Marketing
The decrease in gas marketing revenues for the nine months ended September 30, 2002, relates to a substantial decrease in natural gas commodity prices from the prior year, and was largely offset by a comparable decrease in purchased gas costs. Operating income for the marketing segment was $1.7 million for the first nine months of 2002, compared to $2.2 million for the same period in 2001. The Company marketed 36.2 Bcf of gas in the first nine months of 2002, compared to 36.9 Bcf for the same period in 2001. Volumes marketed for Southwestern's exploration and production subsidiaries were 24.0 Bcf for the first nine months of 2002, compared to 23.5 Bcf in 2001.

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NOARK Pipeline
The Company's share of the NOARK Pipeline System Limited Partnership (NOARK) pre-tax loss included in other income was $.4 million for the first nine months of 2002, down from $1.0 million for the same period in 2001.

Interest Expense
Interest expense decreased 3% for the third quarter of 2002 and 12% for the first nine months of 2002, both as compared to the same periods in 2001, due to lower average borrowings and a lower average interest rate, partially offset by a lower level of capitalized interest. Interest is capitalized in the exploration and production segment on costs that are unevaluated and excluded from amortization.

Income Taxes
The changes in the provisions for deferred income taxes recorded in the three and nine month periods ended September 30, 2002, as compared to the same periods in 2001, resulted primarily from the decrease in the level of taxable income in 2002. Also impacting deferred taxes is the deduction of intangible drilling costs in the year incurred for tax purposes, netted against the turnaround of intangible drilling costs deducted for tax purposes in prior years. Intangible drilling costs are capitalized and amortized over future years for financial reporting purposes under the full cost method of accounting.

Comprehensive Income
In the second quarter of 2002, the Company corrected its presentation of comprehensive income for prior periods to properly reflect amounts associated with hedging activities. This correction resulted in a decrease in comprehensive income of $15.3 million for the nine months ended September 30, 2001. This correction had no effect on the Company's previously reported net income, earnings per share or cash flows, nor did it have any impact on the Company's balance sheet. The prior period corrections in the presentation of comprehensive income were reflected in amendments to the Company's filings on Form 10-K for the year ended December 31, 2001 and Form 10-Q for the three months ended March 31, 2002, both of which were filed in September 2002 in conjunction with the Company's change in auditors from Arthur Andersen LLP to PricewaterhouseCoopers LLP.

Changes in the Company's financial condition at September 30, 2002, as compared to December 31, 2001, primarily reflect changes in the Company's cash flow from operating activities, the

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seasonal nature of the Company's gas distribution segment, the timing of cash payments and receipts and the effects of accounting for the Company's hedging activities as required by SFAS No. 133.

The Company's cash flow from operating activities is highly dependent upon market prices that the Company receives for its gas and oil production. The price that the Company receives for its production is also heavily influenced by the Company's commodity hedging activities. Natural gas and oil prices are subject to wide fluctuations and the prices realized for the nine month period ended September 30, 2002 have declined significantly compared to prices realized during the same period of 2001.

Routine capital expenditures have predominantly been funded through cash provided by operations. For the first nine months of 2002 and 2001, cash provided by operating activities was $68.4 million and $114.7 million, respectively, and met or exceeded the total of these routine requirements.

Financing Requirements
In July 2001, the Company arranged an unsecured revolving credit facility with a group of banks. The revolving credit facility has a current capacity of $140 million and expires in July 2004. The interest rate on the current facility is 150 basis points over the current London Interbank Offered Rate (LIBOR), and was 4.6%, including the effects of interest rate swaps, at September 30, 2002. The interest rate increased 12.5 basis points in July 2002 as the result of a downgrade of the Company's public debt by Moody's from Baa3 to Ba2. Standard and Poor's continues to rate the Company's public debt at BBB.

The revolving credit facility contains covenants which impose certain restrictions on the Company. Under the credit agreement, the Company may not issue total debt in excess of 70% of its total capital, must maintain a certain level of shareholders' equity, and the Company must maintain a ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest expense of at least 3.75 or higher through December 31, 2002. These covenants change over the term of the credit facility and generally become more restrictive. Additionally, the Company is precluded from paying dividends on its common stock under the revolving credit agreement. At September 30, 2002, the Company's revolving credit facility had a balance of $128.2 million and was classified as long-term debt in the Company's balance sheet. The Company has also entered into interest rate swaps for calendar year 2002 that allow the Company to pay an average fixed interest rate of 4.9% (based upon current rates under the revolving credit facility) on $100.0 million of its outstanding revolving debt. Interest rate swaps entered into for 2003 will allow the Company to pay a fixed rate of 3.8% (based upon current rates under the revolving credit facility) on $40.0 million of its outstanding revolving debt.

During the first nine months of 2002, the Company's total debt increased by $3.2 million. Total debt at September 30, 2002, accounted for 66.2% of the Company's capitalization (excluding the Company's several guarantee of NOARK's obligations). The percentage of debt to capitalization at September 30, 2002, would be 65.0% without consideration of the $9.8 million of accumulated

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other comprehensive loss recorded in the equity section of the Company's balance sheet. The other comprehensive loss in the September 30, 2002 balance sheet resulted from the Company's hedging activities and was recorded in accordance with the requirements of SFAS No. 133.

The Company's capital expenditures for the first nine months of 2002 were $67.8 million, compared to $77.1 million for the same period in 2001. Planned capital investments during calendar year 2002 are currently expected to be approximately $88.0 million. This amount includes a recently announced $10.0 million increase in the Company's capital investments for its infill drilling program at its Overton Field in East Texas.

The Company is in the process of selling its non-strategic Oklahoma properties located outside of the Arkoma Basin. Proceeds from this sale will be used to pay down debt and help fund the increase in planned capital investments.

At September 30, 2002, the NOARK partnership had outstanding debt totaling $72.0 million. The Company and the other general partner of NOARK have severally guaranteed the principal and interest payments on the NOARK debt. The Company's share of the several guarantee is 60%.

Working Capital
Accounts receivable has declined since December 31, 2001, primarily due to the seasonality of the gas distribution segment's operations. Changes in accounts payable and other current assets and liabilities since December 31, 2001 are due primarily to the timing of expenditures and receipts and the recording of amounts related to the Company's hedging activities in accordance with SFAS No. 133. Over-recovered purchased gas costs for the Company's gas distribution segment were $5.1 million at September 30, 2002, compared to $8.2 million at December 31, 2001. Purchased gas costs are recovered from the Company's utility customers in subsequent months through automatic cost of gas adjustment clauses included in the utility's filed rate tariffs. At September 30, 2002, the Company had a current hedging asset of $3.3 million, a current hedging liability of $13.9 million, and a regulatory liability of $3.0 million recorded as a result of the provisions of SFAS No. 133.

CRITICAL ACCOUNTING POLICIES

Oil and Gas Properties
The Company utilizes the full cost method of accounting for costs related to its oil and natural gas properties. The Company reviews the carrying value of its oil and gas properties under the full cost accounting rules of the Securities and Exchange Commission on a quarterly basis. Under these rules, all such costs (productive and nonproductive) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test, however, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved gas and oil reserves discounted at 10 percent plus the lower of cost or market value of unproved properties. If the net capitalized costs of oil and natural gas properties exceed the ceiling, the Company will record a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash charge

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to earnings. If required, it reduces earnings and impacts shareholders' equity in the period of occurrence and results in lower depreciation, depletion and amortization expense in future periods. The write-down may not be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.

The risk that the Company will be required to write-down the carrying value of its oil and natural gas properties increases when oil and natural gas prices are depressed or if there are substantial downward revisions in estimated proved reserves. Application of these rules during periods of relatively low oil or natural gas prices, even if temporary, increases the probability of a ceiling test write-down. Based on oil and natural gas prices in effect on September 30, 2002, the unamortized cost of the Company's oil and natural gas properties did not exceed the ceiling of proved oil and natural gas reserves. Natural gas pricing has historically been unpredictable and any significant declines could result in a ceiling test write-down in subsequent quarterly reporting periods.

Oil and natural gas reserves used in the full cost method of accounting cannot be measured exactly. The Company's estimate of oil and natural gas reserves requires extensive judgments of reservoir engineering data and is generally less precise than other estimates made in connection with financial disclosures. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. The uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The Company engages the services of an independent petroleum consulting firm to review reserves as prepared by the Company's reservoir engineers.

Hedging
The Company uses natural gas and crude oil swap agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. The Company's policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings. The primary market risks related to the Company's derivative contracts are the volatility in market prices and basis differentials for natural gas and crude oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged.

The Company's derivative instruments are accounted for under SFAS No. 133 and are recorded at fair value in its financial statements. The Company utilizes market-based quotes from its hedge counterparties to value these open positions. These valuations are recognized as assets or liabilities in the Company's balance sheet and, to the extent an open position is an effective cash flow hedge on equity production or interest rates, the offset is recorded in other comprehensive income. Results of settled commodity hedging transactions are reflected in oil and gas sales or in gas purchases. Results of settled interest rate hedges are reflected in interest expense. Any ineffective hedge, derivative not qualifying for accounting treatment as a hedge, or any ineffective portion

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of a hedge is recognized immediately in earnings. Future market price volatility could create significant changes to the hedge positions recorded in the Company's financial statements. See Part I, Item 3 - Quantitative and Qualitative Disclosures about Market Risk for additional information regarding the Company's hedging activities.

Regulated Utility Operations
The Company's utility operations are subject to the rate regulation and accounting requirements of the Arkansas Public Service Commission. Allocations of costs and revenues to accounting periods for ratemaking and regulatory purposes may differ from bases generally applied by non-regulated operations. Such allocations to meet regulatory accounting requirements are considered generally accepted accounting principles for regulated utilities provided that there is a demonstrated ability to recover any deferred costs in future rates.

During the ratemaking process, the regulatory commission may require a utility to defer recognition of certain costs to be recovered through rates over time as opposed to expensing such costs as incurred. This allows the utility to stabilize rates over time rather than passing such costs on to the customer for immediate recovery. This causes certain expenses to be deferred as a regulatory asset and amortized to expense as they are recovered through rates. The regulatory commission has not required any unbundling of services and there is none currently anticipated. However, should this occur, certain of these assets may no longer meet the criteria for deferred recognition and, accordingly, a write-off of regulatory assets and stranded costs may be required.

See further discussion of the Company's significant accounting policies in Note 1 of Notes to Consolidated Financial Statements in the Company's 2001 annual report on Form 10-K/A.

All statements, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, the timing and extent of changes in commodity prices for gas and oil, the timing and extent of the Company's success in discovering, developing, producing, and estimating reserves, property acquisition or divestiture activities that may occur, the effects of weather and regulation on the Company's gas distribution segment, increased competition, legal and economic factors, governmental regulation, the financial impact of accounting regulations, changing market conditions, the comparative cost of alternative fuels, conditions in capital markets and changes in interest rates, availability of oil field services, drilling rigs and other equipment, as well as various other factors beyond the Company's control.

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Market risks relating to the Company's operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as credit risk concentrations. The Company uses natural gas and crude oil swap agreements and options and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and oil and in interest rates. The Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price and interest rate risks. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risks
The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of customers and their dispersion across geographic areas. No single customer accounts for greater than 5% of accounts receivable. See the discussion of credit risk associated with commodities trading below.

Interest Rate Risk
The Company's revolving debt obligations are sensitive to changes in interest rates. The Company's policy is to manage interest rates through use of a combination of fixed and floating rate debt. Interest rate swaps may be used to adjust interest rate exposures when appropriate. The Company has entered into interest rate swaps for calendar year 2002 that allow the Company to pay an average fixed interest rate of 4.9% (based upon current rates under the revolving credit facility) on $100.0 million of its outstanding revolving debt. The Company's revolving debt was $125.0 million at December 31, 2001, and had an average interest rate of 3.4%. At September 30, 2002, the Company's revolving debt was $128.2 million with an average interest rate of 4.6%, including the effect of the interest rate swaps. Other than the Company's revolving debt, there have been no material changes in the interest rate risk information that was presented in the Company's 2001 annual report on Form 10-K/A.

The Company's interest rate swaps have a carrying amount of $1.9 million, calculated as the contractual payments for interest on the notional amount to be exchanged under futures contracts and does not represent amounts recorded in the Company's financial statements. The fair value of $1.1 million represents the value for the same contracts using comparable market prices at September 30, 2002. At September 30, 2002, the "Carrying Amount" exceeded the "Fair Value" of interest rate swaps by $.8 million.

Commodities Risk
The Company uses over-the-counter natural gas and crude oil swap agreements and options to hedge sales of Company production, to hedge activity in its marketing segment, and to hedge the purchase of gas in its utility segment against the inherent price risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX (New York Mercantile Exchange) futures market. These swaps and options include (1) transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps), (2) transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps), and (3) the purchase and sale of index-related puts and calls (collars) that provide a "floor" price below which the counterparty pays (production hedge) or receives (gas purchase hedge) funds equal to the amount by which the price of the commodity is below the contracted floor, and a "ceiling" price above which the Company pays to (production hedge) or receives from (gas purchase hedge) the counterparty the amount by which the price of the commodity is above the contracted ceiling.

The primary market risks related to the Company's derivative contracts are the volatility in market prices and basis differentials for natural gas and crude oil. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas or sale of the oil that is hedged. Credit risk relates to the risk of loss as a result of non-performance by the Company's counterparties. The counterparties are primarily major investment and commercial banks which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure the Company has to each counterparty are periodically reviewed to ensure limited credit risk exposure.

The following table provides information about the Company's financial instruments that are sensitive to changes in commodity prices. The table presents the notional amount in Bcf (billion cubic feet) and MBbls (thousand barrels), the weighted average contract prices, and the total dollar contract amount by expected maturity dates. The "Carrying Amount" for the contract amounts is calculated as the contractual payments for the quantity of gas or oil to be exchanged under futures contracts and does not represent amounts recorded in the Company's financial statements. The "Fair Value" represents values for the same contracts using comparable market prices at September 30, 2002. At September 30, 2002, the "Carrying Amount" exceeded the "Fair Value" of these financial instruments by $12.3 million.