<PAGE>
                                  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, 2002

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


<TABLE>
<CAPTION>
  COMMISSION                                                    IRS EMPLOYER
     FILE                                    STATE OF         IDENTIFICATION
    NUMBER         REGISTRANT              INCORPORATION           NUMBER
  ----------   -------------------------- ------------------- ---------------
<S>            <C>                        <C>                 <C>
  1-7810       ENERGEN CORPORATION             ALABAMA           63-0757759
  2-38960      ALABAMA GAS CORPORATION         ALABAMA           63-0022000
</TABLE>

                    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:

<TABLE>
<CAPTION>
TITLE OF EACH CLASS                                        EXCHANGE ON WHICH REGISTERED
-------------------                                        ----------------------------
<S>                                                        <C>
Energen Corporation Common Stock, $0.01 par value          New York Stock Exchange
Energen Corporation Preferred Stock Purchase Rights        New York Stock Exchange
</TABLE>

             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. ( )

Aggregate market value of the voting stock held by non-affiliates of the
registrants as of June 30, 2002:

<TABLE>
<CAPTION>
<S>                                              <C>
Energen Corporation                              $931,042,350
</TABLE>

Indicate number of shares outstanding of each of the registrant's classes of
common stock as of March 5, 2003:

<TABLE>
<CAPTION>
<S>                                                <C>
Energen Corporation                                34,868,363 shares
Alabama Gas Corporation                             1,972,052 shares
</TABLE>

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 20,
2003 (Part III, Item 10-13)

<PAGE>

                                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
                           the 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 statigraphic 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 detectable 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.

<PAGE>

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 expected
RESERVES (PUD)             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-               Ratio expressing years of supply determined by
PRODUCTION 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.


<PAGE>



                               ENERGEN CORPORATION
                          2002 FORM 10-K ANNUAL REPORT

                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                                                   PAGE
                                                                                                   ----
<S>             <C>                                                                                <C>

                                                          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 Stock 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...........................28
Item 8.         Financial Statements and Supplementary Data..........................................29
Item 9.         Changes in and Disagreements with Accountants on Accounting and
                Financial Disclosure.................................................................73

                                                      PART III

Item 10.        Directors and Executive Officers of the Registrants..................................74
Item 11.        Executive Compensation...............................................................74
Item 12.        Security Ownership of Certain Beneficial Owners and Management.......................74
Item 13.        Certain Relationships and Related Transactions.......................................74

                                                       PART IV

Item 14.        Controls and Procedures..............................................................75
Item 15.        Exhibits, Financial Statement Schedules, and Reports on Form 8-K.....................75
Signatures      .....................................................................................79
Certifications  .....................................................................................81
</TABLE>



                                       2
<PAGE>


    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: 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 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; 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 is a Birmingham-based 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.

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


                                       3
<PAGE>

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 and 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.

FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS

The information required by this item is provided in Note 20, 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 production
         and all 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 2002, Energen Resources' inventory of proved oil and gas
         reserves totaled 1,262.9 billion cubic feet equivalent (Bcfe).
         Substantially all of the company's approximately 1.3 trillion cubic
         feet equivalent of reserves are located in the San Juan Basin in New
         Mexico, the Black Warrior Basin in Alabama, the Permian Basin in west
         Texas, and the north Louisiana/east Texas region. Approximately 82
         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 64 percent of Energen Resources' proved reserves, with
         oil representing approximately 24 percent and natural gas liquids
         comprising the balance.

         GROWTH STRATEGY: Energen has operated for more than seven years under a
         strategy to grow its oil and gas operations. Since the end of fiscal
         year 1995, Energen Resources has invested approximately $715 million in
         property acquisitions, $435 million in related development, and $90
         million in exploration and associated development. Energen Resources'
         capital investment for oil and gas activities over the five-year period
         ending December 31, 2007, is currently expected to approximate $835
         million.

         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 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 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

                                       4
<PAGE>

         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 1999, the Company's development efforts
         have added approximately 298 Bcfe of proved reserves from the drilling
         of approximately 540 gross development wells and 408 well recompletions
         and pay-adds. In 2002, Energen Resources' successful development wells
         and other activities added approximately 162 Bcfe of proved reserves.
         The company drilled 232 gross development wells, performed some 95 well
         recompletions and pay-adds, and conducted other operational
         enhancements. Energen Resources' production from continuing operations
         totaled 77.4 Bcfe in 2002 and is estimated to total 85 Bcfe in 2003,
         including 82.4 Bcfe of estimated production from proved reserves owned
         at December 31, 2002.

         Most of Energen Resources' coalbed methane production generated
         nonconventional fuels tax credits through December 31, 2002. In 2002,
         Energen Resources' nonconventional fuels tax credits totaled $14.2
         million. Nonconventional fuels tax credits are no longer generated due
         to tax law changes effective December 31, 2002. To mitigate the effects
         on corporate earnings in 2003, Energen Resources has replaced a portion
         of the tax credit benefit with long-term, revenue-generating property
         acquisitions and their related development activities and has increased
         the number of available drilling locations through unit downspacing in
         the Black Warrior Basin.

         RISK MANAGEMENT: Energen Resources attempts to lower the risk
         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 in its
         evaluation models the then-current oil and gas futures prices, 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 annual production in any given year depending on
         its pricing outlook.

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

         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. Also, to the extent that


                                       5
<PAGE>

         Energen Resources has operating agreements with various joint venture
         partners, environmental costs would be shared proportionately.

         OTHER: 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.


-        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 188 cities and communities in 28
         counties. The aggregate population of the counties served by Alagasco
         is estimated to be 2.3 million. Among the cities served by Alagasco are
         Birmingham, the center of the largest metropolitan area in Alabama, and
         Montgomery, the state capital. During 2002, Alagasco served an average
         of 425,630 residential customers and 35,601 commercial, industrial and
         transportation customers. The Alagasco distribution system includes
         approximately 9,723 miles of main and more than 11,395 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 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. 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 performs this real-time
         temperature adjustment calculation monthly, and the 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.


                                       6
<PAGE>

         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 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 and has firm
         transportation contracts with two major interstate pipeline systems -
         Southern Natural Gas Company (Southern) and Transcontinental Gas Pipe
         Line Corporation (Transco). On Southern's system, Alagasco has 251,679
         thousand cubic feet (Mcfd) of No-Notice Firm Transportation service
         through October 31, 2008, and 134,332 Mcfd of Firm Transporation
         service, of which 40,000 Mcfd expires April 30, 2005, 1,959 Mcfd
         expires October 31, 2005 and the balance expires October 31, 2008. The
         Transco Firm Transportation contract, which expires October 31, 2005,
         provides for up to 100,000 Mcfd. As a result, Alagasco has a peak day
         firm interstate pipeline transportation capacity of 486,011 Mcfd.
         Alagasco has 12,464,074 Mcf of storage capacity on Southern's system,
         with a maximum withdrawal rate of 251,679 Mcfd from storage and a
         maximum injection rate of 95,878 Mcfd to storage. Alagasco also
         operates two liquified natural gas (LNG) facilities used to meet peak
         demand.

         Alagasco purchases gas from various gas producers and marketers,
         including affiliates of Southern, and from certain intrastate producers
         and marketers. Alagasco has contracts in place to purchase up to
         233,230 Mcfd of firm supply, of which 234,332 Mcfd is supported by firm
         transportation on the Transco and Southern systems and approximately
         21,450 Mcfd is purchased at the city gate under intrastate firm supply
         contracts. These firm supply volumes along with Alagasco's maximum
         withdrawal from storage of 251,679 Mcfd and LNG peak-shaving capacity
         of 200,000 Mcfd, give Alagasco a peak day firm supply of 684,909 Mcfd.
         Alagasco also utilizes the Southern pipeline systems to access spot
         market gas in order to supplement its firm system supply and serve its
         industrial and large commercial transportation customers. Deliveries of
         sales and transportation gas totaled 97,840 million cubic feet in 2002.

         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
         customers' gas load in the deregulated marketplace. Rate flexibility
         remains critical as the utility faces competition for the large
         customer 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 2002, approximately 300 of Alagasco's transportation
         customers utilized the P Rate, and the resulting reduction in core
         market gas costs totaled approximately $9.1 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


                                       7
<PAGE>

         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 2002 substantially all of Alagasco's large
         commercial and industrial customer deliveries were the transportation
         of customer-owned gas. In addition, Alagasco served as 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 2002, 49 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 2002, Alagasco's average
         number of customers declined slightly due to the previous year's high
         gas costs and industrial load loss resulting from an economic slowdown.
         The utility penetrated 86 percent of the new single-family housing
         market in its service area and 18 percent of the new multi-family
         housing market. For 2003, 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.

         OTHER: 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 1,533 employees; Alagasco employs 1,259; Energen Resources
employs 261; and Energen's other subsidiaries employ 13. The Company believes
that its relations with employees are good.



                                       8
<PAGE>


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,
reserves and development is summarized in the table below and included in Note
19, Oil and Gas Operations (unaudited), in the Notes to Financial Statements
which is included in this Form 10-K.

<TABLE>
<CAPTION>
                                   YEAR ENDED
                               DECEMBER 31, 2002             DECEMBER 31, 2002
                               -----------------             -----------------
                               Production Volumes               Reserves
                                    (MMcfe)                      (MMcfe)
                               -----------------             -----------------
<S>                            <C>                           <C>
San Juan Basin                       27,133                       548,744
Permian Basin                        23,878                       357,455
Black Warrior Basin                  13,494                       257,662
North Louisiana/East Texas           11,376                        82,086
Other                                 2,092                        16,981
                                     ------                     ---------
Total                                77,973                     1,262,928
                                     ======                     =========
</TABLE>

The properties of Alagasco consist primarily of its gas distribution system,
which includes more than 9,723 miles of main, more than 11,395 miles of service
lines, odorization and regulation facilities, and customer meters. Alagasco also
has two LNG facilities, seven division offices, four payment centers, five
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 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 2002.


                                       9
<PAGE>


EXECUTIVE OFFICERS OF THE REGISTRANTS

ENERGEN CORPORATION

<TABLE>
<CAPTION>
Name                         Age    Position (1)
----                         ---    ------------
<S>                          <C>    <C>

Wm. Michael Warren, Jr.      55     Chairman of the Board
                                    President and Chief Executive Officer (2)

Geoffrey C. Ketcham          52     Executive Vice President, Chief Financial Officer
                                    and Treasurer (3)

James T. McManus             44     President and Chief Operating Officer of Energen
                                    Resources (4)

Dudley C. Reynolds           50     President and Chief Operating Officer of Alagasco
                                    (5)

Grace B. Carr                47     Vice President and Controller (6)

J. David Woodruff, Jr.       46     General Counsel and Secretary and Vice
                                    President-Corporate Development (7)
</TABLE>


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 as 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 as 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.

                                       10
<PAGE>

PART II

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

QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE

<TABLE>
<CAPTION>
Quarter ended (in dollars)    HIGH         LOW        CLOSE      DIVIDENDS PAID
--------------------------    ----         ---        -----      --------------
<S>                          <C>        <C>         <C>         <C>

December 31, 1999            21.25        15.75       18.06           .165
March 31, 2000               18.94        14.69       15.94           .165
June 30, 2000                23.69        16.00       21.81           .165
September 30, 2000           30.38        21.00       29.75           .170
                           -------       ------      ------          -----
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
                           -------       ------      ------          -----
</TABLE>

Energen's common stock is listed on the New York Stock Exchange under the symbol
EGN. On February 14, 2003, there were approximately 7,930 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:

<TABLE>
<CAPTION>
                                                                                    Number of Securities Remaining
                                        Number of Securities to       Weighted       Available for Future Issuance
                                        be Issued Upon Exercise        Average      Under Equity Compensation Plans
            Plan Category                of Outstanding Options    Exercise Price
            -------------                ----------------------    --------------   -------------------------------
<S>                                    <C>                         <C>              <C>
Equity compensation plans
     approved by security holders               621,007                $20.38                  2,326,897
Equity compensation plans not
     approved by security holders                    --                    --                         --
                                                -------                ------                  ---------
Total                                           621,007                $20.38                  2,326,897
                                                =======                ======                  =========
</TABLE>



                                       11
<PAGE>


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

<TABLE>
<CAPTION>
                                             Three Months
                               YEAR ENDED        Ended        Year Ended    Year Ended    Year Ended     Year Ended   Year Ended
(dollars in thousands,        DECEMBER 31,   December 31,   September 30, September 30,  September 30,  September 30, September 30,
except per share amounts)         2002           2001*           2001          2000           1999          1998          1997
                              ------------  -------------    ------------ -------------  -------------  ------------- -------------
<S>                           <C>            <C>            <C>           <C>            <C>            <C>           <C>
INCOME STATEMENT
Operating revenues            $  677,175     $  146,164      $  777,374     $  551,409      $  492,942      $498,398     $446,684
Income from continuing
  operations before
  cumulative effect of
  change in accounting
  principle                   $   70,586     $    3,579      $   66,087     $   52,535      $   41,453      $ 35,828     $ 28,736
Net income                    $   68,639     $    3,658      $   67,896     $   53,018      $   41,410      $ 36,249     $ 28,997
Diluted earnings
  per average
  common share from
  continuing operations
  before cumulative
  effect of change in
  accounting principle        $     2.09     $     0.12           $2.13     $     1.73      $     1.38      $   1.22     $   1.13
Diluted earnings
  per average
  common share                $     2.03     $     0.12           $2.18     $     1.75      $     1.38      $   1.23     $   1.14
                              ----------    -----------      ----------     ----------      ----------      --------     --------
BALANCE SHEET
  Capitalization at
     year-end:
     Common shareholders'
       equity                 $  582,810     $  474,205      $  480,767     $  400,860      $  361,504      $329,249     $301,143
     Long-term debt              512,954        544,133         544,110        353,932         371,824       372,782      279,602
                              ----------    -----------      ----------     ----------      ----------      --------     --------
     Total capitalization     $1,095,764     $1,018,338      $1,024,877     $  754,792      $  733,328      $702,031     $580,745
                              ----------    -----------      ----------     ----------      ----------      --------     --------
Total assets                  $1,530,891     $1,240,356      $1,223,879     $1,203,041      $1,184,895      $993,455     $919,797
                              ----------    -----------      ----------     ----------      ----------      --------     --------
Property, plant and
  equipment, net              $1,256,803     $1,005,679      $  998,334     $  907,829      $  861,107      $756,344     $667,003
                              ==========     ==========      ==========     ==========      ==========      ========     ========
COMMON STOCK DATA
Annual dividend rate at
   period-end                 $     0.72     $     0.70      $     0.70     $     0.68      $     0.66      $   0.64     $   0.62
Cash dividends paid per
  common share                $     0.71     $    0.175      $    0.685     $    0.665      $    0.645      $  0.625     $  0.605
Book value per common share   $    16.77     $    15.18      $    15.45     $    13.21      $    12.09      $  11.23     $  10.46
Market-to-book ratio at
  period-end (%)                     174            162             145            225             167           169          170
Yield at period-end (%)              2.5            2.8             3.1            2.3             3.3           3.4          3.5
Return on average common
  equity excluding other
  comprehensive
  income(%)**                       12.4           12.6            15.3           13.7            11.7          11.1         11.9
Return on average common
  equity (%)                        12.4           13.0            15.8           13.7            11.7          11.1         11.9
Price-to-earnings
  (diluted) ratio at
  period-end                        14.3             --            10.3           17.0            14.7          15.4         15.6
Shares outstanding at
  period-end (000)                34,745         31,249          31,125         30,351          29,904        29,327       28,796
Price Range:
     High                     $    29.99     $    25.20      $    40.25     $    30.38      $    20.38      $  22.50     $  18.88
     Low                      $    21.65     $    21.50      $    21.50     $    14.69      $    13.13      $  15.13     $  11.88
     Close                    $    29.10     $    24.65      $    22.50     $    29.75      $    20.25      $  19.00     $  17.78
</TABLE>


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.

**The comparable generally accepted accounting principle measure is return on
average common equity.


                                       12
<PAGE>




SELECTED BUSINESS SEGMENT DATA
Energen Corporation

<TABLE>
<CAPTION>
                                                        Three Months
                                          YEAR ENDED       Ended           Year Ended
                                         DECEMBER 31,   December 31,      September 30,
 (dollars in thousands)                     2002            2001*             2001
                                         ------------   ------------      -------------
<S>                                      <C>            <C>              <C>
OIL AND GAS OPERATIONS
Operating revenues from
continuing operations
     Natural gas                          $150,899         $35,324          $141,505
     Oil                                    75,426          12,375            48,016
     Natural gas liquids                    22,849           4,533            26,011
     Other                                   3,570          (2,746)            7,980
                                          --------         -------          --------
       Total                              $252,744         $49,486          $223,512
                                          --------         -------          --------
Production volumes from continuing
  operations
     Natural gas (MMcf)                     47,776          11,886            45,847
     Oil (MBbl)                              3,139             512             2,019
     Natural gas liquids (MBbl)              1,792             450             1,477
                                          --------         -------          --------
Production volumes from continuing
  operations (MMcfe)                        77,360          17,656            66,823
                                          --------         -------          --------
Total production volumes (MMcfe)            77,973          18,022            68,478
                                          --------         -------          --------
Proved reserves
     Natural gas (MMcf)                    803,748         714,395           627,051
     Oil (MBbl)                             49,833          19,128            20,878
     Natural gas liquids (MBbl)             26,697          25,944            24,931
                                          --------         -------          --------
Other data from continuing operations
     Depreciation and amortization        $ 71,405         $16,351          $ 53,846
     Capital expenditures                 $305,476         $25,052          $136,886
     Operating income                     $ 78,416         $ 3,243          $ 72,425
                                          --------         -------          --------
NATURAL GAS DISTRIBUTION
Operating revenues
     Residential                          $277,088         $63,724          $367,109
     Commercial and industrial-small       104,247          22,445           147,636
     Transportation                         38,395           9,765            33,972
     Other                                   4,701             744             5,145
                                          --------         -------          --------
        Total                             $424,431         $96,678          $553,862
                                          --------         -------          --------
Gas delivery volumes (MMcf)
     Residential                            26,358           5,128            31,064
     Commercial and industrial-small        11,838           2,193            14,054
     Transportation                         59,644          12,973            53,989
                                          --------         -------          --------
        Total                               97,840          20,294            99,107
                                          --------         -------          --------
Average number of customers
     Residential                           425,630         422,461           428,663
     Commercial, industrial and
       transportation                       35,601          35,161            35,882
                                          --------         -------          --------
        Total                              461,231         457,622           464,545
                                          --------         -------          --------
Other data
     Depreciation and amortization        $ 33,682         $ 8,151          $ 30,933
     Capital expenditures                 $ 65,815         $12,873          $ 56,090
     Operating income                     $ 59,370         $ 8,034          $ 50,288
                                          --------         -------          --------

<CAPTION>
                                        Year Ended      Year Ended     Year Ended     Year Ended
                                      September 30,   September 30,   September 30,  September 30,
 (dollars in thousands)                    2000           1999             1998         1997
                                      -------------   -------------   -------------  -------------
<S>                                   <C>             <C>             <C>            <C>
OIL AND GAS OPERATIONS
Operating revenues from
continuing operations
     Natural gas                          $118,271        $116,555       $93,958       $59,474
     Oil                                    39,220          35,207        20,472        13,199
     Natural gas liquids                    22,662           7,207         6,977         5,762
     Other                                   5,095           8,419         7,051         5,265
                                          --------        --------      --------      --------
       Total                              $185,248        $167,388      $128,458       $83,700
                                          --------        --------      --------      --------
Production volumes from continuing
  operations
     Natural gas (MMcf)                     47,441          52,754        42,432        28,995
     Oil (MBbl)                              2,140           2,937         1,378           734
     Natural gas liquids (MBbl)              1,411             757           817           502
                                          --------        --------      --------      --------
Production volumes from continuing
  operations (MMcfe)                        68,756          74,919        55,599        36,412
                                          --------        --------      --------      --------
Total production volumes (MMcfe)            70,482          77,159        57,353        36,980
                                          --------        --------      --------      --------
Proved reserves
     Natural gas (MMcf)                    777,456         740,001       542,039       544,283
     Oil (MBbl)                             24,518          24,719        19,845         9,128
     Natural gas liquids (MBbl)             26,007          21,937        17,292        12,378
                                          --------        --------      --------      --------
Other data from continuing operations
     Depreciation and amortization        $ 56,226        $ 59,322      $ 54,192      $ 35,729
     Capital expenditures                 $ 67,090        $198,577      $120,991      $239,718
     Operating income                     $ 47,568        $ 31,089      $ 20,299      $ 14,295
                                          --------        --------      --------      --------
NATURAL GAS DISTRIBUTION
Operating revenues
     Residential                          $233,839        $209,263      $241,964      $237,022
     Commercial and industrial-small        88,521          77,254        89,361        87,477
     Transportation                         35,312          34,541        35,246        33,080
     Other                                   8,489           4,496         3,369         5,405
                                          --------        --------      --------      --------
        Total                             $366,161        $325,554      $369,940      $362,984
                                          --------        --------      --------      --------
Gas delivery volumes (MMcf)
     Residential                            26,069          24,751        31,079        28,357
     Commercial and industrial-small        12,092          11,662        13,705        12,554
     Transportation                         70,534          66,356        70,563        65,622
                                          --------        --------      --------      --------
        Total                              108,695         102,769       115,347       106,533
                                          --------        --------      --------      --------
Average number of customers
     Residential                           429,368         425,937       423,602       422,878
     Commercial, industrial and
       transportation                       35,526          35,111        34,782        34,485
                                          --------        --------      --------      --------
        Total                              464,894         461,048       458,384       457,363
                                          --------        --------      --------      --------
Other data
     Depreciation and amortization         $28,708         $26,730       $25,153       $23,486
     Capital expenditures                  $67,073         $46,029       $54,168       $43,277
     Operating income                      $49,063         $46,565       $41,663       $38,792
                                          --------        --------      --------      --------
</TABLE>


                                       13
<PAGE>



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 judgements 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.

Estimates of physical quantities of oil and gas reserves are determined by
Company engineers and, in some cases, by third-party experts. 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. The
Company's production of undeveloped reserves require 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 will 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 expenses or due to an immediate writedown of the
property's book value if an impairment is warranted. The table below reflects
the estimated effect on depreciation and depletion expense for 2003 of changes
in oil and gas reserve quantities from the reported amounts at December 31,
2002.

<TABLE>
<CAPTION>
                                                           Percentage Change in Oil & Gas Reserves
                                                        From Reported Reserves as of December 31, 2002
(dollars in thousands)                                +10%           +5%            -5%            -10%
                                                     -------        -------        -------         -------
<S>                                                  <C>            <C>            <C>             <C>
Estimated change in depreciation expense for
the year ended December 31, 2003, net of tax         $(4,300)       $(2,100)       $ 2,400         $ 5,200
                                                     -------        -------        -------         -------
</TABLE>

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 from the
properties. 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.

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


                                       14
<PAGE>

impact on the Company's need for impairment or of 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.

NATURAL GAS DISTRIBUTION
REGULATED OPERATIONS: Alagasco applies 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 BENEFIT PLANS: Determining the Company's obligations to employees under
its defined benefit pension plan requires the use of estimates. The calculation
of the liability related to the Company's defined benefit pension plan 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. At December 31, 2002 the discount rate used for actuarial
purposes was 6.75 percent. A hypothetical 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. At December 31, 2002, the return on assets used for actuarial
purposes was 9 percent. A hypothetical 25 basis point change in the return on
assets would impact total pension expense by approximately $245,000.

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

RESULTS OF OPERATIONS

CONSOLIDATED NET INCOME
Energen Corporation's net income for the year ended December 31, 2002 totaled
$68.6 million, or $2.03 per diluted share compared to fiscal year ended
September 30, 2001 net income of $67.9 million, or $2.18 per diluted share. This
7 percent decrease in earnings per diluted share (EPS) reflects an increase in
the number of shares outstanding related to the acquisition of oil and gas
properties in the Permian Basin in April 2002. Energen Resources Corporation,
Energen's oil and gas subsidiary, had a slight decrease in earnings for the 12
months ended December 31, 2002, as compared with the 12 months ended September
30, 2001. Alabama Gas Corporation (Alagasco), Energen's utility subsidiary,
generated a 6 percent increase in net income in the same period comparisons. For
the 12 months ended September 30, 2000, Energen reported earnings of $53
million, or $1.75 per diluted share.

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 the current year included a non-cash
benefit of $5.7 million after-tax ($0.17 per diluted share) associated with its
previous hedge position with Enron North America Corp. (Enron) and a one-time
charge of $2.2 million after-tax ($0.07 per diluted share), reflecting the
cumulative effect on prior years of the adoption of SFAS No. 143, "Accounting
for Asset Retirement Obligations." Energen Resources' income from continuing
operations in 2002 totaled $43.2 million as compared with $40.8 million in
fiscal 2001, primarily due to a 15.8 percent increase in production volumes
related to an acquisition of oil properties in the Permian Basin in April 2002.
The primary negative influences on income from


                                       15
<PAGE>

operations were increased lease operating expense and increased depreciation,
depletion and amortization (DD&A) expense.

Alagasco's earnings increased to $27.6 million in 2002 from $26 million in
fiscal year 2001 as a result of the utility having increased earnings on a
higher level of equity. Alagasco achieved a return on average equity (ROE) of
12.3 percent in both 2002 and 2001.

2001 VS 2000: Energen Resources' net income in fiscal 2001 rose 55.2 percent to
$42.6 million. Energen Resources' income from continuing operations in fiscal
2001 totaled $40.8 million as compared with $26.9 million in fiscal 2000,
primarily due to a 23.3 percent increase in realized sales prices for natural
gas, oil and natural gas liquids production. The significantly higher realized
commodity prices more than compensated for the negative impact of increased
lease operating expense and a 1.9 Bcfe production decrease. Earnings in fiscal
year 2000 were negatively affected by a $2.2 million ($0.07 per diluted share)
after-tax writedown under SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of," for certain oil
and gas properties resulting from a downward reserve revision.

Alagasco's earnings declined 1.2 percent from $26.3 million in fiscal 2000 to
$26 million in fiscal year 2001. This slight decrease in income was primarily a
result of increased bad debt expense from significantly colder weather and
higher natural gas prices during the fiscal 2001 winter as well as industrial
load loss resulting from an economic slowdown. Alagasco achieved a return on
average equity (ROE) of 12.3 percent in 2001 as compared to 13.4 percent in
2000.

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 net income from continuing operations of $1.1 million in the December
31, 2001 transition quarter as compared with $9.3 million in the same quarter in
the previous year largely due to a one-time 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 the transition quarter were
increased DD&A expense, a $1.7 million writedown on property held for sale and
lower natural gas liquids prices. 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 2002, 2001 and 2000 totaled $136 million, $121
million and $95 million, respectively. This significant growth in operating
income was 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 an
increase in the level 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 production volumes related
to the acquisition of oil properties in the Permian Basin. During 2002,
production from continuing operations increased 15.8 percent to 77.4 Bcfe.
Natural gas production increased 4.2 percent to 47.8 Bcf and oil volumes rose
55.5 percent to 3,139 MBbl. Production of natural gas liquids increased 21.3
percent to 1,792 MBbl. Including the non-cash benefit from the former Enron
hedges, realized gas prices rose 2.3 percent to $3.16 per Mcf, while realized
oil prices increased 1.1 percent to $24.03 per barrel. Natural gas liquids
prices fell 27.6 percent to an average price of $12.75 per barrel.

In fiscal 2001, revenues from oil and gas continuing operations increased
largely as a result of significantly higher commodity prices as compared to the
previous fiscal year. Realized gas prices rose 24.1 percent to $3.09 per Mcf,
while realized oil prices increased 29.7 percent to $23.78 per barrel. Natural
gas liquids prices increased 9.7 percent to an average price of $17.61 per
barrel. During 2001, production from continuing operations declined slightly to
66.8 Bcfe as natural gas production decreased 3.4 percent to 45.8 Bcf and oil
volumes declined 5.7 percent to 2,019 MBbl. Production of natural gas liquids
increased 4.7 percent to 1,477 MBbl. This 1.9 Bcfe


                                       16
<PAGE>

decrease in production largely was due to normal production declines in Energen
Resources' coalbed methane and south Louisiana properties. Drilling in the San
Juan and Permian basins and in the north Louisiana/east Texas area served to
replace aggregate production in these areas.

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 $4.8 million, $7.6 million and $4.3 million in
2002, 2001 and 2000, respectively.

<TABLE>
<CAPTION>
                                                                      DECEMBER 31,    September 30,     September 30,
Years ended (in thousands, except sales price data)                      2002             2001              2000
                                                                      ------------    -------------     -------------
<S>                                                                   <C>             <C>               <C>
Revenues from continuing operations
    Natural gas production                                            $ 150,899        $ 141,505         $ 118,271
    Oil production                                                       75,426           48,016            39,220
    Natural gas liquids production                                       22,849           26,011            22,662
    Operating fees                                                        4,847            7,618             4,262
    Other                                                                (1,277)             362               833
                                                                       --------         --------          --------
Total revenues from continuing operations                             $ 252,744        $ 223,512         $ 185,248
                                                                       --------         --------          --------
Production volumes from continuing operations
    Natural gas (MMcf)                                                   47,776           45,847            47,441
    Oil (MBbl)                                                            3,139            2,019             2,140
    Natural gas liquids (MBbl)                                            1,792            1,477             1,411
                                                                       --------         --------          --------
Average sales price including effects of hedging
    Natural gas (per Mcf)                                              $   3.16         $   3.09          $   2.49
    Oil (per barrel)                                                   $  24.03         $  23.78          $  18.33
    Natural gas liquids (per barrel)                                   $  12.75         $  17.61          $  16.06
                                                                       --------         --------          --------
Average sales price excluding effects of hedging
    Natural gas (per Mcf)                                              $   2.96         $   4.86          $   3.06
    Oil (per barrel)                                                   $  24.75         $  27.46          $  26.45
    Natural gas liquids (per barrel)                                   $  12.75         $  17.61          $  16.06
                                                                       --------         --------          --------
</TABLE>

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, which was adopted as of January 1, 2002. 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. Pre-tax gains from the sale of properties of $1.1
million were recorded in operating revenues in 2000.

Operations and maintenance (O&M) expense increased $10.3 million and $9.9
million in 2002 and 2001, respectively. Lease operating expense in 2002 rose
$7.6 million primarily due to the acquisition of oil and gas properties. In
2001, lease operating expense increased by $9.2 million largely due to
significantly higher operational costs driven by market conditions resulting
from increased commodity costs. In the current year, administrative expense
increased $3.5 million primarily due to labor related costs and additional cost
related to the property acquisition. Administrative expense increased $1.4
million in 2001. Exploration expense decreased $0.6 million in 2002 and $0.7
million in 2001, primarily due to reduced exploratory efforts.

DD&A expense increased $17.6 million in 2002 largely due to increased production
volumes and increased DD&A rates. In 2001, DD&A expense decreased $2.4 million
primarily due to lower production volumes and additional pre-tax DD&A expense of
$3.5 million recorded in 2000 to adjust the carrying amount of certain
properties to their


                                       17
<PAGE>

fair value based on expected future discounted cash flows (see Note 12). The
average depletion rate was $0.90 per Mcfe in 2002 as compared to $0.79 per Mcfe
in the prior year.

Energen Resources' expense for taxes other than income primarily reflected
production-related taxes. Energen Resources recorded severance taxes for 2002 of
$18.9 million. Severance taxes in 2001 were $23.9 million as a result of
increased commodity prices. In 2000, severance taxes were $17.3 million.

OIL AND GAS OPERATIONS - TRANSITION PERIOD: Revenues from oil and gas continuing
operations declined 9.8 percent to $49.5 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 8.4 percent to $2.97 per
Mcf, while realized oil prices rose 7.8 percent to $24.19 per barrel. Natural
gas liquids prices decreased 51.4 percent to an average price of $10.07 per
barrel.

Natural gas production in the transition quarter increased slightly to 11.9 Bcf,
while oil volumes decreased slightly to 512 MBbl. Natural gas liquids production
increased 13.9 percent to 450 MBbl. Natural gas comprised nearly 70 percent of
Energen Resources' production in the transition quarter.

<TABLE>
<CAPTION>
                                                                  DECEMBER 31,      December 31,
Three months ended (in thousands, except sales price data)            2001             2000
                                                                  ------------      ------------
<S>                                                               <C>               <C>
Revenues from continuing operations
    Natural gas production                                          $ 35,324           $32,316
    Oil production                                                    12,375            11,586
    Natural gas liquids production                                     4,533             8,180
    Operating fees                                                       913             2,225
    Other                                                             (3,659)              555
                                                                    --------           -------
Total revenues from continuing operations                           $ 49,486           $54,862
                                                                    --------           -------
Production volumes from continuing operations
    Natural gas (MMcf)                                                11,886            11,796
    Oil (MBbl)                                                           512               516
    Natural gas liquids (MBbl)                                           450               395
                                                                    --------           -------
Average sales price including effects of hedging
    Natural gas (per Mcf)                                           $   2.97           $  2.74
    Oil (per barrel)                                                $  24.19           $ 22.45
    Natural gas liquids (per barrel)                                $  10.07           $ 20.70
                                                                    --------           -------
Average sales price excluding effects of hedging
    Natural gas (per Mcf)                                           $   2.35           $  5.15
    Oil (per barrel)                                                $  19.79           $ 30.65
    Natural gas liquids (per barrel)                                $  10.07           $ 20.70
                                                                    --------           -------
</TABLE>

Prior to the adoption of SFAS No. 144, Energen Resources recorded in operating
revenues a pre-tax loss of $3.4 million for the current 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 $8.6 million for the transition quarter ended December 31,
2001, largely due to the one-time non-cash writedown of $8.7 million pre-tax
associated with Energen Resources' hedge position with Enron. Lease operating
expenses increased by $0.4 million for the transition quarter while exploration
expense remained relatively stable.

Energen Resources' DD&A expense for the period rose $4.5 million primarily
driven by the impact of market declines in commodity prices. The average
depletion rate for the transition quarter was $0.91 as compared to $0.67 for the
same period in the previous year.


                                       18
<PAGE>


Energen Resources' expense for taxes other than income taxes primarily reflected
production-related taxes that were $3.3 million lower in the transition quarter
primarily 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 Company'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 real-time temperature adjustment
mechanism that allows Alagasco to adjust customer bills monthly to reflect
changes in usage due to departures from normal temperatures. The temperature
adjustment applies to residential, small commercial and small industrial
customers.

Alagasco's natural gas and transportation sales revenues totaled $424.4 million,
$553.9 million and $366.2 million in 2002, 2001 and 2000, respectively. 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 the current year. Sales
revenue in fiscal 2001 rose due to significantly higher commodity gas costs as
well as weather that was 29.9 percent colder than in fiscal year 2000.

In the current year, residential sales volumes decreased 15.1 percent 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. During
2001, significantly colder weather in Alagasco's service territory caused a 19.2
percent increase in residential sales volumes and a 16.2 percent increase in
small commercial and industrial sales volumes. Transportation volumes decreased
23.5 percent, primarily due to the prior-year closing of a steel manufacturing
plant and reduced consumption resulting from an economic downturn during the
year.

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. Higher commodity cost of gas, including record high prices in fiscal year
2001, along with increased purchased volumes resulting from colder weather
generated a 111.5 percent increase in cost of gas for fiscal year 2001.

O&M expense at the utility increased 3.1 percent in 2002 primarily due to higher
insurance and labor-related costs partially offset by reduced bad debt expense
and marketing costs. In fiscal 2001, O&M expense increased 1.5 percent primarily
as a result of increased bad debt expense and insurance costs largely offset by
reduced marketing and labor-related costs. The increase in O&M expense per
customer was above the inflation-based Cost Control Measurement (CCM)
established by the APSC as part of the utility's rate-setting mechanism, for the
rate year ended September 30, 2002; as a result, three quarters of the
difference, or $0.3 million pre-tax, was returned to the customers through RSE
(see Note 2). In 2001 and 2000, the increase in O&M expense on a per-customer
basis fell within the CCM.

Consistent with growth in the utility's depreciable base, depreciation expense
rose 8.9 percent in 2002 and 7.8 percent in 2001. 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.


                                       19
<PAGE>


<TABLE>
<CAPTION>
                                                  DECEMBER 31,       September 30,       September 30,
Years ended (in thousands)                            2002                2001                2000
                                                  ------------       -------------       -------------
<S>                                               <C>                <C>                 <C>
Natural gas transportation and sales revenues      $ 424,431           $ 553,862           $ 366,161
Cost of natural gas                                 (191,479)           (329,572)           (155,841)
Revenue taxes                                        (21,591)            (28,766)            (19,749)
                                                   ---------           ---------           ---------
Natural gas transportation and sales margin        $ 211,361           $ 195,524           $ 190,571
                                                   ---------           ---------           ---------
Natural gas sales volumes (MMcf)
    Residential                                       26,358              31,064              26,069
    Commercial and industrial-small                   11,838              14,054              12,092
                                                   ---------           ---------           ---------
Total natural gas sales volumes                       38,196              45,118              38,161
Natural gas transportation volumes (MMcf)             59,644              53,989              70,534
                                                   ---------           ---------           ---------
Total deliveries (MMcf)                               97,840              99,107             108,695
                                                   ---------           ---------           ---------
</TABLE>

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 quarter, weather
that was 30.1 percent warmer than the same period last 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.

<TABLE>
<CAPTION>
                                                    DECEMBER 31,       December 31,
Three months ended (in thousands)                       2001               2000
                                                    ------------       ------------
<S>                                                 <C>                <C>
Natural gas transportation and sales revenues         $ 96,678           $ 119,126
Cost of natural gas                                    (45,651)            (67,679)
Revenue taxes                                           (4,969)             (6,281)
                                                      --------           ---------
Natural gas transportation and sales margin           $ 46,058           $  45,166
                                                      --------           ---------
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
                                                      --------           ---------
</TABLE>

NON-OPERATING ITEMS
CONSOLIDATED: Interest expense in 2002 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). Fiscal 2001 interest expense increased $4.3 million primarily
due to $150 million of medium term notes (MTNs) issued by Energen in December
2000 and, in part, from the issuance of the Notes. The average daily outstanding
balance under short-term credit facilities was $85.6 million in 2002. The
average daily outstanding balance under short-term credit facilities was $80.7
million in fiscal year 2001 as compared to $146.8 million in fiscal year 2000.

The Company's effective tax rates in 2002, 2001 and 2000 were lower than
statutory federal tax rates primarily due to the recognition of nonconventional
fuels tax credits and the amortization of investment tax credits.
Nonconventional fuels tax credits were generated annually on qualified
production through December 31, 2002.


                                       20
<PAGE>

Income tax expense increased in 2002 and 2001 primarily due to higher pre-tax
income. The Company recognized $14.2 million, $13.6 million and $14.4 million in
nonconventional fuels tax credits in 2002, 2001 and 2000, respectively. The
nonconventional fuels tax credits are no longer generated effective December 31,
2002, due to changes in the tax law. As of December 31, 2002, the amount of
minimum tax credit that has been previously recognized and can be carried
forward indefinitely to reduce future regular tax liability is $64.8 million.

TRANSITION PERIOD: Interest expense for the Company increased $0.4 million for
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 and the
amortization of investment 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 in the current
quarter. The effective tax rate utilized in computing income tax expense
reflects financial recognition of $3.5 million of nonconventional fuels tax
credits as produced during the transitional quarter.

FINANCIAL POSITION AND LIQUIDITY
The Company's net cash from operating activities totaled $213.5 million, $156.5
million and $105 million in 2002, 2001 and 2000, respectively. In 2002,
operating cash flow benefited from significantly higher production volumes
related to Energen Resources' property acquisition and decreased storage
inventory balances at Alagasco. Operating cash flow in 2001 benefited from
significantly higher realized commodity prices at Energen Resources. Working
capital needs at Alagasco in 2001 were affected by increased gas costs and
colder-than-normal weather resulting in higher storage inventory balances. 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 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 incurring
approximately $77 million. Energen Resources sold or traded certain properties
during the current year, resulting in cash proceeds of $17 million. Utility
expenditures in 2002 totaled $65.8 million and primarily represented system
distribution expansion and support facilities, including, information technology
application projects. Cash used in investing activities totaled $174.4 million
in 2001. During fiscal 2001, Energen Resources invested $34.3 million for
property acquisitions, $103.6 million for development of proved properties and
$1.2 million for exploration. Energen Resources drilled 140 gross development
wells spending approximately $70 million. Energen Resources sold or traded
certain properties during fiscal 2001, resulting in cash proceeds of $17.3
million. Utility expenditures for fiscal 2001 totaled $56.1 million, including
approximately $3 million for a municipal acquisition. Cash used in investing
activities totaled $131.7 million in 2000. Energen Resources invested $2.4
million for property acquisitions, $66.7 million for development and $1.2
million for exploration during fiscal 2000. Energen Resources drilled 141 gross
development wells incurring approximately $38 million. Utility expenditures in
2000 totaled $67.1 million.

During 2002, the Company added approximately 162 Bcfe of reserves. These reserve
additions are primarily the result of unit downspacing, which increases the
number of available drilling locations, for certain wells in the Black Warrior
and San Juan basins. Energen Resources' added approximately 50 Bcfe and 76 Bcfe
of reserves in fiscal year 2001 and 2000, respectively.


                                       21
<PAGE>
Net cash provided by financing activities totaled $53 million in 2002. In the
current year, 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, and 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. Net cash used in financing activities totaled $114.9 million
in 2000 resulting primarily from fluctuations in the amount and timing of
short-term debt at year-end. The Company borrowed $140.9 million at September
30, 1999 to invest in short-term federal obligations for tax planning purposes
that were sold in early October 2000 with the proceeds used to repay the
related debt. 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 and 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.

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 $546.6 million for capital
projects during the year ended December 31, 2002, the three months ended
December 31, 2001 and the years ended September 30, 2001 and 2000, $12.1
million of which was charged to income as exploration expense primarily due to
the writedown of a portion of an unproved leasehold. Property acquisition
expenditures totaled $221.2 million, development activities totaled $317.5
million, and exploratory expenditures totaled $2.7 million.

<TABLE>
<CAPTION>
                                                                  Three Months
                                                  YEAR ENDED          Ended          Year Ended        Year Ended
                                                 DECEMBER 31,      December 31,     September 30,     September 30,
(in thousands)                                      2002              2001              2001              2000
                                                 ------------     -------------     -------------     -------------

<S>                                              <C>              <C>               <C>               <C>
Capital and exploration expenditures for:
    Property acquisitions                          $184,177          $   319          $ 34,316          $ 2,436
    Development                                     122,494           24,757           103,574           66,717
    Exploration                                         104              228             1,190            1,150
    Other                                             1,880              464             1,477            1,343
                                                   --------          -------          --------          -------
      Total                                         308,655           25,768           140,557           71,646
Less exploration expenditures charged
  to income                                           3,179              716             3,671            4,556
                                                   --------          -------          --------          -------
Net capital expenditures                           $305,476          $25,052          $136,886          $67,090
                                                   ========          =======          ========          =======
</TABLE>


                                      22
<PAGE>
NATURAL GAS DISTRIBUTION: During the year ended December 31, 2002, the three
months ended December 31, 2001 and the years ended September 30, 2001 and 2000,
Alagasco invested $201.9 million for capital projects: $124 million for normal
expansion, replacements and support of its distribution system, $74.9 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.

<TABLE>
<CAPTION>
                                                            Three Months
                                             YEAR ENDED        Ended           Year Ended      Year Ended
                                            DECEMBER 31,    December 31,     September 30,    September 30,
(in thousands)                                 2002            2001              2001             2000
                                            ------------    ------------     -------------    -------------

<S>                                         <C>             <C>              <C>              <C>
Capital and expenditures for:
    Renewals, replacements,
      system expansion and other              $43,029          $ 8,839          $36,340          $35,774
    Support facilities                         22,786            4,034           16,733           31,299
    Municipal gas system acquisition               --               --            3,017               --
                                              -------          -------          -------          -------
      Total                                   $65,815          $12,873          $56,090          $67,073
                                              =======          =======          =======          =======
</TABLE>

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, 2002, Energen's EPS grew at an average
compound rate of 11.5 percent a year. Over the next five years, Energen is
targeting an average EPS growth rate over each rolling five-year period of 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, with long-term debt and equity providing 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. In February
2003, Moody's Investors Service confirmed Energen's debt rating as Baa1 and
Alagasco's debt rating as A1. Standard and Poor's last update in June 2002,
confirmed Energen's and Alagasco's rating as A- with a stable outlook. While
the Company expects to have ongoing access to it's 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
increases in cash flows to help finance Energen Resources' acquisition
strategy.

In 2003, Energen Resources plans to invest approximately $158 million,
including $47 million in property acquisitions and related development and $111
million in other development and exploratory activities. Included in this $111
million is approximately $65 million for the development of previously
identified proved undeveloped reserves and exploratory exposure of
approximately $3 million. Capital investment at Energen Resources in 2004 is
expected to approximate $123 million for property acquisitions and related
development and $68 million for other development and exploration. Of this $68
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, 2007 is estimated to be approximately
$835 million, with $590 million for property acquisitions and related
development, $222 million for other development and $23 million for exploratory
and other activities. During the five year period, Energen Resources
anticipates spending approximately $120 million on development of previously
identified proved undeveloped reserves and incurring approximately $15 million
in exploratory exposure. During this period, the Company expects to issue
approximately $75 million in long-term debt and an estimated $25 million in
equity to replace short-term obligations and to provide permanent financing for
its acquisition strategy. The Company will also provide up to $14 million a
year from the issuance of common stock through the dividend reinvestment and
direct stock purchase plan, and through employee savings plans. 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


                                      23
<PAGE>
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 strategy. These
acquisitions may alter the aforementioned financing requirements. Additionally,
Energen Resources may enter into negotiations to sell, trade or otherwise
dispose of properties which may reduce or eliminate the amount of additional
financing described above.

During 2003, Alagasco plans to invest approximately $57 million in utility
capital expenditures for normal distribution and support systems. Alagasco
maintains an investment in storage gas that is expected to average
approximately $42 million in 2003. Alagasco plans to invest approximately $55
million in utility capital expenditures during 2004. 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 September 30, 2007, Alagasco anticipates capital
investments of approximately $265 million.

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, 2002.

<TABLE>
<CAPTION>
                                                                      PAYMENTS DUE BY PERIOD
                                            ------------------------------------------------------------------------
                                                            LESS THAN                                       AFTER 5
(in thousands)                                TOTAL          1 YEAR       1 - 3 YEARS      4 - 5 YEARS       YEARS
                                            --------        ---------     -----------      -----------     ---------

<S>                                         <C>             <C>           <C>              <C>             <C>
Short-term cash obligations                 $113,000        $113,000        $     --        $     --        $     --
Long-term cash obligations (1)               537,533          23,000          40,000          22,000         452,533
Gas procurement contracts (2)                265,380          50,107         100,017          82,354          32,902
Operating leases                              45,883           3,609           8,467           4,505          29,302
                                            --------        --------        --------        --------        --------
  Total contractual cash obligations        $961,796        $189,716        $148,484        $108,859        $514,737
                                            ========        ========        ========        ========        ========
</TABLE>

(1)      Long-term cash obligations include $1.6 million of unamortized debt
discounts as of December 31, 2002.

(2)      Certain of the Company's long-term contracts for the supply, storage
and delivery of natural gas include fixed charges that amount to approximately
$265.4 million through October 2010. 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 55.4 billion cubic feet through October 2004.

Alagasco entered into an agreement with a financial institution whereby it can
sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million as further
described in Note 8.

OUTLOOK

OIL AND GAS OPERATIONS: Energen Resources plans to continue to implement its
acquisition and development program with capital spending in fiscal years 2003
and 2004 as outlined above. Production in 2003 is expected to be approximately
85 Bcfe, including 82.4 Bcfe of estimated production from proved reserves owned
at December 31, 2002. In 2004, production is estimated to reach approximately
87 Bcfe, including approximately 77 Bcfe produced from proved reserves
currently owned.

Nonconventional fuels tax credits were generated annually on qualified
production through December 31, 2002. To mitigate the effects of the tax credit
benefit, Energen Resources has replaced a portion of the tax credits with
revenue-generating property acquisitions and related development affecting
corporate earnings in 2003 and has increased the number of available drilling
locations through unit downspacing in the Black Warrior Basin.

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


                                      24
<PAGE>
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 cash flow derivative commodity
instruments to hedge its exposure to oil, natural gas and natural gas liquids
price fluctuations. In addition, Alagasco 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.

As of December 31, 2002, 78 percent of Energen Resources' estimated 2003 gas
production, excluding anticipated acquisition volumes, was hedged or under
contract. These hedges included 30.9 Bcf of its estimated gas production at an
average NYMEX price of $4.13 per Mcf, 4.4 Bcf of basin-specific hedges at an
average contract price of $3.86 and 4.8 Bcf of gas production hedged with a
basin-specific collar price of $3.72 to $4.70 per Mcf. The Company also had
hedges in place for 2,478 MBbl or 68 percent of its estimated 2003 oil
production, excluding anticipated acquisition volumes, at an average NYMEX
price of $26.26 per barrel and 38 MMGal or 53 percent of its estimated 2003
natural gas liquids production at an average price of $0.42 per gallon. In
addition, the Company had hedged the basis difference on 11.7 Bcf of its
estimated 2003 gas production and 2,174 MBbl of its oil production. Subsequent
to December 31, 2002, Energen Resources entered into additional hedges for
2003, resulting in a total of 2,628 MBbl of its estimated 2003 oil production
hedged at an average NYMEX price of $26.36. The Company also entered into
additional basis hedges resulting in a total of 15.7 Bcf of basis hedges on its
estimated 2003 gas production and 2,271 MBbl of basis hedges on its estimated
2003 oil production.

At December 31, 2002, Energen Resources had entered into swaps for 6.5 Bcf of
its estimated 2004 gas production at an average NYMEX price of $4.02 per Mcf
and 2.4 Bcf of its estimated 2004 gas production hedged with a NYMEX collar
price of $4.05 to $4.44 per Mcf. Subsequent to December 31, 2002, Energen
Resources entered into additional hedges for 2004, resulting in a total of 8.9
Bcf of its estimated 2004 gas production hedged at an average NYMEX price of
$4.13 per Mcf, 120 MBbl of its estimated 2004 oil production hedged at an
average NYMEX price of $26.15 and 13.9 Bcf of basin-specific hedges at an
average contract price of $3.83 per Mcf. In addition, the Company hedged 30
MMGal of its estimated 2004 natural gas liquids production at an average price
of $0.41 per gallon. For 2005, Energen Resources had entered into swaps for 1.2
Bcf of its gas production at an average NYMEX price of $3.75 per Mcf.

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, 2002, the Company estimated that a 10 percent increase in the
commodities prices would have resulted in a $27.2 million change 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 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, 2001 and September 30, 2001, the Company estimated that
a 10 percent change in the commodities prices would have resulted in a $2.1
million and a $6.9 million change, respectively, in the fair value of open
derivative contracts. Due to the short duration of the


                                      25
<PAGE>
contracts, the time value of money was not considered. 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, unless, after notice to the Company and a hearing, the
Commission votes to either modify or discontinue its operation. As discussed in
Note 2,the utility's CCM is based in part on the number of residential
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 due to the operation of the CCM. 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. Even though the utility enjoys a market saturation rate higher than the
national average, customer growth in the service territory is limited.

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 their fair values 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 compliance with
it's APSC-approved tariff. In accordance with SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation," Alagasco had recorded a regulatory
liability of $16.8 million representing the fair value of derivatives as of
December 31, 2002.

FORWARD-LOOKING STATEMENT AND RISK: 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 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;
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.

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)


                                      26
<PAGE>
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," which requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred. The
Company adopted this statement as of January 1, 2002 (See Note 10).

The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or
Disposal Activities" in June 2002. This statement requires that a liability for
costs associated with exit or disposal activities be recognized at fair value
in the period the liability is incurred. This Statement does not apply to costs
associated with the retirement of long-lived assets covered by SFAS No. 143.
The Company has adopted this statement for disposal or exit activities
initiated after December 31, 2002.

The FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure" in December 2002. This statement is effective for
2003 and amends SFAS No. 123, "Accounting for Stock-Based Compensation" by
providing alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. In
addition, SFAS No. 148 requires additional disclosures related to the effect of
stock-based compensation on reported results. The Company has adopted the
disclosure provisions of SFAS No. 148 and is currently reviewing its treatment
of stock-based compensation as well as the impact of this pronouncement.

The FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosures
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others," (FIN 45) in November 2002. FIN 45 clarifies the requirements of SFAS
No. 5, "Accounting for Contingencies," related to a guarantors accounting for,
and disclosures of, the issuance of certain types of guarantees. Management has
completed a review of potential contingencies and noted the following guarantee
disclosure: Alagasco has an agreement with a financial institution whereby it
can sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million. Alagasco's
exposure to credit loss in the event of non-performance by customers is
represented by the balance of installment receivables (see Note 8). The Company
is required to adopt the provisions for initial recognition and measurement for
all guarantees issued or modified after December 31, 2002 on a prospective
basis. The Company is currently reviewing the impact related to the initial
recognition and measurement guarantees of this Interpretation.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46) which clarifies the application of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." This
Interpretation provides guidance on the identification and consolidation of
variable interest entities (VIEs), whereby control is achieved through means
other than through voting rights. Management has completed an analysis of FIN
46 and has determined that the Company does not have VIEs.


                                      27
<PAGE>
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item in 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.


                                      28
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

<TABLE>
<CAPTION>
                                                                                                                              Page
                                                                                                                              ----
<S>      <C>                                                                                                                  <C>
1.       Financial Statements

         ENERGEN CORPORATION

           Report of Independent Accountants.................................................................................  31

           Consolidated Statements of Income for the year ended December 31, 2002, the
           three months ended December 31, 2001, and the years ended September 30,
           2001 and 2000....................................................................................................   32

           Consolidated Balance Sheets as of December 31, 2002 and 2001, and
           September 30, 2001...............................................................................................   33

           Consolidated Statements of Shareholders' Equity for the year ended December
           31, 2002, the three months ended December 31, 2001, and the years ended
           September 30, 2001 and 2000......................................................................................   35

           Consolidated Statements of Cash Flows for the year ended December 31,
           2002, the three months ended December 31, 2001, and the years ended
           September 30, 2001 and 2000......................................................................................   36

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

         ALABAMA GAS CORPORATION

           Report of Independent Accountants................................................................................   31

           Statements of Income for the year ended December 31, 2002, the three months
           ended December 31, 2001, and the years ended September 30, 2001 and 2000.........................................   37

           Balance Sheets as of December 31, 2002 and 2001, and September 30, 2001 .........................................   38

           Statements of Shareholder's Equity for the year ended December 31, 2002, the
           three months ended December 31, 2001, and the years ended September 30,
           2001 and 2000....................................................................................................   40

           Statements of Cash Flows for the year ended December 31, 2002, the three
           months ended December 31, 2001, and the years ended September 30, 2001
           and 2000.........................................................................................................   41

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

2.       Financial Statement Schedules

         ENERGEN CORPORATION
           Schedule II - Valuation and Qualifying Accounts..................................................................   73

         ALABAMA GAS CORPORATION
           Schedule II - Valuation and Qualifying Accounts..................................................................   73
</TABLE>

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.


                                      29
<PAGE>

REPORT OF MANAGEMENT

The accompanying consolidated financial statements and related notes of Energen
Corporation and subsidiaries and the financial statements and related notes of
Alabama Gas Corporation (collectively, "the financial statements") were
prepared by management, which has the primary responsibility for the integrity
of the financial information therein. These financial statements were prepared
in conformity with accounting principles generally accepted in the United
States of America appropriate in the circumstances and include amounts which
are based necessarily on management's best estimates and judgments. Financial
information presented elsewhere in this report is consistent with the
information in the financial statements.

Management maintains a comprehensive system of internal accounting controls and
relies on the system to discharge its responsibility for the integrity of the
financial statements. This system provides reasonable assurance that corporate
assets are safeguarded and that transactions are recorded in such a manner as
to permit the preparation of materially reliable financial information.
Reasonable assurance recognizes that the cost of a system of internal
accounting controls should not exceed the related benefits. This system of
internal accounting controls is augmented by written policies and procedures,
internal auditing, and the careful selection and training of qualified
personnel. As of December 31, 2002, management was aware of no material
weaknesses in Energen or Alabama Gas Corporation's systems of internal
accounting controls.

The financial statements have been audited by the Company's independent
accountants, whose opinions are expressed elsewhere in this Form 10-K. Their
audits were conducted in accordance with generally accepted auditing standards;
and, in connection therewith, they obtained an understanding of the Company's
systems of internal accounting controls and conducted such tests and related
procedures as they deemed necessary to arrive at an opinion on the fairness of
presentation of the financial statements.

The functioning of the accounting system and related internal accounting
controls is under the general oversight of the Audit Committee of the Board of
Directors, which is comprised of four outside Directors. The Audit Committee
meets regularly with the independent accountants and representatives of
management to discuss matters regarding internal accounting controls, auditing
and financial reporting.



Geoffrey C. Ketcham
Executive Vice President,
Chief Financial Officer and Treasurer


                                      30
<PAGE>

REPORT OF INDEPENDENT ACCOUNTANTS
TO THE 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, 2002
and 2001 and September 30, 2001, and the results of their operations and their
cash flows for the year ended December 31, 2002, the three months ended
December 31, 2001 and the years ended September 30, 2001 and 2000, 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.


PricewaterhouseCoopers LLP
Birmingham, Alabama
February 21, 2003


REPORT OF INDEPENDENT ACCOUNTANTS
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, 2002 and 2001 and September
30, 2001, and the results of its operations and its cash flows for the year
ended December 31, 2002, the three months ended December 31, 2001 and the years
ended September 30, 2001 and 2000, 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
February 21, 2003


                                      31
<PAGE>

CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION

<TABLE>
<CAPTION>
                                                                              Three Months
                                                             YEAR ENDED         Ended           Year Ended        Year Ended
                                                            DECEMBER 31,      December 31,     September 30,     September 30,
(in thousands, except share data)                              2002              2001              2001              2000
                                                            ------------      ------------     -------------     -------------
<S>                                                         <C>               <C>              <C>               <C>
OPERATING REVENUES
Oil and gas operations                                      $   252,744       $    49,486       $   223,512       $   185,248
Natural gas distribution                                        424,431            96,678           553,862           366,161
                                                            -----------       -----------       -----------       -----------
     Total operating revenues                                   677,175           146,164           777,374           551,409
                                                            -----------       -----------       -----------       -----------

OPERATING EXPENSES
Cost of gas                                                     189,810            45,291           327,531           154,201
Operations and maintenance                                      195,954            54,630           182,295           170,708
Depreciation, depletion and amortization                        105,087            24,502            84,779            84,934
Taxes, other than income taxes                                   50,238            10,881            61,734            46,555
                                                            -----------       -----------       -----------       -----------
     Total operating expenses                                   541,089           135,304           656,339           456,398
                                                            -----------       -----------       -----------       -----------

OPERATING INCOME                                                136,086            10,860           121,035            95,011
                                                            -----------       -----------       -----------       -----------

OTHER INCOME (EXPENSE)
Interest expense                                                (43,713)          (10,634)          (42,070)          (37,769)
Accretion expense                                                (1,819)               --                --                --
Other income                                                     15,644             4,354            16,825            17,315
Other expense                                                   (15,103)           (4,385)          (14,892)          (15,540)
                                                            -----------       -----------       -----------       -----------
     Total other expense                                        (44,991)          (10,665)          (40,137)          (35,994)
                                                            -----------       -----------       -----------       -----------

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME
TAXES AND CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE                                             91,095               195            80,898            59,017
Income tax expense (benefit)                                     20,509            (3,384)           14,811             6,482
                                                            -----------       -----------       -----------       -----------
INCOME FROM CONTINUING OPERATIONS BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE              70,586             3,579            66,087            52,535
                                                            -----------       -----------       -----------       -----------

DISCONTINUED OPERATIONS, NET OF TAXES
Income (loss) from discontinued operations                         (267)               79             1,809               483
Gain on disposal                                                    540                --                --                --
                                                            -----------       -----------       -----------       -----------
INCOME FROM DISCONTINUED OPERATIONS                                 273                79             1,809               483
                                                            -----------       -----------       -----------       -----------

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF TAXES                                          (2,220)               --                --                --
                                                            -----------       -----------       -----------       -----------

NET INCOME                                                  $    68,639       $     3,658       $    67,896       $    53,018
                                                            ===========       ===========       ===========       ===========

DILUTED EARNINGS PER AVERAGE COMMON SHARE
Continuing operations                                       $      2.09       $      0.12       $      2.13       $      1.73
Discontinued operations                                            0.01                --              0.05              0.02
Cumulative effect of change in accounting principle               (0.07)               --                --                --
                                                            -----------       -----------       -----------       -----------
Net Income                                                  $      2.03       $      0.12       $      2.18       $      1.75
                                                            ===========       ===========       ===========       ===========
BASIC EARNINGS PER AVERAGE COMMON SHARE
Continuing operations                                       $      2.10       $      0.12       $      2.15       $      1.74
Discontinued operations                                            0.01                --              0.06              0.02
Cumulative effect of change in accounting principle               (0.07)               --                --                --
                                                            -----------       -----------       -----------       -----------
Net Income                                                  $      2.04       $      0.12       $      2.21       $      1.76
                                                            ===========       ===========       ===========       ===========
DILUTED AVERAGE COMMON SHARES OUTSTANDING                    33,838,299        31,277,406        31,083,784        30,359,417
                                                            ===========       ===========       ===========       ===========
BASIC AVERAGE COMMON SHARES OUTSTANDING                      33,604,601        31,052,152        30,725,919        30,108,149
                                                            ===========       ===========       ===========       ===========
</TABLE>

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


                                      32
<PAGE>

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION

<TABLE>
<CAPTION>
                                                                     DECEMBER 31,     December 31,     September 30,
(in thousands)                                                           2002             2001             2001
                                                                     ------------     ------------     -------------
<S>                                                                   <C>              <C>              <C>

ASSETS

CURRENT ASSETS
Cash and cash equivalents                                             $    4,804       $    6,482       $    5,333
Accounts receivable, net of allowance for doubtful accounts
    of $8,874 at December 31, 2002, of $11,783 at December
    31, 2001, and of $10,031 at September 30, 2001                       100,946           77,106           74,078
Inventories, at average cost
     Storage gas inventory                                                23,668           50,978           56,761
     Materials and supplies                                                8,335            8,894           10,225
     Liquified natural gas in storage                                      3,671            3,146            3,271
Deferred gas costs                                                        21,040           17,776            3,275
Regulatory asset                                                              --               --               95
Deferred income taxes                                                     33,941           29,636           12,425
Prepayments and other                                                     20,367            6,948           27,081
                                                                      ----------       ----------       ----------
     Total current assets                                                216,772          200,966          192,544
                                                                      ----------       ----------       ----------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, successful efforts method                      1,103,472          844,962          822,956
Less accumulated depreciation, depletion and amortization                269,616          228,867          209,451
                                                                      ----------       ----------       ----------
Oil and gas properties, net                                              833,856          616,095          613,505
                                                                      ----------       ----------       ----------
Utility plant                                                            825,421          769,259          758,374
Less accumulated depreciation                                            408,165          384,430          378,218
                                                                      ----------       ----------       ----------
Utility plant, net                                                       417,256          384,829          380,156
                                                                      ----------       ----------       ----------
Other property, net                                                        5,691            4,755            4,673
                                                                      ----------       ----------       ----------
     Total property, plant and equipment, net                          1,256,803        1,005,679          998,334
                                                                      ----------       ----------       ----------
OTHER ASSETS
Deferred income taxes                                                     16,333            8,406           12,039
Regulatory asset                                                          14,744               --               --
Deferred charges and other                                                26,239           25,305           20,962
                                                                      ----------       ----------       ----------
     Total other assets                                                   57,316           33,711           33,001
                                                                      ----------       ----------       ----------

TOTAL ASSETS                                                          $1,530,891       $1,240,356       $1,223,879
                                                                      ==========       ==========       ==========
</TABLE>

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


                                      33
<PAGE>

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION

<TABLE>
<CAPTION>
                                                                       DECEMBER 31,      December 31,      September 30,
(in thousands, except share data)                                          2002              2001              2001
                                                                       ------------      ------------      -------------
<S>                                                                    <C>               <C>               <C>

CAPITAL AND LIABILITIES

CURRENT LIABILITIES
Long-term debt due within one year                                      $   23,000        $   16,072        $   16,072
Notes payable to banks                                                     113,000            24,000             7,000
Accounts payable                                                           103,964            58,783            65,412
Accrued taxes                                                               27,936            32,183            30,014
Customers' deposits                                                         17,404            16,399            15,195
Amounts due customers                                                        8,458             6,434                --
Accrued wages and benefits                                                  23,652            22,711            25,821
Regulatory liability                                                        23,814             8,462             3,792
Other                                                                       34,710            29,564            32,217
                                                                        ----------        ----------        ----------

     Total current liabilities                                             375,938           214,608           195,523
                                                                        ----------        ----------        ----------

DEFERRED CREDITS AND OTHER LIABILITIES
Asset retirement obligation                                                 27,235                --                --
Minimum pension liability                                                   25,825                --                --
Regulatory liability                                                         1,468               137               242
Other                                                                        4,661             7,273             3,237
                                                                        ----------        ----------        ----------

     Total deferred credits and other liabilities                           59,189             7,410             3,479
                                                                        ----------        ----------        ----------

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, 34,745,477 shares outstanding at December 31,
   2002, 31,248,547 shares outstanding at December 31, 2001,
   and 31,124,761 shares outstanding at September 30, 2001                     347               312               311
   Premium on capital stock                                                320,060           235,976           233,471
   Capital surplus                                                           2,802             2,802             2,802
   Retained earnings                                                       275,266           230,554           232,354
   Accumulated other comprehensive income (loss), net of tax
      Unrealized gain (loss) on hedges                                     (10,471)            7,168            15,531
      Minimum pension liability                                             (4,340)               --                --
Deferred compensation on restricted stock                                     (770)           (1,513)           (1,186)
Deferred compensation plan                                                  10,348             7,222             5,259
Treasury stock, at cost; 358,228 shares and 341,465 shares at
    December 31, 2002 and 2001, respectively, and 325,355
    shares at September 30, 2001                                           (10,432)           (8,316)           (7,775)
                                                                        ----------        ----------        ----------
   Total common shareholders' equity                                       582,810           474,205           480,767
Long-term debt                                                             512,954           544,133           544,110
                                                                        ----------        ----------        ----------
   Total capitalization                                                  1,095,764         1,018,338         1,024,877
                                                                        ----------        ----------        ----------

TOTAL CAPITAL AND LIABILITIES                                           $1,530,891        $1,240,356        $1,223,879
                                                                        ==========        ==========        ==========
</TABLE>

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


                                      34
<PAGE>

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
ENERGEN CORPORATION

<TABLE>
<CAPTION>
(in thousands, except share amounts)
                                                         Common Stock
                                                  --------------------------
                                                  Number of          Par         Premium on        Capital         Retained
                                                    Shares          Value       Capital Stock      Surplus         Earnings
                                                  ----------      ----------    -------------     ----------      ----------
<S>                                               <C>             <C>           <C>               <C>             <C>
BALANCE SEPTEMBER 30, 1999                        29,903,964      $      299      $  205,831      $    2,802      $  152,572
Net income                                                                                                            53,018
Purchase of treasury shares
Shares issued for:
     Dividend reinvestment plan                       57,920               1           1,438
     Employee benefit plans                          388,918               4           6,313
Deferred compensation obligation
Cash dividends - $0.665 per share                                                                                    (20,029)
                                                  ----------      ----------      ----------      ----------      ----------
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 loss

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
                                                  ==========      ==========      ==========      ==========      ==========

<CAPTION>
(in thousands, except share amounts)
                                                   Accumulated
                                                      Other           Deferred         Deferred
                                                  Comprehensive     Compensation     Compensation      Treasury       Shareholders'
                                                  Income (Loss)   Restricted Stock      Plan            Stock            Equity
                                                  -------------   ----------------   ------------     ----------      -------------
<S>                                               <C>             <C>                <C>              <C>             <C>
BALANCE SEPTEMBER 30, 1999                          $       --       $       --       $    2,054      $   (2,054)      $  361,504
Net income                                                                                                                 53,018
Purchase of treasury shares                                                                               (4,934)          (4,934)
Shares issued for:
     Dividend reinvestment plan                                                                            1,395            2,834
     Employee benefit plans                                                                                2,150            8,467
Deferred compensation obligation                                                           2,911          (2,911)              --
Cash dividends - $0.665 per share                                                                                         (20,029)
                                                    ----------       ----------       ----------      ----------       ----------
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
      tax of ($35,430)                                 (55,416)                                                           (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 loss                                                                                                         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
                                                    ==========       ==========       ==========      ==========       ==========
</TABLE>

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


                                      35
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION

<TABLE>
<CAPTION>
                                                                                    Three Months
                                                                     YEAR ENDED         Ended        Year Ended      Year Ended
                                                                     DECEMBER 31,    December 31,   September 30,   September 30,
(in thousands)                                                           2002            2001           2001            2000
                                                                     ------------   -------------   -------------   -------------
<S>                                                                  <C>            <C>             <C>             <C>
OPERATING ACTIVITIES
Net income                                                             $  68,639       $  3,658       $  67,896       $  53,018
Adjustments to reconcile net income to net cash
   provided by (used in) operating activities:
      Depreciation, depletion and amortization                           110,767         25,184          86,975          87,073
      Deferred income taxes, net                                          10,915         (8,495)          5,349          (5,400)
      Deferred investment tax credits, net                                  (448)          (112)           (448)           (448)
      Change in derivative fair value                                     (9,205)          (174)           (879)             --
      (Gain) loss on sale of assets                                       (3,738)         3,161          (4,716)         (1,107)
      Loss on properties held for sale                                        --             --           3,821              --
      Cumulative effect of change in accounting
          principle, net of taxes                                         (2,220)            --              --              --
      Net change in:
          Accounts receivable                                            (23,840)        (3,028)         19,284         (18,857)
          Inventories                                                     27,344          7,239         (22,018)        (11,912)
          Accounts payable                                                28,600          2,442          16,544           4,569
          Deferred gas costs                                              (3,264)       (14,501)            281          (1,251)
          Amounts due customers                                              626         11,637         (11,655)         (3,662)
          Other current assets and liabilities                             1,712         (4,813)          1,424           8,370
      Other, net                                                           7,619           (837)         (5,362)         (5,350)
                                                                       ---------       --------       ---------       ---------

          Net cash provided by operating activities                      213,507         21,361         156,496         105,043
                                                                       ---------       --------       ---------       ---------

INVESTING ACTIVITIES
Additions to property, plant and equipment                              (166,075)       (37,752)       (190,695)       (133,061)
Acquisition, net of cash acquired                                       (117,043)            --              --              --
Proceeds from sale of assets                                              17,094          2,323          17,326           2,647
Other, net                                                                (2,198)          (252)         (1,038)         (1,329)
                                                                       ---------       --------       ---------       ---------

         Net cash used in investing activities                          (268,222)       (35,681)       (174,407)       (131,743)
                                                                       ---------       --------       ---------       ---------

FINANCING ACTIVITIES
Payment of dividends on common stock                                     (23,927)        (5,458)        (21,103)        (20,029)
Issuance of common stock                                                  12,371          5,172          21,285          11,301
Purchase of treasury stock                                                  (133)        (1,245)         (2,516)         (4,934)
Reduction of long-term debt                                              (21,204)            --         (36,267)         (1,205)
Proceeds from issuance of long-term debt                                      --             --         223,799              --
Debt issuance costs                                                           --             --          (4,777)             --
Net change in short-term debt issued to purchase
   U.S. Treasury securities                                                   --             --              --        (140,917)
Net change in short-term debt                                             85,930         17,000        (161,000)         40,917
                                                                       ---------       --------       ---------       ---------

         Net cash provided by (used in) financing activities              53,037         15,469          19,421        (114,867)
                                                                       ---------       --------       ---------       ---------

Net change in cash and cash equivalents                                   (1,678)         1,149           1,510        (141,567)
Cash and cash equivalents at beginning of period                           6,482          5,333           3,823         145,390
                                                                       ---------       --------       ---------       ---------

Cash and cash equivalents at end of period                             $   4,804       $  6,482       $   5,333       $   3,823
                                                                       =========       ========       =========       =========
</TABLE>

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


                                       36
<PAGE>

STATEMENTS OF INCOME
ALABAMA GAS CORPORATION

<TABLE>
<CAPTION>
                                                                                    Three Months
                                                                      YEAR ENDED        Ended        Year Ended      Year Ended
                                                                      DECEMBER 31,   December 31,   September 30,   September 30,
(in thousands)                                                           2002            2001           2001            2000
                                                                      ------------  -------------   -------------   -------------
<S>                                                                   <C>           <C>             <C>             <C>
OPERATING REVENUES                                                     $ 424,431       $ 96,678       $ 553,862       $ 366,161
                                                                       ---------       --------       ---------       ---------

OPERATING EXPENSES
Cost of gas                                                              191,479         45,651         329,572         155,841
Operations and maintenance                                               109,115         27,687         105,812         104,206
Depreciation                                                              33,682          8,151          30,933          28,708
Income taxes
     Current                                                               8,764         10,348          16,995          16,711
     Deferred, net                                                         9,509         (8,689)         (3,099)         (1,939)
     Deferred investment tax credits, net                                   (448)          (112)           (448)           (448)
Taxes, other than income taxes                                            30,785          7,155          37,257          28,343
                                                                       ---------       --------       ---------       ---------

     Total operating expenses                                            382,886         90,191         517,022         331,422
                                                                       ---------       --------       ---------       ---------

OPERATING INCOME                                                          41,545          6,487          36,840          34,739
                                                                       ---------       --------       ---------       ---------

OTHER INCOME (EXPENSE)
Allowance for funds used during construction                               1,336            122           2,098           1,172
Other income                                                               5,520          1,596           5,978           7,520
Other expense                                                             (6,280)        (1,838)         (6,585)         (7,239)
                                                                       ---------       --------       ---------       ---------

     Total other income (expense)                                            576           (120)          1,491           1,453
                                                                       ---------       --------       ---------       ---------

INTEREST CHARGES
Interest on long-term debt                                                13,153          3,327           8,803           8,542
Other interest charges                                                     1,404            353           3,513           1,328
                                                                       ---------       --------       ---------       ---------

     Total interest charges                                               14,557          3,680          12,316           9,870
                                                                       ---------       --------       ---------       ---------

NET INCOME                                                             $  27,564       $  2,687       $  26,015       $  26,322
                                                                       =========       ========       =========       =========
</TABLE>

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


                                       37
<PAGE>

BALANCE SHEETS
ALABAMA GAS CORPORATION

<TABLE>
<CAPTION>
                                                  December 31,    December 31,   September 30,
(in thousands)                                       2002            2001            2001
                                                  ------------    ------------   -------------
<S>                                               <C>             <C>            <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant                                      $ 825,421       $ 769,259       $ 758,374
Less accumulated depreciation                        408,165         384,430         378,218
                                                   ---------       ---------       ---------

     Utility plant, net                              417,256         384,829         380,156
                                                   ---------       ---------       ---------

Other property, net                                      842             308             333
                                                   ---------       ---------       ---------

CURRENT ASSETS
Cash                                                   2,818           3,372           1,555
Accounts receivable
     Gas                                              70,220          59,504          47,024
     Merchandise                                       1,748           1,506           1,417
     Other                                               656             626           1,448
     Affiliated companies                                 --              --             937
     Allowance for doubtful accounts                  (8,200)        (11,100)         (9,500)
Inventories, at average cost
     Storage gas inventory                            23,668          50,978          56,761
     Materials and supplies                            5,049           5,363           5,423
     Liquified natural gas in storage                  3,671           3,146           3,271
Deferred gas costs                                    21,040          17,776           3,275
Regulatory asset                                          --              --              95
Deferred income taxes                                 20,093          22,820          14,477
Prepayments and other                                 18,314           1,378           2,521
                                                   ---------       ---------       ---------

          Total current assets                       159,077         155,369         128,704
                                                   ---------       ---------       ---------

OTHER ASSETS
Regulatory asset                                      14,744              --              --
Deferred charges and other                            11,290           8,715           8,546
                                                   ---------       ---------       ---------

          Total other assets                          26,034           8,715           8,546
                                                   ---------       ---------       ---------

TOTAL ASSETS                                       $ 603,209       $ 549,221       $ 517,739
                                                   =========       =========       =========
</TABLE>

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


                                       38
<PAGE>

BALANCE SHEETS
ALABAMA GAS CORPORATION

<TABLE>
<CAPTION>
                                                                DECEMBER 31,  December 31,  September 30,
(in thousands, except share data)                                   2002          2001          2001
                                                                ------------  ------------  -------------
<S>                                                             <C>           <C>           <C>
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, 2002 and 2001, and September 30,
        2001, respectively                                              20            20            20
     Premium on capital stock                                       31,682        31,682        31,682
     Capital surplus                                                 2,802         2,802         2,802
     Retained earnings                                             182,852       172,147       174,885
                                                                  --------      --------      --------

     Total common shareholder's equity                             217,356       206,651       209,389
Long-term debt                                                     169,533       185,000       185,000
                                                                  --------      --------      --------

     Total capitalization                                          386,889       391,651       394,389
                                                                  --------      --------      --------

CURRENT LIABILITIES
Long-term debt due within one year                                  15,000         5,000         5,000
Notes payable to banks                                              13,000        19,000         1,000
Accounts payable
     Trade                                                          55,720        34,023        32,078
     Affiliated companies                                            1,432         3,054            --
Accrued taxes                                                       24,044        29,505        26,963
Customers' deposits                                                 17,404        16,399        15,195
Amounts due customers                                                8,458         6,434            --
Accrued wages and benefits                                           5,710        10,509        11,616
Regulatory liability                                                23,814         8,462         3,792
Other                                                                8,947         7,289         9,416
                                                                  --------      --------      --------

     Total current liabilities                                     173,529       139,675       105,060
                                                                  --------      --------      --------

DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes                                               20,747        15,531        15,825
Minimum pension liability                                           18,661            --            --
Accumulated deferred investment tax credits                            756         1,204         1,317
Regulatory liability                                                 1,468           137           242
Customer advances for construction and other                         1,159         1,023           906
                                                                  --------      --------      --------

     Total deferred credits and other liabilities                   42,791        17,895        18,290
                                                                  --------      --------      --------

COMMITMENTS AND CONTINGENCIES
                                                                  --------      --------      --------

TOTAL CAPITAL AND LIABILITIES                                     $603,209      $549,221      $517,739
                                                                  ========      ========      ========
</TABLE>

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


                                       39
<PAGE>

STATEMENTS OF SHAREHOLDER'S EQUITY
ALABAMA GAS CORPORATION

<TABLE>
<CAPTION>
(in thousands, except share amounts)
                                          COMMON STOCK
                                    ------------------------                                                      TOTAL
                                    NUMBER OF        PAR         PREMIUM ON       CAPITAL        RETAINED     SHAREHOLDER'S
                                      SHARES        VALUE       CAPITAL STOCK     SURPLUS        EARNINGS        EQUITY
                                    ---------      ---------    -------------    ---------      ---------     -------------
<S>                                 <C>            <C>          <C>              <C>            <C>           <C>
BALANCE SEPTEMBER 30, 1999          1,972,052      $      20      $  31,682      $   2,802      $ 143,502       $ 178,006
Net income                                                                                         26,322          26,322
Cash dividends                                                                                     (5,057)         (5,057)
                                    ---------      ---------      ---------      ---------      ---------       ---------

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
                                    =========      =========      =========      =========      =========       =========
</TABLE>

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


                                       40
<PAGE>

STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION

<TABLE>
<CAPTION>
                                                                                     Three Months
                                                                      YEAR ENDED        Ended       Year Ended        Year Ended
                                                                      DECEMBER 31,   December 31,   September 30,    September 30,
(in thousands)                                                           2002            2001           2001            2000
                                                                      ------------   ------------   -------------    -------------
<S>                                                                   <C>            <C>            <C>              <C>
OPERATING ACTIVITIES
Net income                                                             $  27,564       $  2,687       $  26,015       $  26,322
Adjustments to reconcile net income to net cash
    provided by (used in) operating activities:
      Depreciation and amortization                                       33,682          8,151          30,933          28,708
      Deferred income taxes, net                                           9,509         (8,689)         (3,099)         (1,939)
      Deferred investment tax credits                                       (448)          (112)           (448)           (448)
      Net change in:
          Accounts receivable                                            (13,887)       (10,147)          5,775          (9,290)
          Inventories                                                     27,099          5,968         (20,351)        (12,040)
          Deferred gas costs                                              (3,264)       (14,501)            281          (1,251)
          Accounts payable                                                21,697          1,945          (7,298)          2,391
          Amounts due customers                                              626         11,637         (11,655)         (3,662)
          Other current assets and liabilities                            (6,666)         1,191           7,692           1,617
      Other, net                                                          (1,447)          (201)         (2,231)         (1,663)
                                                                       ---------       --------       ---------       ---------

          Net cash provided (used) by operating activities                94,465         (2,071)         25,614          28,745
                                                                       ---------       --------       ---------       ---------

INVESTING ACTIVITIES
Additions to property, plant and equipment                               (64,257)       (12,820)        (53,749)        (65,684)
Net advances from (to) parent company                                     (1,622)         3,990          (2,093)         21,811
Other, net                                                                  (814)           143            (327)             18
                                                                       ---------       --------       ---------       ---------

          Net cash used in investing activities                          (66,693)        (8,687)        (56,169)        (43,855)
                                                                       ---------       --------       ---------       ---------

FINANCING ACTIVITIES
Payment of dividends on common stock                                     (16,859)        (5,425)        (15,897)         (5,057)
Reduction of long-term debt                                               (5,467)            --              --              --
Proceeds from issuance of long-term debt                                      --             --          75,000              --
Debt issuance costs                                                           --             --          (3,709)             --
Net change in short-term debt                                             (6,000)        18,000         (24,150)         20,500
                                                                       ---------       --------       ---------       ---------

         Net cash provided (used) by financing activities                (28,326)        12,575          31,244          15,443
                                                                       ---------       --------       ---------       ---------

Net change in cash and cash equivalents                                     (554)         1,817             689             333
Cash and cash equivalents at beginning of period                           3,372          1,555             866             533
                                                                       ---------       --------       ---------       ---------

Cash and cash equivalents at end of period                             $   2,818       $  3,372       $   1,555       $     866
                                                                       =========       ========       =========       =========
</TABLE>

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


                                       41
<PAGE>
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 has continued 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 and gas 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 unit-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 and gas production revenue. Under the
         sales method, revenue is recognized for the Company's total takes of
         oil and gas production that are sold to and payable by its customers.
         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, 2002.

         DERIVATIVE COMMODITY INSTRUMENTS: 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. 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.


                                      42
<PAGE>
         The Company adopted Statement of Financial Accounting Standard (SFAS)
         No. 133 (subsequently amended by SFAS Nos. 137 and 138), "Accounting
         for Derivative Instruments and Hedging Activities," on October 1,
         2000. This statement requires all derivatives to be recognized on the
         balance sheet and measured at fair value. If a derivative is
         designated as a cash flow hedge, the Company is required to measure
         the effectiveness of the hedge, or the degree that the gain (loss) for
         the hedging instrument offsets the loss (gain) on the hedged item, at
         each reporting period. The effective portion of the gain or loss on
         the derivative instrument is recognized in other comprehensive income
         as a component of equity and subsequently reclassified into earnings
         when the forecasted transaction affects earnings. The ineffective
         portion of a derivative's change in fair value is required to be
         recognized in earnings immediately. Derivatives that do not qualify
         for hedge treatment under SFAS No. 133 must be recorded at fair value
         with gains or losses recognized in earnings in the period of change.
         As of December 31, 2002, 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 as approved by the Board of Directors. The policy's objective
         is to preserve revenues from forecasted sales and 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.

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, together with the cost of removal less
         salvage, is charged to the accumulated reserve for depreciation.
         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 year ended December 31,
         2002, for the three months ended December 31, 2001 and for the years
         ended September 30, 2001 and 2000.

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

         OPERATING REVENUE AND GAS COSTS: In accordance with industry practice,
         Alagasco records natural gas distribution revenues on a monthly- and
         cycle-billing basis. The commodity cost of purchased gas applicable to
         gas delivered to customers but not yet billed under the cycle-billing
         method is deferred as a current asset.

         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.


                                      43
<PAGE>
         DERIVATIVE COMMODITY INSTRUMENTS: 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, 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:

<TABLE>
<CAPTION>
                                         Three Months
                          YEAR ENDED        Ended          Year Ended       Year Ended
                         DECEMBER 31,     December 31,    September 30,   September 30,
(in thousands)              2002             2001             2001           2000
                         ------------     ------------    -------------   -------------

<S>                      <C>              <C>             <C>              <C>
Taxes on revenues          $21,591          $4,969          $28,766          $19,749
                           -------          ------          -------          -------
      Total                $21,591          $4,969          $28,766          $19,749
                           =======          ======          =======          =======
</TABLE>

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 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 currently reports stock-based employee compensation
         through the disclosure-only provisions of SFAS No. 123, "Accounting
         for Stock-Based Compensation." Accordingly, no compensation expense
         has been recognized for its stock options. Had compensation cost for
         these options been determined in accordance with SFAS No. 123, the
         Company's net income and diluted earnings per share would have been as
         follows:


                                      44
<PAGE>
<TABLE>
<CAPTION>
                                                                            Three Months
                                                         YEAR ENDED             Ended             Year Ended          Year Ended
                                                        DECEMBER 31,         December 31,       September 30,        September 30,
(in thousands)                                             2002                  2001               2001                  2000
                                                        ------------         ------------       -------------        -------------

<S>                                                      <C>                  <C>                 <C>                  <C>
Net income
   As reported                                           $   68,639           $   3,658           $   67,896           $   53,018

   Stock based compensation expense included
      in reported net income, net of tax                      2,879                 911                2,894                4,545
   Stock based compensation expense
      determined under fair value based method,
      net of tax                                             (3,472)               (822)              (3,142)              (3,539)
                                                         ----------           ---------           ----------           ----------
   Pro forma                                             $   68,046           $   3,747           $   67,648           $   54,024
                                                         ----------           ---------           ----------           ----------
Diluted earnings per average common share
   As reported                                           $     2.03           $    0.12           $     2.18           $     1.75
   Pro forma                                             $     2.01           $    0.12           $     2.18           $     1.78
                                                         ----------           ---------           ----------           ----------
Basic earnings per average common share
   As reported                                           $     2.04           $    0.12           $     2.21           $     1.76
   Pro forma                                             $     2.02           $    0.12           $     2.20           $     1.79
                                                         ==========           =========           ==========           ==========
</TABLE>

         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, 36.35
         percent and 34.64 percent for the three months ended December 31,
         2001, and the years ended September 30, 2001 and 2000, respectively; a
         risk-free interest rate of 3.36 percent, 4.14 percent, and 5.76
         percent for the three months ended December 31, 2001, and the years
         ended September 30, 2001 and 2000, respectively; and a dividend yield
         of 3.12 percent, 2.55 percent and 3.53 percent on options without
         dividend equivalents for the three months ended December 31, 2001, and
         the years ended September 30, 2001 and 2000, respectively. Options
         with dividend equivalents assume no dividend yield for all periods
         presented. The weighted-average grant-date fair value of options
         granted for the three-months ended December 31, 2001, was $9.74 for
         options granted with dividend equivalents and $6.52 for options
         granted without dividend equivalents; $12.66 for options granted with
         dividend equivalents and $9.27 for options granted without dividend
         equivalents during the year-ended September 30, 2001; and $5.91 for
         options granted without dividend equivalents in the year-ended
         September 30, 2000. 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. Actual results could differ from those estimates.
         Significant estimates with regard to these financial statements
         include the estimate of proved oil and gas reserves and the related
         present value of estimated future net revenues therefrom (see Note
         19).

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. Alagasco's allowed range
of return 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. 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


                                      45
<PAGE>
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 above the index range for the rate
year ended September 30, 2002; as a result, the utility returned to customers
$0.3 million pre-tax through rate adjustments under the provisions of RSE. A
$12.4 million, $16.3 million and $9.1 million annual increase in revenues
became effective December 1, 2002, 2001 and 2000, respectively, under RSE as
extended.

Alagasco calculates a temperature adjustment to customers' monthly bills to
substantially remove the effect of departures from normal temperatures on
Alagasco's earnings. Adjustments to customers' bills are made in the same
billing cycle in which the weather variation occurs. The temperature adjustment
applies to residential, small commercial and small industrial customers.
Alagasco's rate schedules for natural gas distribution charges contain a 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 million at December 31, 2002, and $2.7 million at December 31, 2001 and
September 30, 2001, respectively, are included in the consolidated financial
statements.

At December 31, 2002, Alagasco had a $18.7 million accrued obligation related
to its salaried and union pension plans. In accordance with SFAS No. 71,
Alagasco has established a regulatory asset of $14.7 million for the portion of
the accrued obligation to be recovered through rates in future periods.

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, 2002, December 31, 2001 and
September 30, 2001, the net acquisition adjustments were $13.8 million, $12.1
million and $12.4 million, respectively.

3.       LONG-TERM DEBT AND NOTES PAYABLE
-------------------------------------------------------------------------------

Long-term debt consisted of the following:

<TABLE>
<CAPTION>
                                                            DECEMBER 31,      December 31,     September 30,
(in thousands)                                                 2002              2001              2001
                                                            ------------      ------------     -------------

<S>                                                         <C>               <C>              <C>
Energen Corporation:
  Medium-term Notes, interest ranging from 6.81% to
    8.09%, for notes redeemable September 15, 2003,
    to February 15, 2028                                     $353,000          $363,000          $363,000
  Series 1993 Notes                                                --             8,881             8,881
Alabama Gas Corporation:
  Medium-term Notes, interest ranging from 6.25% to
    7.97%, for notes redeemable September 15, 2003,
    to September 23, 2026                                     110,000           115,000           115,000
  6.25% Notes, redeemable September 1, 2016                    39,758            40,000            40,000
  6.75% Notes, redeemable September 1, 2031                    34,775            35,000            35,000
                                                             --------          --------          --------
Total                                                         537,533           561,881           561,881
Less amounts due within one year                               23,000            16,072            16,072
Less unamortized debt discount                                  1,579             1,676             1,699
                                                             --------          --------          --------
     Total                                                   $512,954          $544,133          $544,110
                                                             ========          ========          ========
</TABLE>


                                      46
<PAGE>
The aggregate maturities of Energen's long-term debt for the next five years
are as follows:

<TABLE>
<CAPTION>
                 Years ending December 31, (in thousands)
--------------------------------------------------------------------------
  2003            2004              2005            2006             2007
-------         -------           -------         -------           ------
<S>             <C>               <C>             <C>               <C>
$23,000         $10,000           $10,000         $20,000           $7,000
</TABLE>

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

<TABLE>
<CAPTION>
              Years ending December 31, (in thousands)
----------------------------------------------------------------------
  2003           2004           2005             2006            2007
-------          ---          -------          -------          ------
<S>              <C>          <C>              <C>              <C>
$15,000          $--          $10,000          $10,000          $7,000
</TABLE>

At December 31, 2002, 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, 2002. 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, 2002, 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:

<TABLE>
<CAPTION>
                                                             DECEMBER 31,       December 31,     September 30,
(in thousands)                                                  2002               2001              2001
                                                             ------------       ------------     -------------

<S>                                                          <C>                <C>              <C>
Energen outstanding                                           $100,000           $  5,000           $  6,000
Alagasco outstanding                                            13,000             19,000              1,000
                                                              --------           --------           --------
Notes payable to banks                                         113,000             24,000              7,000
Available for borrowings                                       154,000            196,000            213,000
                                                              --------           --------           --------
Total                                                         $267,000           $220,000           $220,000
                                                              --------           --------           --------
Maximum amount outstanding at any month-end                   $113,000           $ 24,000           $177,000
Average daily amount outstanding                              $ 85,644           $ 16,717           $ 80,681
Weighted average interest rates based on:
     Average daily amount outstanding                             2.28%              2.53%              6.05%
     Amount outstanding at year-end                               1.88%              2.18%              2.97%
                                                              --------           --------           --------
Alagasco maximum amount outstanding at any month-end          $ 21,000           $ 19,000           $ 62,000
Alagasco average daily amount outstanding                     $  3,304           $ 11,761           $ 40,066
Alagasco weighted average interest rates based on:
     Average daily amount outstanding                             2.18%              2.47%              5.31%
     Amount outstanding at year-end                               1.78%              2.16%              2.97%
                                                              --------           --------           --------
</TABLE>

Energen's total interest expense was $43,713,000 for the year ended December
31, 2002, $10,634,000 for the three months ended December 31, 2001 and
$42,070,000 and $37,769,000 for the years ended September 31, 2001 and 2000,
respectively. Total interest expense at Alagasco was $14,557,000 for the year
ended December 31, 2002, $3,680,000 for the three months ended December 31,
2001 and $12,316,000 and $9,870,000 for the years ended September 30, 2001 and
2000, respectively, at Alagasco.


                                      47
<PAGE>
4.       INCOME TAXES
-------------------------------------------------------------------------------

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

<TABLE>
<CAPTION>
                                                                Three Months
                                                 YEAR ENDED         Ended           Year Ended        Year Ended
                                                 DECEMBER 31,    December 31,     September 30,     September 30,
(in thousands)                                      2002            2001              2001              2000
                                                 ------------    ------------     -------------     -------------

<S>                                              <C>             <C>              <C>               <C>
Taxes estimated to be payable currently:
   Federal                                        $ 7,370          $ 3,686           $ 8,601          $ 10,412
   State                                              546            1,537             1,309             1,918
                                                  -------          -------           -------          --------
          Total current                             7,916            5,223             9,910            12,330
                                                  -------          -------           -------          --------
Taxes deferred:
   Federal                                          9,065           (7,211)            3,073            (6,027)
   State                                            3,528           (1,396)            1,828               179
                                                  -------          -------           -------          --------
          Total deferred                           12,593           (8,607)            4,901            (5,848)
                                                  -------          -------           -------          --------
Total income tax expense (benefit)
   from continuing operations                     $20,509          $(3,384)          $14,811          $  6,482
                                                  =======          =======           =======          ========
</TABLE>

In addition, Energen recorded income tax expense, related to income from
discontinued operations, of $2,300,000 in current income tax expense and
($2,126,000) in deferred income tax expense for the year ended December 31,
2002, $59,000 in current income tax expense for the three months ended December
31, 2001, and $1,165,000 and $307,000 in current income tax expense for the
years ended September 30, 2001 and 2000, respectively.

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

<TABLE>
<CAPTION>
                                                                Three Months
                                                 YEAR ENDED         Ended           Year Ended        Year Ended
                                                 DECEMBER 31,    December 31,     September 30,     September 30,
(in thousands)                                      2002            2001              2001              2000
                                                 ------------    ------------     -------------     -------------

<S>                                              <C>             <C>              <C>               <C>
Taxes estimated to be payable currently:
   Federal                                        $ 7,763          $  9,167           $ 15,456           $ 15,225
   State                                            1,001             1,181              1,539              1,486
                                                  -------          --------           --------           --------
          Total current                             8,764            10,348             16,995             16,711
                                                  -------          --------           --------           --------
Taxes deferred:
   Federal                                          7,974            (7,807)            (3,193)            (2,215)
   State                                            1,087              (994)              (354)              (172)
                                                  -------          --------           --------           --------
          Total deferred                            9,061            (8,801)            (3,547)            (2,387)
                                                  -------          --------           --------           --------
Total income tax expense from continuing
   operations                                     $17,825          $  1,547           $ 13,448           $ 14,324
                                                  =======          ========           ========           ========
</TABLE>

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


                                      48
<PAGE>
<TABLE>
<CAPTION>
Energen Corporation
(in thousands)                               DECEMBER 31, 2002          December 31, 2001         September 30, 2001
                                           ----------------------    ----------------------    ----------------------
                                           CURRENT     NONCURRENT    Current     Noncurrent    Current     Noncurrent
                                           -------     ----------    -------     ----------    -------     ----------

<S>                                        <C>         <C>           <C>         <C>           <C>         <C>
Deferred tax assets:
     Minimum tax credit                     $    --      $64,756      $    --      $57,441      $    --      $56,043
     Pension and other costs                  5,326        7,056        7,165           --        6,574           --
     Unbilled revenue and
        other costs                           9,082           --        9,037           --        1,942           --
     Enhanced stability reserve               1,120           --        1,022           --        1,016           --
     Allowance for doubtful
       accounts                               3,316           --        4,236           --        3,631           --
     Insurance and accruals                   2,736           --        2,402           --        2,384           --
     Other comprehensive income               5,980        3,053           --           --           --           --
     Other, net                               6,644        2,153        9,894        1,338        5,979        1,420
                                            -------      -------      -------      -------      -------      -------
        Total deferred tax assets            34,204       77,018       33,756       58,779       21,526       57,463
                                            -------      -------      -------      -------      -------      -------
Deferred tax liabilities:
     Depreciation and
       basis differences                         --       53,622           --       49,217           --       44,165
     Minimum pension liability                   --        7,056           --           --           --           --
     Other comprehensive income                  --           --        3,644        1,151        8,676        1,254
     Other, net                                 263            7          476            5          425            5
                                            -------      -------      -------      -------      -------      -------
        Total deferred tax liabilities          263       60,685        4,120       50,373        9,101       45,424
                                            -------      -------      -------      -------      -------      -------
Net deferred tax
     assets (liabilities)                   $33,941      $16,333      $29,636      $ 8,406      $12,425      $12,039
                                            =======      =======      =======      =======      =======      =======
</TABLE>


<TABLE>
<CAPTION>
Alabama Gas Corporation
(in thousands)                                DECEMBER 31, 2002           December 31, 2001           September 30, 2001
                                            ----------------------      ----------------------      ----------------------
                                            CURRENT     NONCURRENT      Current     Noncurrent      Current     Noncurrent
                                            -------     ----------      -------     ----------      -------     ----------

<S>                                         <C>          <C>            <C>          <C>            <C>          <C>
Deferred tax assets:
     Enhanced stability reserve             $ 1,120      $     --       $ 1,022      $     --       $ 1,016      $     --
     Unbilled revenue and
        other costs                           9,082            --         9,037            --         1,942            --
     Insurance and accruals                   3,418            --         3,182            --         2,817            --
     Inventories                              1,133            --         1,022            --         1,061            --
     Allowance for
       doubtful accounts                      3,100            --         4,197            --         3,592            --
     Pension and other costs                     --         7,056         2,675            --         2,239            --
     Other, net                               2,721           791         1,931           444         2,058           526
                                            -------      --------       -------      --------       -------      --------
        Total deferred tax assets            20,574         7,847        23,066           444        14,725           526
                                            -------      --------       -------      --------       -------      --------
Deferred tax liabilities:
     Depreciation and
       basis differences                         --        21,538            --        15,975            --        16,351
     Minimum pension liability                   --         7,056            --            --            --            --
     Other, net                                 481            --           246            --           248            --
                                            -------      --------       -------      --------       -------      --------
        Total deferred tax liabilities          481        28,594           246        15,975           248        16,351
                                            -------      --------       -------      --------       -------      --------
Net deferred tax
      assets (liabilities)                  $20,093      $(20,747)      $22,820      $(15,531)      $14,477      $(15,825)
                                            =======      ========       =======      ========       =======      ========
</TABLE>


The Company files a consolidated federal income tax return with all of its
subsidiaries. As of December 31, 2002, the amount of minimum tax credit which
can be carried forward indefinitely to reduce future regular tax liability is
$64.8 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:


                                      49
<PAGE>
<TABLE>
<CAPTION>
                                                                     Three Months
                                                        YEAR ENDED       Ended       Year Ended     Year Ended
                                                       DECEMBER 31,   December 31,  September 30,  September 30,
(in thousands)                                             2002          2001           2001          2000
                                                       ------------   ------------  -------------  -------------

<S>                                                    <C>            <C>           <C>            <C>
Income tax expense from  continuing  operations  at
 statutory federal income tax rate                       $ 31,883       $    68       $ 28,314       $ 20,656
Increase (decrease) resulting from:
     Nonconventional fuels tax credits                    (14,165)       (3,481)       (13,588)       (14,405)
     Enhanced oil recovery tax credits                         --            --            (25)          (457)
     Deferred investment tax credits                         (448)         (112)          (448)          (448)
     State income taxes, net of federal income
       tax benefit                                          2,465            28          1,754          1,421
     Other, net                                               774           113         (1,196)          (285)
                                                         --------       -------       --------       --------
Total income tax expense (benefit)
from continuing operations                               $ 20,509       $(3,384)      $ 14,811       $  6,482
                                                         --------       -------       --------       --------
Effective income tax rate (%)                               22.51            --          18.31          10.98
                                                         ========       =======       ========       ========
</TABLE>


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:

<TABLE>
<CAPTION>
                                                                         Three Months
                                                         YEAR ENDED          Ended         Year Ended       Year Ended
                                                        DECEMBER 31,     December 31,     September 30,    September 30,
(in thousands)                                              2002             2001             2001             2000
                                                        ------------     ------------     -------------    -------------

<S>                                                     <C>              <C>              <C>              <C>
Income tax expense from  continuing  operations  at
 statutory federal income tax rate                         $ 15,886         $ 1,482         $ 13,812         $ 14,226
Increase (decrease) resulting from:
     Deferred investment tax credits                           (448)           (112)            (448)            (448)
     State income taxes, net of federal income
       tax benefit                                            1,236             116              799              874
     Other, net                                               1,151              61             (715)            (328)
                                                           --------         -------         --------         --------
Total income tax expense from
  continuing operations                                    $ 17,825         $ 1,547         $ 13,448         $ 14,324
                                                           --------         -------         --------         --------
Effective income tax rate (%)                                 39.27           36.54            34.08            35.24
                                                           ========         =======         ========         ========
</TABLE>

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. The Company's policy is to use the projected unit credit actuarial
method for funding and financial reporting purposes.

The status of the plans was as follows:

<TABLE>
<CAPTION>
(in thousands)                                                                             PLAN A
                                                            --------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,      June 30,          June 30,
                                                                2002             2001              2001             2000
                                                            -------------     -------------      --------          --------

<S>                                                         <C>               <C>                <C>              <C>
Projected benefit obligation:
Balance at beginning of period                                $  92,101         $ 90,613         $ 71,694         $ 73,841
Service cost                                                      3,074              899            2,219            1,988
Interest cost                                                     6,173            1,643            5,458            5,573
Actuarial loss (gain)                                             6,093              (46)          16,478           (2,642)
Benefits paid                                                    (6,042)          (1,008)          (5,236)          (7,066)
                                                              ---------         --------         --------         --------
Balance at end of period                                        101,399           92,101           90,613           71,694
                                                              ---------         --------         --------         --------
</TABLE>

                                      50
<PAGE>
<TABLE>
<S>                                                         <C>               <C>                <C>              <C>
Plan assets:
Fair value of plan assets at beginning of period                 67,967           74,486           87,169           83,844
Actual return on plan assets                                     (5,331)          (5,510)          (7,447)          10,391
Employer contributions                                           11,000               --               --               --
Benefits paid                                                    (6,042)          (1,009)          (5,236)          (7,066)
                                                              ---------         --------         --------         --------
Fair value of plan assets at end of period                       67,594           67,967           74,486           87,169
                                                              ---------         --------         --------         --------
Amounts recognized in the consolidated balance sheets:
Funded status of plan                                           (33,805)         (24,134)         (16,127)          15,475
Unrecognized actuarial loss (gain)                               30,565           12,996            6,001          (22,926)
Unrecognized prior service cost                                   2,027            2,262            2,321            2,555
Unrecognized net transition obligation (asset)                       --             (196)            (261)          (1,069)
                                                              ---------         --------         --------         --------
Accrued pension asset (liability)                             $  (1,213)        $ (9,072)        $ (8,066)        $ (5,965)
                                                              =========         ========         ========         ========
</TABLE>

<TABLE>
<CAPTION>
(in thousands)                                                                             PLAN B
                                                            --------------------------------------------------------------
                                                            SEPTEMBER 30,     September 30,      June 30,          June 30,
                                                                2002             2001              2001             2000
                                                            -------------     -------------      --------          --------

<S>                                                         <C>               <C>                <C>              <C>
Projected benefit obligation:
Balance at beginning of period                                $ 17,945         $ 17,949         $ 17,002         $ 18,227
Service cost                                                       396               80              255              265
Interest cost                                                    1,422              320            1,267            1,361
Plan amendment                                                   1,781               --               --               --
Actuarial loss (gain)                                            1,912               58            1,345             (487)
Benefits paid                                                   (1,468)            (462)          (1,920)          (2,364)
                                                              --------         --------         --------         --------
Balance at end of period                                        21,988           17,945           17,949           17,002
                                                              --------         --------         --------         --------
Plan assets:
Fair value of plan assets at beginning of period                18,420           20,666           23,561           24,043
Actual return on plan assets                                    (1,264)          (1,784)            (975)           1,882
Benefits paid                                                   (1,468)            (462)          (1,920)          (2,364)
                                                              --------         --------         --------         --------
Fair value of plan assets at end of period                      15,688           18,420           20,666           23,561
                                                              --------         --------         --------         --------
Amounts recognized in the consolidated balance sheets:
Funded status of plan                                           (6,300)             475            2,717            6,559
Unrecognized actuarial loss (gain)                               4,315             (481)          (2,729)          (6,458)
Unrecognized prior service cost                                  2,295              869              928            1,163
Unrecognized net transition obligation (asset)                      --               43               57              114
                                                              --------         --------         --------         --------
Accrued pension asset (liability)                             $    310         $    906         $    973         $  1,378
                                                              ========         ========         ========         ========
</TABLE>

The components of net pension expense were:

<TABLE>
<CAPTION>
(in thousands)                                                          PLAN A
                                              ------------------------------------------------------------
                                                             Three Months
                                               YEAR ENDED       Ended         Year Ended      Year Ended
                                              DECEMBER 31,    December 31,   September 30,   September 30,
                                                 2002            2001            2001            2000
                                              ------------    ------------   -------------   -------------

<S>                                           <C>             <C>            <C>             <C>
Components of net periodic benefit cost:
Service cost                                    $ 3,074         $   899         $ 2,219         $ 1,988
Interest cost                                     6,173           1,643           5,458           5,573
Expected long-term return on assets              (6,145)         (1,537)         (5,778)         (5,566)
Prior service cost amortization                     235              59             235             235
Actuarial loss (gain)                                --               2             422              --
Transition amortization                            (196)            (65)           (808)           (808)
                                                -------         -------         -------         -------
Net periodic expense                            $ 3,141         $ 1,001         $ 1,748         $ 1,422
                                                =======         =======         =======         =======
</TABLE>


                                      51
<PAGE>
<TABLE>
<CAPTION>
(in thousands)                                                          PLAN B
                                              ------------------------------------------------------------
                                                             Three Months
                                               YEAR ENDED       Ended         Year Ended      Year Ended
                                              DECEMBER 31,    December 31,   September 30,   September 30,
                                                 2002            2001            2001            2000
                                              ------------    ------------   -------------   -------------

<S>                                           <C>             <C>            <C>             <C>
Components of net periodic benefit cost:
Service cost                                      $   396        $  80         $   255          $   265
Interest cost                                       1,422          320           1,267            1,361
Expected long-term return on assets                (1,619)        (406)         (1,466)          (1,577)
Prior service cost amortization                       354           59             235              235
Actuarial loss (gain)                                  --           --             (28)              --
Transition amortization                                43           14              57               57
                                                  -------        -----         -------          -------
Net periodic expense                              $   596        $  67         $   320          $   341
                                                  =======        =====         =======          =======
</TABLE>

Net pension expense for Alagasco was $3,224,000 for the year ended December 31,
2002, $918,000 for the three-months ended December 31, 2001 and $1,812,000 and
$1,466,000 for the years ended September 30, 2001 and 2000, respectively.

<TABLE>
<CAPTION>
                                                                          PLAN A
                                                  ---------------------------------------------------------
                                                  DECEMBER 31,   December 31,  September 30,  September 30,
                                                     2002           2001           2001           2000
                                                  ------------   ------------  -------------  -------------

<S>                                               <C>            <C>           <C>            <C>
Weighted average rate assumptions in
  pension actuarial calculations:
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%
</TABLE>

<TABLE>
<CAPTION>
                                                                          PLAN B
                                                  ---------------------------------------------------------
                                                  DECEMBER 31,   December 31,  September 30,  September 30,
                                                     2002           2001           2001           2000
                                                  ------------   ------------  -------------  -------------

<S>                                               <C>            <C>           <C>            <C>
Weighted average rate assumptions in
  pension actuarial calculations:
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%
</TABLE>

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, 2002, of $21.7 million. Alagasco established a
regulatory asset of $14.7 million 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 $4.3 million and the balance of $1.7 million was recorded as a
component of accumulated other comprehensive income, net of tax. Subsequent to
December 31, 2002, Energen contributed an additional $9 million to pension Plan
A assets.

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 year ended December 31, 2002, the three
months ended December 31, 2001 and the years ended September 30, 2001 and 2000
was $314,000, $(125,000), $381,000 and $372,000, respectively. At September 30,
2002 and 2001 and at June 30, 2001, the accumulated post-retirement benefit
obligation related to these agreements was $10,093,000, $9,198,000 and
$5,465,000, respectively, and the projected benefit obligation was $15,209,000,
$14,082,000, and $10,750,000, respectively. An accrued post-retirement benefit
liability of $5,860,000, $5,589,000 and $2,408,000 was recorded at December 31,
2002 and 2001 and September 30, 2001, respectively.

The Company recorded a minimum pension liability for supplemental retirement
plans of $4.2 million at December 31, 2002. A corresponding amount was
recognized as an intangible asset for the unrecognized prior service cost of
$81,000 and the balance was recorded as a component of accumulated other
comprehensive income, net of tax, of $2.6 million.

In addition to providing pension benefits, the Company provides certain
post-retirement health care and life


                                      52
<PAGE>
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.

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

<TABLE>
<CAPTION>
(in thousands)                                                                   SALARIED EMPLOYEES
                                                            -------------------------------------------------------------
                                                            SEPTEMBER 30,    September 30,      June 30,         June 30,
                                                                2002             2001             2001             2000
                                                            -------------    -------------      --------         --------

<S>                                                         <C>              <C>                <C>              <C>
Projected post-retirement benefit obligation:
Balance at beginning of period                                $ 35,888         $ 36,518         $ 29,811         $ 29,144
Service cost                                                       831              261            1,095            1,092
Interest cost                                                    2,120              649            2,327            2,203
Actuarial loss (gain)                                           (6,264)          (1,274)           4,964           (1,146)
Benefits paid                                                   (1,567)            (266)          (1,679)          (1,482)
                                                              --------         --------         --------         --------
Balance at end of period                                        31,008           35,888           36,518           29,811
                                                              --------         --------         --------         --------
Plan assets:
Fair value of plan assets at beginning of period                30,921           36,142           41,004           35,494
Actual return on plan assets                                    (7,073)          (5,184)          (4,520)           4,186
Company contribution                                             1,846              229            1,337            2,806
Benefits paid                                                   (1,567)            (266)          (1,679)          (1,482)
                                                              --------         --------         --------         --------
Fair value of plan assets at end of period                      24,127           30,921           36,142           41,004
                                                              --------         --------         --------         --------
Amounts recognized in the consolidated balance sheets:
Funded status of plan                                           (6,881)          (4,967)            (376)          11,193
Unrecognized actuarial loss (gain)                              (1,259)          (4,035)          (8,667)         (19,435)
Unrecognized net transition obligation (asset)                   7,809            8,491            8,672            9,395
Company contribution                                               265              410              369               --
                                                              --------         --------         --------         --------
Accrued pension asset (liability)                             $    (66)        $   (101)        $     (2)        $  1,153
                                                              ========         ========         ========         ========
</TABLE>


<TABLE>
<CAPTION>
(in thousands)                                                              UNION EMPLOYEES
                                                            -------------------------------------------------------------
                                                            SEPTEMBER 30,    September 30,      June 30,         June 30,
                                                                2002             2001             2001             2000
                                                            -------------    -------------      --------         --------

<S>                                                         <C>              <C>                <C>              <C>
Projected post-retirement benefit obligation:
Balance at beginning of period                                $ 40,077         $ 40,986         $ 39,291         $ 37,423
Service cost                                                       807              218              733            1,876
Interest cost                                                    2,800              727            3,095            2,852
Plan amendment                                                     248               --               --               --
Actuarial loss (gain)                                          (11,282)          (1,450)             124           (1,635)
Benefits paid                                                   (2,041)            (404)          (2,257)          (1,225)
                                                              --------         --------         --------         --------
Balance at end of period                                        30,609           40,077           40,986           39,291
                                                              --------         --------         --------         --------
Plan assets:
Fair value of plan assets at beginning of period                27,954           31,917           35,410           26,702
Actual return on plan assets                                    (4,159)          (4,628)          (5,749)           3,928
Company contribution                                             2,141            1,069            4,513            6,005
Benefits paid                                                   (2,041)            (404)          (2,257)          (1,225)
                                                              --------         --------         --------         --------
Fair value of plan assets at end of period                      23,895           27,954           31,917           35,410
                                                              --------         --------         --------         --------
Amounts recognized in the consolidated balance sheets:
Funded status of plan                                           (6,714)         (12,123)          (9,069)          (3,881)
Unrecognized actuarial loss (gain)                              (7,869)          (3,314)          (7,269)         (11,274)
Unrecognized prior service costs                                   237               --               --               --
Unrecognized net transition obligation (asset)                  13,811           15,096           15,417           16,702
Company contribution                                               392              494            1,069               --
                                                              --------         --------         --------         --------
Accrued pension asset (liability)                             $   (143)        $    153         $    148         $  1,547
                                                              ========         ========         ========         ========
</TABLE>


                                      53
<PAGE>
Net periodic post-retirement benefit expense included the following:

<TABLE>
<CAPTION>
(in thousands)                                                         SALARIED EMPLOYEES
                                                ---------------------------------------------------------------
                                                                  Three Months
                                                 YEAR ENDED         Ended         Year Ended       Year Ended
                                                DECEMBER 31,      December 31,   September 30,    September 30,
                                                   2002              2001            2001              2000
                                                ------------      ------------   -------------    -------------

<S>                                             <C>               <C>            <C>              <C>
Components of net periodic benefit cost:
Service cost                                      $   831           $ 261           $ 1,095           $ 1,092
Interest cost                                       2,120             649             2,327             2,203
Expected long-term return on assets                (1,678)           (490)           (1,994)           (1,721)
Actuarial loss (gain)                                (434)           (111)           (1,098)           (1,029)
Transition amortization                               682             181               723               723
                                                  -------           -----           -------           -------
Net periodic expense                              $ 1,521           $ 490           $ 1,053           $ 1,268
                                                  =======           =====           =======           =======
</TABLE>

<TABLE>
<CAPTION>
(in thousands)                                                               UNION EMPLOYEES
                                                ---------------------------------------------------------------
                                                                  Three Months
                                                 YEAR ENDED         Ended         Year Ended       Year Ended
                                                DECEMBER 31,      December 31,   September 30,    September 30,
                                                   2002              2001            2001              2000
                                                ------------      ------------   -------------    -------------

<S>                                             <C>               <C>            <C>              <C>
Components of net periodic benefit cost:
Service cost                                      $   807           $ 218           $   733           $ 1,876
Interest cost                                       2,800             727             3,095             2,852
Expected long-term return on assets                (2,472)           (720)           (1,723)           (1,292)
Actuarial loss (gain)                                 (93)            (57)             (336)             (271)
Prior service cost                                     12              --                --                --
Transition amortization                             1,285             321             1,285             1,285
                                                  -------           -----           -------           -------
Net periodic expense                              $ 2,339           $ 489           $ 3,054           $ 4,450
                                                  =======           =====           =======           =======
</TABLE>

Net periodic post-retirement benefit expense for Alagasco was $3,493,000 for
the year ended December 31, 2002, $905,000 for the three months ended December
31, 2001 and $3,959,000 and $5,449,000 for the years ended September 30, 2001
and 2000, respectively.

<TABLE>
<CAPTION>
                                                                           SALARIED EMPLOYEES
                                                      ------------------------------------------------------------
                                                      DECEMBER 31,    December 31,   September 30,   September 30,
                                                         2002            2001            2001            2000
                                                      ------------    ------------   -------------   -------------
<S>                                                   <C>             <C>            <C>             <C>
Weighted average rate assumptions
  in pension actuarial calculations:
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%
Health care cost trend rate                          GRADED RATE         7.50%           7.50%           7.50%
</TABLE>


<TABLE>
<CAPTION>
                                                                            UNION EMPLOYEES
                                                      ------------------------------------------------------------
                                                      DECEMBER 31,    December 31,   September 30,   September 30,
                                                         2002            2001            2001            2000
                                                      ------------    ------------   -------------   -------------
<S>                                                   <C>             <C>            <C>             <C>
Weighted average rate assumptions
  in pension actuarial calculations:
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%
Health care cost trend rate                          GRADED RATE         7.50%           7.50%           7.50%
</TABLE>

The weighted average health care cost trend rate at December 31, 2002 for both
salaried and union employees is a 10% graduated rate down to 6% per year for
employees under age 65 and a 12% graduated rate down to 6% per year for
employees at or above age 65. This rate used in determining the accumulated
post-retirement benefit obligation has an effect on the amounts reported. For
example, with respect to salaried employees, increasing the


                                      54
<PAGE>
weighted average health care cost trend rate by 1 percentage point would
increase the accumulated post-retirement benefit obligation by $2,708,000 and
the net periodic post-retirement benefit cost by $283,000. For union employees,
increasing the weighted average health care cost trend rate by 1 percentage
point would increase the accumulated post-retirement benefit obligation by
$2,152,000 and the net periodic post-retirement benefit cost by $213,000.

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 has a long-term disability plan covering most salaried employees.
The Company had expense for the year ended December 31, 2002 of $304,000. The
Company had no expense for this plan in the three-months ended December 31,
2001 and in the years ended September 30, 2001 and 2000.

6.       COMMON STOCK PLANS
-------------------------------------------------------------------------------

A majority of Company employees are eligible to participate in the Energen
Employee Savings Plan (ESP) by investing a portion of their compensation in the
ESP, with the Company matching a part of the employee investment by
contributing Company common stock (new issue or treasury shares) or funds for
the purchase of Company common stock. The ESP also contains employee stock
ownership plan provisions. At December 31, 2002, a total of 148,594 common
shares were reserved for issuance under the ESP. Expense associated with
Company contributions to the ESP was $3,963,000 for the year ended December 31,
2002, $803,000 for the three months ended December 31, 2001, and $3,597,000 and
$3,381,000 for the years ended September 30, 2001 and 2000, respectively.

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 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; accordingly, 700,000 shares have been reserved for
issuance. Under the Plan, 76,120 and 102,860 performance units were awarded in
the years ended September 30, 2001 and 2000, respectively. According to the
provisions of the Plan, no additional performance units can be awarded after
September 30, 2001. 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,
111,760 performance units were awarded in the three months ended December 31,
2001. The Company recorded expense of $2,136,250 for the year ended December
31, 2002, $722,500 for the three months ended December 31, 2001, and $2,311,000
and $4,448,000 for the years ended September 30, 2001 and 2000, respectively,
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 22,775 shares awarded in the three-months ended December
31, 2001 and 57,190 and 12,500 shares awarded in the years ended September 30,
2001 and 2000, respectively. The sale or transfer of the shares is limited
during the restricted period. The Company recorded expense of $742,875 for the
year ended December 31, 2002, $188,000 for the three-months ended December 31,
2001 and $583,000 and $97,000 for the years ended September 30, 2001 and 2000,
respectively, 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:


                                      55
<PAGE>
<TABLE>
<CAPTION>
                                             1997 STOCK INCENTIVE PLAN          1988 STOCK OPTION PLAN
                                           ------------------------------    ----------------------------
                                                         Weighted Average                Weighted Average
                                             Shares       Exercise Price      Shares      Exercise Price
                                           ---------     ----------------    --------    ----------------

<S>                                        <C>           <C>                 <C>         <C>
Outstanding at September 30, 1999            335,270         $  18.25         422,076         $12.29
Granted                                      108,500          18.8125              --             --
Exercised                                    (40,262)           18.25        (157,660)          9.65
                                           ---------         --------        --------         ------
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                                           --               --              --             --
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
                                           ---------         --------        --------         ------
Exercisable at September 30, 2000            158,488         $  18.25         237,836         $13.37
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
                                           ---------         --------        --------         ------
Remaining reserved for issuance at
   December 31, 2002                       1,911,541               --              --             --
                                           ---------         --------        --------         ------
</TABLE>

The following table summarizes information about options outstanding as of
December 31, 2002:

<TABLE>
<CAPTION>
          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
-----------------      -------      ---------------------    ---------------     -------      --------------------
<S>                    <C>          <C>                      <C>                 <C>          <C>
 $18.25-$18.81         230,343            5.80 years          $10.06-$11.06       41,000            2.40 years
    $27.44             136,300            7.83 years          $15.00-$18.25       94,514            4.57 years
    $22.63             118,850            8.83 years               --               -                 --
 -------------         -------            ----                -------------      -------            ----
 $18.25-$27.44         485,493            7.11 years          $10.06-$18.25      135,514            3.91 years
 =============         =======            ====                =============      =======            ====
</TABLE>

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, no shares were awarded during the year
ended December 31, 2002, 6,000 shares were awarded during the three-months
ended December 31, 2001 and 4,800 and 5,054 shares were awarded during the
years ended September 30, 2001 and 2000, respectively, leaving 144,639 shares
reserved for issuance as of December 31, 2002.

In 1996 the Company amended its Dividend Reinvestment and Common Stock Purchase
Plan to include a direct stock purchase feature which allows purchases by
non-shareholders. In connection with the amendment, 1,500,000 shares were added
to the Plan. As of December 31, 2002, 843,218 common shares were reserved under
this Plan.

On April 26, 2000, the Company authorized the repurchase of up to 1,000,000
shares of the Company's common stock, in addition to the 500,000 shares
authorized on May 25, 1994. For the year ended December 31, 2002 the Company
repurchased 5,319 shares, for the three-months ended December 31, 2001 the
Company repurchased 55,074 shares, and for the years ended September 30, 2001
and 2000 the Company repurchased 91,600 and 290,000 shares, respectively. As of
December 31, 2002, a total of 787,718 shares remain authorized for future
repurchase.

On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan)
designed to protect


                                      56
<PAGE>
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 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, 2002, were convertible into 347,454 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 2010.
These contracts typically contain minimum demand charge obligations on the part
of Alagasco.

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

To date, the Company's expenditures to comply with environmental or safety
regulations have not been material and are not expected to be significant in
the future. However, new regulations, enforcement policies, claims for damages
or other events could result in significant future costs.

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


                                      57
<PAGE>
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, Energen 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 $8,273,000 for
the year ended December 31, 2002, $1,837,000 for the three-months ended
December 31, 2001, $7,324,000 and $6,267,000 for the years ended September 30,
2001 and 2000, respectively. Minimum future rental payments required after 2002
under leases with initial or remaining noncancelable lease terms in excess of
one year are as follows:

<TABLE>
<CAPTION>
                              Years Ending December 31, (in thousands)
-----------------------------------------------------------------------------------------------------
 2003              2004             2005            2006             2007         2008 AND THEREAFTER
------            ------           ------          ------           ------        -------------------
<S>               <C>              <C>             <C>              <C>           <C>
$3,609            $3,007           $2,770          $2,690           $2,412              $31,395
</TABLE>

Alagasco's total payments related to leases included as operating expense,
inclusive of the sale-leaseback, were $2,362,000 for the year ended December
31, 2002, $587,000 for the three-months ended December 31, 2001 $2,343,000 and
$2,209,000 for the years ended September 30, 2001 and 2000, respectively.
Minimum future rental payments required after 2002 under leases with initial or
remaining noncancelable lease terms in excess of one year are as follows:

<TABLE>
<CAPTION>
                              Years Ending December 31, (in thousands)
-----------------------------------------------------------------------------------------------------
 2003              2004             2005            2006             2007         2008 AND THEREAFTER
------            ------           ------          ------           ------        -------------------
<S>               <C>              <C>             <C>              <C>           <C>
$2,150            $1,590           $1,512          $1,504           $1,494            $22,251
</TABLE>

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 $537,533,000, would be $570,243,000 at December 31, 2002. The fair value of
Alagasco's fixed-rate long-term debt, including the current portion, with a
carrying value of $184,533,000, would be $200,410,000 at December 31, 2002. The
fair values were based on the market value of debt with similar maturities and
current interest rates.

Alagasco entered into an agreement with a financial institution whereby it can
sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million. Alagasco
sold installment receivables of $5,010,000 in the year ended December 31, 2002,
$2,120,000 in the three-months ended December 31, 2001 and $5,444,000 and
$6,879,000 in the years ended September 30, 2001 and 2000, respectively. At
December 31, 2002 the balance of these installment receivables was $10,566,000
and represented 13,812 accounts. At December 31, 2001 and September 30, 2001,
the balance of these installment receivables was $12,838,000 and $13,249,000,
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.

PRICE RISK: The Company adopted SFAS No. 133 (subsequently amended by SFAS Nos.
137 and 138) 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 when the forecasted transaction affects
earnings. The ineffective portion of a derivative's change in fair value is
required to be recognized in earnings immediately. Derivatives that do not
qualify for hedge treatment under SFAS No. 133 must be recorded at fair value
with gains or losses recognized in earnings in the period of change.


                                      58
<PAGE>
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. 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 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 as originally forecasted to occur. As a result,
Energen's net income in the three-month transition period ended December 31,
2001, reflected a one-time, non-cash expense of $5.5 million, net of tax. 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.

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. At December 31, 2001 and September 30, 2001, the
Company had current gains on the fair value of derivatives of $3.6 million and
$22.5 million, respectively, included in prepayments and other and $3 million
and $3.2 million, respectively, of non-current gains included in deferred
charges and other.

As of December 31, 2002, $9.4 million, net of tax, of deferred net losses on
derivative instruments recorded in accumulated other comprehensive income are
expected to be reclassified to earnings during the next twelve-month period.
Gains and losses on derivative instruments that are not accounted for as cash
flow hedge transactions, as well as the ineffective portion of the change in
fair value of derivatives accounted for as cash flow hedges, are included in
operating revenues in the consolidated financial statements. The Company
recorded a $0.8 million after-tax loss in 2002 for the ineffective portion of
the change in fair value of derivatives accounted for as cash flow hedges.
Also, Energen Resources recorded an after-tax gain of $151,000 in 2002 on
contracts which did not meet the definition of cash flow hedges under SFAS No.
133. As of December 31, 2002, all of the Company's swaps and hedges met the
definition of a cash flow hedge. Subsequent to December 31, 2002, the Company
entered into a hedge contract for 150 MBbl of oil that did not meet the
definition of a cash flow hedge. The contract is considered by management to be
an economic hedge and is accounted for as a mark-to-market transaction. The
Company had $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, 2002.

Energen Resources entered into the following contracts and swaps:

<TABLE>
<CAPTION>
                                              AVERAGE CONTRACT
PRODUCTION PERIOD     TOTAL HEDGED VOLUME          PRICE                     DESCRIPTION
-----------------     -------------------    -----------------          ---------------------
                                           NATURAL GAS
---------------------------------------------------------------------------------------------

<S>                   <C>                    <C>                        <C>
    2003                  30.9 Bcf               $4.13 Mcf                   NYMEX Swaps
                           4.4 Bcf               $3.86 Mcf               Basin Specific Swaps
                           4.8 Bcf           $3.72 - $4.70 Mcf          Basin Specific Collars
    2004                   6.5 Bcf               $4.02 Mcf                   NYMEX Swaps
                         * 2.4 Bcf               $4.42 Mcf                   NYMEX Swaps
                        * 13.9 Bcf               $3.83 Mcf               Basin Specific Swaps
                           2.4 Bcf           $4.05 - $4.44 Mcf              NYMEX Collars
    2005                   1.2 Bcf              $3.75 Mcf                   NYMEX Swaps
</TABLE>


                                      59
<PAGE>
<TABLE>
<CAPTION>
                               NATURAL GAS BASIS DIFFERENTIAL
---------------------------------------------------------------------------------------------

<S>                   <C>                    <C>                        <C>
    2003                  11.7 Bcf                  **                       Basis Swaps
                         * 4.0 Bcf                  **                       Basis Swaps


                                                   OIL
---------------------------------------------------------------------------------------------

    2003                2,478 MBbl              $26.26 Bbl                   NYMEX Swaps
                        * 150 MBbl              $28.00 Bbl                   NYMEX Puts
    2004                * 120 MBbl              $26.15 Bbl                   NYMEX Swaps



                                    OIL BASIS DIFFERENTIAL
---------------------------------------------------------------------------------------------

<S>                   <C>                    <C>                        <C>
    2003                2,174 MBbl                  **                        Basis Swaps
                         * 97 MBbl                  **                        Basis Swaps



                                    NATURAL GAS LIQUIDS
---------------------------------------------------------------------------------------------

<S>                   <C>                    <C>                        <C>
    2003                  38 MMGal               $0.42 Gal                   Liquids Swaps
    2004                * 30 MMGal               $0.41 Gal                   Liquids Swaps
</TABLE>

*        Contract entered into subsequent to December 31, 2002.

**       Basis 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 September 30, 2005.

On December 4, 2000, the APSC authorized Alagasco to engage in energy
risk-management activities to manage the utility's cost of gas supply. As of
December 31, 2002, Alagasco had recorded a $16,750,000 receivable in
prepayments and other representing the fair value of derivatives. As required
by SFAS No. 133, Alagasco recognizes all derivatives as either assets or
liabilities on the balance sheet. Any gains or losses are passed through to
customers using the mechanisms of the GSA in accordance with Alagasco's APSC
approved tariff.

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 during the month
following the month of 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. The Company is
monitoring this situation 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 buy approximately 23%, 12% and 11%,
respectively, of Energen Resources' estimated 2003 production. Energen
Resources' other purchasers each buy less than 10% of production.

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.


                                      60
<PAGE>
9.       RECONCILIATION OF EARNINGS PER SHARE
-------------------------------------------------------------------------------

<TABLE>
<CAPTION>
                                                       YEAR ENDED                       Three Months Ended
(in thousands, except per share amounts)            DECEMBER 31, 2002                    December 31, 2001
                                             ---------------------------------    ---------------------------------
                                                                     PER SHARE                            Per Share
                                             INCOME      SHARES       AMOUNT      Income      Shares        Amount
                                             -------     ------      ---------    ------      ------      ---------

<S>                                          <C>         <C>         <C>          <C>         <C>         <C>
Basic EPS                                    $68,639     33,605        $2.04      $3,658      31,052        $0.12
Effect of dilutive securities
     Long-range performance shares                           88                                   96
     Stock options                                          143                                  127
     Restricted stock                                         2                                    2
                                             -------     ------        -----      ------      ------        -----
Diluted EPS                                  $68,639     33,838        $2.03      $3,658      31,277        $0.12
                                             =======     ======        =====      ======      ======        =====
</TABLE>

<TABLE>
<CAPTION>
                                                       Year Ended                           Year Ended
(in thousands, except per share amounts)           September 30, 2001                   September 30, 2000
                                           ----------------------------------  ---------------------------------
                                                                    Per Share                          Per Share
                                            Income      Shares        Amount   Income       Shares       Amount
                                           -------      ------      ---------  -------      ------     ---------

<S>                                        <C>          <C>         <C>        <C>          <C>        <C>
Basic EPS                                  $67,896      30,726        $2.21    $53,018      30,108        $1.76
Effect of dilutive securities
     Long-range performance shares                         165                                 126
     Stock options                                         187                                 125
     Restricted stock                                        6                                  --
                                           -------      ------        -----    -------      ------        -----
Diluted EPS                                $67,896      31,084       $ 2.18    $53,018      30,359        $1.75
                                           =======      ======       ======    =======      ======        =====
</TABLE>

For the year ended December 31, 2002, the Company had 136,300 options and
20,464 shares of non-vested restricted stock that were excluded from the
computation of diluted EPS, as their effect was antidilutive.

10.      ASSET RETIREMENT OBLIGATIONS
-------------------------------------------------------------------------------

The Company has 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 was required to recognize
a liability for the present value of all legal obligations associated with the
retirement of tangible long-lived assets and capitalize an equal amount as a
cost of the asset as of January 1, 2002. Upon initial application of the
Statement, a cumulative effect of a change in accounting principle was also
required in order to recognize a liability for any 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.
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
in resulting gain or loss.

Energen Resources recorded a liability representing expected future costs
associated with site reclamation, facilities dismantlement, and plug and
abandonment of wells as follows:

<TABLE>
<CAPTION>
(in thousands)

<S>                                                                     <C>
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
                                                                        ========
</TABLE>

For the year ended December 31, 2002, Energen Resources recognized additional
costs of $20.1 million, depreciation expense of $1.7 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.


                                      61
<PAGE>
The Company's gas distribution system operates under various property easement
agreements primarily related to 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 will be operated in perpetuity and historical abandonment
costs resulting from such easement agreements have been de minimis, no asset
retirement obligation has been recorded.

11.      SUPPLEMENTAL CASH FLOW INFORMATION
-------------------------------------------------------------------------------

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

<TABLE>
<CAPTION>
                                                                         Three Months
                                                         YEAR ENDED         Ended         Year Ended        Year Ended
                                                        DECEMBER 31,     December 31,    September 30,    September 30,
(in thousands)                                             2002             2001             2001              2000
                                                        ------------     ------------    -------------    ------------

<S>                                                     <C>              <C>             <C>              <C>
Interest paid, net of amount capitalized                  $43,085          $11,418          $42,905          $37,717
Income taxes paid                                         $ 9,838          $ 4,261          $11,636          $11,885
Noncash investing activities:
    First Permian, L.L.C. stock issuance                  $72,891          $    --          $    --          $    --
    Capitalized depreciation                              $   223          $    51          $   243          $   217
    Allowance for funds used during construction          $ 1,336          $   122          $ 2,098          $ 1,172
                                                          -------          -------          -------          -------
</TABLE>

Under SFAS No. 143, the Company recorded additional 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,
all of which are non-cash adjustments concerning Energen's cash flow activities
for the year ended December 31, 2002.

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

<TABLE>
<CAPTION>
                                                                        Three Months
                                                          YEAR ENDED       Ended         Year Ended       Year Ended
                                                         DECEMBER 31,    December 31,   September 30,    September 30,
(in thousands)                                              2002            2001            2001             2000
                                                         ------------    ------------   -------------    -------------

<S>                                                      <C>             <C>            <C>              <C>
Interest paid, net of amount capitalized                  $14,012          $5,666          $12,154          $ 9,787
Income taxes paid                                         $15,519          $9,425          $18,318          $15,833
Noncash investing activities:
    Capitalized depreciation                              $   223          $   51          $   243          $   217
    Allowance for funds used during construction          $ 1,336          $  122          $ 2,098          $ 1,172
                                                          -------          ------          -------          -------
</TABLE>

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." This statement 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 flow 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. All assets
held-for-sale must be reported at the lower of the carrying amount or fair
value. Accordingly, during the second quarter of 2002, Energen Resources
recorded a pre-tax writedown of $2.8 million on certain non-strategic gas
properties located in the Gulf Coast region, adjusting the carrying amount of
the properties to their fair value based upon expected future discounted cash
flows. In November 2002, the Company sold these properties for approximately
the carrying amount. The gain on disposals for the year ended December 31,
2002, included a total of $3.7 million largely due to sales of property located
in the Permian Basin. As of December 31, 2002, the Company had no properties
classified as held-for-sale.


                                      62
<PAGE>
In 2001 and 2000, a pre-tax gain of $0.8 million and $1.1 million,
respectively, was recorded in operating revenues from continuing operations for
certain non-strategic property sales. In the third fiscal quarter of 2000, as a
result of a downward reserve revision in a small oil and gas field, Energen
Resources recorded a pre-tax write-down of $3.5 million in additional
depreciation, depletion and amortization expense, adjusting the carrying amount
of the properties to their fair value based on expected future discounted cash
flows.

The following are the results of operations from discontinued operations:

<TABLE>
<CAPTION>
                                                                     Three Months
                                                     YEAR ENDED         Ended         Year Ended      Year Ended
                                                    DECEMBER 31,     December 31,   September 30,   September 30,
(in thousands, except per share data)                  2002             2001            2001            2000
                                                    ------------     ------------   -------------   -------------

<S>                                                 <C>              <C>            <C>             <C>
Oil and gas revenues                                 $ 1,744           $1,164          $7,599          $4,186
                                                     -------           ------          ------          ------

Pretax income (loss) from
   discontinued operations                           $  (438)          $  138          $2,974          $  790
Income tax expense (benefit)                            (171)              59           1,165             307
                                                     -------           ------          ------          ------
INCOME (LOSS) FROM DISCONTINUED OPERATIONS              (267)              79           1,809             483
                                                     -------           ------          ------          ------

Impairment charge on held-for-sale property           (2,815)              --              --              --
(Loss) gain on disposal                                3,700               --              --              --
Income tax expense (benefit)                             345               --              --              --
                                                     -------           ------          ------          ------
GAIN ON DISPOSAL                                         540               --              --              --
                                                     -------           ------          ------          ------

TOTAL INCOME (LOSS) FROM
   DISCONTINUED OPERATIONS                           $   273           $   79          $1,809          $  483
                                                     =======           ======          ======          ======

DILUTED EARNINGS PER AVERAGE COMMON SHARE
Income (Loss) from Discontinued Operations           $ (0.01)          $   --          $ 0.05          $ 0.02
Gain on Disposal                                        0.02               --              --              --
                                                     -------           ------          ------          ------
Total Income from Discontinued  Operations           $  0.01           $   --          $ 0.05          $ 0.02
                                                     =======           ======          ======          ======

BASIC EARNINGS PER AVERAGE COMMON SHARE
Income (Loss ) from Discontinued Operations          $ (0.01)          $   --          $ 0.05          $ 0.02
Gain on Disposal                                        0.02               --              --              --
                                                     -------           ------          ------          ------
Total Income from Discontinued Operations            $  0.01           $   --          $ 0.05          $ 0.02
                                                     =======           ======          ======          ======
</TABLE>

13.      SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
-------------------------------------------------------------------------------

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

<TABLE>
<CAPTION>
                                                                              Year Ended December 31, 2002
                                                           --------------------------------------------------------------------
(in thousands, except per share amounts)                      First              Second             Third             Fourth
                                                           -----------        -----------        -----------        -----------

<S>                                                        <C>                <C>                <C>                <C>
Operating revenues                                         $   244,383        $   138,464        $   116,952        $   177,376
Operating income                                           $    61,022        $    25,721        $    13,187        $    36,156
Income from continuing operations before cumulative
   effect of change in accounting principle                $    39,038        $    12,611        $       124        $    18,813
Net income                                                 $    36,682        $    12,744        $       127        $    19,086
Diluted earnings per average common share
    Continuing operations                                  $      1.24        $      0.37        $      0.00        $      0.54
    Net income                                             $      1.17        $      0.37        $      0.00        $      0.55
Basic earnings per average common share
    Continuing operations                                  $      1.25        $      0.37        $      0.00        $      0.54
    Net income                                             $      1.18        $      0.37        $      0.00        $      0.55
                                                           -----------        -----------        -----------        -----------
</TABLE>


                                      63
<PAGE>
<TABLE>
<CAPTION>
                                                                                 Year Ended September 30, 2001
                                                           --------------------------------------------------------------------
(in thousands, except per share amounts)                      First             Second              Third              Fourth
                                                           -----------        -----------        -----------        -----------

<S>                                                        <C>                <C>                <C>                <C>
Operating revenues                                         $   173,988        $   331,440        $   159,894        $   112,052
Operating income                                           $    26,725        $    67,931        $    22,740        $     3,639
Income (loss) from continuing operations before
  cumulative effect of change in accounting principle      $    13,115        $    46,503        $    10,013        $    (3,555)
Net income (loss)                                          $    13,719        $    46,992        $    10,373        $    (3,188)
Diluted earnings (loss) per average common share
    Continuing operations                                  $      0.42        $      1.50        $      0.32        $     (0.11)
    Net income (loss)                                      $      0.44        $      1.52        $      0.33        $     (0.10)
Basic earnings (loss) per average common share
    Continuing operations                                  $      0.43        $      1.52        $      0.32        $     (0.11)
    Net income (loss)                                      $      0.45        $      1.53        $      0.34        $     (0.10)
                                                           -----------        -----------        -----------        -----------
</TABLE>


The summarized quarterly information above has been revised to reflect the
adoption of SFAS No. 143, (see Note 10) and SFAS No. 144, (see Note 12) as of
January 1, 2002.

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

<TABLE>
<CAPTION>
                                                              Year Ended December 31, 2002
                                             --------------------------------------------------------------
(in thousands, except per share amounts)      First            Second            Third              Fourth
                                             --------          -------          --------           --------

<S>                                          <C>               <C>              <C>                <C>
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
                                             --------          -------          --------           --------
</TABLE>

<TABLE>
<CAPTION>
                                                             Year Ended September 30, 2001
                                             --------------------------------------------------------------
(in thousands, except per share amounts)      First             Second           Third             Fourth
                                             --------          -------          --------           --------

<S>                                          <C>               <C>               <C>               <C>
Operating revenues                           $119,126          $270,286          $103,779          $ 60,671
Operating income (loss)                      $  6,498          $ 30,176          $  3,186          $ (3,020)
Net income (loss)                            $  4,040          $ 27,333          $    578          $ (5,936)
                                             --------          -------          --------           --------
</TABLE>

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; this
estimate reflects an effective date of January 1, 2002, with appropriate
purchase price adjustments from that date forward until completion of the
transaction, resulting from interim cash flows and related tax items.

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 acquisition had
occurred at the beginning of each period presented. The pro form 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 acquired companies, after giving effect
to the issuance of 3,043,479 million 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.


                                      64
<PAGE>
<TABLE>
<CAPTION>
                                                                        Three Months
                                                      YEAR ENDED           Ended          Year Ended
Unaudited                                             DECEMBER 31,      December 31,     September 30,
(in thousands, except per share amounts)                 2002              2001              2001
                                                      ------------      ------------     -------------
<S>                                                   <C>               <C>              <C>
Operating revenues                                     $683,780          $153,938          $802,187
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
                                                       ========          ========          ========
</TABLE>

15. REGULATORY ASSETS AND LIABILITES

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

<TABLE>
<CAPTION>
                                                  DECEMBER 31, 2002               December 31, 2001           September 30, 2001
Energen Corporation                           --------------------------       ------------------------      --------------------
(in thousands)                                CURRENT         NONCURRENT       Current       Noncurrent      Current   Noncurrent
                                              -------         ----------       -------       ----------      -------   ----------
<S>                                           <C>             <C>              <C>           <C>             <C>       <C>
Regulatory assets:
     Pension asset                            $    --          $14,744          $   --          $ --          $   --      $ --
     Early retirement costs                        --               --              --            --              95        --
                                              -------          -------          ------          ----          ------      ----
        Total regulatory assets               $    --          $14,744          $   --          $ --          $   95      $ --
                                              =======          =======          ======          ====          ======      ====

Regulatory liabilities:
     Enhanced stability reserve               $ 2,963          $    --          $2,702          $ --          $2,686      $ --
     Gas supply adjustment                     20,851               --           5,760            --           1,106        --
     Deferred income taxes                         --            1,468              --           137              --       242
                                              -------          -------          ------          ----          ------      ----
        Total regulatory liabilities          $23,814          $ 1,468          $8,462          $137          $3,792      $242
                                              =======          =======          ======          ====          ======      ====
</TABLE>

16. TRANSACTIONS WITH RELATED PARTIES

Alagasco purchased natural gas from affiliates amounting to $1,820,000 for the
year ended December 31, 2002, $375,000 for the three-months ended December 31,
2001, $5,254,000 and $3,662,000, for the years ended September 30, 2001 and
2000, respectively. These amounts are included in gas purchased for resale.
Alagasco had net payables to affiliates of $1,432,000 and $3,054,000 at December
31, 2002 and December 31, 2001, net receivables from affiliates of $937,000 at
September 30, 2001 and net payables to affiliates of $1,156,000 at September 30,
2000.

17. OTHER INCOME AND EXPENSE

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

<TABLE>
<CAPTION>
                                                                        Three Months
                                                         YEAR ENDED        Ended         Year Ended       Year Ended
                                                        DECEMBER 31,    December 31,    September 30,    September 30,
(in thousands)                                             2002             2001            2001             2000
                                                        ------------    ------------    -------------    -------------
<S>                                                     <C>             <C>             <C>              <C>
Allowance for funds used during construction              $ 1,336          $  122          $ 2,098          $ 1,172
Merchandise revenues                                       14,155           4,226           14,535           15,885
Other                                                         153               6              192              258
                                                          -------          ------          -------          -------
  Total other income                                      $15,644          $4,354          $16,825          $17,315
                                                          =======          ======          =======          =======

Cost of goods sold                                        $10,215          $3,181          $10,136          $10,777
Other merchandise expense                                   4,888           1,204            4,756            4,763
                                                          -------          ------          -------          -------
   Total other expense                                    $15,103          $4,385          $14,892          $15,540
                                                          =======          ======          =======          =======
</TABLE>


                                       65

<PAGE>

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

<TABLE>
<CAPTION>
                                                     Three Months
                                      YEAR ENDED        Ended        Year Ended      Year Ended
                                     DECEMBER 31,    December 31,   September 30,   September 30,
(in thousands)                          2002            2001            2001            2000
                                     ------------    ------------   -------------   -------------
<S>                                  <C>             <C>            <C>             <C>
Merchandise revenues                   $5,520          $1,596          $5,978          $7,520
                                       ------          ------          ------          ------
  Total other income                   $5,520          $1,596          $5,978          $7,520
                                       ======          ======          ======          ======

Cost of goods sold                     $2,702          $  946          $3,051          $3,564
Other merchandise expense               3,578             892           3,534           3,675
                                       ------          ------          ------          ------
   Total other expense                 $6,280          $1,838          $6,585          $7,239
                                       ======          ======          ======          ======
</TABLE>

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

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," which requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred. The
Company adopted this statement as of January 1, 2002 (See Note 10).

The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or
Disposal Activities" in June 2002. This statement requires that a liability for
costs associated with exit or disposal activities be recognized at fair value in
the period the liability is incurred. This Statement does not apply to costs
associated with the retirement of long-lived assets covered by SFAS No. 143. The
Company has adopted this statement for disposal or exit activities initiated
after December 31, 2002.

The FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure" in December 2002. This statement is effective for
2003 and amends SFAS No. 123, "Accounting for Stock-Based Compensation" by
providing alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. In
addition, SFAS No. 148 requires additional disclosures related to the effect of
stock-based compensation on reported results. The Company has adopted the
disclosure provisions of SFAS No. 148 and is currently reviewing its treatment
of stock-based compensation as well as the impact of this pronouncement.

The FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosures
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others," (FIN 45) in November 2002. FIN 45 clarifies the requirements of SFAS
No. 5, "Accounting for Contingencies," related to a guarantors accounting for,
and disclosures of, the issuance of certain types of guarantees. Management has
completed a review of potential contingencies and noted the following guarantee
disclosure: Alagasco has an agreement with a financial institution whereby it
can sell on an ongoing basis, with recourse, certain installment receivables
related to its merchandising program up to a maximum of $20 million. Alagasco's
exposure to credit loss in the event of non-performance by customers is
represented by the balance of installment receivables (see Note 8). The Company
is required to adopt the provisions for initial recognition and measurement for
all guarantees issued or modified after December 31, 2002 on a prospective
basis. The Company is currently reviewing the impact related to the initial
recognition and measurement guarantees of this Interpretation.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46) which clarifies the application of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." This
Interpretation provides guidance on the identification and consolidation of
variable interest entities (VIEs), whereby control is achieved through means
other than through voting rights. Management has completed an analysis of FIN 46
and has determined that the Company does not have VIEs.


                                       66

<PAGE>

19. 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

<TABLE>
<CAPTION>
                                                      DECEMBER 31,       December 31,     September 30,     September 30,
(in thousands)                                           2002               2001              2001              2000
                                                      ------------       ------------     -------------     -------------
<S>                                                   <C>                <C>              <C>               <C>
Proved                                                $1,091,536          $841,155          $818,535          $707,236
Unproved                                                  11,936             3,807             4,421             6,530
                                                      ----------          --------          --------          --------
     Total capitalized costs                           1,103,472           844,962           822,956           713,766
Accumulated depreciation, depletion, and
  amortization                                           269,616           228,867           209,451           165,447
                                                      ----------          --------          --------          --------
Capitalized costs, net                                $  833,856          $616,095          $613,505          $548,319
                                                      ==========          ========          ========          ========
</TABLE>

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:

<TABLE>
<CAPTION>
                                                       Three Months
                                     YEAR ENDED           Ended            Year Ended          Year Ended
                                    DECEMBER 31,       December 31,       September 30,       September 30,
 (in thousands)                        2002               2001                2001               2000
                                    ------------       ------------       -------------       -------------
<S>                                 <C>                <C>                <C>                 <C>
Property acquisition:
     Proved                          $173,984            $   238            $ 33,764            $ 2,086
     Unproved                          10,193                 81                 552                350
Exploration                               527                339               1,734              1,472
Development                           122,494             24,757             103,574             66,717
                                     --------            -------            --------            -------
Total costs incurred                 $307,198            $25,415            $139,624            $70,625
                                     ========            =======            ========            =======
</TABLE>


                                       67

<PAGE>

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

<TABLE>
<CAPTION>
                                                                               Three Months
                                                              YEAR ENDED          Ended             Year Ended          Year Ended
                                                             DECEMBER 31,      December 31,        September 30,       September 30,
(in thousands)                                                  2002               2001                2001                2000
                                                             ------------      ------------        -------------       -------------
<S>                                                          <C>               <C>                 <C>                 <C>
Gross revenues                                                $254,021            $53,145            $223,150            $184,415
Production (lifting costs)                                      80,333             16,630              77,796              62,028
Exploration expense*                                             3,602                827               4,226               4,890
Depreciation, depletion and amortization**                      69,990             16,020              52,502              55,114
Income tax expense                                              23,929              4,035              18,232               8,298
                                                              --------            -------            --------            --------
Results of continuing operation from producing
activities                                                    $ 76,167            $15,633            $ 70,394            $ 54,085
                                                              ========            =======            ========            ========
</TABLE>

*        Includes a $3.2 million pre-tax writedown in the year ended December
         31, 2002, a $0.7 million pre-tax writedown in the three-months ended
         December 31, 2001, and a $2.7 million and $3.8 million pre-tax
         writedown in the years ended September 30, 2001 and 2000, respectively,
         of a portion of an unproved leasehold
**       Includes a pre-tax writedown of $3.5 million in the year ended
         September 30, 2000 under SFAS No. 121 (see Note 12)

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

<TABLE>
<CAPTION>
                                                                             Three Months
                                                             YEAR ENDED         Ended           Year Ended        Year Ended
                                                            DECEMBER 31,     December 31,      September 30,     September 30,
                                                               2002              2001              2001              2000
                                                            ------------     ------------      -------------     -------------
<S>                                                         <C>              <C>               <C>               <C>
Average sales price including the effects of hedging:
     Gas (Mcf)                                                $ 3.16            $ 2.97            $ 3.09            $ 2.49
     Oil (per barrel)                                         $24.03            $24.19            $23.78            $18.33
     Natural gas liquids (per barrel)                         $12.75            $10.07            $17.61            $16.06
Average sales price excluding the effects of hedging:
     Gas (Mcf)                                                $ 2.96            $ 2.35            $ 4.86            $ 3.06
     Oil (per barrel)                                         $24.75            $19.79            $27.46            $26.45
     Natural gas liquids (per barrel)                         $12.75            $10.07            $17.61            $16.06
Average production (lifting) cost (per Mcfe)                  $ 1.04            $ 0.94            $ 1.16            $ 0.90
Average production tax (per Mcfe)                             $ 0.24            $ 0.20            $ 0.36            $ 0.25
Average depreciation rate (per Mcfe)*                         $ 0.90            $ 0.91            $ 0.79            $ 0.75
                                                              ======            ======            ======            ======
</TABLE>

* Excludes a pre-tax writedown of $3.5 million in the year ended
  September 30, 2000 under SFAS No. 121 (see Note 12)

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

<TABLE>
<CAPTION>
                                              Three Months
                             YEAR ENDED          Ended          Year Ended      Year Ended
                            DECEMBER 31,      December 31,     September 30,   September 30,
                               2002              2001             2001             2000
                            ------------      ------------     -------------   -------------
<S>                         <C>               <C>              <C>             <C>
Exploratory:
     Productive                  0.1              0.3              0.1              0.3
     Dry                         0.1               --              1.3               --
                               -----             ----             ----             ----
        Total                    0.2              0.3              1.4              0.3
                               =====             ====             ====             ====
Development:
     Productive                145.9             23.8             90.7             70.6
     Dry                         4.3               --               --              1.5
                               -----             ----             ----             ----
        Total                  150.2             23.8             90.7             72.1
                               =====             ====             ====             ====
</TABLE>


                                       68
<PAGE>
As of December 31, 2002, the Company was participating in the drilling of 6
gross development wells, with the Company's interest equivalent to 3.31 wells.

PRODUCTIVE WELLS AND ACREAGE: The following table sets forth the total gross and
net productive gas and oil wells as of December 31, 2002, and developed and
undeveloped acreage as of the latest practicable date prior to year-end:

<TABLE>
<CAPTION>
                                                           Gross           Net
                                                          -------        -------
<S>                                                       <C>            <C>
Gas Wells                                                   3,426          1,725
Oil Wells                                                   2,785          1,069
                                                          -------        -------
Developed Acreage                                         772,519        428,080
Undeveloped Acreage                                       121,871         53,428
                                                          -------        -------
</TABLE>

There were 42 wells with multiple completions in 2002. 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.

<TABLE>
<CAPTION>
Year ended December 31, 2002                                            Gas MMcf         Oil MBbl          NGL MBbl
----------------------------                                            --------          -------          -------
<S>                                                                     <C>               <C>              <C>
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
                                                                        ========          =======          =======
</TABLE>

<TABLE>
<CAPTION>
Three months ended December 31, 2001                                    Gas MMcf         Oil MBbl          NGL MBbl
------------------------------------                                    --------          -------          -------
<S>                                                                     <C>               <C>              <C>
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
                                                                        ========          =======          =======
</TABLE>

<TABLE>
<CAPTION>

Year ended September 30, 2001                                           Gas MMcf         Oil MBbl          NGL MBbl
-----------------------------                                           --------          -------          -------
<S>                                                                     <C>               <C>              <C>
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
                                                                        ========          =======          =======
</TABLE>


                                       69
<PAGE>

<TABLE>
<CAPTION>
Year ended September 30, 2000                                           Gas MMcf         Oil MBbl          NGL MBbl
-----------------------------                                           --------          -------          -------
<S>                                                                     <C>               <C>              <C>
Proved reserves at beginning of period                                   740,001           24,719            21,937
Revisions of previous estimates                                           37,028           (2,601)            3,250
Purchases                                                                  1,819            1,997               308
Discoveries and other additions                                           47,146            2,890             1,942
Production                                                               (48,084)          (2,304)           (1,429)
Sales                                                                       (454)            (183)               (1)
                                                                          ------           ------              ----
Proved reserves at end of period                                         777,456           24,518            26,007
                                                                          ------           ------              ----
Proved developed reserves at end of period                               691,287           18,714            22,906
                                                                         =======           ======            ======
</TABLE>

During 2002, Energen Resources invested approximately $174 million in proved
property acquisitions. Energen Resources sold approximately 25 Bcfe of proved
reserves, recording net pre-tax gains of $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, 2002, December 31, 2001, and September 30, 2001 and 2000, the Company had a
deferred hedging loss of $17.2 million, a deferred hedging gain of $15.2 million
and $25.7 million and a deferred hedging loss of $89.4 million, respectively,
all of which are excluded from the calculation of standardized measure of future
net cash flows.

<TABLE>
<CAPTION>
                                                                       Three Months
                                                        YEAR ENDED        Ended         Year Ended      Year Ended
                                                       DECEMBER 31,    December 31,    September 30,   September 30,
(in thousands)                                             2002            2001            2001            2000
                                                       ------------     -----------    -------------   -------------
<S>                                                    <C>              <C>            <C>             <C>
Future gross revenues                                   $5,455,802      $2,181,148      $1,672,436      $4,824,681
Future production costs                                  1,754,700         829,968         693,817       1,379,913
Future development costs                                   183,818         114,317          83,781         110,660
                                                        ----------      ----------      ----------      ----------
Future net cash flows before income taxes                3,517,284       1,236,863         894,838       3,334,108
Future income tax expense                                1,100,392         265,611         124,803       1,073,051
                                                        ----------      ----------      ----------      ----------
Future net cash flows after income taxes                 2,416,892         971,252         770,035       2,261,057
Discount at 10% per annum                                1,172,635         399,810         272,493       1,155,792
                                                        ----------      ----------      ----------      ----------
Standardized measure of discounted future net
  cash flows relating to proved oil and gas
  reserves                                              $1,244,257      $  571,442      $  497,542      $1,105,265
                                                        ==========      ==========      ==========      ==========
</TABLE>

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:

<TABLE>
<CAPTION>
                                                                                  Three Months
                                                                  YEAR ENDED         Ended          Year Ended        Year Ended
                                                                  DECEMBER 31,    December 31,     September 30,     September 30,
(in thousands)                                                        2002            2001             2001               2000
                                                                  ------------    ------------     -------------     -------------
<S>                                                               <C>             <C>              <C>               <C>
Balance at beginning of year                                      $   571,442       $ 497,542       $ 1,105,265       $   613,854
                                                                  -----------       ---------       -----------       -----------
Revisions to reserves proved in prior years:
   Net changes in prices, production costs and
      future development costs                                        658,956         100,710        (1,015,900)          715,746
   Net changes due to revisions in quantity
      estimates                                                        (8,380)         49,579           (81,076)           37,049
   Development costs incurred, previously
      estimated                                                        49,418           8,812            50,768            39,589
   Accretion of discount                                               57,144          11,398           144,266            61,385
   Other                                                               (8,669)        (24,012)           95,165             6,850
                                                                  -----------       ---------       -----------       -----------
</TABLE>


                                       70
<PAGE>

<TABLE>
<S>                                                               <C>               <C>             <C>               <C>
Total revisions                                                       748,469         146,487          (806,777)          860,619
New field discoveries and extensions, net of
    future production and development costs                           213,625           5,562            33,685           110,727
Sales of oil and gas produced, net of production
    costs                                                            (162,151)        (23,699)         (220,220)         (157,533)
Purchases                                                             218,799              20            32,811            17,657
Sales                                                                 (14,203)         (2,271)          (26,256)           (1,110)
Net change in income taxes                                           (331,724)        (52,199)          379,034          (338,949)
                                                                  -----------       ---------       -----------       -----------
Net change in standardized measure of
    discounted future net cash flows                                  672,815          73,900          (607,723)          491,411
                                                                  -----------       ---------       -----------       -----------
Balance at end of year                                            $ 1,244,257       $ 571,442       $   497,542       $ 1,105,265
                                                                  ===========       =========       ===========       ===========
</TABLE>


                                       71
<PAGE>
20.      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.

<TABLE>
<CAPTION>
                                                                               Three Months
                                                              YEAR ENDED          Ended           Year Ended        Year Ended
                                                             DECEMBER 31,      December 31,     September 30,     September 30,
(in thousands)                                                  2002              2001              2001              2000
                                                             ------------      ------------     -------------     -------------

<S>                                                          <C>               <C>              <C>               <C>
Operating revenues from continuing operations
     Oil and gas operations                                  $   252,744       $    49,486       $   223,512       $   185,248
     Natural gas distribution                                    424,431            96,678           553,862           366,161
                                                             -----------       -----------       -----------       -----------
       Total                                                 $   677,175       $   146,164       $   777,374       $   551,409
                                                             ===========       ===========       ===========       ===========
Operating income (loss) from continuing operations
     Oil and gas operations                                  $    78,416       $     3,243       $    72,425       $    47,568
     Natural gas distribution                                     59,370             8,034            50,288            49,063
     Eliminations and corporate expenses                          (1,700)             (417)           (1,678)           (1,620)
                                                             -----------       -----------       -----------       -----------
       Total                                                 $   136,086       $    10,860       $   121,035       $    95,011
                                                             ===========       ===========       ===========       ===========
Depreciation, depletion and amortization
  expense from continuing operations
     Oil and gas operations                                  $    71,405       $    16,351       $    53,846       $    56,226
     Natural gas distribution                                     33,682             8,151            30,933            28,708
                                                             -----------       -----------       -----------       -----------
       Total                                                 $   105,087       $    24,502       $    84,779       $    84,934
                                                             ===========       ===========       ===========       ===========
Interest expense
     Oil and gas operations                                  $    29,635       $     7,042       $    30,244       $    28,441
     Natural gas distribution                                     14,557             3,680            12,316             9,870
     Eliminations and other                                         (479)              (88)             (490)             (542)
                                                             -----------       -----------       -----------       -----------
       Total                                                 $    43,713       $    10,634       $    42,070       $    37,769
                                                             ===========       ===========       ===========       ===========
Income tax expense (benefit) from continuing operations
     Oil and gas operations                                  $     3,941       $    (4,843)      $     1,728       $    (7,552)
     Natural gas distribution                                     17,825             1,547            13,448            14,324
     Other                                                        (1,257)              (88)             (365)             (290)
                                                             -----------       -----------       -----------       -----------
       Total                                                 $    20,509       $    (3,384)      $    14,811       $     6,482
                                                             ===========       ===========       ===========       ===========
Capital expenditures
     Oil and gas operations                                  $   305,476       $    25,052       $   136,886       $    67,090
     Natural gas distribution                                     65,815            12,873            56,090            67,073
     Other                                                             5                --                60               287
                                                             -----------       -----------       -----------       -----------
       Total                                                 $   371,296       $    37,925       $   193,036       $   134,450
                                                             ===========       ===========       ===========       ===========
Identifiable assets
     Oil and gas operations                                  $   926,839       $   687,776       $   716,043       $   737,814
     Natural gas distribution                                    603,209           549,221           516,802           471,282
     Eliminations and other                                          843             3,359            (8,966)           (6,055)
                                                             -----------       -----------       -----------       -----------
       Total                                                 $ 1,530,891       $ 1,240,356       $ 1,223,879       $ 1,203,041
                                                             ===========       ===========       ===========       ===========
Property, plant and equipment, net
     Oil and gas operations                                  $   838,526       $   620,305       $   617,592       $   552,287
     Natural gas distribution                                    418,098           385,137           380,489           355,248
     Other                                                           179               237               253               294
                                                             -----------       -----------       -----------       -----------
       Total                                                 $ 1,256,803       $ 1,005,679       $   998,334       $   907,829
                                                             ===========       ===========       ===========       ===========
</TABLE>


                                      72
<PAGE>
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

<TABLE>
<CAPTION>
ENERGEN CORPORATION
                                                                       Three Months
                                                      YEAR ENDED          Ended            Year Ended        Year Ended
                                                     DECEMBER 31,       December 31,      September 30,     September 30,
(IN THOUSANDS)                                          2002               2001               2001              2000
                                                     ------------      -------------      -------------     -------------

<S>                                                  <C>               <C>                <C>               <C>
ALLOWANCE FOR DOUBTFUL ACCOUNTS
BALANCE AT BEGINNING OF YEAR                          $ 11,783           $ 10,031           $  6,681           $ 5,598
                                                      --------           --------           --------           -------

     Additions:
          Charged to income                              5,482              1,819              7,953             4,287
          Recoveries and adjustments                      (495)               139               (901)             (276)
                                                      --------           --------           --------           -------

              Net additions                              4,987              1,958              7,052             4,011
                                                      --------           --------           --------           -------

     Less uncollectible accounts written off            (7,896)              (206)            (3,702)           (2,928)
                                                      --------           --------           --------           -------

BALANCE AT END OF YEAR                                $  8,874           $ 11,783           $ 10,031           $ 6,681
                                                      ========           ========           ========           =======
</TABLE>


<TABLE>
<CAPTION>
ALABAMA GAS CORPORATION
                                                                       Three Months
                                                      YEAR ENDED          Ended            Year Ended        Year Ended
                                                     DECEMBER 31,       December 31,      September 30,     September 30,
(IN THOUSANDS)                                          2002               2001               2001              2000
                                                     ------------      -------------      -------------     -------------

<S>                                                  <C>               <C>                <C>               <C>
ALLOWANCE FOR DOUBTFUL ACCOUNTS
BALANCE AT BEGINNING OF YEAR                          $ 11,100           $  9,500           $ 5,800           $ 4,532
                                                      --------           --------           -------           -------

     Additions:
          Charged to income                              5,410              1,816             7,799             4,275
          Recoveries and adjustments                      (565)               (38)             (452)             (276)
                                                      --------           --------           -------           -------

              Net additions                              4,845              1,778             7,347             3,999
                                                      --------           --------           -------           -------

     Less uncollectible accounts written off            (7,745)              (178)           (3,647)           (2,731)
                                                      --------           --------           -------           -------

BALANCE AT END OF YEAR                                $  8,200           $ 11,100           $ 9,500           $ 5,800
                                                      ========           ========           =======           =======
</TABLE>


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

None


                                      73
<PAGE>
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 23, 2003. The proxy statement will be filed on or
about March 20, 2003.

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 23, 2003.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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 23,
         2003.

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 23,
         2003.

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 23, 2003.


                                      74
<PAGE>
PART IV

ITEM 14.     CONTROLS AND PROCEDURES

A.       Our chief executive officer and chief financial officer, have evaluated
the effectiveness of our disclosure controls and procedures as of a date within
90 days before the filing of this report. Based on that evaluation they have
concluded that our disclosure controls and procedures are effective.

B.       Our chief executive officer and chief financial officer have concluded
that there were no significant changes in our internal controls or in other
factors that could significantly affect those controls subsequent to the date of
their most recent evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

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 March 14, 2002, reporting that Energen Resources signed
         a Purchase and Sale Agreement with First Permian, L.L.C.

         Form 8-K dated April 10, 2002, reporting that Energen Resources
         completed its purchase of oil and gas properties from First Permian,
         L.L.C.

         Form 8-K dated June 4, 2002, reporting that Alagasco had filed a
         request with the Alabama Public Service Commission (APSC) to continue
         its rate-setting methodology, Rate Stabilization and Equalization (RSE)

         Form 8-K dated June 11, 2002, reporting that the APSC extended
         Alagasco's rate-setting methodology, RSE for a six-year period through
         January 1, 2008

         Form 8-K dated July 24, 2002, commenting on the Company's financial
         relationships with Williams Companies Inc. and Dynegy, Inc.

         Form 8-K dated August 14, 2002, reporting the certification which
         accompanied the Form 10-Q for the quarterly period ended June 30, 2002,
         pursuant to 18 United States Code section 1350, as enacted by section
         906 of the Sarbanes-Oxley Act of 2002


                                       75
<PAGE>

                               ENERGEN CORPORATION
                             ALABAMA GAS CORPORATION
                                INDEX TO EXHIBITS
                                  ITEM 14(A)(3)

<TABLE>
<CAPTION>
Exhibit
Number                                                       Description
-------                                                      ------------
<S>           <C>
*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 July 22, 1998) which was filed as Exhibit 3(c) to Energen's
              Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810)

*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 July 22, 1998) which was filed as Exhibit 3(e) to Energen's
              Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810)

*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(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)

*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
</TABLE>


                                       76
<PAGE>
<TABLE>
<S>           <C>

*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 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(d)        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(e)        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(f)        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(g)        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(h)        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(i)        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)

*10(j)        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(k)        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(l)        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)
</TABLE>


                                       77
<PAGE>
<TABLE>
<S>           <C>
*10(m)        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(n)        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           Consent of Independent Accountants (Energen Corporation)
</TABLE>

*Incorporated by reference


                                       78
<PAGE>

                                    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 18, 2003                      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


                                       79
<PAGE>

                                   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:

<TABLE>
<S>                                                     <C>

        March 18, 2003                                  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 18, 2003                                  By /s/ Geoffrey C. Ketcham
--------------------------------                        --------------------------------------------------
                                                        Geoffrey C. Ketcham
                                                        Executive Vice President, Chief Financial Officer and
                                                        Treasurer of Energen and Alabama Gas Corporation



        March 18, 2003                                  By /s/ Grace B. Carr
--------------------------------                        --------------------------------------------------
                                                        Grace B. Carr
                                                        Vice President and Controller of Energen



        March 18, 2003                                  By /s/ Paula H. Rushing
--------------------------------                        --------------------------------------------------
                                                        Paula H. Rushing
                                                        Vice President-Finance of Alabama Gas
                                                        Corporation



        March 18, 2003                                  By /s/ Julian W. Banton
--------------------------------                        --------------------------------------------------
                                                        Julian W. Banton
                                                        Director



        March 18, 2003                                  By /s/ J. Mason Davis, Jr.
--------------------------------                        --------------------------------------------------
                                                        J. Mason Davis, Jr.
                                                        Director



        March 18, 2003                                  By /s/ James S. M. French
--------------------------------                        --------------------------------------------------
                                                        James S. M. French
                                                        Director



        March 18, 2003                                  By /s/ T. Michael Goodrich
--------------------------------                        --------------------------------------------------
                                                        T. Michael Goodrich
                                                        Director



        March 18, 2003                                  By /s/ Judy M. Merritt
--------------------------------                        --------------------------------------------------
                                                        Judy M. Merritt
                                                        Director
</TABLE>


                                       80
<PAGE>

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 officers and I are responsible for
         establishing and maintaining disclosure controls and procedures (as
         defined in Exchange Act Rules 13a-14) for the registrant and we have:

         a)       designed such disclosure controls and procedures 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 as of a date within 90 days prior to
                  the filing date of this report (the "Evaluation Date"); and

         c)       presented in this report our conclusions about the
                  effectiveness of the disclosure controls and procedures based
                  on our evaluation as of the Evaluation Date;

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

         a)       all significant deficiencies in the design or operation of
                  internal controls which could adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial data and have identified for the registrant's
                  auditors any material weakness in internal controls; and

         b)       any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal controls; and

6.       The registrant's other certifying officers and I have indicated in this
         report whether or not there were significant changes in internal
         controls or in other factors that could significantly affect internal
         controls subsequent to the date of our most recent evaluation,
         including any corrective actions with regard to significant
         deficiencies and material weaknesses.



  March 18, 2003                       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

                                       81
<PAGE>

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 officers and I are responsible for
         establishing and maintaining disclosure controls and procedures (as
         defined in Exchange Act Rules 13a-14) for the registrant and we have:

         a)       designed such disclosure controls and procedures 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 as of a date within 90 days prior to
                  the filing date of this report (the "Evaluation Date"); and

         c)       presented in this report our conclusions about the
                  effectiveness of the disclosure controls and procedures based
                  on our evaluation as of the Evaluation Date;

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

         a)       all significant deficiencies in the design or operation of
                  internal controls which could adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial data and have identified for the registrant's
                  auditors any material weakness in internal controls; and

         b)       any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal controls; and

6.       The registrant's other certifying officers and I have indicated in this
         report whether or not there were significant changes in internal
         controls or in other factors that could significantly affect internal
         controls subsequent to the date of our most recent evaluation,
         including any corrective actions with regard to significant
         deficiencies and material weaknesses.



  March 18, 2003                            By /s/ G. C. Ketcham
------------------                          ------------------------------------
                                            G. C. Ketcham
                                            Executive Vice President, Chief
                                            Financial Officer and Treasurer of
                                            Energen Corporation and Alabama Gas
                                            Corporation


                                       82