocated $34 million to us and $6 million to Piedmont.  The agreement further resolved all issues related to the allocation of earnings for all years prior to 2003 by allocating earnings for such prior years based on the current owners’ respective interests for such prior fiscal years.

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

In 2003, AGL Networks determined that it would focus on wholesale telecommunications customers. In particular, these customers would use our network to provide communications services to commercial entities or to create private metropolitan networks. 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 to achieve break-even or better results by the end of 2004

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maintain control of capital costs for connecting carriers to the network

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maintain control of sales and operating expenses

Competition AGL Networks’ competitors exist to the extent that they have or will lay conduit and fiber or may install conduit in the future on the same route in the respective metropolitan areas. We believe our footprint in Atlanta is a unique continuous ring and, as such, will be subscribed ahead of most competitors as market conditions support greater use of our product.

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US Propane is a joint venture formed in 2000 by us, Atmos Energy Corporation, Piedmont and TECO Energy, Inc. During 2003, 2002 and fiscal 2001, we owned 22.36% of the limited partnership interests in US Propane.  US Propane owns all the general partnership interests, directly or indirectly, and approximately 25% of the limited partnership interests in Heritage, a publicly traded marketer of propane.

On January 20, 2004, we closed on an agreement to sell our general and limited partnership interests in Heritage. The agreement involved our subsidiaries, AGL Propane Services Inc. and AGL Energy Corporation, and the three other nonaffiliated utility partners. The aggregate transaction was valued at $130 million. Upon closing, we received $29 million for the sale of our interests. We do not expect to recognize a material gain or loss on the transaction in 2004.  

Results of operations The results of operations for energy investments are as follows:

2003 compared to 2002 The increase in EBIT of $19.5 million for 2003 compared to 2002 was primarily the result of increased earnings of $18.9 million from SouthStar and $1.5 million from US Propane, partially offset by decreased EBIT from AGL Networks of $0.6 million.

The $4.3 million increase in operating margin was due to a $3.0 million increase in AGL Networks’ monthly recurring contract revenues, resulting from an increase in the number of executed leases and a $2.3 million sales-type lease completed in the first quarter of 2003.  Also contributing to the year-over-year change is the recognition in 2002 of a $1.0 million feasibility fee; no such fees were recognized in 2003. The $2.7 million increase in operating expenses was primarily due to business growth at AGL Networks and higher corporate overhead costs.

The $17.9 million increase in other income was primarily the result of increased earnings from SouthStar of $18.9 million.  The increased contribution from SouthStar was primarily due to disproportionate sharing of $5.9 million, higher volumes and related operating margin, additional 20% ownership interest (which contributed approximately $8.0 million), and lower bad debt and operating expenses.  US Propane’s earnings increased $1.5 million, primarily due to colder weather as compared to last year.  The increases in other income were partially offset by a $2.0 million contract renewal payment in 2002 associated with the sale of Utilipro.

2002 compared to fiscal 2001 Effective March 2, 2001, we sold substantially all the assets of Utilipro for $17.9 million resulting in a pretax gain of $10.9 million and an aftertax gain of $7.1 million, in fiscal 2001. Excluding this gain, the increase in EBIT in 2002 compared to fiscal 2001 was $13.2 million. The increase in EBIT of $13.2 million for 2002 compared to fiscal 2001 was primarily the result of increased earnings from SouthStar of $13.3 million. These increases in EBIT were offset by a $1.6 million decrease in EBIT at AGL Networks.

The $6.5 million decrease in operating margin was due to a decrease of $7.9 million in Utilipro’s operating margin from its sale in March 2001. The decrease was offset by a  $1.5 million increase in AGL Networks’ operating margin due to growth of the business.

The $4.9 million decrease in operating expenses was due to the absence of $8.5 million of Utilipro’s operating expenses. The decrease was offset by a $3.8 million increase in AGL Networks’ operating expenses due to additional personnel to support the growth of the business

The $3.9 million increase in other income was primarily the result of increased earnings from SouthStar of $13.3 million due to lower bad debt expense as a result of an increase in credit quality of retail customers, lower wholesale costs and a $2.0 million contract renewal payment in 2002 associated with the sale of Utilipro.  The increases were offset by a $10.9 million pretax gain recorded in 2001 for the sale of Utilipro.

Corporate

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

We allocate substantially all of AGSC’s and AGL Capital’s operating expenses and interest costs to our operating segments in accordance with the PUHCA and state regulations. Our corporate segment also includes intercompany eliminations for transactions between our operating business segments.

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

2003 compared to 2002 The decrease in EBIT of $1.3 million for 2003 compared to 2002 was primarily the result of a loss of $5.6 million on the sale of the buildings and their contents at our Caroline Street campus. The decrease was offset by decreased operating expenses of $3.8 million for 2003 as compared to 2002.

The $3.8 million decrease in operating expenses was due to charges incurred in 2002 that were not incurred in 2003, which were not allocated to our operating segments in 2002. In 2002, we recorded $6.4 million for the termination of the automated meter reading contract, $1.6 million for the write-off of capital costs related to a terminated risk management software implementation project and $1.5 million in employee severance costs. These decreases were offset by 2003 expenses not allocated to our operating segments, consisting primarily of $5.3 million in increased compensation and benefit costs.

2002 compared to fiscal 2001 The decrease in EBIT of $8.7 million for 2002 compared to fiscal 2001 was due to operating expenses recorded in 2002 that were not allocated to our operating segments. We recorded a $6.4 million charge for the termination of the automated meter reading contract, $1.6 million for the write-off of capital costs related to a risk management software implementation project and $1.5 million in employee severance costs.

Results of Operations, three-month periods ended December 31, 2001 and 2000.

In this section, the results of operations for the three-month periods ended December 31, 2001 and 2000 are compared. See Note 16, “Financial Information for the Period of October 1, 2000 to December 31, 2000 (Unaudited),” for results of operations and earnings per share information for the three months ended December 31, 2000. The following is a reconciliation of our operating results to operating margin and EBIT for the three months ended December 31, 2001 and 2000:

Net Income The increase in net income of $2.4 million was primarily the result of increased asset management activity at Sequent (which was formed in January 2001), operational efficiencies at VNG and favorable interest rates, offset by warmer weather.

EBIT by Segment

The following table summarizes EBIT for each of our business segments:

Interest Expense The decrease in interest expense of $0.9 million was primarily a result of favorable interest rates on our commercial paper program and favorable interest rate swaps, offset by higher debt balances due to increases in working capital needs.

Income Taxes The increase in income taxes of $0.3 million was due primarily to an increase in income before income taxes of $2.7 million compared to the same period in 2000. The effective tax rate (income tax expense expressed as a percentage of pretax income) for the three months ended December 31, 2001 was 35.3% compared to 37.2% for the same period in 2000.

Distribution Operations

The decrease in EBIT of $0.1 million for the three months ended December 31, 2001 compared to the same period in 2000 was primarily the result of a $12.5 million decrease in operating margin primarily from warmer weather in the VNG service territory. This was offset by a $1.9 million increase in AGLC’s margin as a result of gas carrying costs charged to Marketers due to higher inventory levels.

Operating expenses decreased $10.8 million, primarily from implementation of operational efficiencies at VNG and CGC of $2.1 million. VNG’s franchise taxes decreased $2.1 million, offset by increased income taxes and the bankruptcy of a Marketer of $2.3 million in the quarter ended December 31, 2000.

Wholesale Services

The increase in EBIT of $3.4 million for the three months ended December 31, 2001 compared to the same period in 2000 was due to earnings from Sequent, which was formed in January 2001. Financial results for the three months ended December 31, 2001 were from Sequent’s asset management activities.

Energy Investments

The decrease in EBIT of $3.0 million was primarily due to losses incurred at US Propane and costs incurred by AGL Networks. Operating margin for energy investments was $0.1 million for the three months ended December 31, 2001 and $4.2 million for the same period in 2000. The decrease of $4.1 million was primarily due to the sale of Utilipro in March 2001.

Operating expenses for energy investments were $1.8 million for the three months ended December 31, 2001 and $5.4 million for the same period in 2000.  The decrease of $3.6 million was primarily due to the sale of Utilipro, offset by expenses incurred by AGL Networks. Other income for energy investments was $5.3 million for the three months ended December 31, 2001 and $7.8 million for the same period in 2000. The decrease of $2.5 million was primarily due to losses incurred at US Propane.

Corporate

The increase in EBIT of $1.5 million was primarily due to decreases in corporate expenses. Other losses for corporate were $0.5 million for the three months ended December 31, 2001 and $3.6 million for the same period in 2000. The decrease of $3.1 million was primarily due to corporate expenses of $2.0 million incurred in 2000.

Liquidity and Capital Resources

We rely on operating cash flow; short-term borrowings under our commercial paper program, which is backed by our supporting credit agreements (Credit Facility); and borrowings or stock issuances in the long-term capital markets to meet our capital and liquidity requirements. For the future, we believe these sources will be sufficient for our working capital needs, debt service obligations and scheduled capital expenditures. However, our liquidity and capital resource requirements may change in the future due to a number of factors, some of which we cannot control. These factors include

o

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

o

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

o

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

o

contractual cash obligations and other commercial commitments

o

interest rate changes

o

pension and postretirement benefit costs

o

changes in income tax laws

o

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

o

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

o

operational risks

The availability of borrowings under our Credit Facility is subject to conditions specified within the Credit Facility, which we currently meet. These conditions include compliance with certain financial covenants and the continued accuracy of representations and warranties contained in the agreements. Although we had no borrowings outstanding under our Credit Facility at December 31, 2003, 2002 and 2001, our unused availability under our Credit Facility was limited by our total debt-to-capital ratio at December 31, 2002 and 2001, as represented in the table below:

In January 2003, the FASB released FASB Interpretation No. (FIN) 45, “Guarantor’s 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 expected commercial commitments that were outstanding as of December 31, 2003 and meet the disclosure criteria required by FIN 45:

Contractual Obligations

Presented below is a summary of our contractual obligations as of December 31, 2003. These items are discussed in further detail in Note 9, “Commitments and Contingencies.”

Cash flow from operating activities

We have historically had a working capital deficit, primarily as a result of our borrowings of short-term debt to finance the purchase of long-term assets, principally property, plant and equipment. Year-to-year changes in our operating cash flows are primarily the result of the following:

o

changes in our operating results

o

variability in the distribution of earnings we receive from our equity investments

o

the timing associated with working capital items such as cash collections from our customers

o

payments for operating expenses to our vendors and employees, income taxes and interest

Our statement of cash flows is prepared using the indirect method.  Under this method, net income is reconciled to cash flows from operating activities by adjusting net income for those items that impact net income but do not result in actual cash receipts or payments during the period. These reconciling items include depreciation, undistributed earnings from equity investments, changes in deferred income taxes, gains or losses on the sale of assets and changes in the balance sheet for working capital from the beginning to the end of the period.   

2003 compared to 2002 Our cash flow from operations in 2003 was $122.1 million, a decrease of $163.4 million from 2002. This decrease was primarily the result of increased spending for injection of natural gas inventories of approximately 11 Bcf. The weighted average cost of this inventory increased approximately 30% as compared to last year. In addition, we made $21.5 million in pension contributions this year as a result of our continued efforts to fully fund our pension liability.  This was offset by increased net income of $24.9 million and cash received from SouthStar of $40.0 million.

2002 compared to fiscal 2001 Our cash flow from operations was $285.5 million for 2002, an increase of $185.7 million from fiscal 2001. This increase was primarily as a result of growth in transaction volumes in wholesale services and cash received of $42.2 million from the sale of natural gas inventories, primarily storage gas sold to Marketers, in excess of cash purchases. Also, the increase was a result of increased net income of $14.1 million.

Cash flow from investing activities

In 2003, 2002 and fiscal 2001, cash used in investing activities consisted primarily of property, plant and equipment expenditures. In 2003, our other investing activities included our cash payment of $20.0 million for the purchase of Dynegy’s 20% interest in SouthStar. In 2002, we received $27.3 million in cash from SouthStar and US Propane. In fiscal 2001, we completed the acquisition of VNG, net of cash acquired, for $541.2 million; this was slightly offset by cash received of $17.9 million from the sale of Utilipro. The following table provides additional information on our actual and estimated property, plant and equipment expenditures and our total capital requirements:

(1)

These expenditures include removal costs. We estimate our total future capital expenditures related to the PRP to be $404.3 million. Capital expenditures under this program are expected to end June 30, 2008, unless the program is extended by the GPSC.

(2)

These costs are not included in our cash flows from investing activities as they are not considered property, plant and equipment expenditures. They are considered a factor in our capital requirements as we estimate our cash requirements for future years.

2003 compared to 2002 The decrease of $28.6 million or 15.3% in property, plant and equipment expenditures for 2003 as compared to 2002 was primarily due to lower telecommunications expenditures of $20.4 million as a result of the completion of the metro Atlanta fiber network in 2002, and a decrease in construction of distribution facilities of $8.0 million associated with distribution operations.  The $4.5 million decrease in the ERC expenditures was primarily due to work delays in Augusta and Savannah. The estimated ERC capital requirements for 2004 will increase as a result of these delays.

2002 compared to fiscal 2001 The increase of $31.3 million in property, plant and equipment expenditures for 2002 compared to fiscal 2001 was primarily from AGL Networks’ completion of the metro Atlanta fiber network and the purchase of the Phoenix fiber network.

2004 compared to 2003 In 2004, we estimate that our total capital requirements will increase as a result of capital expenditures for construction of distribution facilities and the PRP.  Our expected increase in the construction of distribution facilities is primarily from Pivotal’s projects in 2004, including the propane facility at VNG.

As shown in the following chart, our PRP costs are expected to increase in the next five years primarily as a result of the replacement of larger-diameter pipe than in prior years, the majority of which is located in more densely populated areas.  We expect the annual PRP costs through 2008 to be in the range of $75 - $80 million each year.  The PRP recoveries shown in the chart are recorded as revenues and are based upon a formula that allows us to recover operation and maintenance costs in excess of those included in AGLC’s base rates, depreciation expense and an allowed rate of return on capital expenditures.  In the near term, the primary financial impact to us from the PRP is reduced cash flow from operating and investing activities, as the timing related to costs recovery does not match the timing of when costs are incurred.

Cash flow from financing activities

Our financing activities are primarily composed of borrowings and payments of short-term debt, payments of Medium-Term notes, borrowings of Senior Notes, cash dividends on our common stock and the issuance of common stock. Our Credit Facility financial covenants and the PUHCA require us to maintain a ratio of total debt-to-total capitalization of no greater than 70.0%. As of December 31, 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 ($6.9) million in 2003.

(2)

Net of interest rate swaps of $3.2 million in 2003 and $6.1 million in 2002.

Short-term Debt Our short-term debt is composed 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 expires June 16, 2004 and a $300 million three-year Credit Facility that terminates on August 7, 2005. As of December 31, 2003, we had no outstanding borrowings under the Credit Facility.

In December 2003, Sequent’s $15.0 million unsecured line of credit was increased to $25.0 million. Sequent used this unsecured line of credit solely for the posting of margin deposits for NYMEX transactions, and it is unconditionally guaranteed by us. This line of credit expires on July 2, 2004 and bears interest at the federal funds effective rate plus 0.5%.  As of December 31, 2003, the line of credit had an outstanding balance of $2.9 million.

Long-term Debt On July 2, 2003, we issued $225.0 million in Senior Notes Due April 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.We used the net proceeds to repay $203.8 million of our Medium-Term notes, discussed below, and approximately $19.6 million of short-term debt. In 2003, we made $207.3 million in Medium-Term note payments, as follows:

o

In April 2003, we exercised our option to redeem two Medium-Term notes totaling $7.2 million before their scheduled maturity dates at a call premium. These notes were scheduled to mature in 2013 and 2014 with interest rates ranging from 7.4% to 7.5%.

o

In July 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 with interest rates ranging from 7.5% to 8.25%.  

o

In October 2003, we repaid on its original due date a $30.0 million Medium-Term note with an interest rate of 5.90%; and we exercised an option to redeem before their scheduled maturity dates a $10.0 million Medium-Term note, at par bearing interest at a rate of 6.0% scheduled to mature in 2006, and a $2.0 million Medium-Term note, at a premium, bearing interest at a rate of 6.85% scheduled to mature in 2020.

o

In December 2003, we exercised our option to redeem $92.8 million of Medium-Term notes at a call premium. These notes were scheduled to mature in 2005 and 2013 bearing interest rates from 6.55% to 7.2%.

In 2002, we made $93.0 million in scheduled Medium-Term note payments using a combination of cash from operations and proceeds from the commercial paper program. On February 23, 2001, we issued $300.0 million in Senior Notes Due February 2011. These Senior Notes have an interest rate of 7.125% payable on January 14 and July 14. In May 2001, we issued and sold $150.0 million in principal amount of 8.0% Trust Preferred Securities. These Trust Preferred Securities are subject to mandatory redemption in May 2041 and may be redeemed early, beginning in 2006.  We used the proceeds of the Senior Notes and Trust Preferred Securities to reduce our commercial paper balance and for general corporate purposes.

Interest Rate Swaps To maintain an effective capital structure, it is our policy to borrow funds using a mix of fixed-rate debt and variable-rate debt. We have entered into interest rate swap agreements through our wholly owned subsidiary, AGL Capital, for the purpose of hedging the interest rate risk associated with our fixed-rate and variable-rate debt obligations. For more discussion of our interest rate swaps, see Note 3, “Risk Management.”

Common Stock On February 14, 2003, we completed our public offering of 6.4 million shares of common stock. 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.  

Dividends on Common Stock On April 16, 2003, we announced a 3.7% increase in our common stock dividend, raising the quarterly dividend from $0.27 per share to $0.28 per share, which equates to an indicated annual dividend of $1.12 per share. In 2003, this increase in our common stock dividend along with the shares issued in connection with our equity offering resulted in an approximately $10 million increase in dividends paid on our common shares.

Shelf Registration We currently have an active shelf registration statement for up to $750 million of various capital securities, with remaining capacity of approximately $383 million. On September 23, 2003, we filed a second shelf registration with the SEC for authority to increase our capacity to $1.0 billion of various capital securities. We may seek additional financing through debt or equity offerings in the private or public markets at any time.

Credit Rating

Our 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 factors:

o

earnings

o

operating cash flow

o

total debt outstanding

o

total equity outstanding

o

pension liabilities and funding status

o

the level of capital expenditures and other commitments

o

fixed charges such as interest expense, rent or lease payments

o

payments to preferred stockholders

o

liquidity needs and availability

o

total debt-to-total capitalization ratios

o

various ratios calculated from these factors

Qualitative factors appear to include, among other things, the stability of regulation in each jurisdiction, risks and controls inherent with wholesale services, predictability of cash flows, business strategy, management, corporate governance principles, board experience and independence, 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. During 2003, no fundamental adverse shift occurred in our ratings profile.

The following table presents as of January 23, 2004 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

o

a maximum leverage ratio

o

minimum net worth

o

insolvency events and nonpayment of scheduled principal or interest payments

o

acceleration of other financial obligations

o

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 ratings or other trigger events. We are currently in compliance with all existing debt provisions and covenants.

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 were not posted, our ability to continue transacting business with these counterparties would be impaired.

At December 31, 2003, if our credit ratings were downgraded to non-investment grade, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $2.9 million. We believe the existing cash and available liquidity under our Credit Facility is adequate to fund these potential liquidity requirements.

Critical Accounting Policies

The selection and application of critical accounting policies are important processes that have 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” (SFAS 71).  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 statements of consolidated income in the period in which we reflect the same amounts in rates.

If any portion of distribution operations 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 sheets and include them in our statements of consolidated income for the period in which the discontinuance of regulatory accounting treatment occurred.

Pipeline Replacement Program (PRP)

AGLC recorded a long-term liability of $322.7 million as of December 31, 2003 and $444.0 million as of December 31, 2002, which represented engineering estimates for remaining capital expenditure costs in the PRP.  As of December 31, 2003, AGLC had recorded a current liability of $81.6 million, representing expected PRP expenditures for the next 12 months. These estimates are reported on an undiscounted basis.

The PRP ordered by the GPSC to be administered by AGLC requires, among other things, that AGLC replace all bare steel and cast iron pipe in AGLC’s system in the state of Georgia within a 10-year period, beginning October 1, 1998. AGLC identified and provided to the GPSC in accordance with this order 2,312 miles of bare steel and cast iron pipe to be replaced. AGLC has subsequently identified an additional 188 miles of pipe subject to replacement under this program.  If AGLC does not perform in accordance with this order, AGLC will be assessed certain nonperformance penalties. The order also provides for recovery of all prudent costs incurred in the performance of the program, which AGLC has recorded as a regulatory asset. The regulatory asset has two components:

o

the costs incurred to date that have not yet been recovered through rate riders

o

the future expected costs to be recovered through rate riders

Environmental Response Costs (ERC)

AGLC historically reported estimates of future remediation costs based on probabilistic models of potential costs. These estimates were reported on an undiscounted basis. As we continue to conduct the actual remediation and 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 cleanup of AGLC’s two largest sites, Savannah and Augusta, which, if proven, could have the effect of further reducing AGLC’s total future expenditures. The following table shows components of AGLC’s ERC liability as of December 31, 2003 and 2002:

(1) As of September 30, 2003 and September 30, 2002.

(2) For the respective calendar years.

(3) Expenditures during the three months ended December 31, 2003 and December 31, 2002.

Our latest available estimate as of September 30, 2003 for those elements of the MGP program with in-place contracts or engineering cost estimates is $66.4 million. This is a reduction of $42.8 million from the estimate as of September 30, 2002 of projected engineering and in-place contracts, resulting from $36.5 million of program expenditures during the 12 months ended September 30, 2003 and a $6.3 million reduction in future cost estimates.  For elements of the MGP program where AGLC still cannot perform engineering cost estimates, considerable variability remains in available estimates. For these elements, the estimated remaining cost of future actions at MGP sites is $15.3 million.

AGLC estimates certain other costs paid directly by AGLC related to administering the MGP program and remediation of sites currently in the investigation phase. Through January 2005, AGLC estimates the administration costs to be $2.7 million. Beyond January 2005, these costs are not estimable. For those sites currently in the investigation phase our estimate is $9.4 million, which is based upon preliminary data received during 2003 with respect to the existence of contamination of those sites. Our range of estimates for these sites is from $9.4 million to $15.1 million. We have accrued the low end of our range, or $9.4 million, as this is our best estimate at this phase of the remediation process.

The ERC liability is included in a corresponding regulatory asset. As of December 31, 2003, the regulatory asset was $179.4 million, which is a combination of the accrued ERC 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 any potential cost savings from the new cleanup technologies referenced above.

Revenue Recognition

Distribution Operations

The VNG and CGC rate structures 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 WNA factor, which offsets the impact of unusually cold or warm weather on operating margins. VNG’s weather normalization factor was introduced in November 2002 as a two-year experimental WNA program. For certain commercial and industria l customers and all wholesale customers, VNG and CGC recognize revenues based upon actual deliveries during the accounting period.

Wholesale Services

We record wholesale services 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.  

Wholesale services accounts for derivative instruments under SFAS 133, which requires us to record all derivatives, as defined therein, in our balance sheets at their fair value. We reflect these derivatives in our consolidated balance sheets as risk management assets or liabilities. The market prices used in estimating the fair value of these contracts are based on our best estimates, utilizing information such as commodity exchange prices, over-the-counter quotes, volatility, 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, wholesale services recognizes the change in value of derivative instruments as a gain or loss in revenues 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 these settlements as receivables and payables separately from risk management activities in the balance sheets as energy marketing receivables and trade 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 reclassification had no impact on our previously reported net income or shareholders’ equity.

During 2003, 2002 and fiscal 2001, we accounted for derivative transactions in connection with our energy marketing activities in accordance with SFAS 133, and during 2002 and 2001 we accounted for nonderivative energy and energy-related activities in accordance with 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 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 nonderivative 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 this adoption, effective January 1, 2003, wholesale services adjusted the fair value of its nonderivative trading instruments to zero and now accounts for them under the accrual method of accounting.  In addition, its natural gas inventories are now recorded at the lower of average cost or market.  The cumulative effect of a change in accounting principle resulted in a $12.6 million pretax reduction to income before the cumulative effect of a change in accounting principle ($7.8 million net of taxes), 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 consolidated balance sheets.

Energy Investments

SouthStar recognizes revenues from sales of natural gas and transportation services in the same period in which it delivers 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 last 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 recognizes 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 consolidated balance sheets.

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 legal title of the 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 Statement No. 13, Accounting for Leases, for Leases of Real Estate” (EITF 00-11), and SFAS No. 66, “Accounting for Sales of Real Estate” (SFAS 66), which provides that such transactions meet the criteria for sales-type lease accounting if the agreement obligates the lessor to 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.  

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” (SFAS 5). 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 changes in the facts or expectations 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 our assumptions about the discount rate, expected return on plan assets and rate of future compensation increases. 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.

As of December 31, 2002, we recorded an additional minimum pension liability of $79.9 million, which resulted in an aftertax loss to other comprehensive income (OCI) of $48.5 million for 2002. At December 31, 2003, we reduced our minimum pension liability by approximately $13.7 million, which resulted in an aftertax gain to OCI of $8.2 million. This reflects the impact of our 2003 funding contributions to the plan and updated valuations for the projected benefit obligation and plan assets. 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 whole or in part under future rate proceedings or mechanisms.

Equity market performance and corporate bond rates have a significant effect on our reported unfunded accumulated benefit obligation (ABO), as the primary factors that drive the value of our unfunded ABO are the assumed discount rate and the actual return on plan assets.  Additionally, equity market performance has a significant effect on our market-related value of plan assets (MRVPA), which is a calculated value and differs from the actual market value of plan assets.  The MRVPA recognizes the differences between the actual market value and expected market value of our plan assets and is determined by our actuaries using a five-year moving weighted average methodology.  Gains and losses on plan assets are spread through the MRVPA based on the five-year moving weighted average methodology, which affects the expected return on plan assets component of pension expense.

A one-percentage-point increase in the assumed discount rate would have a negative impact on the ABO of approximately $30.5 million and would decrease pension expense by approximately $0.5 million. A one-percentage-point decrease in the assumed discount rate would have a positive impact on the ABO of approximately $34.0 million and would increase pension expense by approximately $2.5 million. Additionally, a one-percentage-point increase or decrease in the expected return on assets would decrease or increase our pension expense by approximately $2.6 million.

As of December 31, 2003, the market value of the pension assets was $258.9 million compared to a market value of $207.8 million as of December 31, 2002. The net increase of $51.1 million resulted from

o

contributions of $6.5 million in February 2003

o

contributions of $5.5 million in September 2003

o

contributions of $9.5 million in October 2003

o

contributions of $0.8 million in 2003 to our supplemental retirement plan

o

an actual return on plan assets of $47.9 million less benefits paid of $19.1 million

Our $21.5 million in contributions to the pension plan this year reduced pension expense by approximately $0.8 million in 2003. The actual return on plan assets compared to the expected return on plan assets will 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.

Accounting Developments

FIN 46 In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), which 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 (SPEs), the revised FIN 46 (FIN 46R) is now required to be applied no later than the end of the first fiscal year or interim reporting period ending after March 15, 2004.  The original guidance under FIN 46 is still applicable, however, for all SPEs created prior to February 1, 2003 at the end of the first interim or annual reporting period ending after December 15, 2003. 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 relatio nship with variable interest entities. We will adopt FIN 46R for non-SPE entities as of March 31, 2004.

In June 1997 and March 2001, we established AGL Capital Trust I and AGL Capital Trust II (Trusts) to issue our Trust Preferred Securities. We consider the Trusts to be variable interest entities since the Trusts’ total equity investment at risk is not sufficient to permit the Trusts to finance their own activities without additional subordinated financial support provided by any parties. We consider ourselves the primary beneficiary of the Trusts as we call options on our loans to the Trusts, thus entitling us to a majority of the Trusts’ expected residual returns.

In addition, there is not one party that absorbs a majority of the Trusts’ expected losses, as the Trust Preferred Securities are publicly traded and widely held. As such, we are the primary beneficiary of the Trusts and have consolidated the Trusts under FIN 46. We have, therefore, continued to classify amounts related to the Trust Preferred Securities as “Subsidiaries’ obligated mandatorily redeemable preferred securities” within Capitalization in our consolidated balance sheets as of December 31, 2003.

We believe FIN 46R will have an impact on the accounting for the Trust Preferred Securities. We believe this will result in deconsolidating the trusts, and recording an investment representing our equity investment in the trusts and our liability to the trusts as a long-term liability. At December 31, 2003, we would have included in our balance sheet an asset of approximately $8 million representing our investment in the trusts, and a liability to the trusts totaling approximately $233 million, had we adopted early FIN 46R. This represents the loan payable to fund our investment in the trusts and the amount due to the trusts from the proceeds received from their issuances of preferred securities of $225 million. We are currently finalizing our evaluation of FIN 46R with respect to the Trust Preferred Securities, and will reflect the necessary adjustments in our March 31, 2004 financial statements.

We are also evaluating the potential impact of FIN 46R on our accounting for our investment in SouthStar (see “Energy Investments” section of our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 13, “Equity Investments” for a discussion about the nature, purpose, size and activities of SouthStar), which will be effective in our March 31, 2004 financial statements. It is at least reasonably possible we will deem that SouthStar is a variable interest entity under its current structure and that we are the primary beneficiary. Additionally, we are in negotiations with Piedmont to revise the SouthStar partnership agreement, and   we are also negotiating a management services agreement under which we would provide certain management functions to SouthStar. We believe that such changes to the SouthStar relationship would require us to re-evaluate whether we are the primary beneficiary of SouthStar under the provisions of FIN 46R. If we determine that we are the primary beneficiary pursuant to FIN 46R, we would be required to consolidate SouthStar and would reflect the necessary adjustments in our March 31, 2004 financial statements. As of December 31, 2003, our maximum exposure to loss is our equity investment in SouthStar of $71.2 million. Additionally, we have not provided any loans, guarantees or pledged collateral to SouthStar, and SouthStar’s creditors have no recourse to our general credit.

SFAS 106 Effective December 8, 2003, the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (Medicare Prescription Drug Act), was signed into law, which provides for a prescription drug benefit under Medicare (Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Our defined benefit postretirement health care and life insurance plans do provide a prescription drug benefit.

The FASB issued FASB Staff Position (FSP) 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-1) on January 12, 2004. FSP 106-1 allowed companies to elect a one-time deferral of the recognition of the effects of the Medicare Prescription Drug Act in accounting for its plan under SFAS 106, and in providing disclosures related to the plan required by SFAS 132 (revised 2003) (see below).  The FASB allowed the one-time deferral because of the accounting issues raised by the Medicare Prescription Drug Act, in particular, the accounting for the federal subsidy that is not explicitly addressed in SFAS 106, and because uncertainties exist regarding the direct effects of the Medicare Prescription Drug Act and its ancillary effects on plan participants.

For companies electing the one-time deferral, such deferral remains in effect until authoritative guidance on the accounting for the federal subsidy is issued, or until certain other events, such as a plan amendment, settlement or curtailment, occur.  We are currently evaluating the effects of the Medicare Prescription Drug Act on our other postretirement benefit plan and its participants and have elected the one-time deferral.  Our accumulated postretirement obligation or net periodic postretirement benefit cost for 2003 does not reflect the effects of the Medicare Prescription Drug Act on our other postretirement plan.  Additionally, once the specific authoritative guidance on the accounting for the federal subsidy is issued, such guidance could cause us to change previously reported information.

SFAS 132 On December 23, 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits--an amendment of FASB Statements No. 87, 88 and 106” (SFAS 132 revised 2003).  SFAS 132 (revised 2003) is effective for fiscal years ending after December 15, 2003.  Interim disclosure requirements under SFAS 132 (revised 2003) will be effective for interim periods beginning after December 15, 2003, and required disclosures related to estimated benefit payments will be effective for fiscal years ending after June 15, 2004.  

SFAS 132 (revised 2003) replaces the disclosure requirements in SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87), SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (SFAS 88), and SFAS 106.  SFAS 132 (revised 2003) addresses disclosures only and does not address measurement and recognition accounting for pension and postretirement benefits.  SFAS 132 (revised 2003) requires additional disclosures related to the description of plan assets including investment strategies, plan obligations, cash flows and net periodic benefit cost of defined benefit pension and other defined benefit postretirement plans.  Effective December 31, 2003, we adopted the disclosure requirements of SFAS No. 132 (revised 2003) with the exception of future expected benefit payments, which becomes effective for fiscal years ending after June 15, 2004 or December 31, 2004 for us.

SFAS 143 In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (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 the obligations are incurred. Upon initial recognition of a liability, that cost is 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 in accordance with rates approved by their state jurisdictions.  In our current presentation, we have reclassified our accrual for removal costs from accumulated depreciation to a regulated liability as “Accumulated removal costs” for the years ended December 31, 2003.

SFAS 149 In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149), which amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities, including the qualifications for the normal purchases and normal sales exception. The amendment reflects decisions made by the FASB in connection with issues raised about the application of SFAS 133. Generally, the provisions of SFAS 149 will be applied prospectively for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. Adoption of SFAS 149 did not have a material effect on our consolidated results of operations, cash flows or financial position.

SFAS 150 In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (SFAS 150), which establishes standards for classification and measurement of certain financial instruments with characteristics of both liabilities and equities. Under SFAS 150, such financial instruments are required to be classified as liabilities in the statement of financial position. The financial instruments affected include mandatorily redeemable stock, certain financial instruments that require or may require the issuer to buy back some of its shares in exchange for cash or other assets, and certain obligations that can be settled with shares of stock. SFAS 150 is effective for all financial instruments entered into or modified after May 31, 2003 and was applied to our existing financial instruments beginning on July 1, 2003. Adoption of SFAS 150 did not have a material effect on our consolidated results of operations, cash flows or financial position.

EITF 02-03 During 2003, 2002 and 2001, wholesale services 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. During 2002 and 2001 we accounted for nonderivative energy and energy-related activities in accordance with EITF 98-10.  Under these methods, we recorded energy commodity contracts (including 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 02-03, which rescinded the provisions of EITF 98-10. For more information on our adoption of EITF 02-03 and its effects on our consolidated results of operations, cash flows and financial position, see “Results of Operations” under “Wholesale Services” and “Critical Accounting Policies” under “Revenue Recognition.”

RISK FACTORS

The following are some of the factors that could affect our forward performance or could cause actual results to differ materially from those expressed or implied in our forward-looking statements. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently deem immaterial, also may become important factors that affect us.

Risks Related to Our Business

Risks related to the regulation of our businesses could impact the rates we are able to charge, our costs and our profitability.

Our businesses are subject to regulation by federal, state and local regulatory authorities. In particular, our distribution businesses are regulated by the SEC under the PUHCA, the FERC, the GPSC, the TRA and the VSCC. These authorities regulate many aspects of our distribution operations, including construction and maintenance of facilities, operations, safety, the rates that we can charge customers and the authorized cost of capital. Our ability to obtain rate increases and rate supplements to maintain our current rates of return depends upon regulatory discretion, and there can be no assurance that we will be able to obtain rate increases or rate supplements or continue receiving our currently authorized rates of return.

Deregulation in the natural gas industry is the separation of the provision and pricing of local distribution gas services into discrete components. Deregulation typically focuses on the separation of the gas distribution business from the gas sales business and is intended to cause the opening of the formerly regulated sales services to alternative unregulated suppliers of those services.

In 1997, the Georgia legislature enacted the Natural Gas Competition and Deregulation Act. To date, Georgia is the only state in the Southeast that has fully deregulated gas distribution operations, which ultimately resulted in AGLC exiting the retail natural gas sales business while retaining its gas distribution operations. Gas marketers then assumed the retail gas sales responsibility at deregulated prices. The deregulation process required AGLC to completely reorganize its operations and personnel at significant expense. It is possible that the legislature could reverse the deregulation process and require or permit AGLC to provide retail gas sales service once again. In addition, the GPSC has statutory authority on an emergency basis to order AGLC to temporarily provide the same retail gas service that it provided prior to deregulation. If either of these events were to occur, we would incur costs to reverse the restructuring process.

Our revenues, operating results and financial condition may fluctuate with the economy and its corresponding impact on our customers.

Our business is influenced by fluctuations in the economy. As a result, adverse changes in the economy can have negative effects on our revenues, operating results and financial condition. The level of economic and population growth in our regulated operations’ service territories, particularly new housing starts, directly affects our potential for growing our revenues.

The cost of providing pension and postretirement health care benefits to eligible former employees is subject to changes in pension fund values and changing demographics, and may have a material adverse effect on our financial results.

We have a defined benefit pension plan for the benefit of substantially all full-time employees and qualified retirees. See the section “Critical Accounting Policies.”  The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension fund assets and changing demographics, including longer life expectancy of beneficiaries and an expected increase in the number of eligible former employees over the next five years.

We believe that sustained declines in equity markets and reductions in bond yields have and may continue to have a material adverse effect on the value of our pension funds. In these circumstances, we may be required to recognize an increased pension expense or a charge to our profit and loss account to the extent that the pension fund values are less than the total anticipated liability under the plans.

We face increasing competition, and if we are unable to compete effectively, our revenues, operating results and financial condition will be adversely affected.

The natural gas business is highly competitive, and we are facing increasing competition from other companies that supply energy, including electric companies and, in some cases, energy marketing and trading companies. In particular, the success of our investment in SouthStar is affected by the competition SouthStar faces from other energy marketers providing retail gas services in the Southeast. Natural gas competes with other forms of energy, such as electricity. The primary competitive factor is price. Changes in the price or availability of natural gas relative to other forms of energy and the ability of end-users to convert to alternative fuels affect the demand for natural gas.

Our wholesale services segment competes with larger, full-service energy providers, which may limit our ability to grow our business.

Wholesale services competes with national and regional full-service energy providers, energy merchants, and producers and pipelines for sales based on our ability to aggregate competitively priced commodities with transportation and storage capacity. Some of our competitors are larger and better capitalized than we are and have more national and global exposure than we do. This competition, and the addition of any new competitors, could negatively impact our wholesale services segment and our ability to grow our business.

Our asset management arrangements between Sequent and the affiliated LDCs and between Sequent and its nonaffiliated customers may not be renewed or may be renewed at lower levels, which could have a significant impact on Sequent’s business.

Sequent currently manages the storage and transportation assets of AGLC, VNG, CGC and four nonaffiliated customers, under which Sequent shares profits it earns from the management of those assets with those customers and their customers. Sequent’s results could be significantly impacted in the event that these agreements are not renewed or are amended or renewed with terms less favorable to us.

We have a concentration of credit risk in Georgia, which could expose a significant portion of our accounts receivable to collection risks.

We have a concentration of credit risk related to the provision of natural gas services to Georgia’s Marketers. At September 30, 1998 (prior to deregulation), AGLC had approximately 1.4 million end-use customers in Georgia. In contrast, at December 31, 2003, AGLC had only 10 certificated and active Marketers in Georgia, four of which (based on customer count and including SouthStar) accounted for approximately 57.8% of our total operating margin for 2003. As a result, AGLC now depends on a very limited number of customers for revenues. The failure of these Marketers to pay AGLC could adversely affect AGLC’s business and results of operations and expose it to difficulties in collecting AGLC’s accounts receivable. AGLC obtains security support in an amount equal to a minimum of two times a Marketer’s highest month’s estimated bill from AGLC and also bills intrastate delivery service in advance rather than in arrears. Additionall y, SouthStar markets directly to end-use customers and has periodically experienced credit losses as a result of cold weather, variable prices and customers’ inability to pay.

Our profitability may decline if the counterparties to our transactions fail to perform in accordance with our agreements.

Wholesale services focuses on capturing the value from idle or underutilized energy assets, typically by executing transactions that balance the needs of various markets and time horizons. Wholesale services is exposed to the risk that counterparties to our transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to enter into alternative hedging arrangements, honor the underlying commitment at then-current market prices or return a significant portion of the consideration received for gas under a long-term contract. In such events, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties.

We have a concentration of credit risk at Sequent that could expose us to collection risks.

We often extend credit to our counterparties. Despite performing credit analysis prior to extending credit and seeking to effectuate netting agreements, we are exposed to the risk that we may not be able to collect amounts owed to us. If the counterparty to such a transaction fails to perform and any collateral we have secured is inadequate, we could experience material financial losses.

We have a concentration of credit risk at Sequent, which could expose a significant portion of our credit exposure to collection risks. Approximately 72% of Sequent’s credit exposure is concentrated in 20 counterparties. Although most of this concentration is with counterparties that are either load-serving utilities or end-use customers and that have supplied some level of credit support, default by any of these counterparties in their obligations to pay amounts due Sequent could result in credit losses that would negatively impact our wholesale services segment.

We are exposed to market risk and may incur losses in wholesale services.

The commodity, storage and transportation portfolios of wholesale services consist of contracts to buy and sell natural gas commodities, including contracts that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate, we could experience financial losses from our trading activities. Value at risk (VaR) is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Based on a 95% confidence interval and employing a 1-day and a 10-day holding period for all positions, Sequent’s portfolio of positions as of December 31, 2003 had a 1-day holding period VaR and 10-day holding period VaR of $0.3 million and $1.0 million, respectively.

Our hedging procedures may not fully protect our sales and net income from volatility.

To lower our financial exposure related to commodity price fluctuations, wholesale services may enter into contracts to hedge the value of our energy assets and operations. As part of this strategy, we may utilize fixed-price, forward, physical purchase and sales contracts; futures; and financial swaps and option contracts traded in the over-the-counter markets or on exchanges. However, we do not always hedge against the entire marketplace volatility exposure of our energy assets or our positions. To the extent we have unhedged positions or our hedging procedures do not work as planned, fluctuating commodity prices could cause our net income to be volatile.

Our accounting results may not be indicative of the risks we are taking or the economic results we expect due to changes in accounting for wholesale services.

Although wholesale services enters into various contracts to hedge the value of our energy assets and operations, the timing of the recognition of profits or losses on the hedges does not always match up with the profits or losses on the item being hedged. This can result in volatility in reported earnings from one period to the next that does not exist from an economic standpoint over the full life of the hedge and the hedged item.

Our business is subject to environmental regulation in all jurisdictions in which we operate and our costs to comply are significant, and any changes in existing environmental regulation could negatively affect our results of operations and financial condition.

Our operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Our current costs to comply with these laws and regulations are significant to our results of operations and financial condition.

In addition, claims against us under environmental laws and regulations could result in material costs and liabilities. Existing environmental regulations could also be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur. With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated by us subject to environmental regulation, our environmental expenditures could increase in the future. Additionally, the discovery of presently unknown environmental conditions could give rise to expenditures and liabilities, including fines or penalties, which could have a material adverse effect on our business, results of operations or financial condition.

We could incur additional material costs for the environmental condition of some of our assets, including former manufactured gas plants.

We are generally responsible for all on-site and certain off-site liabilities associated with the environmental condition of the natural gas assets that we have operated, acquired or developed, regardless of when the liabilities arose and whether they are or were known or unknown. In addition, in connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Before natural gas was widely available in the Southeast, we manufactured gas from coal and other fuels. Those manufacturing operations were known as manufactured gas plants, or MGPs, which we ceased operating in the 1950s.

We have identified 10 sites in Georgia and 3 in Florida where we, or our predecessors, own or owned all or part of an MGP site. We are required to investigate possible environmental contamination at those MGP sites and, if necessary, clean up any contamination. To date, we believe that some cleanup is likely at most of the sites and, as of December 2003, the remediation program was approximately 69% complete. As of December 31, 2003, projected costs associated with the MGP sites were $83.0 million. For elements of the MGP program where we still cannot perform engineering cost estimates, considerable variability remains in available future cost estimates.

The success of our telecommunications business strategy may be adversely affected by uncertain market conditions.

The current strategy of our telecommunications business is based upon our ability to lease telecommunications conduit and dark fiber in the Atlanta, Georgia and Phoenix, Arizona metropolitan areas. The market for these services, like the telecommunications industry in general, is very competitive, rapidly changing and currently suffering from lack of market commitments. We cannot be certain that growth in demand for these services will occur as expected. If the market for these services fails to grow as anticipated or becomes saturated with competitors, including competitors using alternative technologies, our investment in the telecommunications business may be adversely affected.

Future acquisitions and expansions, if any, may affect our business by increasing the level of our indebtedness and contingent liabilities and creating integration difficulties.

From time to time, we will evaluate and acquire assets or businesses, or enter into joint venture arrangements that we believe complement our existing businesses and related assets. These acquisitions and joint ventures may require substantial capital or the incurrence of additional indebtedness. Further, acquired operations or joint ventures may not achieve levels of revenues, operating income or productivity comparable to those of our existing operations, or may not otherwise perform as expected. Acquisitions or joint ventures may also involve a number of risks, including

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our inability to integrate operations, systems and procedures

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the assumption of unknown risks and liabilities

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diversion of management’s attention and resources

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difficulty retaining and training acquired key personnel

Risks Related to Our Corporate and Financial Structure

If we breach any of the material financial covenants under our various indentures, credit facilities or guarantees, our debt service obligations could be accelerated.

Our existing debt and the debt of certain of our subsidiaries contain a number of significant financial covenants. If we or any of these subsidiaries breach any of the financial covenants under these agreements, our debt repayment obligations under these agreements could be accelerated. In such event, we may not be able to refinance or repay all our indebtedness, which would result in a material adverse effect on our business, results of operations and financial condition.

We depend on our ability to successfully access the capital markets. Any inability to access the capital or financial markets may limit our ability to execute our business plan or pursue improvements that we may rely on for future growth.

We rely on access to both short-term money markets (in the form of commercial paper) and long-term capital markets as a source of liquidity for capital and operating requirements not satisfied by the cash flow from our operations. If we are not able to access financial markets at competitive rates, our ability to implement our business plan and strategy will be affected. Certain market disruptions may increase our cost of borrowing or affect our ability to access one or more financial markets. Such market disruptions could result from

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adverse economic conditions

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adverse general capital market conditions

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poor performance and health of the utility industry in general

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bankruptcy or financial distress of unrelated energy companies or Marketers in Georgia

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decreases in the market price of and demand for natural gas

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adverse regulatory actions that affect our local gas distribution companies

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terrorist attacks on our facilities or our suppliers

Increases in our leverage could adversely affect our competitive position and financial condition.

An increase in our debt relative to our total capitalization could adversely affect us by

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increasing the cost of future debt financing

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limiting our ability to obtain additional financing, if we need it, for working capital, acquisitions, debt service requirements or other purposes

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making it more difficult for us to satisfy our existing financial obligations

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requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes

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prohibiting the payment of dividends on our common stock or adversely impacting our ability to pay such dividends at the current rate

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increasing our vulnerability to adverse economic and industry conditions

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limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete

Changing rating agency requirements could negatively affect our growth and business strategy, and a downgrade in our credit rating could negatively affect our ability to access capital.

Standard & Poor’s Ratings Group (S&P), Moody’s Investors Service, Inc. (Moody’s) and Fitch, Inc. (Fitch) have recently implemented new requirements for various ratings levels. In order to maintain our current credit ratings in light of these or future new requirements, we may find it necessary to take steps or change our business plans in ways that may affect our growth and earnings per share. S&P and Fitch currently assign our senior unsecured debt a rating of BBB+, and Moody’s currently assigns our senior unsecured debt a rating of Baa1. Our commercial paper currently is rated A-2 by S&P and Moody’s. If the rating agencies downgraded our ratings, particularly below investment grade, it may significantly limit our access to the commercial paper market, and our borrowing costs would increase. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investor s and funding sources would likely decrease.

Additionally, if our credit rating by either S&P or Moody’s falls to non-investment grade status, we will be required to provide additional support for certain customers of our wholesale business. As of December 31, 2003, if our credit rating had fallen below investment grade, we would have been required to provide collateral of approximately $2.9 million to continue conducting our wholesale services business with certain counterparties.

The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.

We use derivatives, including futures, forwards and swaps, to manage our commodity and financial market risks. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could adversely affect the value of the reported fair value of these contracts.

We depend on cash flow from our operations to pay dividends on our common stock.

We depend on dividends or other distributions of funds from our subsidiaries to pay dividends on our common stock. Payments of our dividends will depend on our subsidiaries’ earnings and other business considerations and may be subject to statutory or contractual obligations. Additionally, payment of dividends on our common stock is at the sole discretion of our Board of Directors.

We are vulnerable to interest rate risk with respect to our debt, which could lead to changes in interest expense.

We are subject to interest rate risk in connection with the issuance of fixed-rate and variable-rate debt. In order to maintain our desired mix of fixed-rate and variable-rate debt, we use interest rate swap agreements and exchange fixed-rate and variable-rate interest payment obligations over the life of the arrangements, without exchange of the underlying principal amounts. See the section “Quantitative and Qualitative Disclosures about Market Risk.” We cannot assure you that we will be successful in structuring such swap agreements to effectively manage our risks. If we are unable to do so, our earnings may be reduced.

Risks Related to Our Industry

Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.

Our gas distribution activities involve a variety of inherent hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, and impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events not fully covered by insurance could adversely affect our financial position and results of operations.

Terrorist activities and the potential for military and other actions could adversely affect our businesses.

The threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic and financial market instability and volatility in the price of natural gas that could affect our operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and companies in the energy industry may face a heightened risk of exposure to acts of terrorism. These developments have subjected our operations to increased risks. The insurance industry has also been disrupted by these events. As a result, the availability of insurance covering risks against which we and our competitors typically insure may be limited. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

Recent investigations and events involving the energy markets have resulted in an increased level of public and regulatory scrutiny in the energy industry and in the capital markets, resulting in increased regulation and new accounting standards.

As a result of the bankruptcy and adverse financial condition affecting several entities, particularly the bankruptcy filing by Enron, recently discovered accounting irregularities of various public companies and investigations by governmental authorities into energy trading activities, public companies have been under an increased amount of public and regulatory scrutiny. Recently discovered practices and accounting irregularities have caused regulators and legislators to review current accounting practices, financial disclosures and relationships between companies and their independent auditors. New laws, such as the Sarbanes-Oxley Act of 2002, and regulations to address these concerns have been and continue to be adopted, and capital markets and rating agencies have increased their level of scrutiny. Costs related to increased scrutiny may have an adverse effect on our business, financial condition and access to capital markets. In addition, the FASB or t he SEC could enact new accounting standards that could impact the way we are required to record revenues, assets and liabilities. These changes in accounting standards could lead to negative impacts on our reported earnings or increases in our liabilities.

ITEM 7.(A)

QUALITATIVE AND QUANTITATIVE 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 at AGLC in distribution operations and in wholesale services.

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

Commodity Price Risk

Wholesale Services This segment routinely utilizes various types of financial and other instruments to mitigate certain commodity price risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, option contracts and financial swap agreements.

The 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 or other contractual arrangements. We do not designate our derivative instruments that manage our 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 maximum terms of these maturities are less than 9 years and represent purchases (long) of 410.4 Bcf and sales (short) of 446.8 Bcf, with approximately 95% of these scheduled to mature in less than 2 years and the remaining 5% in 3 – 9 years.

The following table includes the fair values and average values of our energy marketing and risk management assets and liabilities as of December 31, 2003 and 2002. We base the average values on monthly averages for the 12 months ended December 31, 2003 and 2002.

We employ a systematic approach to the evaluation and management of the risks associated with our contracts related to wholesale marketing and risk management, including VaR.  VaR is defined as the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. On September 30, 2003, our RMC approved a proposal to change Sequent’s 20-day VaR holding period to 10 days. This change was made to better align our risk reporting with that of our peers in the energy industry.

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

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

Our management actively monitors open commodity positions and the resulting VaR. We continue to maintain a relatively matched book, where our total buy volume is close to sell volume, with minimal open commodity risk. Based on a 95% confidence interval and employing a 1-day and a 10-day holding period for all positions, our portfolio of positions for the 12 months ended December 31, 2003 had the following 1-day and 10-day holding period VaRs:

(1)

$0.0 values represent amounts less than $0.1 million.

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 stored gas. We purchase gas for storage when the current market price we pay for 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 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.   

Gas that we purchase and inject into storage is accounted for on an accrual basis, at the lower of average cost or market, as inventory in our consolidated balance sheets and is no longer marked to market following our implementation of the accounting guidance in EITF 02-03. Under current accounting guidance, we would recognize a loss in any period when the market price for gas is lower than the 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 statement 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 substantially lock in the margin upon the sale of stored 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 gas storage 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 gas storage inventory will be offset by losses or gains on the derivatives, resulting in 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. Sequent manages underground storage for our utilities and holds certain capacity rights on its own behalf. The underground storage is of two types:

o

reservoir storage, where supplies are generally injected and withdrawn on a seasonal basis

o

salt dome high-deliverability storage, where supplies may be periodically injected and withdrawn on relatively short notice

Energy Investments SouthStar utilizes financial contracts to hedge the price volatility of natural gas. SouthStar considers these financial contracts (futures, options and swaps) to be derivatives, with prices based on selected market indices. SouthStar reflects the derivatives transactions that qualify as cash flow hedges in its balance sheets at the fair values of the open positions with the corresponding unrealized gain or loss included in OCI.  SouthStar reflects the derivatives transactions that are not designated as hedges in its balance sheets with the corresponding unrealized gains or losses included in cost of sales in SouthStar’s statement of income.

SouthStar also 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” (EITF 99-02).

More than 90% of SouthStar’s residential customers buy gas on a variable-price basis, and 6% buy gas on a fixed-price basis.  SouthStar hedges the price risk associated with these fixed-price sales using physical contracts and derivative instruments.

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. To facilitate the achievement of desired fixed to variable-rate debt ratios, AGL Capital entered into interest rate swaps, whereby it agreed to exchange, at specified intervals, the difference between fixed and variable amounts calculated by reference to agreed-upon notional principal amounts. These swaps are designated to hedge the fair values of $100.0 million of the Senior Notes Due 2011, $100.0 million of the Senior Notes Due 2013 and $75.0 million of the $150.0 million Trust Preferred Securities Due in 2041.