UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

FORM 10-K

|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2003

|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___

COMMISSION                                                         IRS EMPLOYER
   FILE                                        STATE OF           IDENTIFICATION
  NUMBER              REGISTRANT             INCORPORATION            NUMBER
--------------------------------------------------------------------------------
  1-7810          ENERGEN CORPORATION           ALABAMA             63-0757759
 2-38960       ALABAMA GAS CORPORATION          ALABAMA             63-0022000

605 RICHARD ARRINGTON JR. BOULEVARD NORTH
BIRMINGHAM, ALABAMA 35203-2707
TELEPHONE NUMBER 205/326-2700
HTTP://WWW.ENERGEN.COM

Securities Registered Pursuant to Section 12(b) of the Act:

TITLE OF EACH CLASS                                     EXCHANGE ON WHICH REGISTERED
-------------------                                     ----------------------------
Energen Corporation Common Stock, $0.01 par value       New York Stock Exchange
Energen Corporation Preferred Stock Purchase Rights     New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act: NONE

Indicate by a check mark whether registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. YES |X| NO |_|

Indicate by a check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |_|

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). YES |X| NO |_|

Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30 2003:

Energen Corporation                            $1,160,436,680

Indicate number of shares outstanding of each of the registrant's classes of
common stock as of March 4, 2004:

Energen Corporation                            36,346,358 shares
Alabama Gas Corporation                         1,972,052 shares

Alabama Gas Corporation meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format pursuant to General Instruction I(2).

DOCUMENTS INCORPORATED BY REFERENCE

Energen Corporation Proxy Statement to be filed on or about March 29, 2004 (Part III, Item 10-13)


INDUSTRY GLOSSARY

FOR A MORE COMPLETE DEFINITION OF CERTAIN TERMS DEFINED BELOW, PLEASE REFER TO RULE 4-10(A) OF REGULATION S-X, PROMULGATED PURSUANT TO THE SECURITIES ACT OF 1933 AND THE SECURITIES EXCHANGE ACT OF 1934, EACH AS AMENDED.

BASIS                         The difference between the futures price for a
                              commodity and the corresponding cash spot price.
                              The differential commonly is related to factors
                              such as product quality, location and contract
                              pricing.

BASIN-SPECIFIC                A type of derivative contract whereby the
                              contract's settlement price is based on specific
                              geographic basin indices.

BEHIND PIPE RESERVES          Oil or gas reserves located above or below the
                              currently producing zone(s) which cannot be
                              extracted until a recompletion or pay-add occurs.

CASH FLOW HEDGE               The designation of a derivative instrument to
                              reduce exposure to variability in cash flows from
                              the forecasted sale of oil, gas or natural gas
                              liquids production whereby the gains (losses) on
                              the derivative transaction are anticipated to
                              offset the losses (gains) on the forecasted sale.

COLLAR                        A financial arrangement that effectively
                              establishes a price range for the commodity. The
                              producer only bears the risk of fluctuation
                              between the minimum (or floor) price and the
                              maximum (or ceiling) price.

DEVELOPMENT WELL              A well drilled within the proved area of an oil or
                              gas reservoir to the depth of a stratigraphic
                              horizon known to be productive.

EXPLORATORY WELL              A well drilled to a previously untested geologic
                              structure to determine the presence of oil or gas.

FUTURES CONTRACT              An exchange-traded legal contract to buy or sell a
                              standard quantity and quality of a commodity at a
                              specified future date and price. Such contracts
                              offer liquidity and minimal credit risk exposure
                              but lack the flexibility of swap contracts.

HEDGING                       The use of derivative commodity instruments such
                              as futures, swaps and collars to help reduce
                              financial exposure to commodity price volatility.

LIQUIFIED NATURAL GAS         Natural gas that is liquified by reducing the
(LNG)                         temperature to negative 260 degrees Fahrenheit.
                              LNG typically is used to supplement traditional
                              natural gas supplies during periods of peak
                              demand.

LONG-LIVED RESERVES           Reserves generally considered to have a productive
                              life of approximately 10 years or more, as
                              measured by the reserves-to-production ratio.

NATURAL GAS LIQUIDS (NGL)     Liquid hydrocarbons that are extracted and
                              separated from the natural gas stream. NGL
                              products include ethane, propane, butane, natural
                              gasoline and other hydrocarbons.

ODORIZATION                   A characteristic odor added to natural gas so that
                              leaks can be readily detected by smell.

OPERATIONAL ENHANCEMENT       Any action undertaken to improve production
                              efficiency of oil and gas wells and/or reduce well
                              costs.

OPERATOR                      The company responsible for exploration,
                              development and production activities for a
                              specific project.

PAY-ADD                       An operation within a currently producing wellbore
                              that attempts to access and complete an additional
                              pay zone(s) while maintaining production from the
                              existing completed zone(s).

PAY ZONE                      The formation from which oil and gas is produced.

PROVED DEVELOPED RESERVES     The portion of proved reserves which can be
                              expected to be recovered through existing wells
                              with existing equipment and operating methods.

PROVED RESERVES               Estimated quantities of crude oil, natural gas and
                              natural gas liquids that geological and
                              engineering data demonstrate with reasonable
                              certainty to be recoverable in future years from
                              known reservoirs under existing economic and
                              operating conditions.

PROVED UNDEVELOPED            The portion of proved reserves which can be
RESERVES (PUD)                expected to be recovered from new wells on
                              undrilled proved acreage or from existing wells
                              where a relatively major expenditure is required
                              for completion.

PUT OPTION                    A contract that gives the purchaser the right, but
                              not the obligation, to sell the underlying
                              commodity at a certain price on or before an
                              agreed date.

RECOMPLETION                  An operation within an existing wellbore whereby a
                              completion in one pay zone is abandoned in order
                              to attempt a completion in a different pay zone.

RESERVES-TO- PRODUCTION       Ratio expressing years of supply determined by
RATIO                         dividing the remaining recoverable reserves at
                              year end by actual annual production volumes.

SECONDARY RECOVERY            The process of injecting water, gas, etc., into a
                              formation in order to produce additional oil
                              otherwise unobtainable by initial recovery
                              efforts.

SWAP                          A contractual arrangement in which two parties,
                              called counterparties, effectively agree to
                              exchange or "swap" variable and fixed rate payment
                              streams based on a specified commodity volume. The
                              contracts allow for flexible terms such as
                              specific quantities, settlement dates and location
                              but also expose the parties to counterparty credit
                              risk.

TRANSPORTATION                Moving gas through company pipelines on a contract
                              basis for others.

THROUGHPUT                    Total volumes of natural gas sold or transported
                              by the gas utility.

WORKING INTEREST              The ownership interest in the oil and gas
                              properties which is burdened with the cost of
                              development and operation of the property.

WORKOVER                      A major remedial operation on a completed well to
                              restore, maintain, or improve the well's
                              production such as deepening the well or plugging
                              back to produce from a shallow formation.

-E                            Following a unit of measure denotes that the oil
                              and natural gas liquids components have been
                              converted to cubic feet equivalents at a rate of 6
                              thousand cubic feet per barrel.

                               ENERGEN CORPORATION
                          2003 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

                                                                                                            PAGE
                                                                                                            ----
                                                    PART I

Item 1.     Business......................................................................................  3
Item 2.     Properties....................................................................................  9
Item 3.     Legal Proceedings.............................................................................  9
Item 4.     Submission of Matters to a Vote of Security Holders...........................................  9

                                                    PART II

Item 5.     Market for Registrant's Common Equity and Related Stockholder Matters.........................  11

Item 6.     Selected Financial Data.......................................................................  12
Item 7.     Management's Discussion and Analysis of Financial Condition and Results of Operations.........  14
Item 7A.    Quantitative and Qualitative Disclosures about Market Risk....................................  29
Item 8.     Financial Statements and Supplementary Data...................................................  30
Item 9.     Changes in and Disagreements With Accountants on Accounting and
            Financial Disclosure..........................................................................  77

Item 9A.    Controls and Procedures.......................................................................  77

                                                   PART III

Item 10.    Directors and Executive Officers of the Registrants...........................................  78
Item 11.    Executive Compensation........................................................................  78
Item 12.    Security Ownership of Certain Beneficial Owners and Management and
            Related Stockholder Matters...................................................................  78

Item 13.    Certain Relationships and Related Transactions................................................  78
Item 14.    Principal Accountant Fees and Services........................................................  78

                                                    PART IV

Item 15.    Exhibits, Financial Statement Schedules, and Reports on Form 8-K..............................  79
Signatures  ..............................................................................................  83

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This Form 10-K is filed on behalf of Energen Corporation


(Energen or the Company)

and Alabama Gas Corporation (Alagasco).

FORWARD-LOOKING STATEMENT AND RISK FACTORS: Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. The Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. The Company undertakes no obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, future business decisions, and other uncertainties, all of which are difficult to predict.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources Corporation, the Company's oil and gas subsidiary, is unable to fully invest its planned acquisition, development and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors.

Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate risk, fluctuations in future oil and gas prices could materially affect the Company's financial position and results of operation and cash flows; furthermore, such risk mitigation activities may cause the Company's financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk-mitigation assumes that counterparties maintain satisfactory credit quality.

PART I

ITEM 1. BUSINESS

GENERAL

Energen Corporation, based in Birmingham, Alabama, is a diversified energy holding company engaged primarily in the acquisition, development, exploration and production of oil, natural gas and natural gas liquids in the continental United States and in the purchase, distribution, and sale of natural gas, principally in central and north Alabama. Its two major subsidiaries are Energen Resources Corporation and Alabama Gas Corporation (Alagasco).

Energen was incorporated in Alabama in 1978 in connection with the reorganization of its oldest subsidiary, Alagasco. Alagasco was formed in 1948 by the merger of Alabama Gas Company into Birmingham Gas Company, the predecessors of which had been in existence since the mid-1800s. Alagasco became a public company in 1953. Energen Resources was formed in 1971 as a subsidiary of Alagasco and became a subsidiary of Energen in the 1978 reorganization.

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. Alagasco retained a September 30 fiscal year end for rate-setting purposes.

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The Company maintains a Web site with the address www.energen.com. The Company does not include the information contained on its Web site as part of this report nor is the information incorporated by reference into this report. The Company makes available free of charge through its Web site the annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports. These reports are provided as soon as reasonably practicable after such reports are electronically filed with or furnished to the Securities and Exchange Commission. The Company's Web site also includes its Code of Ethics, Corporate Governance Guidelines, Audit Committee Charter, Officers' Review Committee Charter, Governance and Nominations Committee Charter and Finance Committee Charter.

FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS

The information required by this item is provided in Note 21, Industry Segment Information, in the Notes to Financial Statements.

NARRATIVE DESCRIPTION OF BUSINESS

- OIL AND GAS OPERATIONS

GENERAL: Energen's oil and gas operations focus on increasing production and adding proved reserves through the acquisition and development of oil and gas properties. To a lesser extent, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. Substantially all gas, oil and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Black Warrior Basin in Alabama for its partners and third parties. These services include overall project management and day-to-day decision-making relative to project operations.

At the end of 2003, Energen Resources' inventory of proved oil and gas reserves totaled 1,364.9 billion cubic feet equivalent (Bcfe). Substantially all of the company's approximately 1.4 trillion cubic feet equivalent of reserves are located in the San Juan Basin in New Mexico, the Permian Basin in west Texas, the Black Warrior Basin in Alabama, and the north Louisiana/east Texas region. Approximately 81 percent of Energen Resources' year-end reserves are proved developed reserves. Energen Resources reserves are long-lived, with a year-end reserves-to-production ratio of 16. Natural gas represents approximately 65 percent of Energen Resources' proved reserves, with oil representing approximately 23 percent and natural gas liquids comprising the balance.

GROWTH STRATEGY: Energen has operated for more than eight years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $755 million in property acquisitions, $555 million in related development, and $90 million in exploration and related development. Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2008, is currently expected to approximate $1.4 billion, the majority of which represents unidentified acquisitions and related development.

Energen Resources' approach to the oil and gas business calls for the company to pursue onshore North American property acquisitions which offer proved undeveloped (PUD) and/or behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers operated natural gas properties with long-lived reserves and multiple pay-zone opportunities; however, Energen Resources does not preclude possible acquisitions of properties with varying characteristics that otherwise meet its investment requirements.

Following an acquisition, Energen Resources focuses on increasing production and reserves through development of the properties' PUD and behind-pipe reserve potential as well as engaging in other development activities. These activities include development well drilling, behind-pipe recompletions, pay-adds, workovers, secondary recovery and operational enhancements. Energen Resources prefers to operate its properties in order to better control the nature and pace of development activities.

Energen Resources' development activities can result in the addition of new proved reserves and can serve to reclassify proved undeveloped reserves to proved developed reserves. Proved reserve disclosures are provided annually, although changes to reserve classifications occur throughout the year. Accordingly, additions of new

5

reserves from development activities can occur throughout the year and may result from numerous factors including, but not limited to, regulatory approvals for drilling unit downspacing which increase the number of available drilling locations; changes in the economic or operating environments which allow previously uneconomic locations to be added; technological advances which make reserve locations available for development; successful development of existing PUD locations which reclassify adjacent probable locations to PUD locations; increased knowledge of field geology and engineering parameters relative to oil and gas reservoirs; and changes in management's intent to develop certain opportunities.

Since the end of fiscal year 2000, the Company's development efforts have added approximately 357 Bcfe of proved reserves from the drilling of approximately 749 gross development wells and 406 well recompletions and pay-adds. In 2003, Energen Resources' successful development wells and other activities added approximately 135 Bcfe of proved reserves. The company drilled 347 gross development wells, performed some 145 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources' production from continuing operations totaled 85.4 Bcfe in 2003 and is estimated to total 85 Bcfe in 2004, including 81.6 Bcfe of estimated production from proved reserves owned at December 31, 2003.

RISK MANAGEMENT: Energen Resources attempts to lower the risks associated with its oil and natural gas business. A key component of the company's efforts to manage risk is its acquisition versus exploration orientation and its preference for long-lived reserves. In pursuing an acquisition, Energen Resources primarily uses the then-current oil and gas futures prices in its evaluation models, the prevailing swap curve and, for the longer-term, its own pricing assumptions. After a purchase, Energen Resources may use futures, swaps and/or fixed-price contracts to hedge commodity prices on flowing production for up to 36 months to help protect targeted returns from price volatility. On an on-going basis, Energen Resources may hedge up to 80 percent of its estimated annual production in any given year depending on its pricing outlook.

Statement of Financial Accounting Standards (SFAS) No. 133 (as amended), "Accounting for Derivative Instruments and Hedging Activities," 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 as a component of equity and subsequently reclassified into operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized as operating revenues in earnings in the period of change under mark-to-market accounting.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, put options and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change.

See the Forward-Looking Statement and Risk in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion with respect to price and other risk.

ENVIRONMENTAL MATTERS: Energen Resources is subject to various environmental regulations. Management believes that Energen Resources is in compliance with currently applicable standards of the environmental agencies to which it is subject and that potential environmental liabilities are minimal. To the extent that Energen Resources has operating agreements with various joint venture partners, environmental costs would be shared proportionately.

RISK FACTORS: For a discussion of risks inherent in the Company's businesses, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

6

- NATURAL GAS DISTRIBUTION

GENERAL: Alagasco is the largest natural gas distribution utility in the state of Alabama. Alagasco purchases natural gas through interstate and intrastate marketers and suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from producers, marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a fee to transport such customer-owned gas through its distribution system to the customers' facilities.

Alagasco's service territory is located in central and parts of north Alabama and includes approximately 185 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.4 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2003, Alagasco served an average of 427,413 residential customers and 35,463 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 9,810 miles of main and more than 11,494 miles of service lines, odorization and regulation facilities, and customer meters.

APSC REGULATION: 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 in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended RSE for a six-year period, through January 1, 2008. Under the APSC order, Alagasco's allowed range of return on average equity 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 on equity of all major energy utilities operating under a similar methodology. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year).

Under RSE, 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. 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 adjustments.

The temperature adjustment rider to Alagasco's rate tariff, approved by the APSC in 1990, was designed to mitigate the earnings impact of variances from normal temperatures. Alagasco calculates a temperature adjustment to customers' monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco's earnings. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers' bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. Adjustments to customers' bills are made in the same billing cycle in which the weather variation occurs. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider that 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, 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

7

combination of two such events results 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 equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR in an amount of no more than $40,000 monthly until the maximum funding level is achieved.

GAS SUPPLY: Alagasco's distribution system is connected to two major interstate natural gas pipeline systems - Southern Natural Gas Company (Southern) and Transcontinental Gas Pipe Line Company (Transco). It is also connected to several intrastate natural gas pipeline systems and to Alagasco's two liquified natural gas (LNG) facilities.

Alagasco purchases natural gas from various natural gas producers and marketers. Certain volumes are purchased under firm contractual commitments with other volumes purchased on a spot market basis. The purchased volumes are delivered to Alagasco's system using a variety of firm transportation, interruptible transportation and storage capacity arrangements designed to meet the system's varying levels of demand. Alagasco's LNG facilities can provide the system with up to 200,000 additional thousand cubic feet per day (Mcfd) of natural gas to meet peak day demand.

As of December 31, 2003, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:

--------------------------------------------------------------------------
                                                      DECEMBER 31, 2003
--------------------------------------------------------------------------
                                                           (Mcfd)
                                                      -----------------
Southern firm transportation                              164,332
Southern storage and no notice transportation             251,679
Transco firm transportation                               100,000
Various intrastate transportation                          23,900
--------------------------------------------------------------------------

COMPETITION AND RATE FLEXIBILITY: The price of natural gas is a significant competitive factor in Alagasco's service territory, particularly among large commercial and industrial transportation customers. Propane, coal and fuel oil are readily available, and many industrial customers have the capability to switch to alternate fuels and/or alternate sources of gas. In the residential and small commercial and industrial markets, electricity is the principal competitor. With the support of the APSC, Alagasco has implemented a variety of flexible rate strategies to help it compete for the large customer gas load in the deregulated marketplace. Rate flexibility remains critical as the utility faces competition for this load. To date, the utility has been effective in utilizing its flexible rate strategies to minimize bypass and price-based switching to alternate fuels and alternate sources of gas.

In 1994 Alagasco implemented the P Rate in response to the competitive challenge of interstate pipeline capacity release. Under this tariff provision, Alagasco releases much of its excess pipeline capacity and repurchases it as agent for its transportation customers under 12 month contracts. The transportation customers benefit from lower pipeline costs. Alagasco's core market customers benefit, as well, since the utility uses the revenues received from the P Rate to decrease gas costs for its residential and small commercial and industrial customers. In 2003, approximately 300 of Alagasco's transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled approximately $7.5 million.

The Competitive Fuel Clause (CFC) and Transportation Tariff also have been important to Alagasco's ability to compete effectively for customer load in its service territory. The CFC allows Alagasco to adjust large customer rates on a case-by-case basis to compete with alternate fuels and alternate sources of gas. The GSA rider to Alagasco's tariff allows the Company to recover the reduction in charges allowed under the CFC because the retention of any customer, particularly large commercial and industrial transportation customers, benefits all customers by recovering a portion of the system's fixed costs. The Transportation Tariff allows Alagasco to transport gas for customers, rather than buy and resell it to them, and is based on Alagasco's sales profit margin so that operating margins are unaffected. During 2003 substantially all of Alagasco's large commercial and industrial customer deliveries were the transportation of customer-owned gas. In addition, Alagasco served as

8

gas purchasing agent for approximately 99 percent of its transportation customers. Alagasco also uses long-term special contracts as a vehicle for retaining large customer load. At the end of 2003, 50 of the utility's largest commercial and industrial transportation customers were under special contracts of varying lengths.

Natural gas service available to Alagasco customers falls into two broad categories: interruptible and firm. Interruptible service contractually is subject to interruption by Alagasco for various reasons; the most common occurrence is curtailment of industrial customers during periods of peak core market heating demand. Interruptible service typically is provided to large commercial and industrial transportation customers who can reduce their gas consumption by adjusting production schedules or by switching to alternate fuels for the duration of the service interruption. More expensive firm service, on the other hand, generally is not subject to interruption and is provided to residential and small commercial and industrial customers; these core market customers depend on natural gas primarily for space heating.

GROWTH: Customer growth presents a major challenge for Alagasco, given its mature, slow-growth service area. In 2003, Alagasco's average number of customers increased slightly. For 2004, Alagasco will concentrate on maintaining its current penetration levels in the residential new construction market while increasing its focus on generating additional revenue in the small and large commercial and industrial market segments.

A vehicle for supplementing Alagasco's normal growth continues to be Alagasco's municipal acquisition program. Since 1985, Alagasco has acquired 23 municipally owned systems adding more than 43,000 customers through initial system purchases and subsequent customer additions. Approximately 75 municipal systems remain in Alabama. Alagasco continues to pursue the purchase of municipal gas systems, and company management believes that such acquisitions could offer future growth opportunities.

SEASONALITY: Alagasco's gas distribution business is highly seasonal since a material portion of the utility's total sales and delivery volumes is to space heating customers. Alagasco's rate tariff includes a temperature adjustment rider primarily for residential, small commercial and small industrial customers which substantially mitigates the effect of departures from normal temperature on Alagasco's earnings. The calculation is performed monthly, and adjustments are made to customers' bills in the actual month the weather variation occurs.

ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight former manufactured gas plant sites and five manufactured gas distribution sites. It still owns four of the plant sites and one of the distribution sites. An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco's share of any associated costs will not materially affect the Company's results of its operations or financial condition.

RISK FACTORS: For a discussion of risks inherent in the Company's businesses, see Management's Discussion and Analysis of Financial Condition and Results of Operations as set forth in Item 7 of Part II of this Form 10-K.

EMPLOYEES

The Company has 1,500 employees; Alagasco employs 1,232 and Energen Resources employs 268. The Company believes that its relations with employees are good.

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ITEM 2. PROPERTIES

The corporate headquarters of Energen, Alagasco and Energen Resources are located in leased office space in Birmingham, Alabama. Energen Resources maintains leased offices in Houston and Midland, Texas, in Farmington, New Mexico, in Oak Grove and Vance, Alabama and in Arcadia, Louisiana. For a description of Energen Resources' oil and gas properties, see the discussion under Item 1-Business. Information concerning Energen Resources' production and reserves is summarized in the table below and included in Note 20, Oil and Gas Operations (unaudited), included in the Form 10-K in the Notes to Financial Statements.

--------------------------------------------------------------------------------
                                             YEAR ENDED
                                          DECEMBER 31, 2003    DECEMBER 31, 2003
--------------------------------------------------------------------------------
                                         Production Volumes     Proved Reserves
                                               (MMcfe)              (MMcfe)
                                         ---------------------------------------
San Juan Basin                                 28,406                666,349
Permian Basin                                  31,263                365,394
Black Warrior Basin                            15,549                252,416
North Louisiana/East Texas                     10,087                 75,004
Other                                             852                  5,782
--------------------------------------------------------------------------------
Total                                          86,157              1,364,945
--------------------------------------------------------------------------------

The properties of Alagasco consist primarily of its gas distribution system, which includes more than 9,810 miles of main, more than 11,494 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, seven division offices, four payment centers, four district offices, nine service centers, and other related property and equipment, some of which are leased by Alagasco. For a further description of Alagasco's properties, see the discussion under Item 1-Business.

ITEM 3. LEGAL PROCEEDINGS

Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specific relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards may bear little or no relation to culpability or actual damages thus making it difficult to predict litigation results.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during the fourth quarter of 2003.

10

EXECUTIVE OFFICERS OF THE REGISTRANTS

ENERGEN CORPORATION

Name                        Age        Position (1)
----                        ---        ------------
Wm. Michael Warren, Jr.     56         Chairman of the Board
                                       President and Chief Executive Officer (2)

Geoffrey C. Ketcham         53         Executive Vice President, Chief Financial
                                       Officer and Treasurer (3)

James T. McManus            45         President and Chief Operating Officer of
                                       Energen Resources (4)

Dudley C. Reynolds          51         President and Chief Operating Officer of
                                       Alagasco (5)

Grace B. Carr               48         Vice President and Controller (6)

J. David Woodruff, Jr.      47         General Counsel and Secretary and Vice
                                       President-Corporate Development (7)

NOTES: (1) All executive officers of Energen have been employed by Energen or a subsidiary for the past five years. Officers serve at the pleasure of the Board of Directors.

(2) Mr. Warren has been employed by the Company in various capacities since 1983. In January 1992 he was elected President and Chief Operating Officer of Energen and all of its subsidiaries, in October 1995 he was elected Chief Executive Officer of Alagasco and Energen Resources, in February 1997 he was elected Chief Executive Officer of Energen and effective January 1, 1998, he was elected Chairman of the Board of Energen and each of its subsidiaries. Mr. Warren serves as a Director of Energen and each of its subsidiaries. He is also a Director of Protective Life Corporation.

(3) Mr. Ketcham has been employed by the Company in various financial and strategic planning capacities since 1981. He has served as Executive Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries since April 1991.

(4) Mr. McManus has been employed by the Company in various capacities since 1986. He was elected Executive Vice President and Chief Operating Officer of Energen Resources in October 1995 and President of Energen Resources in April 1997.

(5) Mr. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003.

(6) Ms. Carr was employed by the Company in various capacities from January 1985 to April 1989. She was not employed from May 1989 through December 1997. She was elected Controller of Energen in January 1998 and elected Vice President and Controller of Energen in October 2001.

(7) Mr. Woodruff has been employed by the Company in various capacities since 1986. He was elected Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries in April 1991 and Vice President-Corporate Development of Energen in October 1995. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003.

11

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
--------------------------------------------------------------------------------
Quarter ended (in dollars)      HIGH        LOW        CLOSE      DIVIDENDS PAID
--------------------------------------------------------------------------------
December 31, 2000              33.56       26.06       32.19           .170
March 31, 2001                 35.30       27.50       35.30           .170
June 30, 2001                  40.25       26.75       27.60           .170
September 30, 2001             28.21       21.50       22.50           .175
--------------------------------------------------------------------------------
December 31, 2001              25.20       21.50       24.65           .175
--------------------------------------------------------------------------------
March 31, 2002                 26.49       21.69       26.45           .175
June 30, 2002                  29.25       24.70       27.50           .175
September 30, 2002             27.53       21.65       25.31           .180
December 31, 2002              29.99       22.50       29.10           .180
--------------------------------------------------------------------------------
March 31, 2003                 32.06       28.08       32.06           .180
June 30, 2003                  34.29       31.60       33.30           .180
September 30, 2003             37.09       31.35       36.18           .185
December 31, 2003              42.00       36.14       41.03           .185
--------------------------------------------------------------------------------

Energen's common stock is listed on the New York Stock Exchange under the symbol EGN. On February 9, 2004, there were approximately 7,750 holders of record of Energen's common stock. At the date of this filing, Energen Corporation owns all the issued and outstanding common stock of Alabama Gas Corporation.

The following table summarizes information concerning securities authorized for issuance under equity compensation plans:

--------------------------------------------------------------------------------------------------------------
                                  Number of Securities to       Weighted       Number of Securities Remaining
                                  be Issued Upon Exercise        Average        Available for Future Issuance
       Plan Category               of Outstanding Options     Exercise Price   Under Equity Compensation Plans
--------------------------------------------------------------------------------------------------------------
Equity compensation plans
approved by security holders             588,420                  $22.28                 1,744,823
Equity compensation plans not
approved by security holders                  --                      --                        --
--------------------------------------------------------------------------------------------------------------
Total                                    588,420                  $22.28                 1,744,823
--------------------------------------------------------------------------------------------------------------

12

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data as set forth below should be read in conjunction with the Consolidated Financial Statements and the Notes to Financial Statements included in this Form 10-K.

SELECTED FINANCIAL AND COMMON STOCK DATA
ENERGEN CORPORATION

-----------------------------------------------------------------------------------------------------------------------------------
                                                           Three Months
                                YEAR ENDED   Year Ended       Ended       Year Ended     Year Ended     Year Ended     Year Ended
(dollars in thousands, except  DECEMBER 31,  December 31,  December 31,  September 30,  September 30,  September 30,  September 30,
per share amounts)                 2003         2002           2001*         2001           2000           1999           1998
-----------------------------------------------------------------------------------------------------------------------------------
INCOME STATEMENT
Operating revenues              $  842,221    $  668,551    $  143,632    $  762,816     $  542,012     $  487,654     $  492,847
Income from continuing
  operations before
  cumulative effect of change
  in accounting principle       $  110,265    $   70,396    $    3,730    $   62,417     $   51,488     $   41,729     $   32,535
Net income                      $  110,654    $   68,639    $    3,658    $   67,896     $   53,018     $   41,410     $   36,249
Diluted earnings per average
  common share from
  continuing operations
  before cumulative effect of
  change in accounting
  principle                     $     3.09    $     2.08    $     0.12    $     2.01     $     1.70     $     1.39     $     1.11
Diluted earnings per average
  common share                  $     3.10    $     2.03    $     0.12    $     2.18     $     1.75     $     1.38     $     1.23
-----------------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET
Capitalization at year-end:
    Common shareholders'
      equity                    $  699,032    $  582,810    $  474,205    $  480,767     $  400,860     $  361,504     $  329,249
    Long-term debt                 552,842       512,954       544,133       544,110        353,932        371,824        372,782
-----------------------------------------------------------------------------------------------------------------------------------
    Total capitalization        $1,251,874    $1,095,764    $1,018,338    $1,024,877     $  754,792     $  733,328     $  702,031
-----------------------------------------------------------------------------------------------------------------------------------
Total assets                    $1,781,432    $1,643,012    $1,342,346    $1,313,885     $1,286,341     $1,261,469     $1,064,142
-----------------------------------------------------------------------------------------------------------------------------------
Property, plant and
  equipment, net                $1,433,451    $1,351,554    $1,093,201    $1,084,052     $  986,604     $  933,333     $  822,741
-----------------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA
Annual dividend rate at
  period-end                    $     0.74    $     0.72    $     0.70    $     0.70     $     0.68     $     0.66     $     0.64
Cash dividends paid per
  common share                  $     0.73    $     0.71    $    0.175    $    0.685     $    0.665     $    0.645     $    0.625
Book value per common share     $    19.30    $    16.77    $    15.18    $    15.45     $    13.21     $    12.09     $    11.23
Market-to-book ratio at
  period-end (%)                       213           174           162           145            225            167            169
Yield at period-end (%)                1.8           2.5           2.8           3.1            2.3            3.3            3.4
Return on average common
  equity (%)                          17.1          12.4          13.0          15.8           13.7           11.7           11.1
Price-to-earnings (diluted)
  ratio at period-end                 13.2          14.3            --          10.3           17.0           14.7           15.4
Shares outstanding at
  period-end (000)                  36,224        34,745        31,249        31,125         30,351         29,904         29,327
Price Range:
    High                        $    42.00    $    29.99    $    25.20    $    40.25     $    30.38     $    20.38     $    22.50
    Low                         $    28.08    $    21.65    $    21.50    $    21.50     $    14.69     $    13.13     $    15.13
    Close                       $    41.03    $    29.10    $    24.65    $    22.50     $    29.75     $    20.25     $    19.00
-----------------------------------------------------------------------------------------------------------------------------------

Note: All information has been adjusted to reflect the 2-for-1 stock split effective March 2, 1998

*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

13

SELECTED BUSINESS SEGMENT DATA
Energen Corporation

-----------------------------------------------------------------------------------------------------------------------------------
                                                           Three Months
                                YEAR ENDED   Year Ended       Ended       Year Ended     Year Ended     Year Ended     Year Ended
                               DECEMBER 31,  December 31,  December 31,  September 30,  September 30,  September 30,  September 30,
(dollars in thousands)             2003         2002           2001*         2001           2000           1999           1998
-----------------------------------------------------------------------------------------------------------------------------------
OIL AND GAS OPERATIONS
Operating revenues from
  continuing operations
    Natural gas                 $  235,649    $  145,935    $   34,290    $  132,554     $  113,168     $  113,219     $   89,866
    Oil                             87,200        72,758        11,128        43,880         36,143         33,779         19,508
    Natural gas liquids             25,890        21,857         4,282        24,540         21,443          6,683          6,482
    Other                            4,383         3,570        (2,746)        7,980          5,097          8,419          7,051
-----------------------------------------------------------------------------------------------------------------------------------
      Total                     $  353,122    $  244,120    $   46,954    $  208,954     $  175,851     $  162,100     $  122,907
-----------------------------------------------------------------------------------------------------------------------------------
Production volumes from
  continuing operations
    Natural gas (MMcf)              55,433        46,060        11,454        44,071         45,557         51,105         40,631
    Oil (MBbl)                       3,412         3,016           464         1,873          1,983          2,823          1,298
    Natural gas liquids
      (MBbl)                         1,587         1,712           428         1,397          1,334            700            760
-----------------------------------------------------------------------------------------------------------------------------------
Production volumes from
  continuing operations
  (MMcfe)                           85,422        74,424        16,801        63,690         65,459         72,243         52,979
-----------------------------------------------------------------------------------------------------------------------------------
Total production volumes
  (MMcfe)                           86,157        77,973        18,022        68,478         70,482         77,159         57,353
-----------------------------------------------------------------------------------------------------------------------------------
Proved reserves
    Natural gas (MMcf)             886,307       803,748       714,395       627,051        777,456        740,001        542,039
    Oil (MBbl)                      52,528        49,833        19,128        20,878         24,518         24,719         19,845
    Natural gas liquids
      (MBbl)                        27,245        26,697        25,944        24,931         26,007         21,937         17,292
-----------------------------------------------------------------------------------------------------------------------------------
      Total (MMcfe)              1,364,945     1,262,928       984,827       901,905      1,080,605      1,019,937        764,861
-----------------------------------------------------------------------------------------------------------------------------------
Other data from continuing
  operations
  Lease operating expense
    (LOE)
    LOE and other               $   67,920    $   57,141    $   11,474    $   49,273     $   49,866     $   53,441     $   37,918
    Production taxes                27,731        18,254         3,387        22,833         16,536         10,677          8,688
-----------------------------------------------------------------------------------------------------------------------------------
      Total                     $   95,651    $   75,395    $   14,861    $   72,106     $   66,402     $   64,118     $   46,606
-----------------------------------------------------------------------------------------------------------------------------------
    Depreciation and
      amortization              $   79,687    $   68,009    $   15,317    $   50,907     $   53,499     $   57,402     $   52,194
    Capital expenditures        $  163,338    $  305,476    $   25,052    $  136,886     $   67,090     $  198,577     $  120,991
    Operating income            $  155,481    $   78,105    $    3,496    $   66,416     $   45,853     $   31,541     $   16,643
-----------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS DISTRIBUTION
-----------------------------------------------------------------------------------------------------------------------------------
Operating revenues
    Residential                 $  320,938    $  277,088    $   63,724    $  367,109     $  233,839     $  209,263     $  241,964
    Commercial and
      industrial-small             126,638       104,247        22,445       147,636         88,521         77,254         89,361
    Transportation                  38,250        38,395         9,765        33,972         35,312         34,541         35,246
    Other                            3,273         4,701           744         5,145          8,489          4,496          3,369
-----------------------------------------------------------------------------------------------------------------------------------
      Total                     $  489,099    $  424,431    $   96,678    $  553,862     $  366,161     $  325,554     $  369,940
-----------------------------------------------------------------------------------------------------------------------------------
Gas delivery volumes (MMcf)
    Residential                     27,248        26,358         5,128        31,064         26,069         24,751         31,079
    Commercial and
      industrial-small              12,564        11,838         2,193        14,054         12,092         11,662         13,705
    Transportation                  55,623        59,644        12,973        53,989         70,534         66,356         70,563
-----------------------------------------------------------------------------------------------------------------------------------
      Total                         95,435        97,840        20,294        99,107        108,695        102,769        115,347
-----------------------------------------------------------------------------------------------------------------------------------
Average number of customers
    Residential                    427,413       425,630       422,461       428,663        429,368        425,937        423,602
    Commercial, industrial
      and transportation            35,463        35,601        35,161        35,882         35,526         35,111         34,782
-----------------------------------------------------------------------------------------------------------------------------------
      Total                        462,876       461,231       457,622       464,545        464,894        461,048        458,384
-----------------------------------------------------------------------------------------------------------------------------------
Other data
    Depreciation and
      amortization              $   37,171    $   33,682    $    8,151    $   30,933     $   28,708     $   26,730     $   25,153
    Capital expenditures        $   57,906    $   65,815    $   12,873    $   56,090     $   67,073     $   46,029     $   54,168
    Operating income            $   66,848    $   59,370    $    8,034    $   50,288     $   49,063     $   46,565     $   41,663
-----------------------------------------------------------------------------------------------------------------------------------

14

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CRITICAL ACCOUNTING POLICIES

The Company's consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Management has identified the following critical accounting policies in the application of existing accounting standards or in the implementation of new standards that involve significant judgments and estimates by the Company:

OIL AND GAS OPERATIONS
ACCOUNTING FOR NATURAL GAS AND OIL PRODUCING ACTIVITIES

AND RELATED RESERVES: The Company utilizes the successful efforts method of accounting for its natural gas and oil producing activities. Under this accounting method, acquisition and development costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of total proved and proved developed reserves.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have reviewed the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2003. The independent reservoir engineers have issued reports covering approximately 97 percent of the Company's ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate. The Company's production of undeveloped reserves requires the installation or completion of related infrastructure facilities such as pipelines and the drilling of development wells.

Changes in oil and gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property's book value if an impairment is warranted. The table below reflects the estimated increase (decrease) in 2004 depreciation and depletion expense associated with changes in oil and gas reserve quantities from the reported amounts at December 31, 2003.

-------------------------------------------------------------------------------------------------
                                                     Percentage Change in Oil & Gas Reserves
                                                   From Reported Reserves as of December 31, 2003
(dollars in thousands)                             +10%         +5%          -5%          -10%
-------------------------------------------------------------------------------------------------
Estimated change in depreciation expense for
the year ended December 31, 2004, net of tax       $(3,900)     $(2,000)     $ 2,400      $ 5,000
-------------------------------------------------------------------------------------------------

ASSET IMPAIRMENTS: Oil and gas developed and undeveloped properties periodically are assessed for possible impairment, generally on a field-by-field basis, using the estimated undiscounted future cash flows of each field. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. The Company monitors its oil and gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, substantial commodity price declines, unanticipated increased operating costs, and lower-than-expected production performance. If a material event occurs, Energen Resources makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, the Company will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flow.

15

Cash flow and fair value estimates require Energen Resources to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These variables can, and often do, differ from the estimate and can have a positive or negative impact on the Company's need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact the Company's original and ongoing assessments of potential impairment.

DERIVATIVES: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" (as amended) requires all derivatives to be recognized on the balance sheet and measured at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. SFAS No. 133 is subject to interpretations in its application. The potential exists for additional issues to be brought under review, and, if subsequent interpretations of SFAS No. 133 are different than current interpretations, it is possible that the Company's policy, as stated above, may be modified.

NATURAL GAS DISTRIBUTION
REGULATED OPERATIONS: Alagasco applies Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," to its regulated operations. This standard requires a cost to be capitalized as a regulatory asset that otherwise would be charged to expense if it is probable that the cost is recoverable in the future through regulated rates. Likewise, if current recovery is provided for a cost that will be incurred in the future, SFAS No. 71 requires the cost to be recognized as a regulatory liability. The Company anticipates SFAS No. 71 will continue as the applicable accounting standard for its regulated operations. Alagasco's rate setting methodology, Rate Stabilization and Equalization, has been in effect since 1983.

CONSOLIDATED
EMPLOYEE PENSION PLANS: Determining the Company's obligations to employees under its defined benefit pension plans requires the use of estimates. The calculation of the liability related to the Company's defined benefit pension plans requires assumptions regarding the appropriate weighted average discount rate, estimated rate of increase in the compensation level of its employee base and the expected long-term rate of return on the plans' assets. The selection and use of such assumptions affects the amount of expense recorded in the Company's financial statements related to its defined benefit pension plan. The discount rate for pension cost purposes is the rate at which pension obligations could be effectively settled. The discount rate used for actuarial purposes covering a majority of employees was 6 percent for the year ended December 31, 2003. A hypothetical 25 basis point change in the discount rate would impact total pension expense by approximately $560,000. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The return on assets used for actuarial purposes was 9 percent for the year ended December 31, 2003. A hypothetical 25 basis point change in the return on assets would impact total pension expense by approximately $245,000. The discount rate and return on plan assets used in the actuarial assumptions for 2004 is 6 percent and 8.75 percent, respectively.

CHANGE IN YEAR END

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 is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes.

16

RESULTS OF OPERATIONS

CONSOLIDATED NET INCOME
Energen Corporation's net income for the year ended December 31, 2003 totaled $110.7 million, or $3.10 per diluted share compared to year ended December 31, 2002 net income of $68.6 million, or $2.03 per diluted share. This 52.7 percent increase in earnings per diluted share (EPS) largely reflected the result of significantly higher prices for natural gas, oil and natural gas liquids as well as the impact of a 14.8 percent increase in production volumes of Energen's oil and gas subsidiary, Energen Resources Corporation. Prior-year results included a $5.7 million after-tax, or $0.17 per diluted share, non-cash benefit from the Company's previous hedge position with Enron North America Corp. (Enron) and $14.2 million, or $0.42 per diluted share, of nonconventional fuels tax credits. Discontinued operations in 2003 reflected a gain of $0.4 million as compared with a gain of $0.5 million in 2002. Net income in 2002 also included a charge of $2.2 million after-tax or $0.07 per diluted share, reflecting the cumulative effect on prior years of the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." For the year ended December 31, 2003, Energen Resources earned $78.9 million, as compared with $41.2 million in the previous year. Alabama Gas Corporation (Alagasco), Energen's utility subsidiary, generated a 19.8 percent increase in net income, earning $33 million in the current year as compared with net income in the prior period of $27.6 million. For the 12 months ended September 30, 2001, Energen reported earnings of $67.9 million, or $2.18 per diluted share.

2003 VS 2002: Energen Resources' net income rose 91.5 percent to $78.9 million in 2003. Energen Resources' income from continuing operations before the cumulative effect of a change in accounting principle totaled $78.5 million in 2003 as compared with $43 million in 2002, primarily due to higher commodity prices along with the impact of increased gas and oil production volumes due to a full year's production from the April 2002 acquisition of oil properties in the Permian Basin, a new gas project in the Permian Basin, acquisitions in the San Juan Basin and the successful coalbed methane down-spacing program. These increases were partially offset by higher lease operating expense and increased depreciation, depletion and amortization (DD&A) expense. Prior year results included the non-cash benefit associated with the Company's previous hedge position with Enron and the recognition of $14.2 million in non-conventional fuels tax credits. The ability to generate new credits ended December 31, 2002.

Alagasco earned net income of $33 million in 2003 as compared with net income of $27.6 million in 2002. This increase in earnings reflected the utility's ability to earn on a higher level of equity representing investment in utility plant. It also reflected the impact of timing differences between quarters as it relates to revenue recovery under the utility's rate-setting mechanism. Alagasco's return on average equity (ROE) was 13.5 percent in 2003 compared with 12.3 percent in 2002.

2002 VS 2001: For the year ended December 31, 2002, Energen Resources' net income totaled $41.2 million as compared with $42.6 million for the 12 months ended September 30, 2001. Net income in 2002 included a charge of $2.2 million after-tax ($0.07 per diluted share) related to the adoption of SFAS No. 143, as discussed above. Energen Resources' income from continuing operations before the cumulative effect of a change in accounting principle in 2002 totaled $43 million as compared with $37.1 million in 2001. Positively influencing income from continuing operations was a 16.9 percent increase in production volumes related to the acquisition of oil properties in the Permian Basin in April 2002 and the non-cash benefit of $5.7 million after-tax ($0.17 per diluted share) associated with its previous hedge position with Enron. The primary negative influences on income from continuing operations were increased DD&A and lease operating expenses.

Alagasco's earnings increased to $27.6 million in 2002 from $26 million in 2001 as a result of the utility earning on a higher level of equity. Alagasco achieved a ROE of 12.3 percent in both 2002 and 2001.

THREE MONTHS ENDED DECEMBER 31, 2001 VS THREE MONTHS ENDED DECEMBER 31, 2000:
Energen's net income totaled $3.7 million ($0.12 per diluted share) for the three months ended December 31, 2001, compared to net income of $13.7 million ($0.44 per diluted share) recorded in the same period of 2000. Energen Resources realized income from continuing operations of $1.2 million in the December 31, 2001 transition quarter as compared with $8.3 million in the same quarter in the previous year largely due to a non-cash write-off of $5.5 million after-tax ($0.17 per diluted share) associated with its hedge position with Enron. Also negatively impacting net income in

17

the transition quarter were increased DD&A expense and a $1.7 million writedown on property held for sale. Energen's natural gas utility, Alagasco, reported net income of $2.7 million in the transition quarter as compared to $4 million in the same period in the previous year primarily due to increased bad debt expense as well as a decline in cycle and industrial gas usage.

OPERATING INCOME

Consolidated operating income in 2003, 2002 and 2001 totaled $219.8 million, $135.8 million and $115 million, respectively. This significant growth in operating income has been influenced by strong financial performance from Energen Resources under Energen's diversified growth strategy, implemented in fiscal 1996. Alagasco also contributed to this growth in operating income consistent with increases in the levels of equity upon which it has been able to earn a return.

OIL AND GAS OPERATIONS: Revenues from oil and gas operations rose significantly in the current year largely as a result of increased natural gas, oil and natural gas liquids prices; a full year's production from the 2002 acquisition of oil properties in the Permian Basin; a new project in the Permian Basin that produced gas which had previously been reinjected into the reservoir; acquisitions in the San Juan Basin; and a successful coalbed methane down-spacing program. During 2003, production from continuing operations rose 14.8 percent to 85.4 billion cubic feet equivalent (Bcfe). Natural gas production increased 20.3 percent to 55.4 billion cubic feet (Bcf) and oil volumes rose 13.1 percent to 3,412 thousand barrels (MBbl). Production of natural gas liquids declined 7.3 percent to 1,587 MBbl. Including the prior-period non-cash benefit from the former Enron hedges, realized gas prices increased 34.1 percent to $4.25 per thousand cubic feet (Mcf), realized oil prices rose 5.9 percent to $25.56 per barrel and natural gas liquids prices increased 27.8 percent to an average price of $16.32 per barrel during 2003.

In 2002, revenues from oil and gas operations increased primarily as a result of increased production volumes related to the Permian Basin acquisition. During 2002, production from continuing operations increased 16.9 percent to 74.4 Bcfe. Natural gas production increased 4.5 percent to 46.1 Bcf, oil volumes rose 61 percent to 3,016 MBbl and natural gas liquids production increased 22.5 percent to 1,712 MBbl. Including the non-cash benefit from the former Enron hedges, realized gas prices rose 5.3 percent to $3.17 per Mcf, while realized oil prices increased 3 percent to $24.13 per barrel. Natural gas liquids prices fell 27.3 percent to an average price of $12.77 per barrel.

Coalbed methane operating fees are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes and operating expenses. Revenues from operating fees were $6.1 million, $4.8 million and $7.6 million in 2003, 2002 and 2001, respectively.

--------------------------------------------------------------------------------------------------
                                                       DECEMBER 31,   December 31,   September 30,
Years ended (in thousands, except sales price data)        2003           2002            2001
--------------------------------------------------------------------------------------------------
Operating revenues from continuing operations
    Natural gas                                         $ 235,649      $ 145,935       $ 132,554
    Oil                                                    87,200         72,758          43,880
    Natural gas liquids                                    25,890         21,857          24,540
    Operating fees                                          6,077          4,847           7,618
    Other                                                  (1,694)        (1,277)            362
--------------------------------------------------------------------------------------------------
Total operating revenues from continuing operations     $ 353,122      $ 244,120       $ 208,954
--------------------------------------------------------------------------------------------------
Production volumes from continuing operations
    Natural gas (MMcf)                                     55,433         46,060          44,071
    Oil (MBbl)                                              3,412          3,016           1,873
    Natural gas liquids (MBbl)                              1,587          1,712           1,397
--------------------------------------------------------------------------------------------------
Average sales price including effects of hedging
    Natural gas (per Mcf)                               $    4.25      $    3.17       $    3.01
    Oil (per barrel)                                    $   25.56      $   24.13       $   23.43
    Natural gas liquids (per barrel)                    $   16.32      $   12.77       $   17.57
--------------------------------------------------------------------------------------------------
Average sales price excluding effects of hedging
    Natural gas (per Mcf)                               $    4.97      $    2.96       $    4.85
    Oil (per barrel)                                    $   29.19      $   24.82       $   27.42
    Natural gas liquids (per barrel)                    $   18.40      $   12.77       $   17.57
--------------------------------------------------------------------------------------------------

18

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144,"Accounting for Impairment or Disposal of Long-Lived Assets," which was adopted as of January 1, 2002. In 2003, Energen Resources recorded a pre-tax gain of $9.4 million in discontinued operations from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million. Energen Resources recorded in 2002 a pre-tax gain of $0.9 million in total income from discontinued operations from the sale of properties and adjustments to the fair value of properties being held-for-sale. In 2001, prior to the adoption of SFAS No. 144, Energen Resources recorded in operating revenues a net pre-tax gain from the sale of properties and adjustments to the fair value of properties held for sale of $0.8 million.

Operations and maintenance (O&M) expense increased $10.8 million and $10.6 million in 2003 and 2002, respectively. Lease operating expense (excluding production taxes) in 2003 rose $10.8 million primarily due to the acquisition of oil and gas properties; higher operational costs driven by market conditions related to increased commodity costs as well as an increased number of wells in the San Juan and Permian Basins; and increased drilling activity in the coalbed methane down-spacing program. In 2002, lease operating expense (excluding production taxes) increased by $7.9 million primarily due to the acquisition of oil and gas properties. Administrative expense increased $2.8 million and $3.3 million in 2003 and 2002, respectively, primarily due to labor related costs and additional costs related to the property acquisition. Exploration expense decreased $2.5 million in 2003 largely due to a $3.2 million pre-tax writedown of unproved leasehold costs recorded during 2002 offset by increased exploratory efforts. In 2002, exploration expense decreased $0.6 million primarily due to decreased exploratory efforts.

DD&A expense increased $11.7 million in 2003 and $17.1 million in 2002 largely due to increased production volumes. The average depletion rate was $0.92 per Mcfe in 2003, $0.89 per Mcfe in 2002 and $0.78 per Mcfe in 2001.

Energen Resources' expense for taxes other than income primarily reflected production-related taxes. Energen Resources recorded severance taxes for 2003 of $27.7 million as a result of increased commodity prices as well as increased production. Severance taxes in 2002 and 2001 were $18.3 million and $22.8 million, respectively.

OIL AND GAS OPERATIONS - TRANSITION PERIOD: Revenues from oil and gas continuing operations declined 8.6 percent to $47 million for the three months ended December 31, 2001, largely as a result of lower natural gas liquids prices. In the transition quarter, realized gas prices increased 12 percent to $2.99 per Mcf, while realized oil prices rose 10 percent to $24.01 per barrel. Natural gas liquids prices decreased 51.6 percent to an average price of $10.01 per barrel.

Natural gas production in the transition quarter increased slightly to 11.5 Bcf, while oil volumes decreased slightly to 464 MBbl. Natural gas liquids production increased 14.1 percent to 428 MBbl. Natural gas comprised nearly 70 percent of Energen Resources' production in the transition quarter.

19

------------------------------------------------------------------------------------------
                                                              DECEMBER 31,    December 31,
Three months ended (in thousands, except sales price data)        2001            2000
------------------------------------------------------------------------------------------
Revenues from continuing operations
    Natural gas production                                      $ 34,290        $ 30,357
    Oil production                                                11,128          10,502
    Natural gas liquids production                                 4,282           7,758
    Operating fees                                                   913           2,225
    Other                                                         (3,659)            555
------------------------------------------------------------------------------------------
Total revenues from continuing operations                       $ 46,954        $ 51,397
------------------------------------------------------------------------------------------
Production volumes from continuing operations
    Natural gas (MMcf)                                            11,454          11,364
    Oil (MBbl)                                                       464             481
    Natural gas liquids (MBbl)                                       428             375
------------------------------------------------------------------------------------------
Average sales price including effects of hedging
    Natural gas (per Mcf)                                       $   2.99        $   2.67
    Oil (per barrel)                                            $  24.01        $  21.84
    Natural gas liquids (per barrel)                            $  10.01        $  20.70
------------------------------------------------------------------------------------------
Average sales price excluding effects of hedging
    Natural gas (per Mcf)                                       $   2.34        $   5.16
    Oil (per barrel)                                            $  19.52        $  30.50
    Natural gas liquids (per barrel)                            $  10.01        $  20.70
------------------------------------------------------------------------------------------

Prior to the adoption of SFAS No. 144, Energen Resources recorded in operating revenues a pre-tax loss of $3.4 million for the December 31, 2001 transition quarter from the sale of properties and adjustments to the fair value of properties held-for-sale as compared to a pre-tax gain of $0.8 million in the prior year quarter on the sale of various properties.

O&M expense increased $7.8 million in the transition quarter ended December 31, 2001, largely due to the non-cash writedown of $8.7 million pre-tax associated with Energen Resources' hedge position with Enron. Lease operating expense decreased by $0.3 million in the transition quarter while exploration expense declined $0.3 million. Energen Resources' DD&A expense for the period rose $4.1 million primarily driven by the impact of market declines in commodity prices. The average depletion rate for the transition quarter was $0.89 as compared to $0.66 for the same period in the previous year.

Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $3.2 million lower in the transition quarter largely as a result of the significantly decreased commodity market prices.

NATURAL GAS DISTRIBUTION: As discussed more fully in Note 2, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend the utility's rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the company and a hearing, the Commission votes to either modify or discontinue its operation.

Alagasco generates revenues through the sale and transportation of natural gas. The transportation rate does not contain an amount representing the cost of gas, and Alagasco's rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues, but operating margins essentially remain unaffected due to a temperature adjustment mechanism that requires Alagasco to adjust customer bills monthly to reflect changes in usage due to departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

Alagasco's natural gas and transportation sales revenues totaled $489.1 million, $424.4 million and $553.9 million in 2003, 2002 and 2001, respectively. Sales revenue in 2003 rose largely due to a significant increase in the commodity cost of gas. Lower commodity gas costs and weather that was 13.1 percent warmer than in the prior year contributed to the decrease in sales revenue in 2002.

During 2003, weather was comparable to the previous year. Residential sales volumes increased 3.4 percent and small commercial and industrial volumes increased 6.1 percent largely due to increased gas usage per customer. Transportation volumes declined 6.7 percent primarily due to higher gas prices which resulted in alternate fuel use partially offset by certain nonrecurring gas deliveries. In 2002, residential sales volumes decreased 15.1 percent

20

primarily due to the impact of warmer weather on throughput. Small commercial and industrial volumes, also sensitive to weather, decreased 15.8 percent. Transportation volumes rose 10.5 percent, due to the previous period's significantly higher natural gas prices and a general economic weakness.

Higher commodity gas cost generated a 23.3 percent increase in cost of gas for 2003. In 2002, significantly lower commodity gas costs along with decreased purchased volumes due to warmer weather resulted in a 41.9 percent decrease in cost of gas.

O&M expense at the utility increased 4.6 percent in 2003 primarily due to increased labor-related costs. In 2002, O&M expense increased 3.1 percent primarily due to higher insurance and labor-related costs partially offset by reduced bad debt expense and marketing costs. The increase in O&M expense per customer for the rate years ended September 30, 2003 and 2002 were slightly above the inflation-based Cost Control Measurement (CCM) established by the APSC as part of the utility's rate-setting mechanism; as a result, three quarters of the difference, or $0.1 million and $0.3 million pre-tax respectively, was returned to the customers through RSE (see Note 2). In 2001, the increase in O&M expense on a per-customer basis fell within the CCM.

Depreciation expense rose 10.4 percent in 2003 consistent with the growth in the utility's depreciable base and with the replacement of support systems with higher depreciation rates than the average rates applicable to the distribution system. Depreciation expense rose 8.9 percent in 2002 due to normal growth of the utility's distribution system. Alagasco's expense for taxes other than income primarily reflects various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

-------------------------------------------------------------------------------------------
                                                DECEMBER 31,   December 31,   September 30,
Years ended (in thousands)                          2003           2002           2001
Natural gas transportation and sales revenues   $  489,099     $  424,431      $  553,862
Cost of natural gas                               (236,037)      (191,479)       (329,572)
Operations and maintenance                        (114,078)      (109,115)       (105,812)
Depreciation                                       (37,171)       (33,682)        (30,933)
Income taxes                                       (19,675)       (17,825)        (13,448)
Taxes, other than income taxes                     (34,965)       (30,785)        (37,257)
-------------------------------------------------------------------------------------------
Operating income                                $   47,173     $   41,545      $   36,840
-------------------------------------------------------------------------------------------
Natural gas sales volumes (MMcf)
    Residential                                     27,248         26,358          31,064
    Commercial and industrial-small                 12,564         11,838          14,054
-------------------------------------------------------------------------------------------
Total natural gas sales volumes                     39,812         38,196          45,118
Natural gas transportation volumes (MMcf)           55,623         59,644          53,989
-------------------------------------------------------------------------------------------
Total deliveries (MMcf)                             95,435         97,840          99,107
-------------------------------------------------------------------------------------------

NATURAL GAS DISTRIBUTION - TRANSITION PERIOD: Natural gas distribution revenues decreased $22.4 million for the transition quarter ended December 31, 2001, largely due to a decrease in the commodity cost of gas as well as to a decrease in weather-related sales volumes and gas usage volumes. For the transition quarter, weather that was 30.1 percent warmer than the same period in the prior year contributed to a 29.1 percent decrease in residential sales volumes and a 34.3 percent decrease in small commercial and industrial customer sales volumes. Transportation volumes decreased 6.3 percent primarily due to reduced consumption resulting from a general economic weakness in the transition period. Lower commodity gas prices along with decreased gas purchase volumes contributed to a 32.5 percent decrease in cost of gas for the quarter.

O&M expense increased 3.2 percent in the transition quarter primarily due to increased bad debt expense partially offset by reduced labor-related and marketing costs. A 7.9 percent increase in depreciation expense in the three-months ended December 31, 2001 primarily was due to normal growth of the utility's distribution system. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

21

--------------------------------------------------------------------------------
                                                   DECEMBER 31,     December 31,
Three months ended (in thousands)                      2001             2000
--------------------------------------------------------------------------------
Natural gas transportation and sales revenues       $  96,678        $ 119,126
Cost of natural gas                                   (45,651)         (67,679)
Operations and maintenance                            (27,687)         (26,837)
Depreciation                                           (8,151)          (7,554)
Income taxes                                           (1,547)          (2,094)
Taxes, other than income taxes                         (7,155)          (8,464)
--------------------------------------------------------------------------------
Operating income                                    $   6,487        $   6,498
--------------------------------------------------------------------------------
Natural gas sales volumes (MMcf)
    Residential                                         5,128            7,230
    Commercial and industrial-small                     2,193            3,337
--------------------------------------------------------------------------------
Total natural gas sales volumes                         7,321           10,567
Natural gas transportation volumes (MMcf)              12,973           13,851
--------------------------------------------------------------------------------
Total deliveries (MMcf)                                20,294           24,418
--------------------------------------------------------------------------------

NON-OPERATING ITEMS

CONSOLIDATED: Interest expense in 2003 decreased $1.5 million largely due to a $32.1 million equity issuance completed in July 2003 which reduced short-term debt. Current maturities of long-term debt, lower short-term interest rates and $50 million of long-term debt issued by Energen in October 2003 also influenced interest expense in the period comparisons. In 2002, interest expense increased $1.6 million and was influenced by increased short-term debt at Energen, primarily related to Energen Resources' acquisition of Permian Basin properties in April 2002, as well as Alagasco's issuance of $40 million of 6.25% Notes and $35 million of 6.75% Notes in August 2001 (the Notes). The average daily outstanding balance under short-term credit facilities was $81.1 million in 2003. The average daily outstanding balance under short-term credit facilities was $85.6 million in 2002 as compared to $80.7 million in 2001.

Income tax expense increased in 2003 primarily due to higher pre-tax income and a higher effective tax rate. Income tax expense increased in 2002 and 2001 primarily due to higher pre-tax income. The Company's effective tax rates in 2002 and 2001 were lower than statutory federal tax rates primarily due to the recognition of nonconventional fuels tax credits. The Company recognized $14.2 million and $13.6 million of nonconventional fuels tax credits in 2002 and 2001, respectively. The Company's ability to generate nonconventional fuels tax credits on qualified production ended December 31, 2002, with the expiration of the credit. As of December 31, 2003, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $59.3 million.

TRANSITION PERIOD: Interest expense for the Company increased $0.4 million in the transition quarter. Influencing the increase in interest expense for the transition quarter was the issuance of MTNs issued by Energen in December 2000 and the issuance of the Notes by Alagasco in August 2001. The proceeds from the Notes were used for repayment of borrowings under Energen's short-term credit facilities incurred as a result of the growth at Energen Resources and for general corporate purposes at Alagasco.

The Company's effective tax rate was lower than the statutory federal tax rate primarily due to the recognition of nonconventional fuels tax credits. Income tax expense decreased in quarter comparisons primarily as a result of lower consolidated pre-tax income slightly offset by higher nonconventional fuels tax credits of $1.2 million. The increase in credit recognition reflected the annualized effective rate applied on an interim basis in the three months ended December 31, 2000, as compared to the transition period which was presented as a stand alone tax period. The effective tax rate utilized in computing income tax expense reflected financial recognition of $3.5 million of nonconventional fuels tax credits as produced during the transition quarter.

FINANCIAL POSITION AND LIQUIDITY

The Company's net cash from operating activities totaled $243.1 million, $213.5 million and $156.5 million in 2003, 2002 and 2001, respectively. Operating cash flow in 2003 benefited from significantly higher realized

22

commodity prices at Energen Resources; working capital needs at Alagasco in 2003 were affected by increased gas costs resulting in higher storage inventory balances. In 2002, operating cash flow benefited from significantly higher production volumes related to Energen Resources' property acquisition and decreased storage inventory balances at Alagasco. Other working capital items, which primarily are the result of changes in throughput and the timing of payments, combined to create the remaining increases for all years.

During 2003, the Company made net investments of $190.4 million. Energen Resources invested $40.5 million in property acquisitions, $121.9 million for development costs including approximately $89 million to drill 347 gross development wells and $0.4 million for exploration. Energen Resources sold or traded certain properties during the current year, resulting in cash proceeds of $29.1 million. Utility expenditures in 2003 totaled $57.9 million and primarily represented system distribution expansion and support facilities, including information technology application projects. During 2002, the Company made net investments of $268.2 million. Energen Resources invested $184.2 million for property acquisitions, $122.5 million for the development of proved properties and $0.1 million for exploration. In April 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 in cash and 3,043,479 shares of the Company's common stock. The total acquisition approximated $184 million and added 227 Bcfe of reserves. Energen Resources drilled 232 gross development wells for approximately $77 million. Energen Resources sold or traded certain properties during 2002, resulting in cash proceeds of $17.1 million. Utility expenditures in 2002 totaled $65.8 million. Cash used in investing activities totaled $174.4 million in 2001. Energen Resources invested $34.3 million for property acquisitions, $103.6 million for development of proved properties and $1.2 million for exploration during 2001. Energen Resources drilled 140 gross development wells for approximately $70 million. Energen Resources sold or traded certain properties during 2001, resulting in cash proceeds of $17.3 million. Utility expenditures for 2001 totaled $56.1 million, including approximately $3 million for a municipal acquisition.

During 2003, the Company added approximately 101 Bcfe of reserves from acquisitions and 135 Bcfe of reserves from discoveries and other additions primarily the result of unit downspacing that increased the number of available drilling locations for certain wells in the Black Warrior, San Juan and Permian basins. Energen Resources added approximately 389 Bcfe and 69 Bcfe of reserves in 2002 and 2001, respectively.

Net cash used in financing activities totaled $55.4 million in 2003. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. The sale of shares began May 9, 2003, and concluded on July 16, 2003, generating net proceeds of $32.1 million. In October 2003, Energen issued $50 million of long-term debt due October 1, 2013. The 5% coupon notes were priced at 99.557 percent to yield 5.057 percent. Long-term debt was reduced by $23 million for current maturities in 2003. In 2002, net cash provided by financing activities totaled $53 million. The Company utilized $85.9 million in short-term credit facilities to finance Energen Resources' acquisition strategy. Long-term debt was reduced by $21.2 million, including the retirement of the Series 1993 Notes for $7.8 million. Net cash provided by financing activities totaled $19.4 million in 2001. In August 2001, Alagasco issued 6.25% Notes for $40 million, redeemable September 1, 2016, and 6.75% Notes for $35 million, redeemable September 1, 2031. In December 2000, Energen issued $150 million of long-term debt redeemable December 15, 2010. The $223.8 million in net proceeds were used to repay short-term borrowings incurred to finance Energen Resources' growth activities and to repay additional borrowings by the utility as a result of higher capital expenditures related to replacement of liquifaction equipment and for general corporate purposes. The proceeds also were used to reduce long-term debt by $36.3 million, including the retirement of the 8% Debentures for $18.3 million. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders and the issuance of common stock through the dividend reinvestment and direct stock purchase plan as well as the employee savings plans.

TRANSITION PERIOD: Cash flows from operations for the transition quarter were $21.4 million compared to $20.7 million in the three months ended December 31, 2000. The decreased net income during the period was offset by changes in working capital items, which are highly influenced by throughput, changes in weather, and timing of payments.

23

The Company had a net investment of $35.7 million through the three months ended December 31, 2001, primarily in additions of property, plant and equipment. Energen Resources invested $25.1 million in capital expenditures primarily related to the development of oil and gas properties. Utility capital expenditures totaled $12.9 million in the quarter and primarily represented system distribution expansion and support facilities. The Company had cash proceeds of $2.3 million resulting from the sale of certain properties during the transition period.

The Company's financing activities provided $15.5 million for the transition quarter in net cash flows. Increased borrowings under Energen's short-term credit facilities were used to finance Energen Resources' acquisition strategy and general corporate needs at Alagasco.

CAPITAL EXPENDITURES

OIL AND GAS OPERATIONS: Energen Resources spent a total of $639.3 million for capital projects during the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001. Property acquisition expenditures totaled $259.3 million, development activities totaled $372.7 million, and exploratory expenditures totaled $1.9 million.

-------------------------------------------------------------------------------------------------------
                                                                           Three Months
                                              YEAR ENDED     Year Ended        Ended       Year Ended
                                             DECEMBER 31,   December 31,   December 31,   September 30,
(in thousands)                                   2003           2002           2001           2001
-------------------------------------------------------------------------------------------------------
Capital and exploration expenditures for:
    Property acquisitions                      $ 40,486       $184,177       $    319        $ 34,316
    Development                                 121,889        122,494         24,757         103,574
    Exploration                                     397            104            228           1,190
    Other                                         1,548          1,880            464           1,477
-------------------------------------------------------------------------------------------------------
      Total                                     164,320        308,655         25,768         140,557
-------------------------------------------------------------------------------------------------------
Less exploration expenditures charged to
  income                                            982          3,179            716           3,671
-------------------------------------------------------------------------------------------------------
Net capital expenditures                       $163,338       $305,476       $ 25,052        $136,886
-------------------------------------------------------------------------------------------------------

NATURAL GAS DISTRIBUTION: During the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001, Alagasco invested $192.7 million for capital projects: $128.1 million for normal expansion, replacements and support of its distribution system, $61.6 million for support facilities, including the replacement of liquifaction equipment and the development and implementation of information systems, and $3 million to purchase a municipal gas system.

-------------------------------------------------------------------------------------------------------
                                                                           Three Months
                                              YEAR ENDED     Year Ended        Ended       Year Ended
                                             DECEMBER 31,   December 31,   December 31,   September 30,
(in thousands)                                   2003           2002           2001           2001
-------------------------------------------------------------------------------------------------------
Capital and expenditures for:
    Renewals, replacements,
      system expansion and other               $ 39,883       $ 43,029       $  8,839        $ 36,340
    Support facilities                           18,023         22,786          4,034          16,733
    Municipal gas system acquisition                 --             --             --           3,017
-------------------------------------------------------------------------------------------------------
      Total                                    $ 57,906       $ 65,815       $ 12,873        $ 56,090
-------------------------------------------------------------------------------------------------------

FUTURE CAPITAL RESOURCES AND LIQUIDITY

The Company plans to continue to implement its diversified growth strategy that focuses on expanding Energen Resources' oil and gas operations through the acquisition of producing properties with development potential while maintaining the strength of the Company's utility foundation. For the five calendar years ended December 31,

24

2003, Energen's EPS grew at an average compound rate of 21.9 percent a year. Over the next five years, Energen is targeting an average EPS growth rate over each rolling five-year period of approximately 7 percent to 8 percent a year.

To finance Energen Resources' investment program, the Company expects to utilize its short-term credit facilities to supplement internally generated cash flow. The Company may periodically issue long-term debt and equity to replace short-term obligations to provide permanent financing. Energen currently has available short-term credit facilities of $267 million to help finance its growth plans and operating needs. As an acquisition company, access to capital is an integral part of the Company's business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. Standard and Poor's last update in October 2003 confirmed Energen's and Alagasco's rating as A- with a stable outlook. In February 2003, Moody's Investors Service confirmed Energen's debt rating as Baa1 and Alagasco's debt rating as A1. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets, continued accessibility could be affected by future economic and business conditions. Energen's management plans to utilize expected increases in cash flows to help finance Energen Resources' acquisition strategy. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. In October 2003, the Company issued $50 million of long-term debt. These proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.

In 2004, Energen Resources plans to invest approximately $310 million, including $200 million in property acquisitions, $2 million in related acquisition development and $108 million in other development and exploratory activities. Included in this $108 million is approximately $77 million for the development of previously identified proved undeveloped reserves and approximately $4 million of exploratory exposure. Capital investment at Energen Resources in 2005 is expected to approximate $200 million for property acquisitions, $20 million for related acquisition development and $52 million for other development and exploration. Of this $52 million, development of previously identified proved undeveloped reserves is estimated to be $35 million and exploratory exposure is estimated to be $3 million. Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2008 is estimated to be approximately $1.4 billion, with $1.2 billion for property acquisitions and related development, $200 million for other development and $25 million for exploratory and other activities. During the five year period, Energen Resources anticipates spending approximately $137 million on development of previously identified proved undeveloped reserves and incurring approximately $16 million in exploratory exposure. Energen Resources' continued ability to invest in property acquisitions will be influenced significantly by industry trends, as the producing property acquisition market historically has been cyclical. Notwithstanding the estimated expenditures mentioned above, as an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time may pursue acquisitions that meet Energen's acquisition criteria which could result in capital expenditures different than those outlined above. These acquisitions or negotiations to sell, trade or otherwise dispose of properties may alter the aforementioned financing requirements.

During 2004, Alagasco plans to invest approximately $60 million in utility capital expenditures for normal distribution and support systems. Alagasco maintains an investment in storage gas that is expected to average approximately $35 million in 2004 but may vary depending upon the price of natural gas. Alagasco plans to invest approximately $53 million in utility capital expenditures during 2005. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. Over the Company's five-year planning period ending December 31, 2008, Alagasco anticipates capital investments of approximately $275 million. During this period, the Company may issue approximately $50 million in long-term debt.

CONTRACTUAL CASH OBLIGATIONS AND OTHER COMMITMENTS

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes the Company's significant contractual cash obligations, other than hedging contracts as of December 31, 2003.

25

----------------------------------------------------------------------------------------------------------
                                                               PAYMENTS DUE BY PERIOD
                                        ------------------------------------------------------------------
                                                      LESS THAN                                     AFTER
(in thousands)                            TOTAL        1 YEAR      1 - 3 YEARS     4 - 5 YEARS     5 YEARS
----------------------------------------------------------------------------------------------------------
Short-term cash obligations             $ 11,000      $ 11,000       $     --       $     --      $     --
Long-term cash obligations (1)           564,533        10,000         37,000         20,000       497,533
Purchase obligations (2)                 242,312        49,227        147,138         37,824         8,123
Capital lease obligations                     --            --             --             --            --
Operating leases                          44,163         3,388          8,151          4,185        28,439
----------------------------------------------------------------------------------------------------------
  Total contractual cash obligations    $862,008      $ 73,615       $192,289       $ 62,009      $534,095
----------------------------------------------------------------------------------------------------------

(1) Long-term cash obligations include $1.7 million of unamortized debt discounts as of December 31, 2003.

(2) Certain of the Company's long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $240 million through October 2013. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 55.1 Bcf through December 2006.

Alagasco has an agreement with a financial institution whereby it may sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $15 million as further described in Note 8. The fair value of these guarantees is not significant to the Company and is recorded as a non-current other liability. Effective February 1, 2004, Alagasco is no longer selling its installment receivables.

OUTLOOK

OIL AND GAS OPERATIONS: Energen Resources plans to continue to implement its acquisition and development program with capital spending in 2004 and 2005 as outlined above. Production in 2004 is estimated to be approximately 85 Bcfe, including 81.6 Bcfe of estimated production from proved reserves owned at December 31, 2003. In 2005, production is estimated to reach approximately 97 Bcfe, including approximately 77 Bcfe produced from proved reserves currently owned.

In the event Energen Resources is unable to fully invest its planned acquisition, development and exploratory expenditures, future operating revenues, production and proved reserves could be negatively affected. Energen Resources' major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, national supply and demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, worldwide political developments and actions of the Organization of Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its exposure to oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. 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 or Alagasco 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. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. Energen Resources may hedge up to 80 percent of its estimated annual production under this policy. As acquisitions are made, Energen Resources may use futures, swaps and/or fixed-price contracts to hedge commodity prices for up to 36 months in order to protect targeted returns.

26

Energen Resources has entered into the following transactions for 2004 and subsequent years:

--------------------------------------------------------------------------------
PRODUCTION   TOTAL HEDGED      AVERAGE CONTRACT
  PERIOD        VOLUMES              PRICE                   DESCRIPTION
--------------------------------------------------------------------------------
                                   NATURAL GAS
--------------------------------------------------------------------------------
   2004         15.8 Bcf           $4.83 Mcf                 NYMEX Swaps
               * 1.7 Bcf           $5.60 Mcf                 NYMEX Swaps
                20.6 Bcf           $4.17 Mcf            Basin Specific Swaps
               * 4.3 Bcf           $5.09 Mcf            Basin Specific Swaps
                 2.4 Bcf       $4.05 - $4.44 Mcf            NYMEX Collars
   2005          1.2 Bcf           $3.75 Mcf                 NYMEX Swaps
                 6.0 Bcf           $3.96 Mcf            Basin Specific Swaps
               * 4.2 Bcf           $4.70 Mcf            Basin Specific Swaps
--------------------------------------------------------------------------------
                                       OIL
--------------------------------------------------------------------------------
   2004        1,428 MBbl         $27.75 Bbl                 NYMEX Swaps
                 360 MBbl         $27.85 Bbl         West Texas Sour (WTS) Swaps
               * 428 MBbl         $30.29 Bbl                 NYMEX Swaps
               * 646 MBbl         $27.62 Bbl                  WTS Swaps
   2005        * 300 MBbl         $30.50 Bbl                 NYMEX Swaps
--------------------------------------------------------------------------------
                             OIL BASIS DIFFERENTIAL
--------------------------------------------------------------------------------
   2004          300 MBbl             **                     Basis Swaps
                * 60 MBbl             **                     Basis Swaps
--------------------------------------------------------------------------------
                               NATURAL GAS LIQUIDS
--------------------------------------------------------------------------------
   2004          37 MMGal          $0.41 Gal                Liquids Swaps
--------------------------------------------------------------------------------

* Contract entered into subsequent to December 31, 2003

** Average contract prices not meaningful due to the varying nature of each contract

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil, natural gas and natural gas liquids may have on the fair value of its derivative instruments. This analysis measured the impact on the commodity derivative instruments and, thereby, did not consider the underlying exposure related to the commodity. At December 31, 2003, the Company estimated that a 10 percent increase or decrease in the commodities prices would have resulted in a $29.1 million change in the fair value of open derivative contracts; however, gains and losses on derivative contracts are expected to be similarly offset by sales at the spot market price. At December 31, 2002 and 2001, the Company estimated that a 10 percent increase in the commodities prices would have resulted in a $27.2 million and a $2.1 million change, respectively, in the fair value of open derivative contracts while a 10 percent decrease in the commodities prices would have resulted in a $26.6 million and a $2.1 million change, respectively, in the fair value of open derivative contracts. The hypothetical change in fair value was calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes and did not include the variance in basis or the impact of related taxes on actual cash prices.

NATURAL GAS DISTRIBUTION: The extension of RSE in June 2002 provides Alagasco the opportunity to continue earning an allowed ROE between 13.15 percent and 13.65 percent through January 1, 2008. Under the terms of that extension, RSE will continue beyond that date, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue its operation. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment rider which permits the pass-through to customers for changes in the cost of gas supply. Also as discussed in Note 2, the utility's CCM is based in part on the number of customers and the rate of inflation. Continued low inflation, significantly higher gas prices resulting in increased bad debt expense and/or the lack of customer growth could impact the utility's ability to manage its O&M expense per customer sufficiently for the inflation-based cost control requirements of RSE and may result in an average return on equity lower than the allowed range of return. Over this period, Alagasco has the potential for net income growth as the investment in additional utility plant affects the level of equity required in the business. The utility continues to rely on rate flexibility to effectively prevent bypass of its distribution system.

27

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 required by SFAS No. 133, Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Gains or losses are passed through to customers using the mechanisms of the GSA in compliance with its APSC-approved tariff. In accordance with SFAS No. 71, Alagasco had recorded a current regulatory asset of $0.3 million, a current regulatory liability of $17 million and a noncurrent regulatory liability of $8.7 million representing the fair value of derivatives as of December 31, 2003.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS: Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. The Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. The Company undertakes no obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, future business decisions, and other uncertainties, all of which are difficult to predict.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned acquisition, development and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns and these risks can be affected by lease and rig availability, complex geology and other factors.

Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate risk, fluctuations in future oil and gas prices could materially affect the Company's financial position, results of operation and cash flows; furthermore, such risk mitigation activities may cause the Company's financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk-mitigation assumes that counterparties maintain satisfactory credit quality.

Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company's overall exposure to credit risk, either positively or negatively, in that the Company's oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. During 2001 and 2002, the credit rating agencies downgraded the credit ratings of a number of energy marketers and their affiliates, including certain oil and gas purchasers of the Company. Energen Resources monitors the credit quality for its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil and gas purchasers account for approximately 15%, 13% and 12%, respectively, of Energen Resources' estimated 2004 production. Energen Resources' other purchasers each buy less than 11% of production.

28

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)

SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," were issued by the FASB in June 2001 and became effective on July 1, 2001, and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method and SFAS No. 142 establishes new guidelines in accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain intangible assets that have indefinite useful lives are not amortized, but rather are reviewed annually for impairment. The appropriate application of SFAS No. 141 and SFAS No. 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves is currently being considered. One interpretation relative to these standards is that oil and gas mineral rights for both undeveloped and developed leaseholds could be classified separately from oil and gas properties as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. In addition, the disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements. The Company anticipates that this interpretation of SFAS No. 141 and SFAS No. 142 would only affect balance sheet classifications of oil and gas leaseholds. Results of operations and cash flows are not anticipated to be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Company will continue to evaluate the impact of the application of these standards as further guidance is provided.

The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), "Accounting for Stock-Based Compensation," prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to four years; therefore, the cost related to stock-based employee compensation included in the determination of net income is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123.

In December 2003, the FASB revised SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits - an amendment of FASB Statements No. 87, 88 and 106." The revised Statement added additional disclosures relating to the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other postretirement plans and is effective for financial statements with fiscal years ending after December 15, 2003, with an exception for the disclosure of estimated future benefit payments effective for fiscal years ending after June 15, 2004. The Company has incorporated within this report the additional required disclosures (See Note 5).

On December 8, 2003, President Bush signed into law a bill that expands Medicare, adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Although the company anticipates that the benefits it pays after 2006 will be lower as a result of the new Medicare provisions, the retiree medical obligations and costs reported do not reflect the impact of this legislation. Deferring the recognition of the new Medicare provisions' impact is permitted by FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," due to open issues related to the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information.

29

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item with respect to market risk is set forth in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Outlook" and in Note 8, Financial Instruments and Risk Management, in the Notes to Financial Statements.

30

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES

                                                                       Page
                                                                       ----
1.    Financial Statements

      ENERGEN CORPORATION

         Report of Independent Auditors..............................   31

         Consolidated Statements of Income for the years ended
         December 31, 2003and 2002, the three months ended December
         31, 2001, and the year ended  September 30, 2001............   32

         Consolidated Balance Sheets as of December 31, 2003 and
         2002........................................................   33

         Consolidated Statements of Shareholders' Equity for the
         years ended December 31, 2003 and 2002, the three months
         ended December 31, 2001, and the year ended September 30,
         2001........................................................   35

         Consolidated Statements of Cash Flows for the years ended
         December 31,  2003 and 2002, the three months ended
         December 31, 2001, and the year ended September 30, 2001 ...   36

         Notes to Financial Statements...............................   42

      ALABAMA GAS CORPORATION

         Report of Independent Auditors..............................   31

         Statements of Income for the years ended December 31, 2003
         and 2002, the three months ended December 31, 2001, and
         the year ended September 30, 2001...........................   37

         Balance Sheets as of December 31, 2003 and 2002 ............   38

         Statements of Shareholder's Equity for the years ended
         December 31, 2003 and 2002, the three months ended
         December 31, 2001, and the year ended  September 30, 2001...   40

         Statements of Cash Flows for the years ended December 31,
         2003 and 2002,the three months ended December 31, 2001,
         and the year ended September30, 2001........................   41

         Notes to Financial Statements...............................   42

2.    Financial Statement Schedules

      ENERGEN CORPORATION
         Schedule II - Valuation and Qualifying Accounts.............   76

      ALABAMA GAS CORPORATION
         Schedule II - Valuation and Qualifying Accounts.............   76

Schedules other than those listed above are omitted because they are not required or not applicable, or the required information is shown in the financial statements or notes thereto.

31

REPORT OF INDEPENDENT AUDITORS
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF ENERGEN CORPORATION:

In our opinion, the consolidated financial statements of Energen Corporation listed in the accompanying index present fairly, in all material respects, the financial position of Energen Corporation and subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the year ended September 30, 2001, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 10 and 12, of the Notes to Financial Statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standard (SFAS) No. 143, "Accounting for Asset Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment of Long-Lived Assets," respectively. As discussed in Note 1 of the Notes to the Financial Statements, effective October 1, 2000, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities."

PricewaterhouseCoopers LLP
Birmingham, Alabama
March 2, 2004

REPORT OF INDEPENDENT AUDITORS
TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF ALABAMA GAS CORPORATION:

In our opinion, the financial statements of Alabama Gas Corporation listed in the accompanying index present fairly, in all material respects, the financial position of Alabama Gas Corporation at December 31, 2003 and 2002, and the results of its operations and its cash flows for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the year ended September 30, 2001, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

PricewaterhouseCoopers LLP
Birmingham, Alabama
March 2, 2004

32

CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION

-------------------------------------------------------------------------------------------------------------------------------
                                                                                                Three Months
                                                             YEAR ENDED        Year Ended          Ended           Year Ended
                                                            DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands, except share data)                               2003              2002              2001              2001
-------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Oil and gas operations                                      $    353,122      $    244,120      $     46,954      $    208,954
Natural gas distribution                                         489,099           424,431            96,678           553,862
-------------------------------------------------------------------------------------------------------------------------------
     Total operating revenues                                    842,221           668,551           143,632           762,816
-------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas                                                      233,823           189,810            45,291           327,531
Operations and maintenance                                       208,219           191,656            53,032           177,688
Depreciation, depletion and amortization                         116,858           101,691            23,468            81,840
Taxes, other than income taxes                                    63,543            49,619            10,728            60,731
Accretion expense                                                  1,890             1,819                --                --
-------------------------------------------------------------------------------------------------------------------------------
     Total operating expenses                                    624,333           534,595           132,519           647,790
-------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME                                                 217,888           133,956            11,113           115,026
-------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense                                                 (42,262)          (43,713)          (10,634)          (42,070)
Other income                                                       8,744            15,644             4,354            16,825
Other expense                                                     (9,977)          (15,103)           (4,385)          (14,892)
-------------------------------------------------------------------------------------------------------------------------------
     Total other expense                                         (43,495)          (43,172)          (10,665)          (40,137)
-------------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE          174,393            90,784               448            74,889
Income tax expense (benefit)                                      64,128            20,388            (3,282)           12,472
-------------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE                         110,265            70,396             3,730            62,417
-------------------------------------------------------------------------------------------------------------------------------
DISCONTINUED OPERATIONS, NET OF TAXES
Income (loss) from discontinued operations                           973               (80)              (72)            5,479
Gain (loss) on disposal                                             (584)              543                --                --
-------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) FROM DISCONTINUED OPERATIONS                           389               463               (72)            5,479
-------------------------------------------------------------------------------------------------------------------------------
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF TAXES                                               --            (2,220)               --                --
-------------------------------------------------------------------------------------------------------------------------------
NET INCOME                                                  $    110,654      $     68,639      $      3,658      $     67,896
-------------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER AVERAGE COMMON SHARE
Continuing operations                                       $       3.09      $       2.08      $       0.12      $       2.01
Discontinued operations                                             0.01              0.02                --              0.17
Cumulative effect of change in accounting principle                   --             (0.07)               --                --
-------------------------------------------------------------------------------------------------------------------------------
Net Income                                                  $       3.10      $       2.03      $       0.12      $       2.18
-------------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER AVERAGE COMMON SHARE
Continuing operations                                       $       3.11      $       2.09      $       0.12      $       2.03
Discontinued operations                                             0.01              0.02                --              0.18
Cumulative effect of change in accounting principle                   --             (0.07)               --                --
-------------------------------------------------------------------------------------------------------------------------------
Net Income                                                  $       3.12      $       2.04      $       0.12      $       2.21
-------------------------------------------------------------------------------------------------------------------------------
DILUTED AVERAGE COMMON SHARES OUTSTANDING                     35,716,876        33,838,299        31,277,406        31,083,784
-------------------------------------------------------------------------------------------------------------------------------
BASIC AVERAGE COMMON SHARES OUTSTANDING                       35,434,486        33,604,601        31,052,152        30,725,919
-------------------------------------------------------------------------------------------------------------------------------

The accompanying Notes to Financial Statements are an integral part of these statements.

33

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION

----------------------------------------------------------------------------------------------
                                                                 DECEMBER 31,     December 31,
(in thousands)                                                       2003             2002
----------------------------------------------------------------------------------------------
ASSETS

CURRENT ASSETS
Cash and cash equivalents                                         $    2,127       $    4,804
Accounts receivable, net of allowance for doubtful accounts
   of $9,852 at December 31, 2003, and of $8,874 at
   December 31, 2002                                                 172,915          139,356
Inventories, at average cost
     Storage gas inventory                                            40,654           23,668
     Materials and supplies                                            7,677            8,335
     Liquified natural gas in storage                                  3,475            3,671
Deferred income taxes                                                 38,145           33,941
Prepayments and other                                                 25,073           20,367
----------------------------------------------------------------------------------------------
     Total current assets                                            290,066          234,142
----------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, successful efforts method                  1,197,340        1,103,472
Less accumulated depreciation, depletion and amortization            310,368          269,616
----------------------------------------------------------------------------------------------
Oil and gas properties, net                                          886,972          833,856
----------------------------------------------------------------------------------------------
Utility plant                                                        883,225          825,421
Less accumulated depreciation                                        341,787          313,414
----------------------------------------------------------------------------------------------
Utility plant, net                                                   541,438          512,007
----------------------------------------------------------------------------------------------
Other property, net                                                    5,041            5,691
----------------------------------------------------------------------------------------------
     Total property, plant and equipment, net                      1,433,451        1,351,554
----------------------------------------------------------------------------------------------
OTHER ASSETS
Deferred income taxes                                                     --           16,333
Regulatory asset                                                      18,082           14,744
Deferred charges and other                                            39,833           26,239
----------------------------------------------------------------------------------------------
     Total other assets                                               57,915           57,316
----------------------------------------------------------------------------------------------

TOTAL ASSETS                                                      $1,781,432       $1,643,012
----------------------------------------------------------------------------------------------

The accompanying Notes to Financial Statements are an integral part of these statements.

34

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION

-----------------------------------------------------------------------------------------------
                                                                  DECEMBER 31,     December 31,
(in thousands, except share data)                                     2003             2002
-----------------------------------------------------------------------------------------------
CAPITAL AND LIABILITIES

CURRENT LIABILITIES
Long-term debt due within one year                                $    10,000      $    23,000
Notes payable to banks                                                 11,000          113,000
Accounts payable                                                      135,319          103,964
Accrued taxes                                                          28,551           27,936
Customers' deposits                                                    17,884           17,404
Amounts due customers                                                   8,571            8,458
Accrued wages and benefits                                             24,957           23,652
Regulatory liability                                                   54,146           41,184
Other                                                                  37,303           34,710
-----------------------------------------------------------------------------------------------
     Total current liabilities                                        327,731          393,308
-----------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Asset retirement obligation                                            26,515           27,235
Minimum pension liability                                              17,911           25,825
Regulatory liability                                                  113,427           96,219
Deferred income taxes                                                  33,200               --
Other                                                                  10,774            4,661
-----------------------------------------------------------------------------------------------
     Total deferred credits and other liabilities                     201,827          153,940
-----------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
-----------------------------------------------------------------------------------------------
CAPITALIZATION
Preferred stock, cumulative, $0.01 par value, 5,000,000
   shares authorized                                                       --               --
Common shareholders' equity
   Common stock, $0.01 par value; 75,000,000 shares
     authorized, 36,223,531 shares outstanding at December
     31, 2003, and 34,745,477 shares outstanding at December
     31, 2002                                                             362              347
   Premium on capital stock                                           367,765          320,060
   Capital surplus                                                      2,802            2,802
   Retained earnings                                                  360,001          275,266
   Accumulated other comprehensive income (loss), net of tax
     Unrealized gain (loss) on hedges                                 (21,714)         (10,471)
     Minimum pension liability                                         (8,881)          (4,340)
Deferred compensation on restricted stock                              (1,258)            (770)
Deferred compensation plan                                             17,063           10,348
Treasury stock, at cost; 415,869 shares and 358,228 shares at
   December 31, 2003 and 2002, respectively                           (17,108)         (10,432)
-----------------------------------------------------------------------------------------------
   Total common shareholders' equity                                  699,032          582,810
Long-term debt                                                        552,842          512,954
-----------------------------------------------------------------------------------------------
   Total capitalization                                             1,251,874        1,095,764
-----------------------------------------------------------------------------------------------
TOTAL CAPITAL AND LIABILITIES                                     $ 1,781,432      $ 1,643,012
-----------------------------------------------------------------------------------------------

The accompanying Notes to Financial Statements are an integral part of these statements.

35

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
ENERGEN CORPORATION

(in thousands, except share amounts)

---------------------------------------------------------------------------------------------------------------------------
                                                         COMMON STOCK
                                                         ------------
                                                    NUMBER OF          PAR        PREMIUM ON      CAPITAL         RETAINED
                                                      SHARES          VALUE     CAPITAL STOCK     SURPLUS         EARNINGS
---------------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2000                          30,350,802         $304        $213,582        $2,802        $ 185,561
Net income                                                                                                          67,896
Other comprehensive income (loss):
     Transition adjustment on cash
        flow hedging activities, net of
        tax of ($35,430)
     Current period change in fair value
        of derivative instruments, net of
        tax of $11,740
     Reclassification adjustment, net of
        tax of $33,619
Comprehensive income
Purchase of treasury shares
Shares issued for:
     Dividend reinvestment plan                         75,480            1           2,366
     Employee benefit plans                            698,479            6          17,523
Deferred compensation obligation
Issuance of restricted stock
Amortization of restricted stock
Cash dividends - $0.685 per share                                                                                  (21,103)
---------------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2001                          31,124,761          311         233,471         2,802          232,354
Net income                                                                                                           3,658
Other comprehensive loss:
     Current period change in fair value
        of derivative instruments, net of
        tax of ($187)
     Reclassification adjustment, net of
        tax of ($3,821)
     Minimum pension liability, net of
        tax of ($1,127)
Comprehensive loss
Purchase of treasury shares
Shares issued for:
     Dividend reinvestment plan                          5,519           --              72
     Employee benefit plans                            118,267            1           2,433
Deferred compensation obligation
Issuance of restricted stock
Amortization of restricted stock
Cash dividends - $0.175 per share                                                                                   (5,458)
---------------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2001                           31,248,547          312         235,976         2,802          230,554
Net income                                                                                                          68,639
Other comprehensive loss:
     Current period change in fair value
        of derivative instruments, net of
        tax of ($9,893)
     Reclassification adjustment, net of
        tax of ($2,724)
     Minimum pension liability, net of
        tax of ($1,211)
Comprehensive income
Purchase of treasury shares
Shares issued for:
     Stock issuance for acquisition                  3,043,479           30          72,861
     Dividend reinvestment plan                         77,725            1           2,020
     Employee benefit plans                            375,726            4           9,203
Deferred compensation obligation
Amortization of restricted stock
Cash dividends - $0.71 per share                                                                                   (23,927)
---------------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2002                           34,745,477          347         320,060         2,802          275,266
Net income                                                                                                         110,654
Other comprehensive income (loss):
     Current period change in fair value
        of derivative instruments, net of
        tax of ($29,019)
     Reclassification adjustment, net of
        tax of $21,830
     Minimum pension liability, net of
        tax of ($2,445)
Comprehensive income
Purchase of treasury shares
Shares issued for:
     Stock offerings                                 1,000,000           10          32,121
     Dividend reinvestment plan                         53,990            1           1,865
     Employee benefit plans                            424,064            4          12,033
Deferred compensation obligation
Issuance of restricted stock
Amortization of restricted stock
Stock based compensation                                                                270
Tax benefit from exercise of stock options                                            1,416
Cash dividends - $0.73 per share                                                                                   (25,919)
---------------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2003                           36,223,531         $362        $367,765        $2,802        $ 360,001
---------------------------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------------------------------------
                                                ACCUMULATED
                                                   OTHER           DEFERRED
                                               COMPREHENSIVE     COMPENSATION     DEFERRED
                                                   INCOME         RESTRICTED    COMPENSATION    TREASURY      SHAREHOLDERS'
                                                   (LOSS)           STOCK           PLAN          STOCK          EQUITY
---------------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2000                        $     --         $    --         $ 4,965      $ (6,354)      $ 400,860
Net income                                                                                                        67,896
Other comprehensive income (loss):
     Transition adjustment on cash
        flow hedging activities, net of                                                                          (55,416)
        tax of ($35,430)                           (55,416)
     Current period change in fair value
        of derivative instruments, net of
        tax of $11,740                              18,363                                                        18,363
     Reclassification adjustment, net of
        tax of $33,619                              52,584                                                        52,584
                                                                                                               ---------
Comprehensive income                                                                                              83,427
                                                                                                               ---------
Purchase of treasury shares                                                                       (2,516)         (2,516)
Shares issued for:
     Dividend reinvestment plan                                                                      331           2,698
     Employee benefit plans                                                                        1,058          18,587
Deferred compensation obligation                                                       294          (294)             --
Issuance of restricted stock                                        (1,662)                                       (1,662)
Amortization of restricted stock                                       476                                           476
Cash dividends - $0.685 per share                                                                                (21,103)
---------------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2001                          15,531          (1,186)          5,259        (7,775)        480,767
Net income                                                                                                         3,658
Other comprehensive loss:
     Current period change in fair value
        of derivative instruments, net of
        tax of ($187)                                 (292)                                                         (292)
     Reclassification adjustment, net of
        tax of ($3,821)                             (5,977)                                                       (5,977)
     Minimum pension liability, net of
        tax of ($1,127)                             (2,094)                                                       (2,094)
                                                                                                               ---------
Comprehensive loss                                                                                                (4,705)
                                                                                                               ---------
Purchase of treasury shares                                                                       (1,245)         (1,245)
Shares issued for:
     Dividend reinvestment plan                                                                      689             761
     Employee benefit plans                                                                        1,978           4,412
Deferred compensation obligation                                                     1,963        (1,963)             --
Issuance of restricted stock                                          (515)                                         (515)
Amortization of restricted stock                                       188                                           188
Cash dividends - $0.175 per share                                                                                 (5,458)
---------------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2001                            7,168          (1,513)          7,222        (8,316)        474,205
Net income                                                                                                        68,639
Other comprehensive loss:
     Current period change in fair value
        of derivative instruments, net of
        tax of ($9,893)                            (15,473)                                                      (15,473)
     Reclassification adjustment, net of
        tax of ($2,724)                             (4,260)                                                       (4,260)
     Minimum pension liability, net of
        tax of ($1,211)                             (2,246)                                                       (2,246)
                                                                                                               ---------
Comprehensive income                                                                                              46,660
                                                                                                               ---------
Purchase of treasury shares                                                                         (133)           (133)
Shares issued for:
     Stock issuance for acquisition                                                                               72,891
     Dividend reinvestment plan                                                                      401           2,422
     Employee benefit plans                                                                          742           9,949
Deferred compensation obligation                                                     3,126        (3,126)             --
Amortization of restricted stock                                       743                                           743
Cash dividends - $0.71 per share                                                                                 (23,927)
---------------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2002                          (14,811)           (770)         10,348       (10,432)        582,810
Net income                                                                                                       110,654
Other comprehensive income (loss):
     Current period change in fair value
        of derivative instruments, net of
        tax of ($29,019)                           (45,388)                                                      (45,388)
     Reclassification adjustment, net of
        tax of $21,830                              34,145                                                        34,145
     Minimum pension liability, net of              (4,541)                                                       (4,541)
        tax of ($2,445)                                                                                          -------
Comprehensive income                                                                                              94,870
                                                                                                                 -------
Purchase of treasury shares                                                                       (1,046)         (1,046)
Shares issued for:
     Stock offerings                                                                                              32,131
     Dividend reinvestment plan                                                                      491           2,357
     Employee benefit plans                                                                          594          12,631
Deferred compensation obligation                                                     6,715        (6,715)             --
Issuance of restricted stock                                        (1,564)                                       (1,564)
Amortization of restricted stock                                     1,076                                         1,076
Stock based compensation                                                                                             270
Tax benefit from exercise of stock options                                                                         1,416
Cash dividends - $0.73 per share                                                                                 (25,919)
---------------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2003                         $(30,595)        $(1,258)        $17,063      $(17,108)      $ 699,032
---------------------------------------------------------------------------------------------------------------------------

The accompanying Notes to Financial Statements are an integral part of these statements.

36

CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION

-------------------------------------------------------------------------------------------------------------------------------
                                                                                                Three Months
                                                             YEAR ENDED        Year Ended          Ended           Year Ended
                                                            DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands)                                                  2003              2002              2001              2001
-------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income                                                   $ 110,654         $  68,639          $  3,658         $  67,896
Adjustments to reconcile net income to net cash
   provided by (used in) operating activities:
      Depreciation, depletion and amortization                 117,785           107,952            25,184            86,975
      Deferred income taxes, net                                54,632            10,915            (8,495)            5,349
      Deferred investment tax credits, net                        (448)             (448)             (112)             (448)
      Change in derivative fair value                              735            (9,205)             (174)             (879)
      (Gain) loss on sale of assets                             (9,987)           (3,738)            3,161            (4,716)
      Loss on properties held for sale                          10,404             2,815                --             3,821
      Cumulative effect of change in accounting
         principle, net of taxes                                    --             2,220                --                --
      Net change in:
         Accounts receivable                                   (24,811)          (27,104)          (17,529)           19,565
         Inventories                                           (16,132)           27,344             7,239           (22,018)
         Accounts payable                                       12,860            28,600             2,442            16,544
         Amounts due customers                                   4,052               626            11,637           (11,655)
         Other current assets and liabilities                   (5,533)            1,712            (4,813)            1,424
      Other, net                                               (11,084)            3,179              (837)           (5,362)
-------------------------------------------------------------------------------------------------------------------------------
         Net cash provided by operating activities             243,127           213,507            21,361           156,496
-------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property, plant and equipment                    (219,593)         (166,075)          (37,752)         (190,695)
Acquisition, net of cash acquired                                   --          (117,043)               --                --
Proceeds from sale of assets                                    29,149            17,094             2,323            17,326
Other, net                                                          30            (2,198)             (252)           (1,038)
-------------------------------------------------------------------------------------------------------------------------------
         Net cash (used in) investing activities              (190,414)         (268,222)          (35,681)         (174,407)
-------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Payment of dividends on common stock                           (25,919)          (23,927)           (5,458)          (21,103)
Issuance of common stock                                        47,119            12,371             5,172            21,285
Purchase of treasury stock                                      (1,046)             (133)           (1,245)           (2,516)
Reduction of long-term debt                                    (23,000)          (21,204)               --           (36,267)
Proceeds from issuance of long-term debt                        49,778                --                --           223,799
Debt issuance costs                                               (322)               --                --            (4,777)
Net change in short-term debt                                 (102,000)           85,930            17,000          (161,000)
-------------------------------------------------------------------------------------------------------------------------------
         Net cash provided by (used in) financing
            activities                                         (55,390)           53,037            15,469            19,421
-------------------------------------------------------------------------------------------------------------------------------
Net change in cash and cash equivalents                         (2,677)           (1,678)            1,149             1,510
Cash and cash equivalents at beginning of period                 4,804             6,482             5,333             3,823
-------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period                   $   2,127         $   4,804          $  6,482         $   5,333
-------------------------------------------------------------------------------------------------------------------------------

The accompanying Notes to Financial Statements are an integral part of these statements.

37

STATEMENTS OF INCOME
ALABAMA GAS CORPORATION

-------------------------------------------------------------------------------------------------------------------------------
                                                                                                Three Months
                                                             YEAR ENDED        Year Ended          Ended           Year Ended
                                                            DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands)                                                  2003              2002              2001              2001
-------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES                                           $ 489,099          $ 424,431         $ 96,678         $ 553,862
-------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas                                                    236,037            191,479           45,651           329,572
Operations and maintenance                                     114,078            109,115           27,687           105,812
Depreciation                                                    37,171             33,682            8,151            30,933
Income taxes
     Current                                                     6,577              8,764           10,348            16,995
     Deferred, net                                              13,546              9,509           (8,689)           (3,099)
     Deferred investment tax credits, net                         (448)              (448)            (112)             (448)
Taxes, other than income taxes                                  34,965             30,785            7,155            37,257
-------------------------------------------------------------------------------------------------------------------------------
     Total operating expenses                                  441,926            382,886           90,191           517,022
-------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME                                                47,173             41,545            6,487            36,840
-------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Allowance for funds used during construction                       948              1,336              122             2,098
Other income                                                     4,132              5,520            1,596             5,978
Other expense                                                   (5,269)            (6,280)          (1,838)           (6,585)
-------------------------------------------------------------------------------------------------------------------------------
     Total other income (expense)                                 (189)               576             (120)            1,491
-------------------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt                                      12,815             13,153            3,327             8,803
Other interest charges                                           1,152              1,404              353             3,513
-------------------------------------------------------------------------------------------------------------------------------
     Total interest charges                                     13,967             14,557            3,680            12,316
-------------------------------------------------------------------------------------------------------------------------------
NET INCOME                                                   $  33,017          $  27,564         $  2,687         $  26,015
-------------------------------------------------------------------------------------------------------------------------------

The accompanying Notes to Financial Statements are an integral part of these statements.

38

BALANCE SHEETS
ALABAMA GAS CORPORATION

--------------------------------------------------------------------------------
                                                  DECEMBER 31,      December 31,
(in thousands)                                        2003              2002
--------------------------------------------------------------------------------
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant                                      $ 883,225         $ 825,421
Less accumulated depreciation                        341,787           313,414
--------------------------------------------------------------------------------
     Utility plant, net                              541,438           512,007
--------------------------------------------------------------------------------
Other property, net                                      331               842
--------------------------------------------------------------------------------
CURRENT ASSETS
Cash                                                   1,440             2,818
Accounts receivable
     Gas                                             134,376           108,630
     Merchandise                                       1,210             1,748
     Other                                             1,018               656
     Allowance for doubtful accounts                  (9,100)           (8,200)
Inventories, at average cost
     Storage gas inventory                            40,654            23,668
     Materials and supplies                            5,527             5,049
     Liquified natural gas in storage                  3,475             3,671
Regulatory asset                                         251                --
Deferred income taxes                                 17,650            20,093
Prepayments and other                                 22,056            18,314
--------------------------------------------------------------------------------
          Total current assets                       218,557           176,447
--------------------------------------------------------------------------------
OTHER ASSETS
Regulatory asset                                      18,082            14,744
Deferred charges and other                            19,285            11,290
--------------------------------------------------------------------------------
          Total other assets                          37,367            26,034
--------------------------------------------------------------------------------
TOTAL ASSETS                                       $ 797,693         $ 715,330
--------------------------------------------------------------------------------

The accompanying Notes to Financial Statements are an integral part of these statements.

39

BALANCE SHEETS
ALABAMA GAS CORPORATION

----------------------------------------------------------------------------------
                                                       DECEMBER 31,   December 31,
(in thousands, except share data)                          2003           2002
----------------------------------------------------------------------------------
CAPITAL AND LIABILITIES
CAPITALIZATION
Preferred stock, cumulative, $0.01 par value,
   120,000 shares authorized                             $     --       $     --
Common shareholder's equity
     Common stock, $0.01 par value; 3,000,000 shares
        authorized, 1,972,052 shares outstanding at
        December 31, 2003 and 2002, respectively               20             20
     Premium on capital stock                              31,682         31,682
     Capital surplus                                        2,802          2,802
     Retained earnings                                    215,869        182,852
----------------------------------------------------------------------------------
     Total common shareholder's equity                    250,373        217,356
Long-term debt                                            169,533        169,533
----------------------------------------------------------------------------------
     Total capitalization                                 419,906        386,889
----------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt due within one year                             --         15,000
Notes payable to banks                                     11,000         13,000
Accounts payable
     Trade                                                 56,020         55,720
     Affiliated companies                                  37,290          1,432
Accrued taxes                                              22,145         24,044
Customers' deposits                                        17,884         17,404
Amounts due customers                                       8,571          8,458
Accrued wages and benefits                                  6,247          5,710
Regulatory liability                                       54,146         41,184
Other                                                       9,039          8,947
----------------------------------------------------------------------------------
     Total current liabilities                            222,342        190,899
----------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes                                      32,178         20,747
Minimum pension liability                                   6,988         18,661
Regulatory liability                                      113,427         96,219
Customer advances for construction and other                2,852          1,915
----------------------------------------------------------------------------------
     Total deferred credits and other liabilities         155,445        137,542
----------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
----------------------------------------------------------------------------------
TOTAL CAPITAL AND LIABILITIES                            $797,693       $715,330
----------------------------------------------------------------------------------

40

STATEMENTS OF SHAREHOLDER'S EQUITY
ALABAMA GAS CORPORATION

----------------------------------------------------------------------------------------------------------------------
                                         COMMON STOCK
                                         ------------
                                                                                                             TOTAL
(in thousands, except                NUMBER OF      PAR       PREMIUM ON      CAPITAL     RETAINED       SHAREHOLDER'S
share amounts)                         SHARES      VALUE     CAPITAL STOCK    SURPLUS     EARNINGS           EQUITY
----------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2000           1,972,052      $ 20        $ 31,682      $ 2,802    $ 164,767          $199,271
Net income                                                                                  26,015            26,015
Cash dividends                                                                             (15,897)          (15,897)
----------------------------------------------------------------------------------------------------------------------
BALANCE SEPTEMBER 30, 2001           1,972,052        20          31,682        2,802      174,885           209,389
Net income                                                                                   2,687             2,687
Cash dividends                                                                              (5,425)           (5,425)
----------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2001            1,972,052        20          31,682        2,802      172,147           206,651
Net income                                                                                  27,564            27,564
Cash dividends                                                                             (16,859)          (16,859)
----------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2002            1,972,052        20          31,682        2,802      182,852           217,356
Net income                                                                                  33,017            33,017
----------------------------------------------------------------------------------------------------------------------
BALANCE DECEMBER 31, 2003            1,972,052      $ 20        $ 31,682      $ 2,802    $ 215,869          $250,373
----------------------------------------------------------------------------------------------------------------------

The accompanying Notes to Financial Statements are an integral part of these statements.

41

STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION

-------------------------------------------------------------------------------------------------------------------------------
                                                                                                Three Months
                                                             YEAR ENDED        Year Ended          Ended           Year Ended
                                                            DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands)                                                  2003              2002              2001              2001
-------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Net income                                                    $ 33,017          $ 27,564          $  2,687          $ 26,015
Adjustments to reconcile net income to net cash
    provided by (used in) operating activities:
      Depreciation and amortization                             37,171            33,682             8,151            30,933
      Deferred income taxes, net                                13,546             9,509            (8,689)           (3,099)
      Deferred investment tax credits                             (448)             (448)             (112)             (448)
      Net change in:
          Accounts receivable                                  (15,923)          (17,151)          (24,648)            6,056
          Inventories                                          (17,268)           27,099             5,968           (20,351)
          Accounts payable                                          49            21,697             1,945            (7,298)
          Amounts due customers                                  4,052               626            11,637           (11,655)
          Other current assets and liabilities                  (4,140)           (6,666)            1,191             7,692
      Other, net                                               (13,774)           (1,447)             (201)           (2,231)
-------------------------------------------------------------------------------------------------------------------------------
          Net cash provided (used) by operating
            activities                                          36,282            94,465            (2,071)           25,614
-------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property, plant and equipment                     (56,255)          (64,257)          (12,820)          (53,749)
Net advances from (to) parent company                           35,858            (1,622)            3,990            (2,093)
Other, net                                                        (263)             (814)              143              (327)
-------------------------------------------------------------------------------------------------------------------------------
          Net cash (used in) investing activities              (20,660)          (66,693)           (8,687)          (56,169)
-------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Payment of dividends on common stock                                --           (16,859)           (5,425)          (15,897)
Reduction of long-term debt                                    (15,000)           (5,467)               --                --
Proceeds from issuance of long-term debt                            --                --                --            75,000
Debt issuance costs                                                 --                --                --            (3,709)
Net change in short-term debt                                   (2,000)           (6,000)           18,000           (24,150)
-------------------------------------------------------------------------------------------------------------------------------
         Net cash provided (used) by financing
           activities                                          (17,000)          (28,326)           12,575            31,244
-------------------------------------------------------------------------------------------------------------------------------
Net change in cash and cash equivalents                         (1,378)             (554)            1,817               689
Cash and cash equivalents at beginning of period                 2,818             3,372             1,555               866
-------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period                    $  1,440          $  2,818          $  3,372          $  1,555
-------------------------------------------------------------------------------------------------------------------------------

The accompanying Notes to Financial Statements are an integral part of these statements.

42

NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Energen Corporation (Energen or the Company) is a diversified energy holding company engaged primarily in the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations) and in the purchase, distribution, and sale of natural gas principally in central and north Alabama (natural gas distribution). The following is a description of the Company's significant accounting policies and practices.

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 is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes.

A. PRINCIPLES OF CONSOLIDATION

The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation (Alagasco), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years' financial statements to the current-year presentation.

B. OIL AND GAS OPERATIONS

PROPERTY AND RELATED DEPLETION: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred. All development costs are capitalized. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated over the estimated useful life of the related asset. The costs and related accumulated depletion of properties sold or retired are removed from the accounts and the resulting gains or losses are included in discontinued operations.

OPERATING REVENUE: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property's over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no material production imbalances at December 31, 2003.

DERIVATIVE COMMODITY INSTRUMENTS: Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids 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.

43

On October 1, 2000 the Company adopted Statement of Financial Accounting Standard (SFAS) No. 133 (as amended), "Accounting for Derivative Instruments and Hedging Activities," which 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 as a component of equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is recognized in operating revenues immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change. As of December 31, 2003, all of the Company's derivatives qualified for cash flow hedge accounting.

Additionally, the Company may also enter into derivatives that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding NYMEX hedge, put options and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change.

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 has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2005.

C. NATURAL GAS DISTRIBUTION

UTILITY PLANT AND DEPRECIATION: Property, plant and equipment is stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets is charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided on the straight-line method over the estimated useful lives of utility property at rates established by the Alabama Public Service Commission (APSC). Approved depreciation rates averaged approximately 4.5 percent in the years ended December 31, 2003 and 2002, for the three months ended December 31, 2001 and for the year ended September 30, 2001.

INVENTORIES: Inventories, which consist primarily of gas stored underground, are stated at average cost.

OPERATING REVENUE AND GAS COSTS: Alagasco records natural gas distribution revenues in accordance with its tarriff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability.

REGULATORY ACCOUNTING: Alagasco is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." In general, SFAS No. 71 requires utilities to capitalize or defer certain costs or revenues, based upon approvals received from regulatory authorities, to be recovered from or refunded to customers in future periods.

44

DERIVATIVE COMMODITY INSTRUMENTS: Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. 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 Gas Supply Adjustment (GSA) rider in accordance with Alagasco's APSC approved tariff and accordingly are recognized as a regulatory asset or liability as required by SFAS No. 71.

TAXES ON REVENUES: Collections and payments of excise taxes are reported on a gross basis. The amounts included in taxes other than income taxes on the consolidated statements of income are as follows:

--------------------------------------------------------------------------------------------
                                                             Three Months
                          YEAR ENDED        Year Ended          Ended           Year Ended
                         DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands)               2003              2002              2001              2001
--------------------------------------------------------------------------------------------
Taxes on revenues          $ 25,218          $ 21,591          $ 4,969           $ 28,766
--------------------------------------------------------------------------------------------

D. INCOME TAXES

The Company uses the liability method of accounting for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are allocated to appropriate subsidiaries using the separate return method.

E. CASH EQUIVALENTS

The Company includes highly liquid marketable securities and debt instruments purchased with a maturity of three months or less in cash equivalents.

F. EARNINGS PER SHARE

The Company's basic earnings per share amounts have been computed based on the weighted-average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities (see Note 9).

G. STOCK-BASED COMPENSATION

The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), "Accounting for Stock-Based Compensation," prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to six years; therefore, the cost related to stock-based employee compensation included in the determination of net income is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123. The following table illustrates the effect on net income and diluted earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period:

45

-------------------------------------------------------------------------------------------------------------------------
                                                                                          Three Months
                                                       YEAR ENDED        Year Ended          Ended           Year Ended
                                                      DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands)                                            2003              2002              2001              2001
-------------------------------------------------------------------------------------------------------------------------
Net income
   As reported                                          $110,654           $68,639           $3,658           $67,896
   Stock based compensation expense included in
      reported net income, net of tax                      4,553             1,811              573             1,820
   Stock based compensation expense determined
     under fair value based method, net of tax            (3,904)           (2,413)            (539)           (2,158)
-------------------------------------------------------------------------------------------------------------------------
   Pro forma                                            $111,303           $68,037           $3,692           $67,558
-------------------------------------------------------------------------------------------------------------------------
Diluted earnings per average common share
   As reported                                             $3.10             $2.03            $0.12             $2.18
   Pro forma                                               $3.12             $2.01            $0.12             $2.17
-------------------------------------------------------------------------------------------------------------------------
Basic earnings per average common share
   As reported                                             $3.12             $2.04            $0.12             $2.21
   Pro forma                                               $3.14             $2.02            $0.12             $2.20
-------------------------------------------------------------------------------------------------------------------------

The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded, which are included in the pro forma results above. For purposes of this valuation the following assumptions were used to derive the fair values: a seven-year time of exercise; an annualized volatility rate of 34.67 percent for the year ended December 31, 2003 and the three months ended December 31, 2001, and 36.35 percent for the year ended September 30, 2001; a risk-free interest rate of 2.36 percent, 3.36 percent and 4.14 percent for the year ended December 31, 2003, the three months ended December 31, 2001, and the year ended September 30, 2001, respectively; and a dividend yield of 3.12 percent and 2.55 percent on options without dividend equivalents for the three months ended December 31, 2001, and the year ended September 30, 2001, respectively. Options with dividend equivalents assume no dividend yield for all periods presented. The weighted-average grant-date fair value for options granted with dividend equivalents during the year ended December 31, 2003 was $12.10; $9.74 for options granted with dividend equivalents and $6.52 for options granted without dividend equivalents during the three months ended December 31, 2001; $12.66 for options granted with dividend equivalents and $9.27 for options granted without dividend equivalents during the year-ended September 30, 2001. There were no options granted in the year ended December 31, 2002.

H. ESTIMATES

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include but are not limited to estimates of physical quantities of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," will continue as the applicable accounting standard for the Company's regulated operations and estimates used in determining the Company's obligations under its employee pension plans. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

2. REGULATORY MATTERS

All of Alagasco's utility operations are conducted in the state of Alabama. Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended with modifications in 2002, 1996, 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 terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operations. Alagasco's allowed range of return

46

on equity 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 equity 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 percent. 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. As of September 30, 2003, Alagasco had a $3 million reduction in revenues to bring the return on average equity within the allowed range of return. 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 adjustments. The increase in O&M expense per customer was slightly above the index range for the rate year ended September 30, 2003 and 2002; as a result, the utility returned to customers $0.1 million pre-tax and $0.3 million pre-tax through rate adjustments under the provisions of RSE. An $11.2 million, $12.7 million and $16.3 million annual increase in revenues became effective December 1, 2003, 2002, and 2001, respectively, under RSE.

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 primarily to residential, small commercial and small industrial customers. Alagasco's rate schedules for natural gas distribution charges contain a 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 fiscal year 1998 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 results 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 the year ended September 30, 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. The ESR balances of $3.5 million at December 31, 2003 and $3 million at December 31, 2002, are included in the consolidated financial statements.

At December 31, 2003 and 2002, Alagasco had a $21.7 million and an $18.7 million, respectively, gross additional minimum pension liability related to its salaried and union pension plans. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," Alagasco has established a regulatory asset of $18.1 million and $14.7 million for the accrued obligation to be recovered through rates in future periods at December 31, 2003 and 2002, respectively.

During 2003, Alagasco revised its balance sheet presentation to reflect the margin on service delivered to cycle customers but not yet billed in current assets as accounts receivable with a corresponding regulatory liability and has reclassified deferred gas costs as accounts receivable. As a result, current assets and regulatory liability increased $26.1 million and $17.4 million at December 31, 2003 and 2002, respectively.

47

The excess of total acquisition costs over book value of net assets of acquired municipal gas distribution systems is included in utility plant and is being amortized through Alagasco's rate-setting mechanism on a straight-line basis over approximately 23 years. At December 31, 2003 and 2002, the net acquisition adjustments were $12.6 million and $13.8 million, respectively.

3. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

---------------------------------------------------------------------------------------------------------
(in thousands)                                                   DECEMBER 31, 2003      December 31, 2002
---------------------------------------------------------------------------------------------------------
Energen Corporation:
  Medium-term Notes, interest ranging from 6.81% to 8.09%,
for notes redeemable July 14, 2004, to February 15, 2028             $ 345,000              $ 353,000
  5% Notes, redeemable October 1, 2013                                  50,000                     --
Alabama Gas Corporation:
  Medium-term Notes, interest ranging from 6.35% to 7.97%,
for notes redeemable July 15, 2005, to September 23, 2026               95,000                110,000
  6.25% Notes, redeemable September 1, 2016                             39,758                 39,758
  6.75% Notes, redeemable September 1, 2031                             34,775                 34,775
---------------------------------------------------------------------------------------------------------
Total                                                                  564,533                537,533
Less amounts due within one year                                        10,000                 23,000
Less unamortized debt discount                                           1,691                  1,579
---------------------------------------------------------------------------------------------------------
     Total                                                           $ 552,842              $ 512,954
---------------------------------------------------------------------------------------------------------

The aggregate maturities of Energen's long-term debt for the next five years are as follows:

--------------------------------------------------------------------------------
                    Years ending December 31, (in thousands)
--------------------------------------------------------------------------------
  2004             2005               2006              2007              2008
--------------------------------------------------------------------------------
$ 10,000         $ 10,000           $ 20,000           $ 7,000          $ 15,000
--------------------------------------------------------------------------------

The aggregate maturities of Alagasco's long-term debt for the next five years are as follows:

--------------------------------------------------------------------------------
                    Years ending December 31, (in thousands)
--------------------------------------------------------------------------------
  2004             2005               2006              2007              2008
--------------------------------------------------------------------------------
$     --         $ 10,000           $ 10,000           $ 7,000          $  5,000
--------------------------------------------------------------------------------

At December 31, 2003, the Company was not subject to restrictions on the payment of dividends. The Company is in compliance with the covenants under the various long-term debt agreements. Except as discussed below, debt covenants address routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. Payments with respect to Alagasco's 6.25% Notes and 6.75% Notes are insured by Ambac Assurance Corporation. Under the insurance agreement, Alagasco agreed that it will not dispose of distribution plant assets if, after such disposition, its distribution plant will be less than $200 million. Alagasco's distribution plant exceeded $200 million at December 31, 2003. All of the Company's debt is unsecured.

Energen and Alagasco had short-term credit lines and other credit facilities of $267 million available as of December 31, 2003, for working capital needs; Alagasco has been authorized to borrow up to $70 million of the available credit lines by the APSC. The following is a summary of information relating to notes payable to banks:

-----------------------------------------------------------------------------------------------
(in thousands)                                           DECEMBER 31, 2003    December 31, 2002
-----------------------------------------------------------------------------------------------
Energen outstanding                                          $     --              $100,000
Alagasco outstanding                                           11,000                13,000
-----------------------------------------------------------------------------------------------
Notes payable to banks                                         11,000               113,000
Available for borrowings                                      256,000               154,000
-----------------------------------------------------------------------------------------------
Total                                                        $267,000              $267,000
-----------------------------------------------------------------------------------------------
Maximum amount outstanding at any month-end                  $ 83,000              $113,000

48

Average daily amount outstanding                             $ 81,121              $ 85,644
Weighted average interest rates based on:
     Average daily amount outstanding                            1.71%                 2.28%
     Amount outstanding at year-end                              1.42%                 1.88%
-----------------------------------------------------------------------------------------------
Alagasco maximum amount outstanding at any month-end         $ 11,000              $ 21,000
Alagasco average daily amount outstanding                    $  9,592              $  3,304
Alagasco weighted average interest rates based on:
     Average daily amount outstanding                            1.53%                 2.18%
     Amount outstanding at year-end                              1.42%                 1.78%
-----------------------------------------------------------------------------------------------

Energen's total interest expense was $42,262,000 and $43,713,000 for the years ended December 31, 2003 and 2002, respectively, $10,634,000 for the three months ended December 31, 2001 and $42,070,000 for the year ended September 31, 2001. Total interest expense at Alagasco was $13,967,000 and $14,557,000 for the years ended December 31, 2003 and 2002, respectively, $3,680,000 for the three months ended December 31, 2001 and $12,316,000 for the year ended September 30, 2001.

4. INCOME TAXES

The components of Energen's income taxes consisted of the following:

------------------------------------------------------------------------------------------------------------
                                                                              Three Months
                                               YEAR ENDED      Year Ended        Ended          Year Ended
                                              DECEMBER 31,    December 31,    December 31,     September 30,
(in thousands)                                    2003            2002            2001             2001
------------------------------------------------------------------------------------------------------------
Taxes estimated to be payable currently:
     Federal                                    $  8,904        $  7,263        $  3,774         $  6,498
     State                                         1,294             535           1,551            1,073
------------------------------------------------------------------------------------------------------------
          Total current                           10,198           7,798           5,325            7,571
------------------------------------------------------------------------------------------------------------
Taxes deferred:
     Federal                                      47,805           9,062          (7,211)           3,073
     State                                         6,125           3,528          (1,396)           1,828
------------------------------------------------------------------------------------------------------------
          Total deferred                          53,930          12,590          (8,607)           4,901
------------------------------------------------------------------------------------------------------------
Total income tax expense (benefit) from
   continuing operations                        $ 64,128        $ 20,388        $ (3,282)        $ 12,472
------------------------------------------------------------------------------------------------------------

In addition, Energen recorded income tax expense (benefit), related to income from discontinued operations, of ($5,000) in current income tax benefit and $254,000 in deferred income tax expense for the year ended December 31, 2003, $2,418,000 in current income tax expense and ($2,123,000) in deferred income tax benefit for the year ended December 31, 2002, ($43,000) in current income tax benefit for the three months ended December 31, 2001, and $3,504,000 in current income tax expense for the year ended September 30, 2001.

The components of Alagasco's income taxes consisted of the following:

------------------------------------------------------------------------------------------------------------
                                                                              Three Months
                                               YEAR ENDED      Year Ended        Ended          Year Ended
                                              DECEMBER 31,    December 31,    December 31,     September 30,
(in thousands)                                    2003            2002            2001             2001
------------------------------------------------------------------------------------------------------------
Taxes estimated to be payable currently:
     Federal                                    $  5,827        $  7,763        $  9,167         $ 15,456
     State                                           750           1,001           1,181            1,539
------------------------------------------------------------------------------------------------------------
          Total current                            6,577           8,764          10,348           16,995
------------------------------------------------------------------------------------------------------------
Taxes deferred:
     Federal                                      11,549           7,974          (7,807)          (3,193)
     State                                         1,549           1,087            (994)            (354)
------------------------------------------------------------------------------------------------------------
          Total deferred                          13,098           9,061          (8,801)          (3,547)
------------------------------------------------------------------------------------------------------------
Total income tax expense from continuing
   Operations                                   $ 19,675        $ 17,825        $  1,547         $ 13,448
------------------------------------------------------------------------------------------------------------

49

Temporary differences and carryforwards which gave rise to a significant portion of Energen's and Alagasco's deferred tax assets and liabilities for 2003, 2002 and 2001 were as follows:

--------------------------------------------------------------------------------------------------------------
Energen Corporation
--------------------------------------------------------------------------------------------------------------
(in thousands)                                        DECEMBER 31, 2003                 December 31, 2002
--------------------------------------------------------------------------------------------------------------
                                                  CURRENT        NONCURRENT          Current        Noncurrent
                                                 -------------------------------------------------------------
Deferred tax assets:
     Minimum tax credit                          $      --        $  59,313         $      --        $  64,756
     Pension and other costs                            --            8,093             5,326            7,056
     Unbilled and deferred revenue                  10,578               --             8,690               --
     Enhanced stability reserve and other
        regulatory costs                             1,346               --             1,217               --
     Allowance for doubtful accounts                 3,611               --             3,316               --
     Insurance accruals                              2,946               --             2,736               --
     Compensation accruals                           3,639               --             2,789               --
     Inventories                                     1,001               --             1,204               --
     Other comprehensive income                     12,548            6,116             5,980            3,053
     Other, net                                      2,851              556             2,792            2,153
--------------------------------------------------------------------------------------------------------------
        Total deferred tax assets                   38,520           74,078            34,050           77,018
--------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
     Depreciation and basis differences                 --           99,185                --           53,622
     Minimum pension liability                          --            8,093                --            7,056
     Other comprehensive income                         --               --                --               --
     Other, net                                        375               --               109                7
--------------------------------------------------------------------------------------------------------------
        Total deferred tax liabilities                 375          107,278               109           60,685
--------------------------------------------------------------------------------------------------------------
Net deferred tax  assets (liabilities)           $  38,145        $ (33,200)        $  33,941        $  16,333
--------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------
Alabama Gas Corporation
--------------------------------------------------------------------------------------------------------------
(in thousands)                                        DECEMBER 31, 2003                 December 31, 2002
--------------------------------------------------------------------------------------------------------------
                                                  CURRENT        NONCURRENT          Current        Noncurrent
                                                 -------------------------------------------------------------
Deferred tax assets:
     Pension and other costs                     $      --        $   8,093         $     823        $   7,056
     Unbilled and deferred revenue                  10,578               --             8,690               --
     Enhanced stability reserve and other
        regulatory costs                             1,346               --             1,217               --
     Allowance for doubtful accounts                 3,441               --             3,100               --
     Insurance accruals                              2,503               --             2,330               --
     Compensation accruals                           2,216               --             1,680               --
     Inventories                                       835               --             1,171               --
     Other, net                                      1,241              486             1,093              791
--------------------------------------------------------------------------------------------------------------
        Total deferred tax assets                   22,160            8,579            20,104            7,847
--------------------------------------------------------------------------------------------------------------
Deferred tax liabilities:
     Depreciation and basis differences                 --           32,664                --           21,538
      Pension and other costs                        4,498               --                --               --
      Minimum pension liability                         --            8,093                --            7,056
      Other, net                                        12               --                11               --
--------------------------------------------------------------------------------------------------------------
        Total deferred tax liabilities               4,510           40,757                11           28,594
--------------------------------------------------------------------------------------------------------------
Net deferred tax assets (liabilities)            $  17,650        $ (32,178)        $  20,093        $ (20,747)
--------------------------------------------------------------------------------------------------------------

The Company files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2003,

50

the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $59.3 million. No valuation allowance with respect to deferred taxes is deemed necessary, as the Company anticipates generating adequate future taxable income to realize the benefits of all deferred tax assets on the consolidated balance sheets.

Total income tax expense for the Company differed from the amount which would have been provided by applying the statutory federal income tax rate of 35% to earnings before taxes from continuing operations as illustrated below:

--------------------------------------------------------------------------------------------------------------------
                                                                                       Three Months
                                                       YEAR ENDED       Year Ended        Ended         Year Ended
                                                      DECEMBER 31,     December 31,    December 31,    September 30,
(in thousands)                                            2003             2002            2001            2001
--------------------------------------------------------------------------------------------------------------------
Income tax expense from continuing operations
  at statutory federal income tax rate                  $ 61,038         $ 31,774        $    157        $ 26,211
Increase (decrease) resulting from:
     Nonconventional fuels tax credits                        --          (14,165)         (3,481)        (13,588)
     Enhanced oil recovery tax credits                      (469)              --              --             (25)
     Deferred investment tax credits                        (448)            (448)           (112)           (448)
     State income taxes, net of federal income
       tax benefit                                         5,108            2,453              41           1,518
     Other, net                                           (1,101)             774             113          (1,196)
--------------------------------------------------------------------------------------------------------------------
Total income tax expense (benefit)
from continuing operations                              $ 64,128         $ 20,388        $ (3,282)       $ 12,472
--------------------------------------------------------------------------------------------------------------------
Effective income tax rate (%)                              36.77            22.46              --           16.65
--------------------------------------------------------------------------------------------------------------------

Total income tax expense for Alagasco differed from the amount which would have been provided by applying the statutory federal income tax rate of 35% to earnings before taxes from continuing operations as illustrated below:

--------------------------------------------------------------------------------------------------------------------
                                                                                       Three Months
                                                       YEAR ENDED       Year Ended        Ended         Year Ended
                                                      DECEMBER 31,     December 31,    December 31,    September 30,
(in thousands)                                            2003             2002            2001            2001
--------------------------------------------------------------------------------------------------------------------
Income tax expense from continuing operations
  at statutory federal income tax rate                  $ 18,442         $ 15,886        $  1,482        $ 13,812
Increase (decrease) resulting from:
     Deferred investment tax credits                        (448)            (448)           (112)           (448)
     State income taxes, net of federal income
       tax benefit                                         1,480            1,236             116             799
     Other, net                                              201            1,151              61            (715)

--------------------------------------------------------------------------------------------------------------------
Total income tax expense from continuing
  operations                                            $ 19,675         $ 17,825        $  1,547        $ 13,448
--------------------------------------------------------------------------------------------------------------------
Effective income tax rate (%)                              37.34            39.27           36.54           34.08
--------------------------------------------------------------------------------------------------------------------

5. EMPLOYEE BENEFIT PLANS

The Company has two defined benefit non-contributory pension plans: Plan A covers a majority of the employees and Plan B covers employees under certain labor union agreements. Benefits are based on years of service and final earnings for Plan A. Plan B provides benefits based on years of service and flat dollar amounts. The Company's policy is to use the projected unit credit actuarial method for funding and financial reporting purposes. For its pension plans, Energen used a September 30 measurement date.

51

The status of the plans was as follows:

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                                   PLAN A
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Projected benefit obligation:
Balance at beginning of period                                $ 101,399         $  92,101         $  90,613
Service cost                                                      3,955             3,074               899
Interest cost                                                     6,640             6,173             1,644
Actuarial loss (gain)                                            15,449             6,093               (46)
Benefits paid                                                   (11,810)           (6,042)           (1,009)
-------------------------------------------------------------------------------------------------------------
Balance at end of period                                        115,633           101,399            92,101
-------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of period                 67,594            67,967            74,486
Actual return (loss) on plan assets                              14,252            (5,331)           (5,510)
Employer contributions                                           19,900            11,000                --
Benefits paid                                                   (11,810)           (6,042)           (1,009)
-------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                       89,936            67,594            67,967
-------------------------------------------------------------------------------------------------------------
Amounts recognized in the consolidated balance sheets:
Funded status of plan                                           (25,697)          (33,805)          (24,134)
Prepaid pension costs                                           (14,087)               --                --
Unrecognized actuarial loss (gain)                               37,991            30,565            12,996
Unrecognized prior service cost                                   1,793             2,027             2,262
Unrecognized net transition obligation (asset)                       --                --              (196)
-------------------------------------------------------------------------------------------------------------
Accrued pension asset (liability)                             $      --         $  (1,213)        $  (9,072)
-------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation                                $  94,476         $  83,871         $  73,725
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                                   PLAN B
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Projected benefit obligation:
Balance at beginning of period                                $  21,988         $  17,945         $  17,949
Service cost                                                        491               396                80
Interest cost                                                     1,417             1,422               320
Plan amendment                                                       --             1,781                --
Actuarial loss (gain)                                             2,190             1,912                58
Benefits paid                                                    (1,799)           (1,468)             (462)
-------------------------------------------------------------------------------------------------------------
Balance at end of period                                         24,287            21,988            17,945
-------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of period                 15,688            18,420            20,666
Actual return (loss) on plan assets                               2,946            (1,264)           (1,784)
Employer contributions                                            4,000                --                --
Benefits paid                                                    (1,799)           (1,468)             (462)
-------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                       20,835            15,688            18,420
-------------------------------------------------------------------------------------------------------------
Amounts recognized in the consolidated balance sheets:
Funded status of plan                                            (3,452)           (6,300)              475
Prepaid pension costs                                            (3,609)               --                --
Unrecognized actuarial loss (gain)                                5,120             4,315              (481)
Unrecognized prior service cost                                   1,941             2,295               869
Unrecognized net transition obligation (asset)                       --                --                43
Company contribution                                              3,200                --                --
-------------------------------------------------------------------------------------------------------------
Accrued pension asset (liability)                             $   3,200         $     310         $     906
-------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation                                $  24,287         $  21,988         $  17,945
-------------------------------------------------------------------------------------------------------------

Weighted average rate assumptions used to determine the projected benefit obligations at the measurement date:

52

-------------------------------------------------------------------------------------------------------------
                                                                                 PLAN A
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Discount rate                                                    6.00%             6.75%             7.50%
Rate of compensation increase                                    4.00%             4.50%             4.50%
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
                                                                                 PLAN B
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Discount rate                                                    6.00%             6.75%             7.50%
-------------------------------------------------------------------------------------------------------------

The components of net pension expense were:

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                              PLAN A
-------------------------------------------------------------------------------------------------------------
                                                                                Three Months
                                                 YEAR ENDED      Year Ended        Ended         Year Ended
                                                DECEMBER 31,    December 31,    December 31,    September 30,
                                                    2003            2002            2001            2001
                                                -------------------------------------------------------------
Components of net periodic benefit cost:
Service cost                                      $ 3,955         $ 3,074         $   899         $ 2,219
Interest cost                                       6,640           6,173           1,643           5,458
Expected long-term return on assets                (6,858)         (6,145)         (1,537)         (5,778)
Prior service cost amortization                       235             235              59             235
Actuarial loss (gain)                                  --              --               2             422
Net periodic benefit cost                             628              --              --              --
Transition amortization                                --            (196)            (65)           (808)
-------------------------------------------------------------------------------------------------------------
Net periodic expense                              $ 4,600         $ 3,141         $ 1,001         $ 1,748
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                              PLAN B
-------------------------------------------------------------------------------------------------------------
                                                                                Three Months
                                                 YEAR ENDED      Year Ended        Ended         Year Ended
                                                DECEMBER 31,    December 31,    December 31,    September 30,
                                                    2003            2002            2001            2001
                                                -------------------------------------------------------------
Components of net periodic benefit cost:
Service cost                                      $   491         $   396         $    80         $   255
Interest cost                                       1,417           1,422             320           1,267
Expected long-term return on assets                (1,561)         (1,619)           (406)         (1,466)
Prior service cost amortization                       354             354              59             235
Actuarial loss (gain)                                  --              --              --             (28)
Transition amortization                                --              43              14              57
-------------------------------------------------------------------------------------------------------------
Net periodic expense                              $   701         $   596         $    67         $   320
-------------------------------------------------------------------------------------------------------------

Net pension expense for Alagasco was $4,370,000 and $3,224,000 for the years ended December 31, 2003 and 2002, respectively, $918,000 for the three months ended December 31, 2001 and $1,812,000 for the year ended September 30, 2001.

Weighted average rate assumptions to determine net periodic benefit costs for the period ending:

-------------------------------------------------------------------------------------------------------------
                                                                            PLAN A
-------------------------------------------------------------------------------------------------------------
                                                DECEMBER 31,    December 31,    December 31,    September 30,
                                                    2003            2002            2001            2001
                                                -------------------------------------------------------------
Discount rate                                       6.75%           7.50%           7.50%           8.00%
Expected long-term return on plan assets            9.00%           9.00%           9.00%           8.25%
Rate of compensation increase                       4.50%           4.50%           4.50%           5.50%
-------------------------------------------------------------------------------------------------------------

53

-------------------------------------------------------------------------------------------------------------
                                                                            PLAN B
-------------------------------------------------------------------------------------------------------------
                                                DECEMBER 31,    December 31,    December 31,    September 30,
                                                    2003            2002            2001            2001
                                                -------------------------------------------------------------
Discount rate                                       6.75%           7.50%           7.50%           8.00%
Expected long-term return on plan assets            9.00%           9.00%           9.00%           8.25%
-------------------------------------------------------------------------------------------------------------

The Company's weighted-average pension plan asset allocations by asset category were as follows:

-------------------------------------------------------------------------------------------------------------
                                                                                 PLAN A
-------------------------------------------------------------------------------------------------------------
                                                             DECEMBER 31,      DECEMBER 31,      DECEMBER 31,
                                                                 2003              2002              2001
                                                             ------------------------------------------------
Asset category:
Equity securities                                                 64%               54%               56%
Debt securities                                                   34%               40%               41%
Other                                                              2%                6%                3%
-------------------------------------------------------------------------------------------------------------
Total                                                            100%              100%              100%
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
                                                                                 PLAN B
-------------------------------------------------------------------------------------------------------------
                                                             DECEMBER 31,      DECEMBER 31,      DECEMBER 31,
                                                                 2003              2002              2001
                                                             ------------------------------------------------
Asset category:
Equity securities                                                 71%               66%               61%
Debt securities                                                   27%               31%               36%
Other                                                              2%                3%                3%
-------------------------------------------------------------------------------------------------------------
Total                                                            100%              100%              100%
-------------------------------------------------------------------------------------------------------------

Equity securities for Plan A and Plan B do not include the Company's common stock.

Under SFAS No. 87, "Employers' Accounting for Pensions," Energen recorded a minimum pension liability for the accumulated benefit obligation in excess of plan assets at December 31, 2003 and 2002, of $8 million and $21.7 million, respectively. Alagasco established a regulatory asset of $18.1 million and $14.7 million as of December 31, 2003 and 2002, respectively, for the portion of this accrued benefit obligation to be recovered through rates in future periods in accordance with SFAS No. 71. An intangible asset was recorded for the unrecognized prior service cost of $3.7 million and $4.3 million at December 31, 2003 and 2002, respectively, and the balance of $2.5 million and $1.7 million at December 31, 2003 and 2002, respectively, was recorded as a component of accumulated other comprehensive income, net of tax. Subsequent to December 31, 2003, Energen contributed an additional $773,000 to Plan A assets and $46,000 to Plan B assets. The Company does not expect to make additional contributions to Plan A or Plan B assets during 2004.

The Company has supplemental retirement plans with certain key executives providing payments on retirement, termination, death or disability. Expense (income) under these agreements for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the year ended September 30, 2001 was $386,000 $314,000, $(125,000), and $381,000, respectively. At September 30, 2003, 2002 and 2001, the accumulated post-retirement benefit obligation related to these agreements was $15,760,000, $10,093,000 and $9,198,000, respectively, and the projected benefit obligation was $23,203,000, $15,209,000 and $14,082,000, respectively. An accrued post-retirement benefit liability of $5,327,000 and $5,860,000 was recorded at December 31, 2003 and 2002, respectively. The Company has established and funded a trust of $5.9 million and $2.9 million as of December 31, 2003 and December 31, 2002, respectively. While intended for payment of this benefit, the trusts' assets remain subject to the claims of our creditors. The Company is not required to make any contributions to the supplemental retirement plans for 2004 but is currently evaluating possible discretionary contributions. For its supplemental retirement plans, the Company used a September 30 measurement date.

The Company recorded a minimum pension liability for supplemental retirement plans of $9.9 million and $4.2 million at December 31, 2003 and 2002, respectively. A corresponding amount was recognized as an intangible

54

asset for the unrecognized prior service cost of $76,000 and $81,000 at December 31, 2003 and 2002, respectively, and the balance was recorded as a component of accumulated other comprehensive income, net of tax, of $6.4 million and $2.6 million at December 31, 2003 and 2002, respectively.

In addition to providing pension benefits, the Company provides certain post-retirement health care and life insurance benefits. Substantially all of the Company's employees may become eligible for certain benefits if they reach normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability. For its post-retirement benefit programs, the Company used a September 30 measurement date.

The status of the post-retirement benefit programs was as follows:

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                             SALARIED EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Projected post-retirement benefit obligation:
Balance at beginning of period                                 $ 31,008          $ 35,888         $ 36,518
Service cost                                                        823               831              261
Interest cost                                                     2,045             2,120              649
Actuarial loss (gain)                                             7,262            (6,264)          (1,274)
Benefits paid                                                    (1,663)           (1,567)            (266)
-------------------------------------------------------------------------------------------------------------
Balance at end of period                                         39,475            31,008           35,888
-------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of period                 24,127            30,921           36,142
Actual return (loss) on plan assets                               5,064            (7,073)          (5,184)
Company contribution                                              1,762             1,846              229
Benefits paid                                                    (1,663)           (1,567)            (266)
-------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                       29,290            24,127           30,921
-------------------------------------------------------------------------------------------------------------
Amounts recognized in the consolidated balance sheets:
Funded status of plan                                           (10,185)           (6,881)          (4,967)
Unrecognized actuarial loss (gain)                                2,235            (1,259)          (4,035)
Unrecognized net transition obligation                            7,126             7,809            8,491
Company contribution                                                650               265              410
-------------------------------------------------------------------------------------------------------------
Accrued benefit asset (liability)                              $   (174)         $    (66)        $   (101)
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                              UNION EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Projected post-retirement benefit obligation:
Balance at beginning of period                                 $ 30,609          $ 40,077         $ 40,986
Service cost                                                        412               807              218
Interest cost                                                     2,010             2,800              727
Plan amendment                                                     (158)              248               --
Actuarial loss (gain)                                             3,256           (11,282)          (1,450)
Benefits paid                                                    (2,320)           (2,041)            (404)
-------------------------------------------------------------------------------------------------------------
Balance at end of period                                         33,809            30,609           40,077
-------------------------------------------------------------------------------------------------------------
Plan assets:
Fair value of plan assets at beginning of period                 23,895            27,954           31,917
Actual return (loss) on plan assets                               5,829            (4,159)          (4,628)
Company contribution                                              1,224             2,141            1,069
Benefits paid                                                    (2,320)           (2,041)            (404)
-------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of period                       28,628            23,895           27,954
-------------------------------------------------------------------------------------------------------------
Amounts recognized in the consolidated balance sheets:
Funded status of plan                                            (5,181)           (6,714)         (12,123)

55

Unrecognized actuarial loss (gain)                               (8,066)           (7,869)          (3,314)
Unrecognized prior service costs                                     63               237               --
Unrecognized net transition obligation (asset)                   12,526            13,811           15,096
Company contribution                                                500               392              494
-------------------------------------------------------------------------------------------------------------
Accrued benefit asset (liability)                             $   (158)        $   (143)        $      153
-------------------------------------------------------------------------------------------------------------

Weighted average rate assumptions used to determine post-retirement benefit obligations at the measurement date:

-------------------------------------------------------------------------------------------------------------
                                                                           SALARIED EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Discount rate                                                    6.00%             6.75%             7.50%
Rate of compensation increase                                    4.00%             4.50%             4.50%
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
                                                                            UNION EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Discount rate                                                    6.00%             6.75%             7.50%
-------------------------------------------------------------------------------------------------------------

Net periodic post-retirement benefit expense included the following:

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                       SALARIED EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                                               Three Months
                                                 YEAR ENDED      Year Ended        Ended         Year Ended
                                                DECEMBER 31,    December 31,    December 31,    September 30,
                                                    2003            2002            2001            2001
                                                -------------------------------------------------------------
Components of net periodic benefit cost:
Service cost                                      $   823          $   831         $   261         $ 1,095
Interest cost                                       2,045            2,120             649           2,327
Expected long-term return on assets                (1,298)          (1,678)           (490)         (1,994)
Actuarial loss (gain)                                  --             (434)           (111)         (1,098)
Transition amortization                               682              682             181             723
-------------------------------------------------------------------------------------------------------------
Net periodic expense                              $ 2,252          $ 1,521         $   490         $ 1,053
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                        UNION EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                                               Three Months
                                                 YEAR ENDED      Year Ended        Ended         Year Ended
                                                DECEMBER 31,    December 31,    December 31,    September 30,
                                                    2003            2002            2001            2001
                                                -------------------------------------------------------------
Components of net periodic benefit cost:
Service cost                                      $   412          $   807         $   218         $   733
Interest cost                                       2,010            2,800             727           3,095
Expected long-term return on assets                (2,102)          (2,472)           (720)         (1,723)
Actuarial loss (gain)                                (283)             (93)            (57)           (336)
Prior service cost                                     16               12              --              --
Transition amortization                             1,285            1,285             321           1,285
-------------------------------------------------------------------------------------------------------------
Net periodic expense                              $ 1,338          $ 2,339         $   489         $ 3,054
-------------------------------------------------------------------------------------------------------------

Net periodic post-retirement benefit expense for Alagasco was $2,902,000, $3,493,000 for the years ended December 31, 2003 and 2002, respectively, $905,000 for the three months ended December 31, 2001 and $3,959,000 for the year ended September 30, 2001.

Weighted average rate assumptions to determine net periodic benefit costs for the period ending:

56

-------------------------------------------------------------------------------------------------------------
                                                                     SALARIED EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                DECEMBER 31,    December 31,    December 31,    September 30,
                                                    2003            2002            2001            2001
                                                -------------------------------------------------------------
Discount rate                                       6.75%           7.50%           7.50%           8.00%
Expected long-term return on plan assets            9.00%           9.00%           9.00%           8.25%
Rate of compensation increase                       4.50%           4.50%           4.50%           4.50%
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
                                                                      UNION EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                DECEMBER 31,    December 31,    December 31,    September 30,
                                                    2003            2002            2001            2001
                                                -------------------------------------------------------------
Discount rate                                       6.75%           7.50%           7.50%           8.00%
Expected long-term return on plan assets            9.00%           9.00%           9.00%           8.25%
-------------------------------------------------------------------------------------------------------------

Assumed post-65 health care cost trend rates used to determine the post-retirement benefit obligation at the measurement date:

-------------------------------------------------------------------------------------------------------------
                                                                           SALARIED EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Health care cost trend rate assumed for next year               10.00%            11.00%             7.50%
Rate to which the cost trend rate is assumed to decline          6.00%             6.00%             7.50%
Year that rate reaches ultimate rate                              2008              2008               --
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
                                                                            UNION EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,     September 30,
                                                                 2003              2002              2001
                                                            -------------------------------------------------
Health care cost trend rate assumed for next year               10.00%            11.00%             7.50%
Rate to which the cost trend rate is assumed to decline          6.00%             6.00%             7.50%
Year that rate reaches ultimate rate                              2008              2008               --
-------------------------------------------------------------------------------------------------------------

Assumed health care cost trend rates used in determining the accumulated post-retirement benefit obligation have a significant effect on the amounts reported. For example, increasing the weighted average health care cost trend rate by 1 percentage point would have the following effects:

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                          SALARIED EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                   1-PERCENTAGE POINT INCREASE    1-PERCENTAGE POINT DECREASE
                                                   ----------------------------------------------------------
Effect on total of service and interest cost                 $   331                       $   (271)
Effect on net post-retirement benefit obligation             $ 4,215                       $ (3,330)
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
(in thousands)                                                           UNION EMPLOYEES
-------------------------------------------------------------------------------------------------------------
                                                   1-PERCENTAGE POINT INCREASE    1-PERCENTAGE POINT DECREASE
                                                   ----------------------------------------------------------
Effect on total of service and interest cost                 $   200                       $   (172)
Effect on net post-retirement benefit obligation             $ 2,496                       $ (2,070)
-------------------------------------------------------------------------------------------------------------

The Company's weighted-average post-retirement benefit program asset allocations by asset category were as follows:

--------------------------------------------------------------------------------------------
                                                             SALARIED EMPLOYEES
--------------------------------------------------------------------------------------------
                                                DECEMBER 31,    December 31,    December 31,
                                                    2003            2002            2001
                                                --------------------------------------------
Asset category:
Equity securities                                     91%             90%             90%
Debt securities                                        7%              9%              8%
Other                                                  2%              1%              2%
--------------------------------------------------------------------------------------------
Total                                                100%            100%            100%
--------------------------------------------------------------------------------------------

57

UNION EMPLOYEES

--------------------------------------------------------------------------------------------
                                                              UNION EMPLOYEES
--------------------------------------------------------------------------------------------
                                                DECEMBER 31,    December 31,    December 31,
                                                    2003            2002            2001
                                                --------------------------------------------
Asset category:
Equity securities                                     92%             89%            90%
Debt securities                                        7%              8%             9%
Other                                                  1%              3%             1%
--------------------------------------------------------------------------------------------
Total                                                100%            100%           100%
--------------------------------------------------------------------------------------------

Equity securities for the post-retirement benefit programs do not include the Company's common stock.

The Company expects to contribute $3.7 million to post-retirement benefit program assets during 2004.

For both defined benefit plans and other post-retirement plans, certain financial assumptions are used in determining the Company's projected benefit obligation. These assumptions are examined periodically by the Company, and any required changes are reflected in the subsequent determination of projected benefit obligations.

The Company employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition, and market conditions.

The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Because the post-retirement plans have lower short and intermediate-term cash requirements and, accordingly, are less impacted by short-term investment performance volatility, the Company has elected to allocate a large percentage of investments in equity securities with higher expected returns. Investment managers are retained by the Company to manage separate pools of assets, and funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment mangers are performing satisfactorily.

The Company has a long-term disability plan covering most salaried employees. The Company had expense for the years ended December 31, 2003 and 2002 of $265,000 and $304,000, respectively. The Company had no expense for this plan in the three months ended December 31, 2001 and in the year ended September 30, 2001.

On December 8, 2003, President Bush signed into law a bill that expands Medicare, adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Although the company anticipates that the benefits it pays after 2006 will be lower as a result of the new Medicare provisions, the retiree medical obligations and costs reported do not reflect the impact of this legislation. Deferring the recognition of the new Medicare provisions' impact is permitted by FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," due to open issues related to the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information.

58

6. COMMON STOCK PLANS

A majority of Company employees are eligible to participate in the Energen Employee Savings Plan (ESP) by electing to contribute a portion of their compensation in the ESP. The Company matches a percentage of the contributions and may make additional contributions in the form of Company common stock (new issue or treasury shares) or funds for the purchase of Company common stock. Prior to January 1, 2004, employees were allowed to invest their elective contributions in Company stock. Effective January 1, 2004, the Company stock is no longer an investment option for new elective contributions and vested employees may diversify 100% of their ESP Company stock account into other ESP investment options regardless of whether the Company stock was acquired through elective contribution, Company match, Company contribution or reinvestment of earnings. In 2003 an additional 1,000,000 shares were reserved for issuance under the ESP resulting in total shares reserved for issuance of 1,005,239 at December 31, 2003. Expense associated with Company contributions to the ESP was $4,199,000 and $3,963,000 for the years ended December 31, 2003 and 2002, respectively, $803,000 for the three months ended December 31, 2001, and $3,597,000 for the year ended September 30, 2001.

In 1992 the Company adopted the Energen Corporation 1992 Long-Range Performance Plan which provides for the award of up to 1,000,000 performance units, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of a four-year award period. Under the Plan, a portion of the performance units is payable with Company common stock. Under the Plan, 76,120 performance units were awarded in the year ended September 30, 2001; no additional performance units can be awarded after September 30, 2001, according to the provisions of the Plan. In October 2001, the Company added provisions for the award of future performance units, comparable to the 1992 Long-Range Performance Plan, under the 1997 Stock Incentive Plan. Under the 1997 Stock Incentive Plan, 117,500 performance units were awarded in the year ended December 31, 2003 and 111,760 performance units were awarded in the three months ended December 31, 2001. The Company recorded expense of $5,653,100 and $2,136,250 for the years ended December 31, 2003 and 2002, respectively, $722,500 for the three months ended December 31, 2001, and $2,311,000 for the year ended September 30, 2001, under the Plans.

On November 27, 1997, the Company adopted the Energen Corporation 1997 Stock Incentive Plan. The 1997 Stock Incentive Plan, along with the Energen Corporation 1988 Stock Option Plan, provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Plans provide for purchase of Company common stock at not less than the fair market value on the date the option is granted. In addition, the 1997 Stock Incentive Plan provides for the grant of restricted stock with 53,475 shares awarded in the year ended December 31, 2003, 22,775 shares awarded in the three months ended December 31, 2001 and 57,190 shares awarded in the year ended September 30, 2001. The sale or transfer of the shares is limited during restricted periods. The Company recorded expense of $1,076,000 and $743,000 for the years ended December 31, 2003 and 2002, respectively, $188,000 for the three months ended December 31, 2001 and $583,000 for the year ended September 30, 2001, related to the restricted stock. Under the 1988 Stock Option Plan, 540,000 shares of Company common stock reserved for issuance have been granted. Under the 1997 Stock Incentive Plan, an additional 1,500,000 shares of Company common stock were reserved for issuance during 2002 resulting in total shares reserved for issuance of 2,800,000. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date.

Transactions under the plans are summarized as follows:

----------------------------------------------------------------------------------------------------------------
                                              1997 STOCK INCENTIVE PLAN             1988 STOCK OPTION PLAN
----------------------------------------------------------------------------------------------------------------
                                                          Weighted Average                      Weighted Average
                                             Shares        Exercise Price          Shares        Exercise Price
----------------------------------------------------------------------------------------------------------------
Outstanding at September 30, 2000            403,508          $  18.40             264,416          $  13.86
Granted                                      137,200             27.44                  --                --
Exercised                                   (152,786)            18.30            (105,302)            13.90
----------------------------------------------------------------------------------------------------------------
Outstanding at September 30, 2001            387,922             21.64             159,114             13.84
----------------------------------------------------------------------------------------------------------------
Granted                                      120,340             22.63                  --                --
Exercised                                         --                                (1,000)            18.25
----------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2001             508,262             21.87             158,114             13.81
----------------------------------------------------------------------------------------------------------------
Granted                                           --                                    --                --

59

Exercised                                    (20,379)            18.46             (22,600)             9.19
Forfeited                                     (2,390)            24.44                  --                --
----------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2002             485,493             22.00             135,514             14.58
----------------------------------------------------------------------------------------------------------------
Granted                                      122,080             29.71                  --                --
Exercised                                   (122,153)            21.97             (32,514)            15.16
----------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2003             485,420          $  23.95             103,000          $  14.39
----------------------------------------------------------------------------------------------------------------
Exercisable at September 30, 2001            138,068          $  18.34             159,114          $  13.84
Exercisable at December 31, 2001             249,349          $  19.66             158,114          $  13.81
Exercisable at December 31, 2002             299,619          $  20.56             135,514          $  14.58
Exercisable at December 31, 2003             243,000          $  21.70             103,000          $  14.39
----------------------------------------------------------------------------------------------------------------
Remaining reserved for issuance at
   December 31, 2003                       1,529,011                --                  --                --
----------------------------------------------------------------------------------------------------------------

The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), for all stock-based employee compensation on a prospective basis effective January 1, 2003. Of the total shares granted during 2003 55,300 had stock appreciation rights on which expense of $209,000 was recorded for the year ended December 31, 2003. The Company recorded expense of $269,000 during the year ended December 31, 2003, on the remaining 66,780 shares which had a weighted average grant-date fair value of $12.10.

The following table summarizes information about options outstanding as of December 31, 2003:

-------------------------------------------------------------------------------------------------------------------
               1997 STOCK INCENTIVE PLAN                                  1988 STOCK OPTION PLAN
-------------------------------------------------------------------------------------------------------------------
                                      Weighted Average                                          Weighted Average
Range of Exercise                   Remaining Contractual       Range of                      Remaining Contractual
      Prices            Shares              Life             Exercise Prices      Shares              Life
-------------------------------------------------------------------------------------------------------------------
  $18.25-$18.81        142,120           4.59 years           $10.06-$11.06       28,000           1.42 years
      $27.44           104,200           6.83 years           $15.00-$18.25       75,000           3.48 years
      $22.63           117,020           7.83 years                     --            --                   --
      $29.71           122,080           9.08 years                     --            --                   --
-------------------------------------------------------------------------------------------------------------------
  $18.25-$29.71        485,420           6.98 years           $10.06-$18.25      103,000           2.92 years
-------------------------------------------------------------------------------------------------------------------

In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan to pay part of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 7,500 shares were awarded during the year ended December 31, 2003, 6,000 shares were awarded during the three months ended December 31, 2001 and 4,800 shares were awarded during the year ended September 30, 2001, leaving 137,139 shares reserved for issuance as of December 31, 2003.

The Company's Dividend Reinvestment and Direct Stock Purchase Plan includes a direct stock purchase feature which allows purchases by non-shareholders. As of December 31, 2003, 789,612 common shares were reserved under this Plan.

By resolution adopted May 25, 1994, and supplemented by a resolution adopted April 26, 2000, the Board authorized the Company to repurchase of up to 1,782,200 shares of the Company's common stock. For the year ended December 31, 2003, the three months ended December 31, 2001 and the year ended September 30, 2001, the Company repurchased 650 shares, 54,600 shares and 91,600 shares, respectively, pursuant to its repurchase authorization. As of December 31, 2003, a total of 1,075,350 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company's stock compensation plans. For the years ended December 31, 2003 and 2002, and the three months ended December 31, 2001, the Company acquired 29,232 shares, 5,319 shares and 474 shares, respectively, in connection with its stock compensation plans.

On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan) designed to protect shareholders from coercive or unfair takeover tactics. Under certain circumstances, the 1998 Plan provides shareholders with the right to acquire the Company's Series 1998 Junior Participating Preferred Stock (or, in certain cases, securities of an acquiring person) at a significant discount. Terms and conditions are set forth in a Rights

60

Agreement between the Company and its Rights Agent. Under the 1998 Plan, one right is associated with each outstanding share of common stock. Rights outstanding under the 1998 Plan at December 31, 2003, were convertible into 362,235 shares of Series 1998 Junior Participating Preferred Stock (1/100 share of preferred stock for each full right) subject to adjustment upon occurrence of certain take-over related events. No rights were exercised or exercisable during the period. The price at which the rights would be exercised is $70 per right, subject to adjustment upon occurrence of certain take-over related events. In general, absent certain take-over related events as described in the Plan, the rights may be redeemed prior to the July 27, 2008, expiration for $0.01 per right.

In 1997 the Company adopted the 1997 Deferred Compensation Plan to allow officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Company's common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants' accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trusts' assets remain subject to the claims of our creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the Consolidated Statements of Shareholders' Equity.

7. COMMITMENTS AND CONTINGENCIES

CONTRACTS AND AGREEMENTS: Alagasco has various firm gas supply and firm gas transportation contracts which expire at various dates through the year 2013. These contracts typically contain minimum demand charge obligations on the part of Alagasco.

ENVIRONMENTAL MATTERS: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company's financial position and results of operations and is not expected to do so in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

Alagasco is in the chain of title of eight former manufactured gas plant sites, of which it still owns four, and five manufactured gas distribution sites, of which it still owns one. An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the results of operations or financial condition of Alagasco.

LEGAL MATTERS: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards may bear little or no relation to culpability or actual damages, thus making it increasingly difficult to predict litigation results.

Various pending or threatened legal proceedings arising in the normal course of business are in progress currently, and the Company has accrued a provision for estimated costs.

LEASE OBLIGATIONS: In January 1999 Alagasco closed on a sale-leaseback of the Company's headquarters building. The proceeds from the sale approximated the investment in the facility. The building is being leased back from the purchaser over a 25-year lease term and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Energen's total lease payments related to leases included as operating lease expense, inclusive of the sale-leaseback, were $8,412,000 and $8,273,000 for the years ended December 31, 2003 and 2002, $1,837,000 for

61

the three months ended December 31, 2001, $7,324,000 for the year ended September 30, 2001. Minimum future rental payments required after 2003 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

--------------------------------------------------------------------------------
                    Years Ending December 31, (in thousands)
--------------------------------------------------------------------------------
  2004        2005       2006         2007        2008       2009 AND THEREAFTER
--------------------------------------------------------------------------------
$ 3,388     $ 3,054     $ 2,676     $ 2,421      $ 2,093          $ 30,531
--------------------------------------------------------------------------------

Alagasco's total payments related to leases included as operating expense, inclusive of the sale-leaseback, were $2,602,000 and $2,362,000 for the years ended December 31, 2003 and 2002, $587,000 for the three months ended December 31, 2001 and $2,343,000 for the year ended September 30, 2001. Minimum future rental payments required after 2003 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

--------------------------------------------------------------------------------
                    Years Ending December 31, (in thousands)
--------------------------------------------------------------------------------
  2004        2005       2006         2007        2008       2009 AND THEREAFTER
--------------------------------------------------------------------------------
$ 2,209     $ 1,904     $ 1,531     $ 1,503      $ 1,483          $ 22,004
--------------------------------------------------------------------------------

8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

FINANCIAL INSTRUMENTS: The fair value of cash and cash equivalents, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen's fixed-rate long-term debt, including the current portion, with a carrying value of $564,533,000, would be $614,950,000 at December 31, 2003. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, with a carrying value of $169,533,000, would be $188,201,000 at December 31, 2003. The fair values were based on the market value of debt with similar maturities and current interest rates.

Alagasco has an agreement with a financial institution whereby it may sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $15 million. Alagasco sold installment receivables of $4,992,000 and $5,010,000 in the years ended December 31, 2003 and 2002, respectively, $2,120,000 in the three months ended December 31, 2001 and $5,444,000 in the year ended September 30, 2001. At December 31, 2003 and 2002, the balances of these installment receivables were $8,167,000 and $10,566,000, respectively. Receivables sold under this agreement are considered financial instruments with off-balance sheet risk. Alagasco's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables. The fair value of these guarantees is not significant to the Company and is recorded as a non-current other liability. Effective February 1, 2004, Alagasco is no longer selling its installment receivables.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the consolidated balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. At December 31, 2003, the gas guaranteed had an aggregate purchase price of $14.6 million and a market value of $16.3 million. The maximum term over which Alagasco has guarantees outstanding is through December 2004.

PRICE RISK: The Company adopted SFAS No. 133 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 as a component of equity and subsequently reclassified into earnings in operating revenues when the forecasted transaction affects earnings.

The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues

62

immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change.

Energen Resources periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange 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 or Alagasco 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 other comprehensive income (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 were recorded in accumulated other comprehensive income until such time as they were reclassified to earnings in operating revenues as originally forecasted to occur. As a result, Energen's net income in the three-month transition period ended December 31, 2001, reflected a non-cash expense of $5.5 million, net of tax. Net income in the year ended December 31, 2002, reflected a total non-cash benefit of $5.7 million, net of tax, related to the Enron hedge position.

At December 31, 2003, the Company had current gains on the fair value of derivatives of $0.6 million included in prepayments and other, current losses of $34.6 million included in accounts payable and $3.5 of non-current losses included in deferred credits and other liabilities on the consolidated balance sheet. The Company had current losses on the fair value of derivatives of $15.9 million included in accounts payable and $1.9 million of non-current losses included in deferred credits and other liabilities on the consolidated balance sheet at December 31, 2002.

As of December 31, 2003, $19.6 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to operating revenues in 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 a $1.5 million after-tax loss in 2003 for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, the Company recorded an after-tax loss of $634,000 in 2003 on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of December 31, 2003, all of the Company's swaps and hedges met the definition of a cash flow hedge. The Company had $13.9 million and $6.7 million included in current and noncurrent deferred income taxes on the consolidated balance sheet related to other comprehensive income as of December 31, 2003 and 2002, respectively.

Energen Resources has entered into the following transactions for 2004 and subsequent years:

-------------------------------------------------------------------------------------------
PRODUCTION    TOTAL HEDGED VOLUMES       AVERAGE CONTRACT               DESCRIPTION
  PERIOD                                       PRICE
-------------------------------------------------------------------------------------------
                                         NATURAL GAS
-------------------------------------------------------------------------------------------
   2004              15.8 Bcf                $4.83 Mcf                  NYMEX Swaps
                     20.6 Bcf                $4.17 Mcf              Basin Specific Swaps
                      2.4 Bcf            $4.05 - $4.44 Mcf             NYMEX Collars
   2005               1.2 Bcf                $3.75 Mcf                  NYMEX Swaps
                      6.0 Bcf                $3.96 Mcf              Basin Specific Swaps

63

-------------------------------------------------------------------------------------------
                                             OIL
-------------------------------------------------------------------------------------------
   2004             1,428 MBbl              $27.75 Bbl                  NYMEX Swaps
                      360 MBbl              $27.85 Bbl          West Texas Sour (WTS) Swaps
-------------------------------------------------------------------------------------------
                                   OIL BASIS DIFFERENTIAL
-------------------------------------------------------------------------------------------
  2004               300 MBbl                  **                      Basis Swaps
-------------------------------------------------------------------------------------------
                                     NATURAL GAS LIQUIDS
-------------------------------------------------------------------------------------------
  2004               37 MMGal               $0.41 Gal                 Liquids Swaps
-------------------------------------------------------------------------------------------

** Average contract prices not meaningful due to the varying nature of each contract

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 has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 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 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 accordance with SFAS No. 71, Alagasco had recorded a current regulatory asset of $0.3 million, a current regulatory liability of $17 million and a noncurrent regulatory liability of $8.7 million representing the fair value of derivatives as of December 31, 2003. As of December 31, 2002, Alagasco recorded a current regulatory liability of $16.8 million representing the fair value of derivatives.

CONCENTRATION OF CREDIT RISK: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company's overall exposure to credit risk, either positively or negatively, in that the Company's oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. During 2001 and 2002, the credit rating agencies downgraded the credit ratings of a number of energy marketers and their affiliates, including certain oil and gas purchasers of the Company. Energen Resources monitors the credit quality for its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 465,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.

9. RECONCILIATION OF EARNINGS PER SHARE

64

--------------------------------------------------------------------------------------------------------------------
                                                          YEAR ENDED                           Year Ended
(in thousands, except per share amounts)              DECEMBER 31, 2003                    December 31, 2002
--------------------------------------------------------------------------------------------------------------------
                                                                      PER SHARE                            Per Share
                                               INCOME      SHARES       AMOUNT      Income      Shares       Amount
--------------------------------------------------------------------------------------------------------------------
Basic EPS                                    $110,654      35,434        $3.12     $68,639      33,605        $2.04
Effect of dilutive securities
     Long-range performance shares                             73                                   88
     Stock options                                            201                                  143
     Restricted stock                                           9                                    2
--------------------------------------------------------------------------------------------------------------------
Diluted EPS                                  $110,654      35,717        $3.10     $68,639      33,838        $2.03
--------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------
                                                     Three Months Ended                       Year Ended
(in thousands, except per share amounts)             December 31, 2001                    September 30, 2001
--------------------------------------------------------------------------------------------------------------------
                                                                      Per Share                            Per Share
                                               Income      Shares       Amount      Income      Shares       Amount
--------------------------------------------------------------------------------------------------------------------
Basic EPS                                      $3,658      31,052        $0.12     $67,896      30,726        $2.21
Effect of dilutive securities
     Long-range performance shares                             96                                  165
     Stock options                                            127                                  187
     Restricted stock                                           2                                    6
--------------------------------------------------------------------------------------------------------------------
Diluted EPS                                    $3,658      31,277        $0.12     $67,896      31,084        $2.18
--------------------------------------------------------------------------------------------------------------------

For the year ended December 31, 2003, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

10. ASSET RETIREMENT OBLIGATIONS

In 2002, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires the Company to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Upon adoption of SFAS No. 143, the Company recognized a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalized an equal amount as a cost of the asset as of January 1, 2002. Upon initial application of the Statement, the Company recorded a cumulative effect of a change in accounting principle to recognize a liability for existing AROs adjusted for cumulative accretion, an increase to the carrying amount of the associated long-lived asset and accumulated depreciation on the capitalized cost. For the year ended December 31, 2002, Energen Resources recognized additional capitalized costs of $20.1 million, depreciation expense of $1.7 million, accretion expense of $1.8 million, a deferred tax asset of $1.3 million and an after-tax charge of $2.2 million for the cumulative effect on prior years. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company will settle the obligation for its recorded amount and will record the resulting gain or loss.

In 2002 and 2003, Energen Resources recognized activity representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

--------------------------------------------------------------------------------
(in thousands)
--------------------------------------------------------------------------------
Balance of ARO as of January 1, 2002                                   $ 20,493
Liabilities incurred during the year ended December 31, 2002              4,923
Accretion expense                                                         1,819
--------------------------------------------------------------------------------
Balance of ARO as of December 31, 2002                                 $ 27,235
--------------------------------------------------------------------------------
Liabilities incurred during the year ended December 31, 2003              1,139
Liabilities settled during the year ended December 31, 2003              (3,750)
Accretion expense                                                         1,891
--------------------------------------------------------------------------------
Balance of ARO as of December 31, 2003                                 $ 26,515
--------------------------------------------------------------------------------

The Company's gas distribution system operates under various property easement agreements primarily related to

65

public rights of way. In some instances, the entity granting the easement retains the option to require certain actions in the event the Company abandons the asset. Since the Company expects its gas distribution assets to be operated in perpetuity and historical abandonment costs resulting from such easement agreements have been de minimis, no asset retirement obligation has been recorded. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. In 2003, Alagasco revised its balance sheet presentation to reclassify the accrual for net removal costs from accumulated depreciation to a regulatory liability in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result, regulatory liabilities increased for accumulated asset removal costs by $103.7 million, $94.7 million and $87.5 million for December 31, 2003, 2002 and 2001, respectively.

11. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental information concerning Energen's cash flow activities is as follows:

------------------------------------------------------------------------------------------------------------------------
                                                                                         Three Months
                                                      YEAR ENDED        Year Ended          Ended           Year Ended
                                                     DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands)                                           2003              2002              2001              2001
------------------------------------------------------------------------------------------------------------------------
Interest paid, net of amount capitalized                $39,963          $43,085           $11,418           $42,905
Income taxes paid                                       $10,929          $ 9,838           $ 4,261           $11,636
Noncash investing activities:
    First Permian, L.L.C. stock issuance                $    --          $72,891           $    --           $    --
    Capitalized depreciation                            $   123          $   223           $    51           $   243
    Allowance for funds used during construction        $ 1,529          $ 1,336           $   122           $ 2,098
------------------------------------------------------------------------------------------------------------------------

Under SFAS No. 143, the Company recorded a non-cash adjustment for accretion expense of $1.9 million during 2003. During 2002, additional capitalized costs of $20.1 million, a non-current liability of $27.2 million, accretion expense of $1.8 million, depreciation expense of $1.7 million, and a deferred tax asset of $1.3 million were recorded, all of which are non-cash adjustments concerning Energen's cash flow activities.

Supplemental information concerning Alagasco's cash flow activities is as follows:

------------------------------------------------------------------------------------------------------------------------
                                                                                         Three Months
                                                      YEAR ENDED        Year Ended          Ended           Year Ended
                                                     DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands)                                           2003              2002              2001              2001
------------------------------------------------------------------------------------------------------------------------

Interest paid, net of amount capitalized                $12,477           $14,012           $5,666            $12,154
Income taxes paid                                       $12,754           $15,519           $9,425            $18,318
Noncash investing activities:
    Capitalized depreciation                            $   123           $   223           $   51            $   243
    Allowance for funds used during construction        $ 1,529           $ 1,336           $  122            $ 2,098
------------------------------------------------------------------------------------------------------------------------

12. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS

On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which retains the previous asset impairment requirements of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," for loss recognition when the carrying value of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In addition, SFAS No. 144 requires that gains and losses in the sale of certain oil and gas properties and write-downs of certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for prior periods in accordance with SFAS No. 144. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale must be reported at the lower of the carrying amount or fair value.

66

Accordingly, during 2003, Energen Resources recorded a pre-tax writedown to fair value based upon expected market value of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region. These properties were subsequently sold during 2003 for a pre-tax gain of $0.4 million. The gain on disposals for the year ended December 31, 2003, totaled $9.4 million primarily due to sales of properties in the San Juan Basin. As of December 31, 2003, the Company had no properties classified as held-for-sale. During 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. In November 2002, the Company sold these properties for approximately the carrying amount. The gain on disposals for the year ended December 31, 2002, totaled $3.7 million largely due to sales of property located in the Permian Basin. In 2001, prior to adopting SFAS No. 144, a pre-tax gain of $0.8 million was recorded in operating revenues from continuing operations for certain non-strategic property sales.

The following are the results of operations from discontinued operations:

-------------------------------------------------------------------------------------------------------------------------------
                                                                                                Three Months
                                                             YEAR ENDED        Year Ended          Ended           Year Ended
                                                            DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands, except per share data)                           2003              2002              2001              2001
-------------------------------------------------------------------------------------------------------------------------------
Oil and gas revenues                                          $  3,586          $ 10,362          $ 3,696           $22,157
-------------------------------------------------------------------------------------------------------------------------------
Pretax income (loss) from discontinued
  operations                                                  $  1,594          $   (133)         $  (115)          $ 8,983
Income tax expense (benefit)                                       621               (53)             (43)            3,504
-------------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) FROM DISCONTINUED OPERATIONS                         973               (80)             (72)            5,479
-------------------------------------------------------------------------------------------------------------------------------
Impairment charge on held-for-sale property                    (10,404)           (2,815)              --                --
Gain on disposal                                                 9,448             3,706               --                --
Income tax expense (benefit)                                      (372)              348               --                --
-------------------------------------------------------------------------------------------------------------------------------
GAIN (LOSS) ON DISPOSAL                                           (584)              543               --                --
-------------------------------------------------------------------------------------------------------------------------------
TOTAL INCOME (LOSS) FROM DISCONTINUED
  OPERATIONS                                                  $    389          $    463          $   (72)          $ 5,479
-------------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER AVERAGE COMMON SHARE
Income (Loss) from Discontinued Operations                    $   0.03          $     --          $    --           $  0.17
-------------------------------------------------------------------------------------------------------------------------------
Gain (Loss) on Disposal                                          (0.02)             0.02               --                --
-------------------------------------------------------------------------------------------------------------------------------
Total Income from Discontinued  Operations                    $   0.01          $   0.02          $    --           $  0.17
-------------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER AVERAGE COMMON SHARE
Income (Loss) from Discontinued Operations                    $   0.03          $     --          $    --           $  0.18
Gain (Loss) on Disposal                                          (0.02)             0.02               --                --
-------------------------------------------------------------------------------------------------------------------------------
Total Income from Discontinued Operations                     $   0.01          $   0.02          $    --           $  0.18
-------------------------------------------------------------------------------------------------------------------------------

13. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)

The Company's business is seasonal in character. The following data summarizes quarterly operating results. The summarized quarterly information may differ from amounts previously reported due to changes in the classification of properties reported as discontinued operations as required by SFAS No. 144 (see Note 12).

-------------------------------------------------------------------------------------------------------------------
                                                                        YEAR ENDED DECEMBER 31, 2003
                                                                        ----------------------------
(in thousands, except per share amounts)                     First          Second           Third          Fourth
-------------------------------------------------------------------------------------------------------------------
Operating revenues                                         $309,658        $184,030        $146,141        $202,392
Operating income                                           $ 96,614        $ 50,512        $ 29,356        $ 43,296
Income from continuing operations before cumulative
   effect of change in accounting principle                $ 53,323        $ 24,459        $ 11,457        $ 21,026

67

Net income                                                 $ 54,581        $ 23,347        $ 11,896        $ 20,830
Diluted earnings per average common share
    Continuing operations                                  $   1.52        $   0.69        $   0.32        $   0.58
    Net income                                             $   1.56        $   0.66        $   0.33        $   0.57
Basic earnings per average common share
    Continuing operations                                  $   1.54        $   0.70        $   0.32        $   0.58
    Net income                                             $   1.57        $   0.67        $   0.33        $   0.58
-------------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------------
                                                                        YEAR ENDED DECEMBER 31, 2002
                                                                        ----------------------------
(in thousands, except per share amounts)                     First          Second           Third          Fourth
-------------------------------------------------------------------------------------------------------------------
Operating revenues                                         $241,413        $137,844        $114,844        $174,450
Operating income                                           $ 61,252        $ 25,762        $ 13,137        $ 35,624
Income from continuing operations before cumulative
   effect of change in accounting principle                $ 39,042        $ 12,771        $     97        $ 18,486
Net income                                                 $ 36,682        $ 12,744        $    127        $ 19,086
Diluted earnings per average common share
    Continuing operations                                  $   1.24        $   0.37        $   0.00        $   0.53
    Net income                                             $   1.17        $   0.37        $   0.00        $   0.55
Basic earnings per average common share
    Continuing operations                                  $   1.25        $   0.37        $   0.00        $   0.53
    Net income                                             $   1.18        $   0.37        $   0.00        $   0.55
-------------------------------------------------------------------------------------------------------------------

Alagasco's business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco's quarterly operating results.

-------------------------------------------------------------------------------------------------------------------
                                                                        YEAR ENDED DECEMBER 31, 2003
                                                                        ----------------------------
(in thousands, except per share amounts)                     First          Second           Third          Fourth
-------------------------------------------------------------------------------------------------------------------
Operating revenues                                         $221,139        $ 94,248        $ 58,147        $115,565
Operating income (loss)                                    $ 57,200        $  6,988        $ (9,575)       $ 12,235
Net income (loss)                                          $ 33,447        $  2,135        $ (7,781)       $  5,216
-------------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------------
                                                                        YEAR ENDED DECEMBER 31, 2002
                                                                        ----------------------------
(in thousands, except per share amounts)                     First          Second           Third          Fourth
-------------------------------------------------------------------------------------------------------------------
Operating revenues                                         $196,524        $ 75,709        $ 50,225        $101,973
Operating income (loss)                                    $ 52,811        $  4,721        $ (8,907)       $ 10,745
Net income (loss)                                          $ 30,542        $    964        $ (7,700)       $  3,758
-------------------------------------------------------------------------------------------------------------------

14. ACQUISITION OF OIL AND GAS PROPERTIES

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 total acquisition approximated $184 million.

Summarized below are the consolidated results of operations for the year ended December 31, 2002, the three months ended December 31, 2001 and the year ended September 30, 2001, on an unaudited pro forma basis as if the purchase of assets had occurred at the beginning of each period presented. The pro forma information is based on our consolidated results of operations for the year ended December 31, 2002, the three months ended December 31, 2001 and the year ended September 30, 2001, and on the data provided by the seller, after giving effect to the issuance of 3,043,479 shares of common stock. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above nor are they indicative of results of the future operations of the combined enterprises.

68

------------------------------------------------------------------------------------------------------------
                                                                                Three Months
                                                                 YEAR ENDED        Ended         Year Ended
Unaudited                                                       DECEMBER 31,    December 31,   September 30,
(in thousands, except per share amounts)                            2002            2001            2001
------------------------------------------------------------------------------------------------------------
Operating revenues                                                $675,156        $151,406        $787,629
Income from continuing operations before cumulative effect
  of change in accounting principle                               $ 71,529        $  4,459        $ 61,083
Net income                                                        $ 69,772        $  4,387        $ 66,562
Diluted earnings per average common share                         $   2.06        $   0.14        $   2.14
Basic earnings per average common share                           $   2.08        $   0.14        $   2.17
------------------------------------------------------------------------------------------------------------

15. REGULATORY ASSETS AND LIABILITES

The following table details regulatory asset and liabilities on the consolidated balance sheets:

Energen Corporation

-----------------------------------------------------------------------------------------------------
(in thousands)                                  DECEMBER 31, 2003               December 31, 2002
-----------------------------------------------------------------------------------------------------
                                             CURRENT       NONCURRENT        Current       Noncurrent
-----------------------------------------------------------------------------------------------------
Regulatory assets:
     Pension asset                          $     --        $ 18,082        $     --        $ 14,744
     Risk management activities                  251              --              --              --
-----------------------------------------------------------------------------------------------------
        Total regulatory assets             $    251        $ 18,082        $     --        $ 14,744
-----------------------------------------------------------------------------------------------------
Regulatory liabilities:
     Enhanced stability reserve             $  3,481        $     --        $  2,963        $     --
     Gas supply adjustment                     4,903              --           3,845              --
     Risk management activities               17,025           8,650          16,750              --
     RSE                                       2,619              --             256              --
     Unbilled service margin                  26,118              --          17,370              --
     Asset removal costs, net                     --         103,727              --          94,751
     Other                                        --           1,050              --           1,468
-----------------------------------------------------------------------------------------------------
        Total regulatory liabilities        $ 54,146        $113,427        $ 41,184        $ 96,219
-----------------------------------------------------------------------------------------------------

16. EQUITY AND DEBT OFFERINGS

In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. The sale of shares began May 9, 2003, and concluded on July 16, 2003, generating net proceeds of $32.1 million. In October 2003, Energen issued $50 million of long-term debt due October 1, 2013. The 5% coupon notes were priced at 99.557 percent to yield 5.057 percent. These proceeds were be used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.

17. TRANSACTIONS WITH RELATED PARTIES

Alagasco purchased natural gas from affiliates of $3,195,000 and $1,820,000 for the years ended December 31, 2003 and 2002, $375,000 for the three months ended December 31, 2001 and $5,254,000 for the year ended September 30, 2001. These amounts are included in gas purchased for resale. Alagasco had net payables to affiliates of $37,290,000 and $1,432,000 at December 31, 2003 and December 31, 2002, respectively.

18. OTHER INCOME AND EXPENSE

69

The following table details Energen's other income and expense amounts on the consolidated income statements:

-----------------------------------------------------------------------------------------------------------
                                                                               Three Months
                                                  YEAR ENDED     Year Ended       Ended        Year Ended
                                                 DECEMBER 31,   December 31,   December 31,   September 30,
(in thousands)                                       2003           2002           2001           2001
-----------------------------------------------------------------------------------------------------------
Allowance for funds used during construction        $   948        $ 1,336        $   122        $ 2,098
Merchandise revenues                                  7,696         14,155          4,226         14,535
Other                                                   100            153              6            192
-----------------------------------------------------------------------------------------------------------
   Total other income                               $ 8,744        $15,644        $ 4,354        $16,825
-----------------------------------------------------------------------------------------------------------
Cost of goods sold                                  $ 8,549        $10,215        $ 3,181        $10,136
Other merchandise expense                             1,428          4,888          1,204          4,756
-----------------------------------------------------------------------------------------------------------
   Total other expense                              $ 9,977        $15,103        $ 4,385        $14,892
-----------------------------------------------------------------------------------------------------------

The following table details Alagasco's other income and expense amounts on the income statements:

-----------------------------------------------------------------------------------------------------------
                                                                               Three Months
                                                  YEAR ENDED     Year Ended       Ended        Year Ended
                                                 DECEMBER 31,   December 31,   December 31,   September 30,
(in thousands)                                       2003           2002           2001           2001
-----------------------------------------------------------------------------------------------------------
Merchandise revenues                                $ 5,080        $ 5,520        $ 1,596        $ 5,978
-----------------------------------------------------------------------------------------------------------
   Total other income                               $ 5,080        $ 5,520        $ 1,596        $ 5,978
-----------------------------------------------------------------------------------------------------------
Cost of goods sold                                  $ 5,142        $ 2,702        $   946        $ 3,051
Other merchandise expense                               127          3,578            892          3,534
-----------------------------------------------------------------------------------------------------------
   Total other expense                              $ 5,269        $ 6,280        $ 1,838        $ 6,585
-----------------------------------------------------------------------------------------------------------

The sale of merchandise inventory items are reflected in other income and expense. In 2003, a key supplier of certain merchandise inventories ended its business relationship with the Company. Alagasco no longer participates in direct sales of natural gas merchandise effective February 1, 2004. Alagasco continues to work closely with various contractors and retail companies to meet the merchandise requirements of its customers.

19. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)

SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," were issued by the FASB in June 2001 and became effective on July 1, 2001, and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method and SFAS No. 142 establishes new guidelines in accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain intangible assets that have indefinite useful lives are not amortized, but rather are reviewed annually for impairment. The appropriate application of SFAS No. 141 and SFAS No. 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves is currently being considered. One interpretation relative to these standards is that oil and gas mineral rights for both undeveloped and developed leaseholds could be classified separately from oil and gas properties as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. In addition, the disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements. The Company anticipates that this interpretation of SFAS No. 141 and SFAS No. 142 would only affect balance sheet classifications of oil and gas leaseholds. Results of operations and cash flows are not anticipated to be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with

SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Company will continue to evaluate the impact of the application of these standards as further guidance is provided.

70

The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to four years; therefore, the cost related to stock-based employee compensation included in the determination of net income is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123.

In December 2003, the FASB revised SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits - an amendment of FASB Statements No. 87, 88 and 106." The revised Statement added additional disclosures relating to the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other postretirement plans and is effective for financial statements with fiscal years ending after December 15, 2003, with an exception for the disclosure of estimated future benefit payments effective for fiscal years ending after June 15, 2004. The Company has incorporated within this report the additional required disclosures (See Note 5).

20. OIL AND GAS OPERATIONS (UNAUDITED)

The following schedules detail historical financial data of the Company's oil and gas operations. Certain terms appearing in the schedules are prescribed by the Securities and Exchange Commission (SEC) and are briefly described as follows:

EXPLORATION EXPENSES are costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties, exploratory geological and geophysical activities, and costs of impaired and expired leaseholds.

DEVELOPMENT COSTS include costs necessary to gain access to, prepare and equip development wells in areas of proved reserves.

PRODUCTION (LIFTING) COSTS include costs incurred to operate and maintain wells.

GROSS REVENUES are reported after deduction of royalty interest payments.

GROSS WELL OR ACRE is a well or acre in which a working interest is owned.

NET WELL OR ACRE is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.

DRY WELL is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

PRODUCTIVE WELL is an exploratory or a development well that is not a dry well.

CAPITALIZED COSTS

--------------------------------------------------------------------------------------------------
(in thousands)                                             DECEMBER 31, 2003     December 31, 2002
--------------------------------------------------------------------------------------------------
Proved                                                        $1,191,528             $1,091,536
Unproved                                                           5,812                 11,936
--------------------------------------------------------------------------------------------------
     Total capitalized costs                                   1,197,340              1,103,472
Accumulated depreciation, depletion, and  amortization           310,368                269,616
--------------------------------------------------------------------------------------------------
Capitalized costs, net                                        $  886,972             $  833,856
--------------------------------------------------------------------------------------------------

COSTS INCURRED: The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:

71

-----------------------------------------------------------------------------------------------------------------------
                                                                                          Three Months
                                                            YEAR ENDED      Year Ended       Ended         Year Ended
                                                           DECEMBER 31,    December 31,   December 31,    September 30,
(in thousands)                                                 2003            2002           2001            2001
-----------------------------------------------------------------------------------------------------------------------
Property acquisition:
     Proved                                                  $ 40,219        $173,984        $    238        $ 33,764
     Unproved                                                     267          10,193              81             552
Exploration                                                       468             527             339           1,734
Development                                                   122,094         122,494          24,757         103,574
-----------------------------------------------------------------------------------------------------------------------
Total costs incurred                                         $163,048        $307,198        $ 25,415        $139,624
-----------------------------------------------------------------------------------------------------------------------

RESULTS OF CONTINUING OPERATIONS: The following table sets forth results of the Company's oil and gas continuing operations:

-----------------------------------------------------------------------------------------------------------------------
                                                                                          Three Months
                                                            YEAR ENDED      Year Ended       Ended         Year Ended
                                                           DECEMBER 31,    December 31,   December 31,    September 30,
(in thousands)                                                 2003            2002           2001            2001
-----------------------------------------------------------------------------------------------------------------------
Gross revenues                                               $354,816        $245,397       $ 50,613         $208,592
Production (lifting costs)                                     95,651          75,395         14,861           72,106
Exploration expense                                             1,053           3,595            827            4,206
Depreciation, depletion and amortization                       78,241          66,594         14,986           49,563
Accretion expense                                               1,820           1,890             --               --
Income tax expense                                             66,419          23,102          4,103           15,688
-----------------------------------------------------------------------------------------------------------------------
Results of continuing operation from producing
  activities                                                 $111,632        $ 74,821       $ 15,836         $ 67,029
-----------------------------------------------------------------------------------------------------------------------

AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE FROM CONTINUING OPERATIONS

-----------------------------------------------------------------------------------------------------------------------
                                                                                          Three Months
                                                            YEAR ENDED      Year Ended       Ended         Year Ended
                                                           DECEMBER 31,    December 31,   December 31,    September 30,
                                                               2003            2002           2001            2001
-----------------------------------------------------------------------------------------------------------------------
Average sales price including the effects of hedging:
    Gas (Mcf)                                                $   4.25        $   3.17       $   2.99        $   3.01
     Oil (per barrel)                                        $  25.56        $  24.13       $  24.01        $  23.43
     Natural gas liquids (per barrel)                        $  16.32        $  12.77       $  10.01        $  17.57
Average sales price excluding the effects of hedging:
    Gas (Mcf)                                                $   4.97        $   2.96       $   2.34        $   4.85
     Oil (per barrel)                                        $  29.19        $  24.82       $  19.52        $  27.42
     Natural gas liquids (per barrel)                        $  18.40        $  12.77       $  10.01        $  17.57
Average production (lifting) cost (per Mcfe)                 $   1.12        $   1.01       $   0.88        $   1.13
Average production tax (per Mcfe)                            $   0.32        $   0.25       $   0.20        $   0.36
Average depreciation rate (per Mcfe)                         $   0.92        $   0.89       $   0.89        $   0.78
-----------------------------------------------------------------------------------------------------------------------

DRILLING ACTIVITY: The following table sets forth the total number of net productive and dry exploratory and development wells drilled:

72

----------------------------------------------------------------------------------------
                                                           Three Months
                             YEAR ENDED      Year Ended       Ended         Year Ended
                            DECEMBER 31,    December 31,   December 31,    September 30,
                                2003            2002           2001            2001
----------------------------------------------------------------------------------------
Exploratory:
     Productive                     0.7             0.1            0.3              0.1
     Dry                            0.3             0.1             --              1.3
----------------------------------------------------------------------------------------
        Total                       1.0             0.2            0.3              1.4
----------------------------------------------------------------------------------------
Development:
     Productive                   194.2           145.9           23.8             90.7
     Dry                            3.0             4.3             --               --
----------------------------------------------------------------------------------------
        Total                     197.2           150.2           23.8             90.7
----------------------------------------------------------------------------------------

As of December 31, 2003, the Company was participating in the drilling of 6 gross development wells, with the Company's interest equivalent to 4.21 wells.

PRODUCTIVE WELLS AND ACREAGE: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2003, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

--------------------------------------------------------------------------------
                                                         Gross               Net
--------------------------------------------------------------------------------
Gas Wells                                                3,388             1,747
Oil Wells                                                2,233               996
--------------------------------------------------------------------------------
Developed Acreage                                      740,786           451,319
Undeveloped Acreage                                    101,034            55,439
--------------------------------------------------------------------------------

There were 44 wells with multiple completions in 2003. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in the Permian Basin.

OIL AND GAS OPERATIONS: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that only proved categories of reserves be disclosed and that reserves and associated values be calculated using year-end prices and current costs. Changes to prices and costs could have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of reserves disclosed. The proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, Miller and Lents, Ltd., and T. Scott Hickman and Associates, Inc., independent oil and gas reservoir engineers, have reviewed the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2003. Ryder Scott Company reviewed the reserve estimates for the Black Warrior Basin and substantially all of the Permian Basin reserves. Miller and Lents, Ltd. reviewed the reserves for the north Louisiana/east Texas regions. T. Scott Hickman and Associates, Inc. reviewed the reserves for the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 97 percent of the Company's ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

73

---------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2003                      Gas MMcf         Oil MBbl         NGL MBbl
---------------------------------------------------------------------------------------------
Proved reserves at beginning of period             803,748           49,833           26,697
Revisions of previous estimates                    (10,847)           1,237             (826)
Purchases                                           93,700            1,172               --
Discoveries and other additions                     80,124            5,051            4,068
Production                                         (55,796)          (3,458)          (1,602)
Sales                                              (24,622)          (1,307)          (1,092)
---------------------------------------------------------------------------------------------
Proved reserves at end of period                   886,307           52,528           27,245
---------------------------------------------------------------------------------------------
Proved developed reserves at end of period         714,866           40,802           23,552
---------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------
Year ended December 31, 2002                      Gas MMcf         Oil MBbl         NGL MBbl
---------------------------------------------------------------------------------------------
Proved reserves at beginning of period             714,395           19,128           25,944
Revisions of previous estimates                     (3,916)          (1,303)             624
Purchases                                            6,263           36,779               --
Discoveries and other additions                    141,435            1,367            2,030
Production                                         (48,051)          (3,193)          (1,794)
Sales                                               (6,378)          (2,945)            (107)
---------------------------------------------------------------------------------------------
Proved reserves at end of period                   803,748           49,833           26,697
---------------------------------------------------------------------------------------------
Proved developed reserves at end of period         672,633           36,782           24,009
---------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------
Three months ended December 31, 2001              Gas MMcf         Oil MBbl         NGL MBbl
---------------------------------------------------------------------------------------------
Proved reserves at beginning of period             627,051           20,878           24,931
Revisions of previous estimates                     89,055           (1,038)           1,381
Purchases                                                1               27                2
Discoveries and other additions                     10,805               43              154
Production                                         (12,018)            (550)            (451)
Sales                                                 (499)            (232)             (73)
---------------------------------------------------------------------------------------------
Proved reserves at end of period                   714,395           19,128           25,944
---------------------------------------------------------------------------------------------
Proved developed reserves at end of period         646,202           16,293           23,476
---------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------
Year ended September 30, 2001                     Gas MMcf         Oil MBbl         NGL MBbl
---------------------------------------------------------------------------------------------
Proved reserves at beginning of period             777,456           24,518           26,007
Revisions of previous estimates                   (134,543)          (2,407)          (2,006)
Purchases                                            9,334            1,100              836
Discoveries and other additions                     26,145            1,995            1,672
Production                                         (46,463)          (2,187)          (1,482)
Sales                                               (4,878)          (2,141)             (96)
---------------------------------------------------------------------------------------------
Proved reserves at end of period                   627,051           20,878           24,931
---------------------------------------------------------------------------------------------
Proved developed reserves at end of period         579,991           17,467           22,867
---------------------------------------------------------------------------------------------

During 2003, Energen Resources sold approximately 39 Bcfe of proved reserves, recording a net pre-tax loss of $1 million, which includes a $10.4 million writedown on assets held-for-sale and subsequently sold during the year partially offset by gains on property sales of $9.4 million.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of the Company's crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. At December 31, 2003, December 31, 2002, December 31, 2001, and September 30, 2001, the Company had a deferred hedging loss of $35.6 million and $17.2 million, and a deferred hedging gain of $15.2 million and $25.7 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.

74

-------------------------------------------------------------------------------------------------------------------------
                                                                                         Three Months
                                                     YEAR ENDED         Year Ended          Ended            Year Ended
                                                    DECEMBER 31,       December 31,      December 31,       September 30,
(in thousands)                                          2003               2002              2001               2001
-------------------------------------------------------------------------------------------------------------------------
Future gross revenues                               $ 7,211,830        $ 5,455,802        $ 2,181,148        $ 1,672,436
Future production costs                               2,189,464          1,754,700            829,968            693,817
Future development costs                                204,513            183,818            114,317             83,781
-------------------------------------------------------------------------------------------------------------------------
Future net cash flows before income taxes             4,817,853          3,517,284          1,236,863            894,838
Future income tax expense                             1,609,324          1,100,392            265,611            124,803
-------------------------------------------------------------------------------------------------------------------------
Future net cash flows after income taxes              3,208,529          2,416,892            971,252            770,035
Discount at 10% per annum                             1,635,450          1,172,635            399,810            272,493
-------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net
  cash flows relating to proved oil and gas
  reserves                                          $ 1,573,079        $ 1,244,257        $   571,442        $   497,542
-------------------------------------------------------------------------------------------------------------------------

Reserves and associated values were calculated using year-end prices and current costs. The following are the principal sources of changes in the standardized measure of discounted future net cash flows:

-------------------------------------------------------------------------------------------------------------------------
                                                                                         Three Months
                                                     YEAR ENDED         Year Ended          Ended            Year Ended
                                                    DECEMBER 31,       December 31,      December 31,       September 30,
(in thousands)                                          2003               2002              2001               2001
-------------------------------------------------------------------------------------------------------------------------
Balance at beginning of year                        $ 1,244,257        $   571,442        $   497,542        $ 1,105,265
-------------------------------------------------------------------------------------------------------------------------
Revisions to reserves proved in prior years:
  Net changes in prices, production costs
    and future development costs                        365,816            658,956            100,710         (1,015,900)
  Net changes due to revisions in
    quantity estimates                                  (14,804)            (8,380)            49,579            (81,076)
    Development costs incurred,
      previously estimated                               80,878             49,418              8,812             50,768
    Accretion of discount                               124,426             57,144             11,398            144,266
    Other                                                39,134             (8,669)           (24,012)            95,165
-------------------------------------------------------------------------------------------------------------------------
Total revisions                                         595,450            748,469            146,487           (806,777)
New field discoveries and extensions, net
  of future production and development costs            200,880            213,625              5,562             33,685
Sales of oil and gas produced, net of
  production costs                                     (311,189)          (162,151)           (23,699)          (220,220)
Purchases                                                74,201            218,799                 20             32,811
Sales                                                   (48,107)           (14,203)            (2,271)           (26,256)
Net change in income taxes                             (182,413)          (331,724)           (52,199)           379,034
-------------------------------------------------------------------------------------------------------------------------
Net change in standardized measure
  of discounted future net cash flows                   328,822            672,815             73,900           (607,723)
-------------------------------------------------------------------------------------------------------------------------
Balance at end of year                              $ 1,573,079        $ 1,244,257        $   571,442        $   497,542
-------------------------------------------------------------------------------------------------------------------------

75

21. INDUSTRY SEGMENT INFORMATION

The Company is principally engaged in two business segments: the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution). The accounting policies of the segments are the same as those described in Note 1. Certain reclassifications have been made to conform the prior years' financial statements to the current year presentation.

--------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Three Months
                                                              YEAR ENDED        Year Ended          Ended           Year Ended
                                                             DECEMBER 31,      December 31,      December 31,      September 30,
(in thousands)                                                   2003              2002              2001              2001
--------------------------------------------------------------------------------------------------------------------------------
Operating revenues from continuing operations
     Oil and gas operations                                   $  353,122        $  244,120        $   46,954        $  208,954
     Natural gas distribution                                    489,099           424,431            96,678           553,862
--------------------------------------------------------------------------------------------------------------------------------
       Total                                                  $  842,221        $  668,551        $  143,632        $  762,816
--------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) from continuing operations
     Oil and gas operations                                   $  153,591        $   76,286        $    3,496        $   66,416
     Natural gas distribution                                     66,848            59,370             8,034            50,288
--------------------------------------------------------------------------------------------------------------------------------
       Subtotal                                               $  220,439        $  135,656        $   11,530        $  116,704
     Eliminations and corporate expenses                          (2,551)           (1,700)             (417)           (1,678)
--------------------------------------------------------------------------------------------------------------------------------
       Total                                                  $  217,888        $  133,956        $   11,113        $  115,026
--------------------------------------------------------------------------------------------------------------------------------
Depreciation, depletion and amortization expense
  from continuing operations
     Oil and gas operations                                   $   79,687        $   68,009        $   15,317        $   50,907
     Natural gas distribution                                     37,171            33,682             8,151            30,933
--------------------------------------------------------------------------------------------------------------------------------
       Total                                                  $  116,858        $  101,691        $   23,468        $   81,840
--------------------------------------------------------------------------------------------------------------------------------
Interest expense
     Oil and gas operations                                   $   28,577        $   29,635        $    7,042        $   30,244
     Natural gas distribution                                     13,967            14,557             3,680            12,316
--------------------------------------------------------------------------------------------------------------------------------
       Subtotal                                               $   42,544        $   44,192        $   10,722        $   42,560
     Eliminations and other                                         (282)             (479)              (88)             (490)
--------------------------------------------------------------------------------------------------------------------------------
       Total                                                  $   42,262        $   43,713        $   10,634        $   42,070
--------------------------------------------------------------------------------------------------------------------------------
Income tax expense (benefit) from continuing operations
     Oil and gas operations                                   $   46,616        $    3,820        $   (4,741)       $     (611)
     Natural gas distribution                                     19,675            17,825             1,547            13,448
--------------------------------------------------------------------------------------------------------------------------------
       Subtotal                                               $   66,291        $   21,645        $   (3,194)       $   12,837
     Other                                                        (2,163)           (1,257)              (88)             (365)
--------------------------------------------------------------------------------------------------------------------------------
       Total                                                  $   64,128        $   20,388        $   (3,282)       $   12,472
--------------------------------------------------------------------------------------------------------------------------------
Capital expenditures
     Oil and gas operations                                   $  163,338        $  305,476        $   25,052        $  136,886
     Natural gas distribution                                     57,906            65,815            12,873            56,090
     Other                                                            --                 5                --                60
--------------------------------------------------------------------------------------------------------------------------------
       Total                                                  $  221,244        $  371,296        $   37,925        $  193,036
--------------------------------------------------------------------------------------------------------------------------------
Identifiable assets
     Oil and gas operations                                   $  959,815        $  926,839        $  687,776        $  716,043
     Natural gas distribution                                    797,693           715,330           651,211           606,808
--------------------------------------------------------------------------------------------------------------------------------
       Subtotal                                               $1,757,508        $1,642,169        $1,338,987        $1,322,851
     Eliminations and other                                       23,924               843             3,359            (8,966)
--------------------------------------------------------------------------------------------------------------------------------
       Total                                                  $1,781,432        $1,643,012        $1,342,346        $1,313,885
--------------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net
     Oil and gas operations                                   $  891,682        $  838,526        $  620,305        $  617,592
     Natural gas distribution                                    541,769           512,849           472,659           466,207
     Other                                                            --               179               237               253
--------------------------------------------------------------------------------------------------------------------------------
       Total                                                  $1,433,451        $1,351,554        $1,093,201        $1,084,052
--------------------------------------------------------------------------------------------------------------------------------

76

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

ENERGEN CORPORATION

------------------------------------------------------------------------------------------------------------------
                                                                                     Three Months
                                                      YEAR ENDED      Year Ended        Ended         Year Ended
                                                     DECEMBER 31,    December 31,    December 31,    September 30,
(in thousands)                                           2003            2002            2001            2001
------------------------------------------------------------------------------------------------------------------
ALLOWANCE FOR DOUBTFUL ACCOUNTS
BALANCE AT BEGINNING OF YEAR                           $  8,874        $ 11,783        $ 10,031        $  6,681
------------------------------------------------------------------------------------------------------------------
     Additions:
          Charged to income                               5,820           5,482           1,819           7,953
          Recoveries and adjustments                       (616)           (495)            139            (901)
------------------------------------------------------------------------------------------------------------------
              Net additions                               5,204           4,987           1,958           7,052
------------------------------------------------------------------------------------------------------------------
     Less uncollectible accounts written off             (4,226)         (7,896)           (206)         (3,702)
------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR                                 $  9,852        $  8,874        $ 11,783        $ 10,031
------------------------------------------------------------------------------------------------------------------

ALABAMA GAS CORPORATION

------------------------------------------------------------------------------------------------------------------
                                                                                     Three Months
                                                      YEAR ENDED      Year Ended        Ended         Year Ended
                                                     DECEMBER 31,    December 31,    December 31,    September 30,
(in thousands)                                           2003            2002            2001            2001
------------------------------------------------------------------------------------------------------------------
ALLOWANCE FOR DOUBTFUL ACCOUNTS
BALANCE AT BEGINNING OF YEAR                           $  8,200        $ 11,100        $  9,500        $  5,800
------------------------------------------------------------------------------------------------------------------
     Additions:
          Charged to income                               5,668           5,410           1,816           7,799
          Recoveries and adjustments                       (601)           (565)            (38)           (452)
------------------------------------------------------------------------------------------------------------------
              Net additions                               5,067           4,845           1,778           7,347
------------------------------------------------------------------------------------------------------------------
     Less uncollectible accounts written off             (4,167)         (7,745)           (178)         (3,647)
------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR                                 $  9,100        $  8,200        $ 11,100        $  9,500
------------------------------------------------------------------------------------------------------------------

77

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

A. Our chief executive officer and chief financial officer have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

B. Our chief executive officer and chief financial officer have concluded that during the period covered by this report there were no changes in our internal controls that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

78

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004. The proxy statement will be filed on or about March 29, 2004.

ITEM 11. EXECUTIVE COMPENSATION

The information regarding executive compensation is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

A. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The information regarding the security ownership of the beneficial owners of more than five percent of Energen's common stock is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004.

B. SECURITY OWNERSHIP OF MANAGEMENT

The information regarding the security ownership of management is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004.

C. SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The information regarding securities authorized for issuance under equity compensation plans is included in Part 2 under Item 5.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information regarding certain relationships and related transactions is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004.

79

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

A. DOCUMENTS FILED AS PART OF THIS REPORT

(1) FINANCIAL STATEMENTS

The consolidated financial statements of Energen and the financial statements of Alagasco are included in Item 8 of this Form 10-K

(2) FINANCIAL STATEMENT SCHEDULES

The financial statement schedules are included in Item 8 of this Form 10-K

(3) EXHIBITS

The exhibits listed on the accompanying Index to Exhibits are filed as part of this Form 10-K

B. REPORTS ON FORM 8-K

Form 8-K dated January 15, 2003, reporting Drayton Nabers, Jr., former chairman and chief executive officer of Protective Life Corporation, resigned from the Board of Directors of Energen Corporation effective January 15, 2003.

Form 8-K/A dated January 24, 2003, reporting Drayton Nabers, Jr., former chairman and chief executive officer of Protective Life Corporation, resigned from the Board of Directors of Energen Corporation effective January 15, 2003.

Form 8-K dated April 24, 2003, reporting Energen and Alagasco issued a press release announcing financial results for the first quarter of 2003.

Form 8-K dated July 18, 2003, reporting the sale of 1,000,000 shares of Energen common stock.

Form 8-K dated July 23, 2003, reporting Energen and Alagasco issued a press release announcing financial results for the second quarter of 2003.

Form 8-K dated October 3, 2003, reporting Energen and Alagasco issued a series of 5% Notes due October 3, 2013. The aggregate principal amount of notes offered was $50,000,000.

Form 8-K dated October 29, 2003, reporting Energen and Alagasco issued a press release announcing financial results for the third quarter of 2003.

Form 8-K dated December 10, 2003, reporting Energen and Alagasco issued a press release announcing financial results earnings guidance for 2004, the election of David W. Wilson as a Director of Energen Corporation effective January 1, 2004 and Wm. Michael Warren, Jr., Chairman of the Board and Chief Executive Officer of Energen Corporation adopted a Securities Trading Plan. Mr. Warren adopted the plan pursuant to Rule 10b5-1 of the Securities Exchange Act of 1934 and during an open trading window.

80

ENERGEN CORPORATION
ALABAMA GAS CORPORATION

INDEX TO EXHIBITS

ITEM 14(A)(3)

Exhibit
Number                             Description
------                             -----------

*3(a)       Restated Certificate of Incorporation of Energen Corporation
            (composite, as amended February 2, 1998) which was filed as Exhibit
            3(a) to Energen's Annual Report on Form 10-K for the year ended
            September 30, 1998 (File No. 1-7810)

*3(b)       Articles of Amendment to Restated Certificate of Incorporation of
            Energen, designating Series 1998 Junior Participating Preferred
            Stock (July 27, 1998) which was filed as Exhibit 4(b) to Energen's
            Post Effective Amendment No. 1 to Registration Statement on Form S-3
            (Registration No. 333-00395)

*3(c)       Bylaws of Energen Corporation (as amended through October 30, 2002)
            which was filed as Exhibit 4(c) to Energen's Registration Statement
            on Form S-8 (Registration No. 33-46641)

*3(d)       Articles of Amendment and Restatement of the Articles of
            Incorporation of Alabama Gas Corporation, dated September 27, 1995,
            which was filed as Exhibit 3(i) to the Registrant's Annual Report on
            Form 10-K for the year ended September 30, 1995 (file No. 1-7810)

3(e)        Bylaws of Alabama Gas Corporation (as amended through October 30,
            2002).

*4(a)       Rights Agreement, dated as of July 27, 1998, between Energen
            Corporation and First Chicago Trust Company of New York, Rights
            Agent, which was filed as Exhibit 1 to Energen's Registration
            Statement on Form 8-A, dated July 10, 1998 (File No. 1-7810)

*4(b)       Form of Indenture between Energen Corporation and The Bank of New
            York, as Trustee, which was dated as of September 1, 1996 (the
            "Energen 1996 Indenture"), and which was filed as Exhibit 4(i) to
            the Registrant's Registration Statement on Form S-3 (Registration
            No. 333-11239)

*4(b)(i)    Officers' Certificate, dated September 13, 1996, pursuant to Section
            301 of the Energen 1996 Indenture setting forth the terms of the
            Series A Notes which was filed as Exhibit 4(d)(i) to Energen's
            Annual Report on Form 10-K for the year ended September 30, 2001
            (File No. 1-7810)

*4(b)(ii)   Officers' Certificate, dated July 8, 1997, pursuant to Section 301
            of the Energen 1996 Indenture amending the terms of the Series A
            Notes which was filed as Exhibit 4(d)(ii) to Energen's Annual Report
            on Form 10-K for the year ended September 30, 2001 (File No. 1-7810)

*4(b)(iii)  Amended and Restated Officers' Certificate, dated February 27, 1998,
            setting forth the terms of the Series B Notes which was filed as
            Exhibit 4(d)(iii) to Energen's Annual Report on Form 10-K for the
            year ended September 30, 2001 (File No. 1-7810)

*4(b)(iv)   Officers' Certificate, dated October 3, 2003, pursuant to Section
            301 of the Energen 1996 Indenture setting forth the terms of the 5%
            Notes due October 1, 2013, which was filed as Exhibit 4 to Energen's
            Current Report on Form 8-K, dated October 3, 2003 (File No. 1-7810)

*4(d)       Indenture dated as of November 1, 1993, between Alabama Gas
            Corporation and NationsBank of Georgia, National Association,
            Trustee, ("Alagasco 1993 Indenture"), which was filed as Exhibit
            4(k) to Alabama Gas' Registration Statement on Form S-3
            (Registration No. 33-70466)

81

*4(d)(i)    Officers' Certificate, dated August 30, 2001, pursuant to Section
            301 of the Alagasco 1993 Indenture setting forth the terms of the
            6.25 percent Notes due September 1, 2016, which was filed as Exhibit
            4.01 to Alabama Gas' Current Report on Form 8-K filed September 27,
            2001

*4(d)(ii)   Officers' Certificate, dated August 30, 2001, pursuant to Section
            301 of the Alagasco 1993 Indenture setting forth the terms of the
            6.75 percent Notes due September 1, 2031, which was filed as Exhibit
            4.02 to Alabama Gas' Current Report on Form 8-K filed September 27,
            2001

*10(a)      Form of Service Agreement Under Rate Schedule CSS (No. S10710),
            between Southern Natural Gas Company and Alabama Gas Corporation
            which was filed as Exhibit 10(a) to Energen's Annual Report on Form
            10-K for the year ended September 30, 1993 (File No. 1-7810)

*10(b)      Form of Service Agreement Under Rate Schedule FT-NN (No. 866941),
            between Southern Natural Gas Company and Alabama Gas Corporation
            which was filed as Exhibit 10(c) to Energen's Annual Report on Form
            10-K for the year ended September 30, 1993 (File No. 1-7810)

*10(c)      Form of Service Agreement Under Rate Schedule FT (No. 866940)
            between Southern Natural Gas Company and Alabama Gas Corporation
            which was file as Exhibit 10(d) to Energen's Annual Report on Form
            10-K for the year ended September 30, 1993 (File No. 1-7810)

*10(d)      Form of Service Agreement Under Rate Schedule IT (No. 790420),
            between Southern Natural Gas Company and Alabama Gas Corporation
            which was filed as Exhibit 10(b) to Energen's Annual Report on Form
            10-K for the year ended September 30, 1993 (File No. 1-7810)

10(e)       Service Agreement between Transcontinental Gas Pipeline Corporation
            and Transco Energy Marketing Company as Agent for Alabama Gas
            Corporation, dated August 1, 1991.

*10(f)      Form of Executive Retirement Supplement Agreement between Energen
            Corporation and it's executive officers (as revised October 2000)
            which was filed as Exhibit 10(c) to Energen's Annual Report on Form
            10-K for the year ended September 30, 2000 (File No. 1-7810)

*10(g)      Form of Addendum to Executive Retirement Supplement Agreement
            between Energen Corporation and it's executive officers which was
            filed as Exhibit 10(d) to Energen's Annual Report on Form 10-K for
            the year ended September 30, 2000 (File No. 1-7810)

*10(h)      Form of Severance Compensation Agreement between Energen Corporation
            and it's executive officers which was filed as Exhibit 10(d) to
            Energen's Annual Report on Form 10-K for the year ended September
            30, 1999 (File No. 1-7810)

*10(i)      Energen Corporation 1988 Stock Option Plan (as amended November 25,
            1997) which was filed as Exhibit 10(e) to Energen's Annual Report on
            Form 10-K for the year ended September 30, 1998 (File No. 1-7810)

*10(j)      Energen Corporation 1992 Long-Range Performance Share Plan (as
            amended effective October 1, 1999) which was filed as Exhibit 10(f)
            to Energen's Annual Report on Form 10-K for the year ended September
            30, 1999 (File No. 1-7810)

*10(k)      Energen Corporation 1997 Stock Incentive Plan (as amended effective
            October 1, 2001) which was filed as Exhibit 10(h) to Energen's
            Annual Report on Form 10-K for the year ended September 30, 2001
            (File No. 1-7810)

*10(l)      Energen Corporation 1997 Deferred Compensation Plan (as amended
            effective October 1, 1999) which was filed as Exhibit 10(h) to
            Energen's Annual Report on Form 10-K for the year ended September
            30, 1999 (File No. 1-7810)

82

*10(m)      Energen Corporation 1992 Directors Stock Plan (as amended April 25,
            1997) which was filed as Exhibit 10(i) to Energen's Annual Report on
            Form 10-K for the year ended September 30, 1998 (File No. 1-7810)

*10(n)      Energen Corporation Annual Incentive Compensation Plan, as amended
            effective October 1, 2001 which was filed as Exhibit 10(k) to
            Energen's Annual Report on Form 10-K for the year ended September
            30, 2001 (File No. 1-7810)

*10(o)      Energen Corporation Officer Split Dollar Life Insurance Plan,
            effective October 1, 1999 which was filed as Exhibit 10(l) to
            Energen's Annual Report on Form 10-K for the year ended September
            30, 2000 (File No. 1-7810)

*10(p)      Form of Split Dollar Life Insurance Plan Agreement under Energen
            Corporation Officer Split Dollar Life Insurance Plan which was filed
            as Exhibit 10(m) to Energen's Annual Report on Form 10-K for the
            year ended September 30, 2000 (File No. 1-7810)

*10(q)      Officer Split Dollar Tax Matters Agreement which was filed as
            Exhibit 10(n) to Energen's Annual Report on Form 10-K for the year
            ended September 30, 2000 (File No. 1-7810)

21          Subsidiaries of Energen Corporation

23(a)       Consent of Independent Accountants (PricewaterhouseCoopers LLP)

23(b)       Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott
            Company)

23(c)       Consent of Independent Oil and Gas Reservoir Engineers (Miller and
            Lents, Ltd.)

23(d)       Consent of Independent Oil and Gas Reservoir Engineers (T. Scott
            Hickman and Associates, Inc.)

31(a)       Certification of Chief Executive Officer pursuant to Rule 13a-14(a)
            or 15d-14(a)

31(b)       Certification of Chief Financial Officer pursuant to Rule 13a-14(a)
            or 15d-14(a)

32          Certification pursuant to Section 1350

*Incorporated by reference

83

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

ENERGEN CORPORATION
(Registrant)

ALABAMA GAS CORPORATION
(Registrant)

March 12, 2004                           By /s/ Wm. Michael Warren, Jr.
--------------                           ------------------------------
                                         Wm. Michael Warren, Jr.
                                         Chairman, President and Chief Executive
                                         Officer of Energen, Chairman and Chief
                                         Executive Officer of Alabama Gas
                                         Corporation

84

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrants and in the capacities and on the dates indicated:

March 12, 2004                            By /s/ Wm. Michael Warren, Jr.
--------------                            --------------------------------------
                                          Wm. Michael Warren, Jr.
                                          Chairman, President and Chief
                                          Executive Officer of Energen, Chairman
                                          and Chief Executive Officer of Alabama
                                          Gas Corporation

March 12, 2004                            By /s/ Geoffrey C. Ketcham
--------------                            --------------------------------------
                                          Geoffrey C. Ketcham
                                          Executive Vice President, Chief
                                          Financial Officer and Treasurer of
                                          Energen and Alabama Gas Corporation

March 12, 2004                            By /s/ Grace B. Carr
--------------                            --------------------------------------
                                          Grace B. Carr
                                          Vice President and Controller of
                                          Energen

March 12, 2004                            By /s/ Paula H. Rushing
--------------                            --------------------------------------
                                          Paula H. Rushing
                                          Vice President-Finance of Alabama Gas
                                          Corporation

March 12, 2004                            By /s/ Julian W. Banton
--------------                            --------------------------------------
                                          Julian W. Banton
                                          Director

March 12, 2004                            By /s/ James S. M. French
--------------                            --------------------------------------
                                          James S. M. French
                                          Director

March 12, 2004                            By /s/ T. Michael Goodrich
--------------                            --------------------------------------
                                          T. Michael Goodrich
                                          Director

March 12, 2004                            By /s/ Judy M. Merritt
--------------                            --------------------------------------
                                          Judy M. Merritt
                                          Director

March 12, 2004                            By /s/ David W. Wilson
--------------                            --------------------------------------
                                          David W. Wilson
                                          Director

85

EXHIBIT 3(E)

ALABAMA GAS CORPORATION

BY-LAWS
As Amended Through October 30, 2002

ARTICLE I

SECTION 1. The annual meeting, for the purpose of electing Directors and transacting any other proper business, shall be held at 10:00 A.M. on the fourth Wednesday in January of each year, if not a legal holiday, and if a legal holiday then on the first succeeding business day not a legal holiday, or at such other date and time as shall be designated from time to time by the Board of Directors and stated in the notice of the meeting. Special meetings may be held, and shall be called by the Secretary, whenever directed by the Chairman of the Board or the President or whenever requested by a majority of the directors, either by vote at a meeting or in writing.

SECTION 2. At least ten days before each annual and each special meeting and in any event such number of days as will conform with any statutory requirement, the Secretary shall mail or cause to be mailed to each stockholder entitled to vote at the meeting, at his address appearing on the books of the corporation, a notice which shall state the time and the place of the meeting, and, in the case of a special meeting, shall state also the objects or purposes of the meeting.

SECTION 3. All meetings of the stockholders, including meetings for the election of directors, shall be held at the principal office of the corporation in the City of Birmingham, Alabama.

SECTION 4. Prior to each meeting of stockholders, the Board of Directors shall either fix a period of not less than ten days preceding the day of the meeting during which the stock transfer books shall be closed, or fix a date not less than ten days preceding the day of the meeting as a record date for the determination of the stockholders entitled to notice of and to vote at such meeting, and when a record date shall have been so fixed, only stockholders of record on such date shall be entitled to notice of and to vote at such meeting.

SECTION 5. Stockholders may vote in person or by proxy. The vote of stockholders for the election of directors, or upon any question before a meeting, need not be by ballot except when required by statute or demanded by a stockholder of record entitled to vote at the meeting; when so required or demanded, the vote shall be by ballot. All questions shall be decided by the vote of a majority of the shares voting on the question, except where otherwise required by statute or by the Certificate of Incorporation, as now or hereafter amended.

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SECTION 6. The Chairman of the Board, and in his absence, the President, or in the absence of both, the Executive Vice President, shall call meetings of stockholders to order and act as Chairman of such meeting. In the absence of all these officers the Board of Directors shall appoint a chairman of the meeting, but if the Board shall not make such appointment, then, any stockholder or the proxy of any stockholder may call the meeting to order, and a chairman shall be elected.

SECTION 7. The Secretary or any Assistant Secretary may act as Secretary of any meeting of stockholders; but the Board of Directors before the meeting may designate any person to act as secretary thereof, and if no such designation shall have been made, then the Chairman of the meeting may appoint any person to act as secretary thereof.

SECTION 8. At each meeting of the stockholders at which the voting shall be by ballot, the voting shall be conducted and all questions touching the qualifications of the voters, the validity of proxies and the acceptance or rejection of votes shall be decided by one judge. Such judge may be an officer of the corporation and may be appointed before the meeting by the board of directors, but if no such appointment shall have been made, then by the Chairman of the meeting; and if for any reason any judge previously appointed shall fail to attend, or refuse or be unable to serve, then a judge to act in his place shall be appointed by the Chairman of the meeting. No such judge need be a stockholder.

SECTION 9. At each meeting of stockholders, except as otherwise provided by statute or by the Certificate of Incorporation or an amendment thereof, the holders of a majority of all of the stock which at the time shall be entitled to vote, present in person or represented by proxy, shall be requisite for the transaction of business and shall constitute a quorum. A meeting of the stockholders may be adjourned to any day, and from time to time, as such meeting shall determine, whether or not a quorum be present The time and place to which an adjournment is taken shall be publicly announced at the meeting, and no further notice thereof shall be necessary.

ARTICLE II

Board of Directors

SECTION 1. The general management of the property, business and affairs of the Corporation shall be vested in a Board of Directors, eleven in number, who shall hold office until the next annual meeting of the stockholders and until others are duly chosen in their place and shall have qualified.

SECTION 2. The Board of Directors may provide for stated meetings at regular intervals to be held pursuant to a standing resolution of the Board. No notice of such meetings need be given. Special meetings of the Board may be called upon written instructions signed by the Chairman of the Board, the President or a Vice President, or at least two of the directors, and delivered to the Secretary of the Corporation, stating the time and place thereof. The Secretary

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shall give, or cause to be given, notice of the time and place of holding each special meeting by mailing the same at least thirty-six (36) hours before the meeting or by causing the same to be transmitted by telephone, cable or wire message at least twenty-four (24) hours before the meeting to each director to his address on file with the Secretary of the Company.

The directors may hold their meetings at such place or places, either within or without the State of Alabama, as the board shall designate from time to time.

SECTION 3. A majority of the directors shall constitute a quorum for the transaction of business at meetings of the board. Subject to the provisions of the Certificate of Incorporation, as amended, vacancies in the board shall be filled by a majority of the directors then in office. A majority of the directors present at any meeting may adjourn the meeting until a later day or hour, or sine die, whether or not a quorum be present. A minute of such adjournment shall be entered on the records by the Secretary, and no further notice thereof shall be necessary.

SECTION 4. The Board of Directors may adopt such rules and regulations for the conduct of its meetings and the management of the affairs of the corporation as it may deem proper not inconsistent with these by-laws or the certificate of incorporation and the amendments thereof.

SECTION 5. The Board of Directors shall fix and authorize the payment of compensation for all officers of the corporation, including such officers as may be directors of the corporation, for services to the corporation; and shall fix and authorize the payment of compensation and expenses to the directors for services to the corporation, including fees and expenses for attendance at meetings of the board, of the executive committee and of all other committees.

ARTICLE III

Officers and Agents

SECTION 1. The officers of this corporation shall consist of a Chairman of the Board, a President, one or more Vice Presidents, a Secretary, and a Treasurer. In addition, the Board of Directors of this corporation may, but shall not be required to, elect one or more of the following: Executive Vice President, Senior Vice President, Assistant Vice President, Assistant Secretary, and Assistant Treasurer. In addition, the Board of Directors of this Corporation may, but shall not be required to, elect a Controller. The Chairman of the Board and the President shall be members of the Board of Directors; the other officers may, but need not be Directors. The Chairman of the Board and the President may be the same person, and the Secretary and Treasurer may be the same person; and the Executive Vice President, a Senior Vice President, or a Vice President may also hold the office of Secretary or Assistant Secretary or Treasurer or Assistant Treasurer or Controller, provided, however, that the Chairman of the Board may not also hold the offices of either Executive Vice President, Senior Vice President, or Vice President; that the President may not also hold the office of Executive Vice President, Senior Vice President, or Vice President; and that an Executive Vice President, a Senior Vice President, or a Vice President may not hold both the offices of Secretary and Treasurer.

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Except where otherwise expressly provided in a written contract duly authorized by the Board of Directors, all officers, agents and employees shall be subject to removal at any time by the affirmative vote of a majority of the Directors for the time being in office, and all officers, agents and employees other than officers elected or appointed by the Board of Directors shall also be subject to removal at any time by the officer appointing them.

In addition to the powers and duties of the officers of the corporation as set forth in these By-laws and except as otherwise provided in the Certificate of Incorporation, they shall have such authority and shall perform such duties as from time to time may be determined by the Board of Directors.

SECTION 2. The Board of Directors shall by resolution duly adopted, designate one of the executive officers of the corporation as the chief executive officer of the corporation and the officer so designated by the Board of Directors shall, subject to the control of the Board of Directors, have general charge and control of the business and affairs of the corporation and shall perform such other duties as may from time to time be assigned to him by the Board of Directors. The designation by the Board of Directors of one of such executive officers other than the Chairman of the Board as the chief executive officer of the corporation shall not affect the duties required to be performed by the Chairman of the Board of the corporation under the provisions of Sections 6 and 8 of Article I of these By-laws. The Chairman of the Board shall preside at all meetings of the stockholders and of the Directors at which he is present, and shall perform such other duties as may, from time to time, be assigned to him by the Board of Directors.

SECTION 3. The President shall be the chief operating officer of the corporation. He shall, from time to time, obtain information concerning the affairs and business of the corporation and shall promptly lay such information before the Board of Directors. He shall communicate to the Board of Directors all matters presented by any officer of the corporation for its consideration and shall, from time to time, communicate to the officers such action of the Board of Directors as may, in his judgment, affect the performance of their official duties. He shall have power to appoint and remove all servants, agents and employees of the corporation (other than its officers), and shall perform all such other duties as are incident to the office of President and such specific duties as may, from time to time, be assigned to him by the Board of Directors.

In the absence of the Chairman of the Board he shall preside at all meetings of stockholders and at all meetings of the Board of Directors at which he is present.

SECTION 4. The Chairman of the Board shall in the absence of the President or in case of his inability to act, perform the duties and exercise the authority of the President. Each Vice President may have such title designation, and each Vice President, and the Executive Vice President, if there be one, each Senior Vice President, if there be one or more of them, and each Assistant Vice President, if there be one or more of them, shall perform such duties and exercise such authority as from time to time may be prescribed and conferred by the Board of Directors.

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SECTION 5. The Secretary shall attend all meetings of the stockholders and of the Board of Directors and shall keep a record of all their proceedings. He shall give due notices of all meetings of the Stockholders and of the Board of Directors. He shall notify the several officers of the corporation of all action taken at any such meeting concerning matters in their respective departments, and shall transmit to the Treasurer for proper record copies of all contracts and resolutions providing for the payment of money to or by the corporation. He shall procure and keep in his files certified copies of the minutes of all meetings of the stockholders and of the Board of Directors of all companies a majority of whose capital stock is owned by this corporation. He shall be the custodian of the seal of the corporation, of mortgages, leases, and of such other papers and documents as shall be committed to his care by the Board of Directors. He shall have charge of the transfer department and supervision of the transfer of the stocks and of the registration and transfer of the bonds issued by the corporation. He shall have power to affix the seal of the corporation to instruments authorized by the Board of Directors and to attest the same; and shall perform such other duties as shall be assigned to him by the Board of Directors. He shall be sworn to the faithful discharge of his duty.

SECTION 6. The Assistant Secretaries shall exercise such of the powers and perform such of the duties of the Secretary as shall be assigned to them by the Secretary or the Board of Directors. Each Assistant Secretary of this corporation be and he hereby is authorized, in the absence or disability of the Secretary, to perform all the duties and exercise all the powers of the Secretary. Any action which in Article I or Article II of these by-laws it is stated shall be taken by or in connection with the Secretary may be taken by or in connection with any Assistant Secretary with the same effect as if he were the Secretary.

SECTION 7. The Treasurer is authorized to receive and collect all moneys due to the corporation and to receipt therefor, and to endorse for deposit to the credit of the corporation in depositories designated by the Board of Directors, checks, drafts or vouchers drawn to the order of the corporation or payable to it. He is authorized to pay interest on obligations and dividends on stock when due and payable. He shall cause to be kept in his office true and full accounts of all receipts and disbursements. He shall disburse the funds of the corporation as may be ordered by the Board of Directors, taking proper vouchers for such disbursements. He shall also perform such other duties as shall be assigned to him by the Board of Directors.

SECTION 8. The Controller, if there be one, shall, subject to the Board of Directors, provide and maintain financial and accounting controls over the business and affairs of the Corporation. He shall maintain, among others, adequate records of the assets, liabilities, and financial transactions of the Corporation, and shall direct the preparation of financial statements, reports, and analyses. He shall perform all acts incident to the position of Controller, subject to the control of the Board of Directors, the Chairman, and any Vice President or other executive officer charged by Board of Directors with general supervision of the financial affairs of the Corporation. If there shall be no Controller, the duties set out above in this Section 8 shall be performed by the Treasurer.

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SECTION 9. The Assistant Treasurers shall exercise such of the powers and perform such of the duties of the Treasurer as shall be assigned to them by the Treasurer or by the Board of Directors. Each Assistant Treasurer of this corporation be and he hereby is authorized, in the absence or disability of the Treasurer, to perform all the duties and exercise all the powers of the Treasurer.

SECTION 10. In case of the absence or incapacity of any officer of this corporation, the Board of Directors may delegate his powers and duties for the time being to any other officer or to any Director.

ARTICLE IV

Issue and Transfer of Stock Certificates

SECTION 1. The Board of Directors shall provide for issue, transfer and registration of the certificates representing the capital stock of the corporation, and shall appoint the necessary officers, transfer agents and registrars of transfers for that purpose.

SECTION 2. Until otherwise ordered by the Board of Directors, stock certificates shall be signed by the President or by a Vice President, and by the Secretary or an Assistant Secretary thereunto authorized by the Board of Directors.

SECTION 3. Unless otherwise ordered by the Board of Directors, the signatures on stock certificates of the President, the Executive Vice President or a Vice President and Secretary or Assistant Secretary of the Company may be facsimiles engraved or printed and the corporate seal to be affixed thereto may be a facsimile, engraved or imprinted thereon. In case any officer or officers whose facsimile signatures may be used on any stock certificate cease to be such officer or officers, whether because of death, resignation, or otherwise, before such certificates have been issued, such certificates shall nevertheless be deemed to have been adopted by the corporation and may be countersigned and issued by any transfer agent or registrar as though such person or persons whose facsimile signatures have been used thereon had not ceased to be such officer or officers of the corporation.

SECTION 4. Transfers of stock shall be made on the books of the corporation only by order of the person in whose name such stock is registered or by his attorney lawfully constituted in writing, and unless otherwise authorized by the Board of Directors, only upon surrender and cancellation of the old certificate. No new stock certificate shall be issued to a transferee until the transfer has been made on the books of the corporation.

SECTION 5. In case any stock certificate shall be lost, by theft or otherwise, or destroyed, the Board of Directors in its absolute discretion may order the issuance of a new certificate in lieu thereof, upon delivery to the corporation of a bond of indemnity satisfactory to the board.

6

SECTION 6. The Board of Directors may fix in advance any period of not more than thirty days preceding any dividend payment date or any date for the allotment of rights, during which the stock transfer books shall be closed; or in the event that the Board of Directors shall not have fixed such period, it may fix a date not more than thirty days preceding any dividend payment date or any date for the allotment of rights, as a record date for the determination of the stockholders entitled to receive such dividends or rights, as the case may be; and only stockholders of record on such date shall be entitled to receive such dividends or rights, as the case may be.

ARTICLE V

Checks - Notes - Drafts - Etc.

SECTION 1. Unless otherwise directed by the Board of Directors, all notes, acceptances, checks, drafts and orders for the payment of money shall be signed by the Treasurer, Controller, or an Assistant Treasurer and any one of the following officers of the corporation: Chairman of the Board, President, Executive Vice President, Senior Vice President, any Vice President, Secretary, Treasurer, Controller, Assistant Secretary and Assistant Treasurer.

ARTICLE VI

INDEMNIFICATION OF DIRECTORS, OFFICERS, EMPLOYEES AND AGENTS

SECTION 1. Indemnification.

(a) The Corporation shall indemnify, to the fullest extent permitted by law, including, without limitation, the Alabama Business Corporation Act, any person who is or was a director or officer of the Corporation, and any director or officer of the Corporation (and any other person, as evidenced by a duly adopted resolution of the board of directors of the Corporation) who is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, against liability or other expenses incurred in connection with the defense of any proceeding, or of any claim, issue or matter in such proceeding, in which such director, officer or other person is a party because such person is or was a director or officer of the Corporation or is or was serving at the request of the Corporation in one of the capacities referred to above. If the amount, extent, or quality of indemnification permitted by law should be in any way restricted after the adoption of these bylaws, then the Corporation shall indemnify such persons to the fullest extent permitted by law as in effect at the time of the occurrence of the omission or the act giving rise to the claimed liability with respect to which indemnification is sought.

7

(b) The Corporation shall indemnify, to the same extent as provided in
Section 1 (a) of this Article VI of these bylaws with respect to officers and directors of the Corporation, any employee of the Corporation, and any employee of the Corporation (and any other person, as evidenced by a duly adopted resolution of the board of directors of the Corporation) who is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, against liability or other expenses incurred in connection with the defense of any proceeding, or of any claim, issue or matter in such proceeding, in which proceeding both such employee or other person is a party because such person is or was an employee of the Corporation or is or was serving at the request of the Corporation in one of the capacities referred to above and the Corporation is obligated to provide, and is providing, indemnification to one or more officers or directors of the Corporation pursuant to Section 1 (a) above of this Article VI.

(c) In connection with indemnification of officers, directors and other persons pursuant to Sections 1 (a) and 1 (b) of this Article VI of these bylaws, the Corporation shall advance expenses to such persons as and to the extent permitted by law, including, without limitation, the Alabama Business Corporation Act.

(d) The Corporation may indemnify, and may advance expenses to, an employee or agent of the Corporation who is not an officer or director of the Corporation and any other person not described in, or not provided indemnification pursuant to the provisions of, Sections 1 (a), 1 (b) or 1 (c) of this Article VI who is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise to the same extent as provided in Section 1 (a) of this Article VI of these bylaws with respect to officers and directors of the Corporation. Notwithstanding the foregoing, nothing contained in this Section (d) shall, or shall be deemed to, constitute or create an entitlement on the part of any employee or agent of the Corporation to be indemnified or to have expenses advanced to or for such employee's or agent's benefit.

(e) The indemnification and advancement of expenses pursuant to this Article VI shall be in addition to, and not exclusive of, any other right that the person seeking indemnification may have under these bylaws, the articles of incorporation of the Corporation, any separate contract or agreement or applicable law.

8

SECTION 2. Insurance.

The Corporation may purchase and maintain insurance on behalf of any person who is or was a director, officer, partner, trustee, employee or agent of the Corporation, or any person who is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee, or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, against any liability asserted against such person and incurred by such person in any such capacity, or arising out of such person's status as such, whether or not the Corporation would have the power to indemnify such person against such liability under applicable law.

SECTION 3. Survival of Right.

Any right to indemnification or advancement of expenses provided by or granted pursuant to this Article VI shall continue as to a person who has ceased to be a director, officer, employee or agent or to serve as a director, officer, partner, trustee, employee or agent of such other foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise and shall inure to the benefit of the heirs, executors, administrators and personal representatives of such a person. Any repeal or modification of this Article VI which serves to restrict or lessen the rights to indemnification or advancement of expenses provided by this Article VI shall be prospective only and shall not lessen the right to indemnification or advancement of expenses existing at the time of such repeal or modification with respect to liabilities arising out of claimed acts or omissions occurring prior to such repeal or modification.

ARTICLE VII

General Provisions

SECTION 1. All officers, agents and employees, in exercise of the powers conferred and the performance of the duties imposed upon them, by these by-laws or otherwise, shall at all times be subject to the direction, supervision and control of the Board of Directors.

SECTION 2. Except as otherwise ordered by the Board of Directors, the Chairman of the Board, the President, the Executive Vice President and each Vice President shall severally have power to execute on behalf of the corporation any deed, bond, indenture, certificate, contract or other instrument, and to cause the corporate seal to be thereto affixed and attested by the Secretary or an Assistant Secretary.

SECTION 3. Unless otherwise ordered by the Board of Directors, the Chairman of the Board, the President or any Vice-President, or such other officer as may be designated by the Board of Directors to act in the absence of the Chairman of the Board, the President or any Vice President, shall have full power and authority on behalf of the corporation to attend and to act and to vote, and to execute a proxy or proxies empowering others to attend and to act and to vote, at any meetings of security holders of any corporation in which the corporation may hold

9

securities, and at such meetings the Chairman of the Board, or such other officer of the corporation, or such proxy shall possess and may exercise any and all rights and powers incident to the ownership of such securities, and which as the owner thereof the corporation might have possessed and exercised, if present. The Chairman of the Board, or such other officer of the corporation, or such proxy may also exercise any part or all of such voting and other authority, rights and power through execution of an action by written consent in lieu of a meeting of shareholders. The Secretary or any Assistant Secretary may affix the corporate seal to any such proxy or proxies so executed by the Chairman of the Board, or such other officer, and attest the same. The Board of Directors by resolution from time to time may confer like powers upon any other person or persons.

SECTION 4. Any stockholder, director or officer may waive any notice required to be given to him under these by-laws.

SECTION 5. In addition to its principal office in the State of Alabama, the corporation may have an office or offices, either within or without the State.

SECTION 6. The corporate seal shall be an impression on wax or paper, circular in form, with the words "Alabama Gas Corporation, Alabama" on the outer margin thereof and bearing on the inner portion the words "Corporate Seal, 1929."

SECTION 7. These by-laws may be altered, amended or repealed at any meeting of stockholders, by vote of the holders, present in person or by proxy, of a majority of all of the stock which at the time shall be entitled to vote at elections of directors, or at any meeting of the Board of Directors, by vote of a majority of all the members of the board.


The foregoing Bylaws of Alabama Gas Corporation are as amended by action of the Board of Directors at its meeting on October 30, 2002.


Assistant Secretary

10

EXHIBIT 10(E)

87 1533 004
System Contract #.1983

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

SERVICE AGREEMENT

between

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

and

TRANSCO ENERGY MARKETING COMPANY
As Agent for ALABAMA GAS CORPORATION

DATED

AUGUST 1, 1991


87 1533 004

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

SERVICE AGREEMENT

THIS AGREEMENT entered into this lst day of August, 1991, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as "Seller," first party, and TRANSCO ENERGY MARKETING COMPANY, as Agent for ALABAMA GAS CORPORATION, hereinafter referred to as "Buyer;" second party,

W I T N E S S E T H

WHEREAS, Buyer has requested Seller to receive certain quantities of natural gas at various points downstream of Seller's Compressor Station No. 70 on Seller's mainline in the State of Mississippi and transport such gas, on a firm basis, to the existing interconnections between Seller and Alabama Gas Corporation ("Alagasco") in Chilton and Dallas Counties, Alabama; and

WHEREAS, Seller agrees to receive, transport and redeliver or cause the redelivery of such quantities of natural gas as requested under the terms and conditions hereinafter set forth;

NOW, THEREFORE, Seller and Buyer agree as follows:

ARTICLE I
GAS TRANSPORTATION SERVICE

1. Subject to the terms and provisions of this agreement and of Seller's Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to the dekatherm equivalent of a Transportation Contract Quantity ("TCQ") of 100,000 Mcf per day.

2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 of the General Terms and Conditions of Seller's FERC Gas Tariff.

ARTICLE II
POINT(S) OF RECEIPT

Buyer shall deliver or cause to be delivered gas at the point(s) of receipt hereunder at a pressure sufficient to allow the gas to enter Seller's pipeline system at the varying pressures that may exist in such system from time to time; provided, however, that such pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressure(s) specified below. In the event the maximum operating pressure(s) of Seller's pipeline system, at the point(s) of receipt hereunder, is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas


delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon written notification of Seller to Buyer. The point(s) of receipt for natural gas received for transportation pursuant to this agreement shall be:

See EXHIBIT A for Points of Receipt

ARTICLE III
POINT(S) OF DELIVERY

Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following point(s) of delivery and at a pressure(s) of:

See EXHIBIT B for Points of Delivery

ARTICLE IV
TERM OF AGREEMENT

This agreement shall be in effect as of August 1, 1991 and shall remain in force and effect until 8:00 a.m. Eastern Standard Time October 31, 2002 and thereafter until terminated by Seller or Buyer upon at least three (3) years written notice; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any, Seller may discontinue service hereunder if (a) Buyer, in Seller's reasonable judgement fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 8.3 of Seller's Rate Schedule FT. As set forth in Section 8 of Article II of Seller's August 7, 1989 revised Stipulation and Agreement in Docket 88-68 et. al., (a) pregranted abandonment under Section
284.221 (d) of the Commission's Regulations shall not apply to any long term conversions from firm sales service to transportation service under Seller's Rate Schedule FT and (b) Seller shall not exercise its right to terminate this service agreement as it applies to transportation service resulting from conversions from firm sales service so long as Buyer is willing to pay rates no less favorable than Seller is otherwise able to collect from third parties for such service.


ARTICLE V
RATE SCHEDULE AND PRICE

1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Seller's Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be legally amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof.

2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up in providing the transportation service hereunder, which quantity may be changed from time to time and which will be specified in the currently effective Sheet No. 44 of Volume No. 1 of this Tariff which relates to service under this agreement and which is incorporated herein.

3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Seller's Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees incurred as a result of Buyer's request for service under Seller's Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction.

ARTICLE VI
MISCELLANEOUS

1. This Agreement supersedes and cancels as of the effective date hereof the following contract(s) between the parties hereto:

Agreement between Buyer and Seller dated November 21, 1987.

2. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.

3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect to the subject matter, including present and future orders, rules and regulations of duly constituted authorities.


4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.

5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address:

(a) If to Seller:

Transcontinental Gas Pipe Line Corporation P. O. Box 1396
Houston, Texas 77251

Attention: Customer Services

(b) If to Buyer:

Transco Energy Marketing Company as Agent for Alabama Gas Corporation P. O. Box 1396
Houston, Texas 77251

Attention: Natural Gas Marketing

Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party by certified or registered mail.


IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized.

TRANSCONTINENTAL GAS PIPE LINE
CORPORATION
(Seller)

By

Thomas E: Skains Senior Vice President Transportation and Customer Services

TRANSCO ENERGY MARKETING COMPANY
as Agent for ALABAMA GAS CORPORATION
(Buyer)

By
Title

87 1533 004

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

EXHIBIT "A"
(FT)

                                                                    Buyer's
                                                               Mainline Capacity
                                                                  Entitlement
Point(s) of Receipt                                                 (Mcf/d)*
-------------------                                            -----------------
1.    Discharge Side of Seller's Compressor                         100,000
      Station 70 at M.P. 661.77 in Walthall
      County, Mississippi. (M.P. 661.77 -
      Station 70 Discharge TP# 7142)

2.    Existing Point of Interconnection between                     100,000
      Seller and United Gas Pipe Line Company
      at Walthall (Seller Meter No. 3095),
      Walthall County, Mississippi. (Walthall-
      UGPL TP# 6310)***

3.    Existing Point of Interconnection between                     100,000
      Seller and Meter named Darbun-Pruett 34-10
      (Seller Meter No. 3446) at M.P. 668.46 on
      Sellers Main Transmission Line, Darbun
      Field, Walthall County, Mississippi.
      (Darbun Pruett TP# 6750)

4.    Existing Point of Interconnection between                     100,000
      Seller and Meter named Ivy Newsome (Seller
      Meter No. 3413) in Marion County,
      Mississippi. (Ivy Newsome TP# 6179)

5.    Existing Point of Interconnection between                     100,000
      Seller and West Oakvale Field at M.P.
      680.47-Marion County, Mississippi.
      (M.P. 680.47-West Oakvale Field TP# 7144)

6.    Existing Point of Interconnection between                     100,000
      Seller and East Morgantown Field at M.P.
      680.47 in Marion County, Mississippi.
      (M.P. 680.47-E. Morgantown Field TP# 7145)

7.    Existing Point of Interconnection between                     100,000
      Seller and Greens Creek Field, at M.P.
      681.84 Marion County, Mississippi.
      (M.P. 681.84 Greens Creek Field TP# 7146)


TRANSCONTINENTAL GAS PIPE LINE CORPORATION

EXHIBIT "A"
(Continued)

                                                                    Buyer's
                                                               Mainline Capacity
                                                                  Entitlement
Point(s) of Receipt                                                 (Mcf/d)*
-------------------                                            -----------------
8.    Existing Point of Interconnection between                     100,000
      Seller and Meter named M.P. 685.00-Oakville
      Unit 6-6 in Jefferson Davis County,
      Mississippi. (M.P. 685.00-Oakville Unit 6-6
      TP# 1376)

9.    Existing Point of Interconnection between                     100,000
      Seller and Meter named M.P. 687.23-Oakvale
      Field in Marion County, Mississippi.
      (M.P. 687.23-Oakvale Field TP# 7147)

10.   Existing Point of Interconnection between                     100,000
      Seller and Bassfield at named M.P. 696.40
      in Marion County, Mississippi. (M.P. 696.40
      Bassfield TP# 9439)

11.   Existing Point of Interconnection between                     100,000
      Seller and Meter named Lithium/Holiday
      Creek-Frm (Seller Meter No. 3418), in
      Jefferson Davis County, Mississippi.
      (Lithium/Holiday Creek-Frm TP# 7041).

12.   Existing Point of Interconnection between                     100,000
      Seller and S. W. Sumrall Field and Holiday
      Creek at M.P. 692.05-Holiday Creek in
      Jefferson Davis, Mississippi. (M.P. 692.05-
      Holiday Creek TP# 7159)

13.   Exiting Point of Interconnection between                      100,000
      Seller and ANR Pipe Line Company at
      Holiday Creek (Seller Meter No. 3241),
      Jefferson Davis County, Mississippi.
      (Holiday Creek-ANR TP# 398)


TRANSCONTINENTAL GAS PIPE LINE CORPORATION

EXHIBIT "A"
(Continued)

                                                                    Buyer's
                                                               Mainline Capacity
                                                                  Entitlement
Point(s) of Receipt                                                 (Mcf/d)*
-------------------                                            -----------------
14.   Existing Point of Interconnection between                     100,000
      Seller and Mississippi Fuel Company at
      Jeff Davis (Seller Meter No. 3252),
      Jefferson Davis County, Mississippi.
      (Jefferson Davis County-Miss Fuels
      TP# 6579)***

15.   Existing Point of Interconnection between                     100,000
      Seller and Meter named Jefferson Davis-Frm
      (Seller Meter No. 4420), in Jefferson Davis
      County, Mississippi. (Jefferson Davis-Frm
      TP# 7033)

16.   Existing Point of Interconnection between                     100,000
      Seller and Carson Dome Field M.P. 696.41,
      in Jefferson Davis County, Mississippi.
      (M.P. 696.41-Carson Dome Field TP# 7148)

17.   Existing Point of Interconnection between                     100,000
      Seller and Meter Station named Bassfield-
      ANR Company at M.P. 703.17 on Seller's Main
      Transmission Line (Seller Meter No. 3238),
      Covington County, Mississippi.  (Bassfield-
      ANR TP# 7029)

18.   Existing Point of Interconnection between                     100,000
      Seller and Meter named Patti Bihm # l
      (Seller Meter No. 3468), in Covington
      County, Mississippi. (Patti Bihm # 1
      TP# 7629)

19.   Discharge Side of Seller's Compressor                         100,000
      at Seller's Eminence Storage Field
      (Seller Meter No. 4166 and 3160)
      Covington County, Mississippi.
      (Eminence Storage TP# 5561)


TRANSCONTINENTAL GAS PIPE LINE CORPORATION

EXHIBIT "A"
(Continued)

                                                                    Buyer's
                                                               Mainline Capacity
                                                                  Entitlement
Point(s) of Receipt                                                 (Mcf/d)*
-------------------                                            -----------------
20.   Existing Point of Interconnection between                     100,000
      Seller and Dont Dome Field at M.P. 713.39
      in Covington County, Mississippi.
      (M.P. 713.39 - Dont Dome TP# 1396)

21.   Existing Point of Interconnection between                     100,000
      Seller and Endevco in Covington County,
      Mississippi. (Hattiesburg-Interconnect
      Storage TP# 1686)

22.   Existing Point at U.P. 719.58 on Seller's                     100,000
      Main Transmission Line (Seller Meter No.
      354.4), Centerville Dome Field, Jones
      County, Mississippi. (Centerville Dome
      Field TP# 1532)

23.   Existing Point at M.P. 727.78 on                              100,000
      Seller's Main Transmission Line,
      Jones County, Mississippi. (Jones
      County-Gitano TP# 7166)

24.   Existing Point of Interconnection between                     100,000
      Seller and a Meter named Koch Reedy Creek
      (Seller Meter No. 3333), Jones County,
      Mississippi. (Reedy Creek-Koch TP# 670)

25.   Existing Point of Interconnection between                     100,000
      Seller and Meter named Sharon Field
      (Seller Meter No. 3000), in Jones County,
      Mississippi. (Sharon Field TP# 419)

26.   Existing Point of Interconnection between                     100,000
      Seller and Tennessee Gas Transmission
      Company at Heidelberg (Seller Meter No. 3109),
      Jasper County, Mississippi. (Heidelberg-
      Tennessee TP# 6120)***


TRANSCONTINENTAL GAS PIPE LINE CORPORATION

EXHIBIT "A"
(Continued)

                                                                    Buyer's
                                                               Mainline Capacity
                                                                  Entitlement
Point(s) of Receipt                                                 (Mcf/d)*
-------------------                                            -----------------
27.   Existing Point of Interconnection between                     100,000
      Seller and Mississippi Fuel Company at
      Clarke (Seller Meter No. 3254),
      Clarke County, Mississippi. (Clarke County-
      Miss Fuels TP# 6047)***

28.   Existing Point of Interconnection between                     100,000
      Seller and Meter named Clarke County-Koch
      at M.P. 757.29 in Clarke County, Mississippi.
      (Clarke County-Koch TP# 5566)

29.   Existing Point of Interconnection between                     100,000
      Seller and Meter named M.P. 784.66 - Mobile
      Bay in Butler Co., Alabama (M.P. 784.66 -
      MB But TP #8244)

Buyer shall not tender, without the prior consent of Seller, at any point(s) of receipt on any day a quantity in excess of the applicable Buyer's Mainline Capacity Entitlement for such point(s) of receipt.


* These quantities do not include the additional quantities of gas retained by Seller for applicable compressor fuel and line loss make-up provided for in Article V, 2 of this Service Agreement, which are subject to change as provided for in Article V, 2 hereof. Receipt of gas limited to physical capacity of the receipt point.

** Receipt of gas by displacement only.

*** Receipt of gas limited to physical capacity of Seller's lateral line facilities.


87 1533 004

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

Exhibit B

      Point(s) of Delivery                            Pressure
      --------------------                            --------
1.    Existing interconnection between Seller         Not less than fifty (50) pounds per
      and Alagasco at Milepost 875.80 in              square inch gauge or at such other
      Dallas County, AL (Selma).                      pressures as may be agreed upon in
                                                      the day-to-day operations of Buyer
                                                      and Seller.

2.    Existing interconnection between Seller         Not less than fifty (50)  pounds per
      and Alagasco at Milepost 904.06 in              square inch gauge or at such other
      Chilton County, AL (Verbena).                   pressures as may be agreed upon in
                                                      the day-to-day operations of Buyer
                                                      and Seller.

3.    Seller's Eminence Storage Field,                Prevailing pressure in Seller's
      Covington County, MS.                           pipeline system not to exceed
                                                      maximum allowable operating pressure.


EXHIBIT 21

SUBSIDIARIES OF ENERGEN CORPORATION

Alabama Gas Corporation*
Energen Resources Corporation*
Energen Resources TEAM, Inc.*

* Incorporated in the State of Alabama


EXHIBIT 23(A)

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-43245 and File No. 333-86056) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 33-26111, File No. 33-45107 and File No. 333-84170) of Energen Corporation of our report dated March 2, 2004 relating to the consolidated financial statements and financial statement schedule of Energen Corporation, which appears in this Form 10-K.

PricewaterhouseCoopers LLP
Birmingham, Alabama
March 12, 2004


EXHIBIT 23(B)

CONSENT

We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-43245 and File No. 333-86056) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 33-26111, File No. 33-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K.

Ryder Scott Company, L.P.
Houston, Texas
March 1, 2004


EXHIBIT 23(C)

CONSENT

We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-43245 and File No. 333-86056) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 33-26111, File No. 33-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K.

Miller and Lents, Ltd.
Birmingham, Alabama
March 12, 2004


EXHIBIT 23(D)

CONSENT

We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-43245 and File No. 333-86056) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 33-26111, File No. 33-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K.

T. Scott Hickman & Associates, Inc.
March 12, 2004


EXHIBIT 31(A)

CERTIFICATION

I, Wm. Michael Warren, Jr., certify that:

1. I have reviewed this report on Form 10-K of Energen Corporation and Alabama Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

March 12, 2004                By /s/ Wm. Michael Warren, Jr.
--------------                --------------------------------
                              Wm. Michael Warren, Jr.
                              Chairman, President and Chief
                              Executive Officer of Energen
                              Corporation, Chairman and Chief
                              Executive Officer of Alabama Gas
                              Corporation


EXHIBIT 31(B)

CERTIFICATION

I, G. C. Ketcham, certify that:

1. I have reviewed this report on Form 10-K of Energen Corporation and Alabama Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

March 12, 2004                By /s/ G. C. Ketcham
--------------                -----------------------------------
                              G. C. Ketcham
                              Executive Vice President, Chief
                              Financial Officer and Treasurer of
                              Energen Corporation and Alabama Gas
                              Corporation


EXHIBIT 32

CERTIFICATION PURSUANT TO
18 U.S.C. 1350,
AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Report of Energen Corporation and Alabama Gas Corporation (the "Registrants") on Form 10-K for the period ended December 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each of the undersigned hereby certifies with respect to each registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of March 12, 2004

By /s/ Wm. Michael Warren, Jr.
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Wm. Michael Warren, Jr.
Chief Executive Officer

By /s/ G. C. Ketcham
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G. C. Ketcham
Chief Financial Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Energen Corporation and Alabama Gas Corporation and will be retained by Energen Corporation and Alabama Gas Corporation and furnished to the Securities and Exchange Commission or its staff upon request.