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1. BASIS OF PRESENTATION

All adjustments to the unaudited financial statements that are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods have been recorded. Such adjustments consisted of normal recurring items. Certain reclassifications were made to conform prior years' financial statements to the current-quarter presentation.

The unaudited financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended September 30, 2001, 2000, and 1999, included in the 2001 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. On December 5, 2001, the Board of Directors of the Company approved a change in the Company's fiscal year end from September 30 to December 31, effective January 1, 2002. A transition report was filed on Form 10-Q for the period October 1, 2001 to December 31, 2001. Alagasco will continue on a September 30 fiscal year for rate-setting purposes (rate year) and will report on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The Company's natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for the interim periods are not necessarily indicative of the results that may be expected for the year.

As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which, in 1983, established the Rate Stabilization and Equalization (RSE) rate-setting process. RSE was extended with modifications in 2002, 1990, 1987 and 1985. On June 10, 2002, the APSC extended Alagasco's rate-setting methodology, RSE, without change, for a six-year period through January 1, 2008. Under the APSC's new order, Alagasco's allowed range of return remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the returns of all major energy utilities operating under a similar methodology. Under RSE as extended, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and year-to-date performance, whether Alagasco's return on average equity at the end of the rate year will be within the allowed range of 13.15 percent to 13.65 perce nt. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. RSE limits the utility's equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco's operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjust ments. Under RSE as extended, a $16.3 million and a $9.1 million annual increase in revenues became effective December 1, 2001 and 2000, respectively.

Alagasco calculates a temperature adjustment to customers' monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco's earnings. Adjustments to customers' bills are made in the same billing cycle in which the weather variation occurs. The temperature adjustment applies to residential, small commercial and small industrial customers. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply.

The APSC approved an Enhanced Stability Reserve (ESR), beginning October 1997 in the amount of $3.9 million with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses, resulting from force majeure events such as storms, severe weather, and outages, when one or a combination of two such events result in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco's return on average equity to fall below 13.15 percent. During 2001, Alagasco charged $1.2 million against the ESR related to extraordinary bad debt expense and revenue losses from certain large industrial customers. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR of no more than $40,000 monthly until the maximum funding level is achieved. At Jun e 30, 2002, and December 31, 2001, the ESR balance of $2.9 million and $2.7 million, respectively, was included in amounts due customers on the consolidated financial statements.

The Company adopted Statement of Financial Accounting Standard (SFAS) No. 133 (subsequently amended by SFAS Nos. 137 and 138), Accounting for Derivative Instruments and Hedging Activities, on October 1, 2000. This statement requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the Company is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must b e recorded at fair value with gains or losses recognized in earnings in the period of change.

Energen Resources Corporation, Energen's oil and gas subsidiary, periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on oil and gas production. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade status to have available counterparty credit.

Energen Resources had certain agreements with Enron North America Corp. (Enron) as the counterparty as of October 1, 2001. As prescribed by SFAS No. 133, the value of the outstanding Enron contracts which qualified for cash flow hedge accounting treatment was reflected on the balance sheet as an asset and the effective portion of the derivative was reported as OCI, a component of shareholders' equity. These outstanding contracts ceased to qualify as cash flow hedges during October 2001 as a result of Enron's credit issues. The Company recorded an expense to O&M for the write-down to fair value of the asset related to the effected derivative contracts. The deferred revenues related to the non-performing hedges are recorded in accumulated other comprehensive income until such time as they are reclassified to earnings as originally forecasted to occur. As a result, Energen's net income in the three-month transition period ended December 31, 2001, reflected a one-time, non-cash expense of $5.5 million, net of tax. Energen's net income reflected a non-cash benefit of $2 million, net of tax, for the three-month period ended June 30, 2002, and a $4.2 million, net of tax, non-cash benefit for the year-to-date. Net income in the year ended December 31, 2002, will reflect a total non-cash benefit of $5.9 million, net of tax, related to the Enron hedge position.

As of June 30, 2002, $4.2 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, including $1.7 million of gains, net of tax, related to the Enron transactions, are expected to be reclassified to earnings during the next twelve-month period. Gains and losses on derivative instruments that are not accounted for as cash flow hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. The Company recorded an after-tax loss of $477,000 for the three-months ended June 30, 2002, and a $645,000 after-tax loss year-to-date for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, Energen Resources recorded an after-tax loss of $267,000 for the quarter and a $535,000 after-tax gain year-to-date on contracts which did not meet the def inition of cash flow hedges under SFAS No. 133. As of June 30, 2002, the Company had 0.3 billion cubic feet (Bcf) of gas basis hedges, 8.1 Bcf of gas collars, 0.6 million barrels (MMBbl) of oil basis hedges and 0.01 MMBbl of oil swaps that did not meet the definition of a cash flow hedge, however, the Company considers these hedges to be viable economic hedges. As of June 30, 2002, and December 31, 2001, the Company had $3 million and $5.9 million, respectively, included in deferred income taxes on the consolidated balance sheets related to OCI.

As of June 30, 2002, Energen Resources had basin-specific hedges in place for 0.5 Bcf of its estimated 2002 gas production at an average contract price of $3.77 per million cubic feet (Mcf), 9.3 Bcf of gas production hedged at an average NYMEX price of $3.62 per Mcf, 0.2 Bcf of gas production hedged at a NYMEX collar price of $4.25 to $6.15 per Mcf, 3.6 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.25 per Mcf, 3.6 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.30 per Mcf and 2.1 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.62 per Mcf. Energen Resources also had hedges in place for 465 thousand barrels (MBbl) of its estimated oil production at an average NYMEX price of $24.97 per barrel. In addition, the Company had hedged the basis difference on 0.3 Bcf of its estimated 2002 gas production and 0.6 MMBbl of its estimated 2002 oil production. Subsequent to June 30, 2002, Energen Resources entered into additional hedges for 200 2, resulting in a total of 645 MBbl of its oil production hedged at an average NYMEX price of $25.26 per barrel and 1.1 Bcf of its gas basis hedged. Realized prices are anticipated to be lower than NYMEX prices due to basis differences and other factors. Production estimates from continuing operations for 2002 total 75 Bcfe, almost all of which are from proved reserves owned by the Company, and include 46.1 Bcf of gas, 3.1 MMBbl of oil and 1.7 MMBbl of natural gas liquids; another 0.6 Bcfe is expected to be generated by discontinued operations.

As of June 30, 2002, Energen Resources had entered into basin-specific swaps for 1.4 Bcf of its gas production in 2003 at an average contract price of $3.77 per Mcf, swaps for 5.3 Bcf of its 2003 gas production at an average NYMEX price of $4.07 per Mcf and hedges for 4.8 Bcf of gas production at a basin specific collar price of $3.72 to $4.70 per Mcf. In addition, the Company hedged the basis difference on 4.8 Bcf of its estimated 2003 gas production. For 2004 and 2005, Energen Resources had entered into swaps for 1.7 Bcf and 1.2 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively.

All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness in hedging the exposure to the hedged transaction's variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative is not determined to be highly effective as a hedge or it has ceased to be a highly ef fective hedge. The maximum term over which Energen Resources is hedging exposures to the variability of cash flows is through September 30, 2005.

On December 4, 2000, the APSC authorized Alagasco to engage in energy risk management activities to manage the utility's cost of gas supply. As of June 30, 2002, and December 31, 2001, Alagasco had recorded an $8.4 million asset and a $378,000 asset, respectively, representing the fair value of derivatives. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in accordance with Alagasco's APSC-approved tariff.

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company is required to adopt this statement in 2003. The impact of this pronouncement on the Company currently is being evaluated and is not expected to be material.

For the three months and the year-to-date ended June 30, 2002, the Company had 136,300 options and 38,827 shares of non-vested restricted stock that were excluded from the computation of diluted EPS, as their effect was non-dilutive.

The Company principally is engaged in two business segments: the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution) and the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations).

On April 8, 2002, Energen Resources completed its purchase of oil and gas properties located in the Permian Basin in west Texas from First Permian, L.L.C. (First Permian), for approximately $120 million cash and 3,043,479 shares of the Company's common stock. The common stock was valued at $23.95 per share, the average stock price at the time Energen signed the related Purchase and Sale Agreement. The Company estimates a total acquisition cost of approximately $183.5 million; this estimate reflects an effective date of January 1, 2002, with appropriate purchase price adjustments from that date forward until completion of the transaction, resulting from interim cash flows and related tax items.

More than 97 percent of the acquired reserves are oil, and this acquisition adds an estimated 37.8 million barrels of proved oil equivalent reserves to our Permian Basin holdings. The reserves have a reserve to production ratio of 24, and approximately 60 percent are proved developed.

On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which addresses accounting and reporting standards for long-lived assets. This statement requires that gains and losses on the sale of certain oil and gas properties and writedowns of certain properties held-for-sale be reported as discontinued operations, with income or loss from the operations of the associated properties reported as income or loss from discontinued operations. The Statement also provides that all assets classified as held-for-sale be reported at the lower of the carrying amount or fair value. Accordingly, during the second quarter of 2002, Energen Resources recorded a pre-tax writedown of $2.8 million on certain non-strategic gas properties located in the Gulf Coast region, adjusting the carrying amount of the properties to their fair value based upon expected future discounted cash flows. The net carrying amount of these gas properties at June 30, 2002 totaled $2.5 million. The Company is actively marketing the properties being held-for-sale and anticipates disposal within the next year. The Company periodically reviews its portfolio of assets for potential dispositions and receives unsolicited offers to buy certain of its assets.

The following are the results of operations from discontinued operations: