10-K

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, 2008

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM              TO             

Commission File Number	Registrant	State of Incorporation	IRS Employer Identification Number
1-7810	Energen Corporation	Alabama	63-0757759
2-38960	Alabama Gas Corporation	Alabama	63-0022000

605 Richard Arrington Jr. Boulevard North, Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

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

Title of Each Class	Exchange on Which Registered
Energen Corporation Common Stock, $0.01 par value	New York Stock Exchange

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

Indicate by check mark if the registrants are a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

YES   x    NO  ¨

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    YES  ¨    NO  x

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 is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Energen Corporation	Large accelerated filer   x	Accelerated filer  ¨	Non-accelerated filer  ¨	Smaller reporting company ¨
Alabama Gas Corporation	Large accelerated filer   ¨	Accelerated filer  ¨	Non-accelerated filer  x	Smaller reporting company ¨

Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  ¨    NO  x

Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30, 2008:

Energen Corporation $5,462,223,417

Indicate number of shares outstanding of each of the registrant’s classes of common stock as of February 17, 2009:

Energen Corporation	71,700,551 shares
Alabama Gas Corporation	1,972,052 shares

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

DOCUMENTS INCORPORATED BY REFERENCE

Energen Corporation Proxy Statement to be filed on or about March 24, 2009 (Part III, Item 10-14)

INDUSTRY GLOSSARY

For a more complete definition of certain terms defined below, as well as other terms and concepts applicable to successful efforts accounting, 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. This 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) that cannot be extracted until a recompletion or pay-add occurs.
Cash Flow Hedge	The designation of a derivative instrument to reduce exposure to variability in cash flows from the forecasted sale of oil, gas or natural gas liquids production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale.
Collar	A financial arrangement that effectively establishes a price range between a floor and a ceiling for the underlying commodity. The purchaser bears the risk of fluctuation between the minimum (or floor) price and the maximum (or ceiling) price.
Development Costs	Costs necessary to gain access to, prepare and equip development wells in areas of proved reserves.
Development Well	A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Downspacing	An increase in the number of available drilling locations as a result of a regulatory commission order.
Dry Well	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.
Exploration Expenses	Costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties, exploratory geological and geophysical activities, and costs of impaired and expired leaseholds.
Exploratory Well	A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
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.
Gross Revenues	Revenues reported after deduction of royalty interest payments.
Gross Well or Acre	A well or acre in which a working interest is owned.
Liquified Natural Gas (LNG)	Natural gas that is liquified by reducing the 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.

Net Well or Acre	A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.
Odorization	The adding of odorant to natural gas which is a characteristic odor so that leaks can be readily detected by smell.
Operational Enhancement	Any action undertaken to improve production efficiency of oil and gas wells and/or reduce well costs.
Operator	The company responsible for exploration, development and production activities for a specific project.
Pay-Add	An operation within a currently producing wellbore that attempts to access and complete an additional pay zone(s) while maintaining production from the existing completed zone(s).
Pay Zone	The formation from which oil and gas is produced.
Production (Lifting) Costs	Costs incurred to operate and maintain wells.
Productive Well	An exploratory or a development well that is not a dry well.
Proved Developed Reserves	The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves	Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves (PUD)	The portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
Recompletion	An operation within an existing wellbore whereby a completion in one pay zone is abandoned in order to attempt a completion in a different pay zone.
Reserves-to-Production Ratio	Ratio expressing years of supply determined by dividing the remaining recoverable reserves at year end by actual annual production volumes. The reserve-to-production ratio is a statistical indicator with certain limitations, including predictive value. The ratio varies over time as changes occur in production levels and remaining recoverable reserves.
Secondary Recovery	The process of injecting water, gas, etc., into a formation in order to produce additional oil otherwise unobtainable by initial recovery efforts.
Service Well	A well employed for the introduction into an underground stratum of water, gas or other fluid under pressure or disposal of salt water produced with oil or other waste.
Sidetrack Well	A new section of wellbore drilled from an existing well.
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 pipelines on a contract basis for others.
Throughput	Total volumes of natural gas sold or transported by the gas utility.
Working Interest	Ownership interest in the oil and gas properties that is burdened with the cost of development and operation of the property.

Workover	A major remedial operation on a completed well to restore, maintain, or improve the well’s production such as deepening the well or plugging back to produce from a shallow formation.
-e	Following a unit of measure denotes that the oil and natural gas liquids components have been converted to cubic feet equivalents at a rate of 6 thousand cubic feet per barrel.

ENERGEN CORPORATION

2008 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

	PART I	Page
Item 1.	Business	3
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	11
Item 2.	Properties	12
Item 3.	Legal Proceedings	13
Item 4.	Submission of Matters to a Vote of Security Holders	14
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6.	Selected Financial Data	19
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	37
Item 8.	Financial Statements and Supplementary Data	38
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	85
Item 9A.	Controls and Procedures	85
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	88
Item 11.	Executive Compensation	88
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	88
Item 13.	Certain Relationships and Related Transactions, and Director Independence	88
Item 14.	Principal Accountant Fees and Services	88
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	89
Signatures		93

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This Form 10-K is filed on behalf of Energen Corporation (Energen or the Company)

and Alabama Gas Corporation (Alagasco).

Forward-Looking Statements: 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 forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any 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, the Company’s ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict.

See Item 1A, Risk Factors, for a discussion of risk factors that may affect the Company and cause material variances from forward-looking statement expectations. The Item 1A, Risk Factors, discussion is incorporated by reference to this forward-looking statement disclosure.

PART I

ITEM 1. BUSINESS

General

Energen Corporation, based in Birmingham, Alabama, is a diversified energy holding company engaged primarily in the development, acquisition, 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 in central and north Alabama. Its two principal subsidiaries are Energen Resources Corporation and Alabama Gas Corporation (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 publicly traded in 1953. Energen Resources was formed in 1971 as a subsidiary of Alagasco. Energen was incorporated in 1978 in preparation for the 1979 corporate reorganization in which Alagasco and Energen Resources became subsidiaries of Energen.

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

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Financial Information About Industry Segments

The information required by this item is provided in Note 18, 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 development and acquisition of oil and gas properties. In addition, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. All gas, oil and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Black Warrior, San Juan and Permian basins for its joint interest and third parties. These services include overall project management and day-to-day decision-making relative to project operations.

At the end of 2008, Energen Resources’ proved oil and gas reserves totaled 1,584 billion cubic feet equivalent (Bcfe). Substantially all of these reserves are located in the San Juan Basin in New Mexico and Colorado, the Permian Basin in west Texas and the Black Warrior Basin in Alabama. Approximately 84 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 15 years. Natural gas represents approximately 66 percent of Energen Resources’ proved reserves, with oil representing approximately 23 percent and natural gas liquids comprising the balance.

Growth Strategy: Energen has operated for more than ten years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $1.2 billion in property acquisitions, $1.8 billion in related development, and $248 million in exploration and related development. Energen Resources’ capital investment in 2009 is currently expected to approximate $227 million primarily for existing properties. The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional development of existing properties and the exploration and further development of potential shales acreage primarily in Alabama.

Energen Resources seeks to acquire onshore North American properties which offer proved undeveloped and behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers properties with long-lived reserves and multiple pay-zone opportunities; however, Energen Resources will consider acquisitions of other types of properties which meet its investment requirements, including acquisitions with unproved properties. In addition, Energen Resources conducts exploration activities primarily in areas in which it has operations and remains open to exploration activities which complement its core expertise and meet its investment requirements. Following an acquisition, Energen Resources focuses on increasing production and reserves through development of the properties’ undeveloped reserves and behind-pipe reserve potential as well as engaging in other activities. These activities include development well drilling, exploration, 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 operated approximately 91 percent of its proved reserves at December 31, 2008.

In October 2006, Energen Resources sold to Chesapeake Energy Corporation (Chesapeake) a 50 percent interest in its unproved lease position of approximately 200,000 gross acres in various shale plays in Alabama for $75 million plus a then expected $15 million in net future drilling cost. In addition, the two companies signed an agreement to form an area of mutual interest (AMI) through which they will pursue new leases, exploration, development and operations on a 50-50 basis, for at least the next 10 years. The AMI encompassed Alabama and parts of Georgia. During 2008, Energen Resources and Chesapeake leased shared acreage in the AMI. Through December 31, 2008, approximately $21.7 million of drilling costs have been incurred and paid by Chesapeake. Of these drilling costs paid by Chesapeake, approximately $10.85 million relate to Energen Resources’ interest under the initial agreement. Chesapeake currently does not plan on participating in future drilling costs; accordingly, all future drilling costs will be paid by Energen Resources. As of February 24, 2009, Energen Resources’ net acreage position in Alabama shales totaled approximately 343,000 acres representing multiple shale opportunities.

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As of December 31, 2008, Energen Resources had approximately $42 million of unproved leasehold costs related to its lease position in Alabama shales. Results of the initial well testing program which occurred during 2008 were neither positive nor conclusive. Included in the capital spending estimates above, the Company plans to invest approximately $10 million during 2009 to drill additional shale wells, test alternative completion techniques and complete other zones in the existing test wells.

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 that increase the number of available drilling locations; changes in the economic or operating environments that allow previously uneconomic locations to be added; technological advances that make reserve locations available for development; successful development of existing proved undeveloped reserve locations that reclassify adjacent probable locations to proved undeveloped reserve 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.

During the three years ended December 31, 2008, the Company’s development efforts have added 399 Bcfe of proved reserves from the drilling of 1,087 gross development and service wells (including 38 sidetrack wells) and 176 well recompletions and pay-adds. In 2008, Energen Resources’ successful development wells and other activities added approximately 124 Bcfe of proved reserves; the Company drilled 406 gross development and service wells (including 11 sidetrack wells), performed some 103 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources’ production totaled 102.4 Bcfe in 2008 and is estimated to total 106.5 Bcfe in 2009, including 104 Bcfe of estimated production from proved reserves owned at December 31, 2008.

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

Years ended December 31,	2008	2007	2006
Development:
Productive	199.2	135.5	151.7
Dry	0.9	1.0	-
Total	200.1	136.5	151.7
Exploratory:
Productive	1.8	21.7	40.1
Dry	1.7	0.3	3.0
Total	3.5	22.0	43.1

As of December 31, 2008, the Company was participating in the drilling of 10 gross development and exploratory wells, with the Company’s interest equivalent to 8 wells. In addition to the development wells drilled, the Company drilled 84.1, 99.8 and 35.9 net service wells during 2008, 2007 and 2006, respectively. As of December 31, 2008, the Company was participating in the drilling of 2 gross service wells, with the Company’s interest equivalent to 1.5 wells.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2008, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

	Gross	Net
Gas wells	4,272	2,388
Oil wells	3,231	1,644
Developed acreage	783,124	534,922
Undeveloped acreage	696,281	361,656

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There were 5 wells with multiple completions in 2008. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Alabama.

Risk Management: Energen Resources attempts to lower the commodity price risk associated with its oil and natural gas business through the use of futures, swaps and options. Energen Resources does not hedge more than 80 percent of its estimated annual production and generally does not hedge more than two fiscal years forward. Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured 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 operating revenues in the period of change.

The Company may also enter 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 hedge 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.

In the case of an acquisition, Energen Resources may hedge more than two years forward to protect targeted returns. Energen Resources prefers long-lived reserves and primarily uses the then-current oil and gas futures prices in its evaluation models, the prevailing swap curve and, for the longer-term, its own pricing assumptions.

See the Forward-Looking Statements in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 1A, Risk Factors, for further discussion with respect to price and other risks.

• 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 184 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.4 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2008, Alagasco served an average of 413,151 residential customers and 33,911 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 10,200 miles of main and more than 11,900 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 established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended in 2007, 2002, 1996, 1990, 1987 and 1985. On December 21, 2007, the APSC extended RSE for a seven-year period through December 31, 2014. Under the terms of the extension, RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing,

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the APSC votes to modify or discontinue the RSE methodology. Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year).

Under RSE, the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, whether Alagasco’s return on average equity at the end of the rate year will be within the allowed range of return. 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. At September 30, 2008, RSE limited the utility’s equity upon which a return is permitted to 57 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco’s operations and maintenance (O&M) expense. The equity upon which a return is permitted will be phased down to 55 percent by September 30, 2009. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 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 on an aggregate basis 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 O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the cost control measurement calculation

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco is allowed a temperature adjustment to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment such as the impact of wind velocity or cloud cover and the elasticity of demand as a result of higher commodity prices.

The APSC approved an Enhanced Stability Reserve (ESR) beginning October 1997, with an approved maximum funding level of $4 million pre-tax, 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 large 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. Under the terms of the 2007 RSE extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR.

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

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

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As of December 31, 2008, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:

	December 31, 2008
	(Mcfd)
Southern firm transportation	132,933
Southern storage and no notice transportation	251,679
Transco firm transportation	70,000
Various intrastate transportation	20,216

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 alternate sources of gas. In the residential and small commercial and industrial markets, electricity is the principal competitor. With the support of the APSC, Alagasco has implemented a variety of flexible rate strategies to help it compete for the large customer gas load in the marketplace. Rate flexibility remains critical as the utility faces competition for this load. To date, the utility has been effective in utilizing its flexible rate strategies to minimize bypass and price-based switching to alternate fuels and alternate sources of gas.

In 1994 Alagasco implemented the P Rate in response to the competitive challenge of interstate pipeline capacity release. Under this tariff provision, Alagasco releases much of its excess pipeline capacity and repurchases it as agent for its transportation customers under 12 month contracts. The transportation customers benefit from lower pipeline costs; Alagasco’s core market customers benefit, as well, since the utility uses the revenues received from the P Rate to decrease gas costs for its residential, small commercial and industrial sales customers. In 2008, approximately 300 of Alagasco’s transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled more than $6.3 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 a reduction in charges allowed under the CFC because the retention of any customer, particularly large commercial and industrial transportation customers, benefits all customers by recovering a portion of the system’s fixed costs. The Transportation Tariff allows Alagasco to transport gas for customers, rather than buy and resell it to them, and is based on Alagasco’s sales profit margin so that operating margins are unaffected. During 2008, substantially all of Alagasco’s large commercial and industrial customer deliveries involved 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 2008, 57 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 to 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 recent years, the higher price commodity environment has resulted in a decline in the utility’s customer base of approximately 1 percent annually. Recent lower commodity prices have not yet reversed this adverse trend at the utility. In 2008, Alagasco’s average number of customers decreased 1 percent. Alagasco will continue to concentrate on maintaining its current penetration levels and increasing residential saturation levels for all end-use applications. Alagasco will continue to explore opportunities to increase revenue in the small and large commercial and industrial market segments.

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Seasonality: Alagasco’s gas distribution business is highly seasonal since a material portion of the utility’s total sales and delivery volumes relate to space heating customers. Alagasco’s rate Tariff includes a Temperature Adjustment Rider primarily for residential, small commercial and small industrial customers that moderates the impact of departures from normal temperatures on Alagasco’s earnings. The adjustments are made through the GSA.

• Environmental Matters

Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company’s financial position, results of operations or cash flows; however, remediation of the Huntsville, Alabama manufactured gas plant site discussed below, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

A discussion of certain litigation against Energen Resources in the state of Louisiana related to the restoration of oilfield properties is included in Item 3, Legal Proceedings of Part I in this Form 10-K.

Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns) and five manufactured gas distribution sites (one of which it still owns). Subject to the following paragraph discussing the Huntsville, Alabama manufactured gas plant site, an investigation of the sites does not indicate the present need for remediation activities and 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 financial position of Alagasco.

In October 2008, Alagasco received a request from the United States Environmental Protection Agency (EPA) for information pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) Section 104(e) and Section 7007 of the Resource Conservation and Recovery Act in connection with a former manufactured gas plant site located in Huntsville, Alabama. The site, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company anticipates that the EPA will consider Alagasco a potentially responsible party under CERCLA and is in discussions with EPA and the current site owner to develop an action plan for the site. Based on the limited information available at this time, Alagasco preliminarily estimates that it may incur costs associated with the site ranging from $2.9 million to $5.9 million. At the present time, the Company cannot conclude that any amount within this range is a better estimate than any other, and accordingly the Company has accrued a contingent liability of $2.9 million. The estimate assumes an action plan for surface soil. If it is determined that a greater scope of work is appropriate, then actual costs will likely exceed the preliminary estimate. Alagasco expects to recover such costs through insurance recovery and future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

• Employees

The Company has approximately 1,530 employees, of which Alagasco employs 1,130 and Energen Resources employs 400. The Company believes that its relations with employees are good.

9

ITEM 1A. RISK FACTORS

The future success and continued viability of Energen and its businesses, like any venture, is subject to many recognized and unrecognized risks and uncertainties. Such risks and uncertainties could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by management. The following list identifies and briefly summarizes certain risk factors, and should not be viewed as complete or comprehensive. The Company undertakes no obligation to correct or update such risk factors whether as a result of new information, future events or otherwise. These risk factors should be read in conjunction with the Company’s disclosure specific to Forward-Looking Statements made elsewhere in this report.

Commodity Prices: The Company and Alagasco are significantly influenced by commodity prices. Historical markets for natural gas, oil and natural gas liquids have been volatile. Energen Resources’ revenues, operating results, profitability and cash flows depend primarily upon the prices realized for its oil, gas and natural gas liquid production. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.

Access to Credit Markets: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for both lenders and the Company. Recent market volatility and credit market disruption have demonstrated that credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs or limit availability of funds to the Company.

Energen Resources’ Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future oil, gas and natural gas liquids prices could materially affect the Company’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options and fixed- price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position.

Alagasco’s Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position.

Energen Resources Customer Concentration: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil, natural gas and natural gas liquids purchasers are expected to account for approximately 19 percent, 18 percent and 13 percent, respectively, of Energen Resources’ estimated 2009 production. Energen Resources’ other purchasers are each expected to purchase less than 9 percent of estimated 2009 production.

10

Third Party Facilities: Energen Resources delivers to and Alagasco is served by third party facilities. These facilities include third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Alagasco, Energen Resources and the Company.

Energen Resources’ Production and Drilling: There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition 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. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and the Company’s financial position, results of operations and cash flows.

Alagasco’s Service Territory: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.

Complex federal, state and local laws and regulations: Energen and Alagasco are subject to extensive federal, state and local regulation which significantly influences operations. Although, the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase costs or limit operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

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ITEM 2. PROPERTIES

The corporate headquarters of Energen, Alagasco and Energen Resources are located in leased office space in Birmingham, Alabama. See the discussion under Item 1, Business for further information related to Energen Resources’ and Alagasco’s business operations. Information concerning Energen Resources’ production and reserves is summarized in the table below and included in Note 17, Oil and Gas Operations (Unaudited), in the Notes to Financial Statements. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the future outlook and expectations for Energen Resources and Alagasco.

Oil and Gas Operations

Energen Resources focuses on increasing its production and proved reserves through the acquisition and development of onshore North American producing oil and gas properties. Energen Resources maintains offices in Arcadia, Louisiana; in Farmington, New Mexico; and in Midland, Texas. The Company also maintains offices in Lehman, Seminole, Westbrook and Penwell, Texas; and in Brookwood and Tuscaloosa, Alabama.

The major areas of operations include (1) the San Juan Basin, (2) the Permian Basin, (3) the Black Warrior Basin and (4) North Louisiana/East Texas as highlighted on the above map.

The following table sets forth the production volumes for the year ended December 31, 2008, and proved reserves and reserves-to-production ratio by area as of December 31, 2008:

	Year ended December 31, 2008	December 31, 2008	December 31, 2008
	Production Volumes (MMcfe)	Proved Reserves (MMcfe)	Reserves-to- Production Ratio
San Juan Basin	50,319	870,618	17.30 years
Permian Basin	28,878	434,452	15.04 years
Black Warrior Basin	14,115	216,662	15.35 years
North Louisiana/East Texas	8,554	57,925	6.77 years
Other	488	4,718	9.67 years
Total	102,354	1,584,375	15.48 years

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The following table sets forth proved reserves by area as of December 31, 2008:

	Gas MMcf	Oil MBbl	NGL MBbl
San Juan Basin	710,893	1,059	25,562
Permian Basin	49,468	60,772	3,391
Black Warrior Basin	216,662	-	-
North Louisiana/East Texas	57,331	98	-
Other	4,099	105	-
Total	1,038,453	62,034	28,953

The following table sets forth proved developed reserves by area as of December 31, 2008:

	Gas MMcf	Oil MBbl	NGL MBbl
San Juan Basin	555,136	1,029	22,056
Permian Basin	46,211	50,705	2,813
Black Warrior Basin	212,157	-	-
North Louisiana/East Texas	51,270	90	-
Other	4,099	105	-
Total	868,873	51,929	24,869

Energen Resources files Form EIA-23 with the Department of Energy which reports gross proved reserves, including the working interest share of other owners, for properties operated by the Company. The proved reserves reported in the table above represent our share of proved reserves for all properties, based on our ownership interest in each property. For properties operated by Energen Resources, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Company-owned proved reserves reported in the table above does not exceed five percent. Estimated proved reserves as of December 31, 2008 are based upon studies for each of our properties prepared by Company engineers and reviewed by Ryder Scott Company, L.P. and T. Scott Hickman and Associates, Inc., independent oil and gas reservoir engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines.

The following table sets forth the total net productive gas and oil wells by area as of December 31, 2008, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

	Net Wells	Net Developed Acreage	Net Undeveloped Acreage
San Juan Basin	1,419	276,909	9,563
Permian Basin	1,636	83,012	1,000
Black Warrior Basin	796	147,650	670
North Louisiana/East Texas	170	20,664	1,400
Alabama Shales and Other	11	6,687	349,023
Total	4,032	534,922	361,656

Natural Gas Distribution

The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 10,200 miles of main and more than 11,900 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, four division commercial offices, three division business centers, one district office, seven service centers, and other related property and equipment, some of which are leased by Alagasco.

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

13

conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive or other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Jefferson County, Alabama

As discussed in prior filings, in January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources’ calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. The lawsuit was settled during December 2008. Consistent with the Company’s evaluation of the case, the Company did not incur any material charge.

Enron Corporation

Enron and Enron North America Corporation (ENA) have settled with Energen Resources and Alagasco related to the Enron and ENA bankruptcy proceedings. Under the settlement, Energen Resources was allowed claims in the bankruptcy cases against Enron and ENA of $12.5 million each. In December 2006, Energen Resources sold its claims against Enron and ENA for a gain of $6.7 million after-tax. All other claims have been released.

Legacy Litigation

During recent years, numerous lawsuits have been filed against oil production companies in Louisiana for restoration of oilfield properties. These suits are referred to in the industry as “legacy litigation” because they usually involve operations that were conducted on the affected properties many years earlier. Energen Resources is or has been a party to several legacy litigation lawsuits, most of which result from the operations of predecessor companies. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from legacy litigation in excess of the Company’s accrued provision for estimated liability are not considered material to the Company’s financial position.

Other

Various other pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for the estimated liability.

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 2008.

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EXECUTIVE OFFICERS OF THE REGISTRANTS

Energen Corporation

Name	Age	Position (1)
James T. McManus, II	50	Chairman, Chief Executive Officer and President of Energen and Chairman and Chief Executive Officer of Alagasco (2)
Charles W. Porter, Jr.	44	Vice President, Chief Financial Officer and Treasurer of Energen and Alagasco (3)
John S. Richardson	51	President and Chief Operating Officer of Energen Resources (4)
Dudley C. Reynolds	56	President and Chief Operating Officer of Alagasco (5)
J. David Woodruff, Jr.	52	General Counsel and Secretary of Energen and Alagasco and Vice President-Corporate Development of Energen (6)
Russell E. Lynch, Jr.	35	Vice President and Controller of Energen (7)

Notes: (1)    All executive officers of Energen have been employed by Energen or a subsidiary for the past five years. Officers serve at the pleasure of the Board of Directors.   (2)    Mr. 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. He was elected President and Chief Operating Officer of Energen effective January 1, 2006 and Chief Executive Officer of Energen and each of its subsidiaries effective July 1, 2007. He was elected Chairman of the Board of Energen and each of its subsidiaries effective January 1, 2008. Mr. McManus serves as a Director of Energen and each of its subsidiaries.   (3)    Mr. Porter has been employed by the Company in various financial capacities since 1989. He was elected Controller of Energen Resources in 1998. In 2001, he was elected Vice President – Finance of Energen Resources. He was elected Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries effective January 1, 2007.   (4)    Mr. Richardson has been employed by the Company in various capacities since 1985. He was elected Vice President – Acquisitions and Engineering of Energen Resources in 1997. He was elected Executive Vice President and Chief Operating Officer of Energen Resources effective January 1, 2006. He was elected President and Chief Operating Officer of Energen Resources effective January 23, 2008.   (5)    Mr. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003.

15

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

(7)    Mr. Lynch has been employed by the Company in various capacities since 2001. He was elected Vice President and Controller of Energen effective January 1, 2009.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Quarterly Market Prices and Dividends Paid Per Share
Quarter ended (in dollars)	High	Low	Close	Dividends Paid
March 31, 2007	51.43	43.78	50.89	.115
June 30, 2007	60.49	51.05	54.94	.115
September 30, 2007	58.90	48.24	57.12	.115
December 31, 2007	70.41	56.81	64.23	.115
March 31, 2008	66.88	57.61	62.30	.12
June 30, 2008	79.57	61.97	78.03	.12
September 30, 2008	79.33	41.03	45.28	.12
December 31, 2008	45.50	23.00	29.33	.12

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On February 17, 2009, there were 6,902 holders of record of Energen’s common stock. At the date of this filing, Energen Corporation owned all the issued and outstanding common stock of Alabama Gas Corporation. Energen expects to pay annual cash dividends of $0.50 per share on the Company’s common stock in 2009. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

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

Plan Category	Number of Securities to be Issued for Outstanding Options and Performance Share Awards	Weighted Average Exercise Price		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders*	620,517	$	40.75	2,007,156
Equity compensation plans not approved by security holders	-		-	-
Total	620,517	$	40.75	2,007,156

* These plans include the Company’s 1997 Stock Incentive Plan and the 1992 Energen Corporation Directors Stock Plan

The following table summarizes information concerning purchases of equity securities by the issuer:

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares that May Yet Be Purchased Under the Plans**
October 1, 2008 through October 31, 2008	-			-	-	8,992,700
November 1, 2008 through November 30, 2008	8,558	*	$	33.58	-	8,992,700
December 1, 2008 through December 31, 2008	2,685	*	$	28.78	-	8,992,700
Total	11,243		$	32.43	-	8,992,700

* Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.

** By resolution adopted May 24, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board of Directors authorized the Company to repurchase up to 12,564,400 shares of the Company’s common stock. The resolutions do not have an expiration date.

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PERFORMANCE GRAPH

Energen Corporation — Comparison of Five-Year Cumulative Shareholder Returns

This graph compares the total shareholder returns of Energen, the Standard & Poor’s Composite Stock Index (S&P 500), the Standard & Poor’s Supercomposite Oil & Gas Exploration & Production Index (S15OILP), and the Standard & Poor’s Supercomposite Gas Utilities Index (S15GASUX). The graph assumes $100 invested at the per-share closing price of the common stock on the New York Exchange Composite Tape on December 31, 2003, in the Company and each of the indices. Total shareholder return includes reinvested dividends.

As of December 31,	2003		2004		2005		2006		2007		2008
S&P 500 Index	$	100	$	111	$	116	$	135	$	142	$	90
Energen	$	100	$	146	$	182	$	238	$	328	$	151
S15OILP Index	$	100	$	136	$	220	$	228	$	326	$	204
S15GASUX	$	100	$	117	$	127	$	158	$	180	$	137

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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

Years ended December 31, (dollars in thousands, except per share amounts)	2008		2007		2006			2005		2004
INCOME STATEMENT
Operating revenues	$	1,568,910	$	1,435,060	$	1,393,986	*	$	1,128,394	$	936,857
Income from continuing operations	$	321,915	$	309,212	$	273,523	*	$	172,886	$	127,305
Net income	$	321,915	$	309,233	$	273,570	*	$	173,012	$	127,463
Diluted earnings per average common share from continuing operations	$	4.47	$	4.28	$	3.73	*	$	2.35	$	1.74
Diluted earnings per average common share	$	4.47	$	4.28	$	3.73	*	$	2.35	$	1.74
BALANCE SHEET
Total property, plant and equipment, net	$	2,867,648	$	2,538,243	$	2,252,414		$	2,068,011	$	1,783,059
Total assets	$	3,775,404	$	3,079,653	$	2,836,887		$	2,618,226	$	2,181,739
Long-term debt	$	561,361	$	562,365	$	582,490		$	683,236	$	612,891
Total shareholders’ equity	$	1,913,920	$	1,378,658	$	1,202,069		$	892,678	$	803,666
COMMON STOCK DATA
Annual dividend rate at period-end	$	0.48	$	0.46	$	0.44		$	0.40	$	0.385
Cash dividends paid per common share	$	0.48	$	0.46	$	0.44		$	0.40	$	0.3775
Diluted average common shares outstanding (000)		72,030		72,181		73,278			73,715		73,117
Price range:
High	$	79.57	$	70.41	$	47.60		$	44.31	$	30.04
Low	$	23.00	$	43.78	$	32.16		$	27.06	$	19.94
Close	$	29.33	$	64.23	$	46.94		$	36.32	$	29.48

* Includes an after-tax gain of $34.5 million, or $0.47 per diluted share, on the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shales to Chesapeake Energy Corporation.

All information has been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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SELECTED BUSINESS SEGMENT DATA

Energen Corporation

Years ended December 31, (dollars in thousands)	2008		2007		2006		2005		2004
OIL AND GAS OPERATIONS
Operating revenues from continuing operations
Natural gas	$	536,283	$	499,406	$	437,560	$	365,635	$	276,482
Oil		292,908		251,497		181,459		116,651		98,409
Natural gas liquids		68,216		68,623		50,258		38,455		30,902
Other		16,725		6,066		61,265		6,953		4,324
Total	$	914,132	$	825,592	$	730,542	$	527,694	$	410,117
Production volumes from continuing operations
Natural gas (MMcf)		67,573		64,300		62,824		61,048		57,164
Oil (MBbl)		4,114		3,879		3,645		3,316		3,434
Natural gas liquids (MMgal)		70.7		77.2		76.3		70.5		68.2
Production volumes from continuing operations (MMcfe)		102,354		98,606		95,596		91,020		87,513
Total production volumes (MMcfe)		102,354		98,605		95,595		91,099		87,606
Proved reserves
Natural gas (MMcf)		1,038,453		1,115,918		1,096,429		1,080,161		1,019,436
Oil (MBbl)		62,034		74,625		74,893		74,962		54,500
Natural gas liquids (MBbl)		28,953		31,664		29,504		31,934		34,613
Total (MMcfe)		1,584,375		1,753,652		1,722,811		1,721,537		1,554,114
Other data from continuing operations
Lease operating expense (LOE)
LOE and other	$	174,127	$	148,280	$	134,853	$	104,241	$	79,191
Production taxes		62,552		53,798		49,509		52,271		37,285
Total	$	236,679	$	202,078	$	184,362	$	156,512	$	116,476
Depreciation, depletion and amortization	$	139,539	$	114,241	$	97,842	$	89,340	$	80,896
Capital expenditures	$	449,571	$	379,479	$	259,678	$	353,712	$	403,936
Operating income	$	482,588	$	451,567	$	405,149	$	243,876	$	180,379
NATURAL GAS DISTRIBUTION
Operating revenues
Residential	$	408,280	$	388,291	$	426,066	$	384,753	$	340,229
Commercial and industrial		177,719		164,903		181,900		166,957		138,686
Transportation		51,116		49,255		45,950		43,291		40,221
Other		17,663		7,019		9,528		5,699		7,604
Total	$	654,778	$	609,468	$	663,444	$	600,700	$	526,740
Gas delivery volumes (MMcf)
Residential		21,632		20,665		22,310		24,601		25,383
Commercial and industrial		10,934		10,593		11,226		12,498		12,323
Transportation		46,789		51,448		50,760		49,850		54,385
Total		79,355		82,706		84,296		86,949		92,091
Average number of customers
Residential		413,151		416,967		420,558		425,110		425,673
Commercial, industrial and transportation		33,911		34,200		34,456		34,936		35,248
Total		447,062		451,167		455,014		460,046		460,921
Other data
Depreciation and amortization	$	48,874	$	47,136	$	44,244	$	42,351	$	39,881
Capital expenditures	$	63,320	$	58,862	$	76,157	$	73,276	$	58,208
Operating income	$	81,956	$	72,742	$	74,274	$	72,922	$	66,199

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

RESULTS OF OPERATIONS

Consolidated Net Income

Energen Corporation’s net income for the year ended December 31, 2008 totaled $321.9 million, or $4.47 per diluted share and compared favorably to the year ended December 31, 2007 net income of $309.2 million, or $4.28 per diluted share. This 4.4 percent increase in earnings per diluted share (EPS) largely reflected the result of significantly higher prices for natural gas, oil and natural gas liquids and the impact of a 3.7 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen Resources Corporation, Energen’s oil and gas subsidiary, partially offset by higher lease operating expense and increased depreciation, depletion and amortization (DD&A) expense. For the year ended December 31, 2008, Energen Resources earned $282.7 million, as compared with $273.2 million in the previous year. Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, generated net income of $40.2 million in the current year as compared with net income in the prior period of $36.8 million. For the year ended December 31, 2006, Energen reported net income of $273.6 million, or $3.73 per diluted share.

2008 vs 2007: Energen Resources’ net income and income from continuing operations totaled $282.7 million in 2008 as compared with $273.2 million in 2007 primarily due to increased commodity prices of approximately $27 million after-tax, the impact of increased production volumes of approximately $22 million after-tax and a $6.4 million after-tax gain on the sale of certain Permian Basin oil properties. These increases were partially offset by higher lease operating expense of approximately $16 million after-tax, increased DD&A expense of approximately $15 million after-tax and the reduced benefit of the Section 199 Domestic Production Activities Deduction on qualified oil and gas production income of approximately $8 million after-tax.

Alagasco earnings increased to $40.2 million in 2008 from $36.8 million in 2007 largely reflecting the utility’s ability to earn on a higher level of equity combined with timing differences associated with rate recovery of approximately $4.1 million after-tax, the $2.5 million after-tax utilization of the Enhanced Stability Reserve (ESR) to compensate for large industrial and commercial market sensitive load loss and the approximate $1.8 million after-tax benefit from the utility holding its O&M expense to below the inflation-based Cost Control Measurement (CCM). Negatively affecting net income was a decrease in customer usage and other of approximately $5 million after-tax. Alagasco achieved a return on average equity (ROE) of 12.9 percent in 2008 compared with 12.3 percent in 2007.

2007 vs 2006: For the year ended December 31, 2007, Energen Resources’ net income and income from continuing operations totaled $273.2 million and compared favorably to $237.6 million in the prior year. The primary factors positively influencing income from continuing operations included significantly higher commodity prices of approximately $80 million after-tax, the impact of increased production volumes of approximately $14 million after-tax and the benefit from the Section 199 deduction of approximately $7 million after-tax. Negatively affecting comparable income from continuing operations was the 2006 after-tax gain of approximately $34.5 million on the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shales to Chesapeake Energy Corporation (Chesapeake), higher DD&A expense of approximately $10 million after-tax, higher lease operating expense of approximately $8 million after-tax, increased administrative expenses of approximately $3 million after-tax and a prior year $6.7 million after-tax gain on the sale of Energen Resources’ bankruptcy claim against Enron.

Alagasco earned net income of $36.8 million in 2007 as compared with net income of $37.3 million in 2006. This decrease in earnings largely reflected revenue reductions under the utility’s rate-setting mechanism of $2.3 million after-tax partially offset by a $1.2 million after-tax increase arising from the utility’s ability to earn on a higher level of equity and a $0.9 million after-tax reduction in expenses associated with the prior year’s CCM giveback. Alagasco’s ROE was 12.3 percent in 2007 compared with 13.1 percent in 2006.

Operating Income

Consolidated operating income in 2008, 2007 and 2006 totaled $562.1 million, $522 million and $477.3 million, respectively. This growth in operating income has been influenced by strong financial performance from Energen Resources arising from increased

21

commodity prices and production. During 2008, Alagasco 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 combined with timing differences associated with rate recovery, the utilization of the ESR and the benefit from the increase in O&M expense being below its CCM partially offset by lower customer usage. Alagasco’s operating income has been relatively flat for the two previous years as the utility’s ability to earn a return on a higher level of equity was offset by decreased customer usage, a decline in the number of customers and revenue reductions under its rate-setting mechanisms.

Oil and Gas Operations: Revenues from oil and gas operations rose in the current year largely as a result of increased commodity prices as well as the impact of increased production volumes. Production increased primarily due to additional development activities in the San Juan and North Louisiana/East Texas basins partially offset by normal production declines and other. Revenue per unit of production for natural gas production increased 2.2 percent to $7.94 per thousand cubic feet (Mcf), oil revenue per unit of production rose 9.8 percent to $71.20 per barrel and natural gas liquids revenue per unit of production increased 7.9 percent to $0.96 per gallon during 2008. Production rose 3.8 percent to 102.4 Bcfe during 2008. Natural gas production increased 5.1 percent to 67.6 billion cubic feet (Bcf) and oil volumes rose 6.1 percent to 4,114 thousand barrels (MBbl). Production of natural gas liquids decreased 8.4 percent to 70.7 million gallons (MMgal) due to normal production declines and severe winter weather in the San Juan Basin.

In 2007, revenues from oil and gas operations rose primarily due to the impact of higher commodity prices along with increased production volumes. The primary factors affecting the increase in production were additional development activities in the San Juan and Permian basins partially offset by normal production declines. Revenue per unit of production for natural gas production rose 11.6 percent to $7.77 per Mcf, oil revenue per unit of production increased 30.2 percent to $64.83 per barrel and natural gas liquids revenue per unit of production increased 34.8 percent to $0.89 per gallon during 2007. Production from continuing operations rose 3.1 percent to 98.6 Bcfe during 2007. Natural gas production increased 2.3 percent to 64.3 Bcf and oil volumes increased 6.4 percent to 3,879 MBbl. Production of natural gas liquids increased 1.2 percent to 77.2 MMgal.

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 $8.6 million, $6.1 million and $6.6 million in 2008, 2007 and 2006, respectively. During 2006, Energen Resources recorded a $55.5 million pre-tax gain in other operating revenues for the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shales to Chesapeake.

Years ended December 31, (in thousands, except sales price data)	2008		2007			2006
Operating revenues from continuing operations
Natural gas	$	536,283	$	499,406		$	437,560
Oil		292,908		251,497			181,459
Natural gas liquids		68,216		68,623			50,258
Operating fees		8,599		6,119			6,553
Other		8,126		(53	)		54,712
Total operating revenues from continuing operations	$	914,132	$	825,592		$	730,542
Production volumes from continuing operations
Natural gas (MMcf)		67,573		64,300			62,824
Oil (MBbl)		4,114		3,879			3,645
Natural gas liquids (MMgal)		70.7		77.2			76.3
Revenue per unit of production including effects of all derivative instruments
Natural gas (per Mcf)	$	7.94	$	7.77		$	6.96
Oil (per barrel)	$	71.20	$	64.83		$	49.79
Natural gas liquids (per gallon)	$	0.96	$	0.89		$	0.66
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (per Mcf)	$	7.92	$	7.76		$	6.96
Oil (per barrel)	$	71.45	$	64.80		$	49.54
Natural gas liquids (per gallon)	$	0.96	$	0.89		$	0.66
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (per Mcf)	$	7.94	$	6.45		$	6.53
Oil (per barrel)	$	94.97	$	67.17		$	59.88
Natural gas liquids (per gallon)	$	1.14	$	0.98		$	0.80
Average production (lifting) cost (per Mcfe)	$	1.70	$	1.50		$	1.41
Average production tax (per Mcfe)	$	0.61	$	0.55		$	0.52
Average DD&A rate (per Mcfe)	$	1.33	$	1.13		$	1.00

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Operations and maintenance (O&M) expense increased $22.6 million and $28.7 million in 2008 and 2007, respectively. Lease operating expense (excluding production taxes) in 2008 increased $25.8 million largely due to higher workover expense, (approximately $10 million), increased transportation costs primarily related to increased San Juan production (approximately $5 million), additional compression costs (approximately $3 million), higher ad valorem taxes (approximately $2 million) and increased labor costs (approximately $2 million). In 2007, lease operating expense (excluding production taxes) increased $13.4 million largely due to additional compression costs (approximately $2 million), increased repair and maintenance expense in the San Juan and Permian basins (approximately $7 million), higher transportation related to increased San Juan Basin production (approximately $3 million) and a general rise in field service costs. Administrative expense decreased $9.7 million in 2008 largely due to lower benefit costs primarily related to the Company’s performance-based compensation plans. The year ended 2007 included settlement charges for the nonqualified supplemental retirement plans and the defined benefit pension plans of $2.3 million. In 2007, administrative expense increased $16.6 million primarily due to a 2006 pre-tax gain of $10.7 million on the sale of Energen Resources’ bankruptcy claims against Enron and increased labor-related costs, including settlement charges of $2.3 million as discussed above. Exploration expense rose $6.4 million in 2008 largely due to the writeoff of two wells in the San Juan Basin where mechanical difficulties were encountered. In 2007, exploration expense declined $1.3 million.

DD&A expense increased $25.3 million in 2008 and $16.4 million in 2007. The average DD&A rates were $1.33 per Mcfe in 2008, $1.13 per Mcfe in 2007 and $1.00 per Mcfe in 2006. Higher development costs along with the impact in the fourth quarter of pricing year-end proved reserves resulted in an increase in the average 2008 DD&A rate of approximately $20.6 million. The increase in the average 2007 DD&A rate, which contributed approximately $13 million, was primarily due to higher development costs along with a decline in 2006 year-end reserve prices. Increased production volumes also contributed approximately $4.2 million and $3 million to the increase in DD&A expense in 2008 and 2007, respectively.

Energen Resources’ expense for taxes other than income taxes primarily reflected production-related taxes. Energen Resources recorded severance taxes of $62.6 million, $53.8 million and $49.5 million for 2008, 2007 and 2006, respectively. Higher severance taxes in 2008 resulted from increased commodity market prices and higher natural gas and oil production volumes. Higher commodity market prices and the impact of increased production volumes contributed approximately $13.7 million and $2 million, respectively. Partially offsetting the increase in severance taxes during 2008 was a $6.9 million adjustment related to 2005 through 2008 for reduced severance taxes in New Mexico. Severance taxes increased $4.3 million in 2007 over the prior year. Higher commodity market prices and increased production volumes contributed approximately $2.7 million and $1.6 million, respectively. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution: As discussed more fully in Note 2, Regulatory Matters, in the Notes to Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) and is allowed to earn a range of return on equity of 13.15 percent to 13.65 percent. At September 30, 2008, RSE limited the utility’s equity upon which a return is permitted to 57 percent of total capitalization and provided for certain cost control measures designed to monitor Alagasco’s O&M expense. The equity upon which a return is permitted will be limited to 55 percent by September 30, 2009.

Under the inflation-based CCM established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 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 on an aggregate basis 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

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difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the cost control measurement calculation. 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; as such Alagasco is allowed recovery of a temperature adjustment to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

Alagasco’s natural gas and transportation sales revenues totaled $654.8 million, $609.5 million and $663.4 million in 2008, 2007 and 2006, respectively. In 2008, sales revenue increased primarily due to an increase in gas costs of approximately $22 million and a weather-driven increase in customer usage of approximately $11 million. Adjustments from the utility’s rate setting mechanisms also contributed to the increase in revenues as Alagasco charged approximately $4 million against the ESR during the third quarter of 2008 due to a decline in usage by market sensitive large commercial and industrial customers. At the end of the 2008 rate year, the increase in O&M expense was below its inflation-based cost control measure; as a result the utility benefited by a $2.9 million pre-tax increase in revenues. At the end of the 2007 rate year, Alagasco had a $3.6 million pre-tax reduction in revenues to bring the return on average equity to midpoint in the allowed range of return. Sales revenue in 2007 declined largely due to a decrease in gas costs of approximately $28 million and a decline in customer usage of approximately $27 million. In 2008, weather that was 13.3 percent colder than in the prior year contributed to a 4.7 percent increase in residential sales volumes while commercial and industrial volumes rose 3.2 percent. Transportation volumes declined 9.1 percent largely due to decreased usage from construction industry related customers. In 2007, weather was 7.9 percent warmer than in the prior year. Residential sales volumes declined 7.4 percent while commercial and industrial volumes decreased 5.6 percent. Transportation volumes rose 1.4 percent. Higher gas costs combined with an increase in gas purchase volumes resulted in a 10.5 percent increase in cost of gas in 2008. In 2007, lower gas costs along with decreased gas purchase volumes contributed to a 14.7 percent decrease in cost of gas.

O&M expense at the utility decreased 1.1 percent in 2008 primarily due to lower labor-related costs (approximately $3.9 million) and decreased insurance costs (approximately $1.9 million) partially offset by increased consulting and technology fees (approximately $3.5 million) and higher bad debt expense (approximately $1 million). The year ended December 31, 2007 included settlement charges for the nonqualified supplemental retirement plans and the defined benefit pension plans of $3.4 million. In 2007, O&M expense at the utility increased 1.9 percent primarily due to increased labor-related costs (approximately $2 million), including settlement charges of $3.4 million as discussed above, largely offset by decreased bad debt expense (approximately $1 million). For the rate year ended September 30, 2006, the increase in O&M expense per customer was above the Index Range; as a result, three quarters of the difference, or $1.5 million pre-tax, was returned to the customers through RSE. Alagasco’s O&M expense fell within the Index Range for the rate year ended September 30, 2007.

Depreciation expense rose 3.7 percent and 6.5 percent in 2008 and 2007, respectively, due to extension and replacement of the utility’s distribution and replacement of its support systems. 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.

Years ended December 31, (in thousands)	2008			2007			2006
Natural gas transportation and sales revenues	$	654,778		$	609,468		$	663,444
Cost of natural gas		(351,774	)		(318,429	)		(373,097	)
Operations and maintenance		(127,877	)		(129,351	)		(126,948	)
Depreciation		(48,874	)		(47,136	)		(44,244	)
Income taxes		(24,829	)		(21,636	)		(22,002	)
Taxes, other than income taxes		(44,297	)		(41,810	)		(44,881	)
Operating income	$	57,127		$	51,106		$	52,272
Natural gas sales volumes (MMcf)
Residential		21,632			20,665			22,310
Commercial and industrial		10,934			10,593			11,226
Total natural gas sales volumes		32,566			31,258			33,536
Natural gas transportation volumes (MMcf)		46,789			51,448			50,760
Total deliveries (MMcf)		79,355			82,706			84,296

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Non-Operating Items

Consolidated: Interest expense in 2008 declined $5.1 million largely due to the May 2007 voluntary call of the $100 million Floating Rate Senior Notes due November 15, 2007 along with lower interest rates on short term borrowings. In 2007, interest expense decreased $1.6 million primarily due to lower borrowings at Energen Resources along with decreased interest expense associated with the May 2007 call of the $100 million Floating Rate Senior Notes. Also contributing to the decrease in interest expense at Alagasco was the January 2007 redemption of $34.4 million of 6.75% Notes maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026 partially offset by the issuance of $45 million in long-term debt with an interest rate of 5.9%. The average daily outstanding balance under short-term credit facilities was $89.2 million in 2008. The average daily outstanding balance under short-term credit facilities was $67.7 million in 2007 as compared to $63.7 million in 2006. Income tax expense increased in the periods presented primarily due to higher pre-tax income. Also increasing income tax expense during 2008 was the approximate $8 million reduction in the after-tax benefit of the Section 199 deduction. Partially offsetting the increase in income tax expense in 2007 was the after-tax impact of the Section 199 deduction of approximately $7 million.

FINANCIAL POSITION AND LIQUIDITY

The Company’s net cash from operating activities totaled $569.2 million, $484.2 million and $482.9 million in 2008, 2007 and 2006, respectively. Operating cash flow in 2008, 2007 and 2006 benefited from higher realized commodity prices and production volumes at Energen Resources. Positively affecting operating cash flows during 2008 was a decrease from the prior period in income taxes payable related to the tax effect of depreciation and basis differences. During 2007, operating cash flows were negatively affected by the increase in income taxes payable related to the tax effect of the depreciation and basis differences along with the 2006 utilization of minimum tax credit. In 2006, income from operations before income taxes included a pre-tax gain of $55.5 million related to the Chesapeake acreage sale. During 2008, working capital needs were primarily affected by increased gas costs and income tax receivables. Working capital needs at Alagasco were reduced by declining gas costs for 2007. During 2006, working capital needs at Alagasco were largely affected by increased gas costs compared to the prior period and storage gas inventory. 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 2008, the Company made net investments of $464.6 million. Energen Resources invested $19 million in property acquisitions including approximately $18.1 million of unproved leaseholds (including approximately $13 million related to Alabama shales), $386.7 million for development costs including approximately $262 million (excludes approximately $45 million of accrued development cost) to drill 285 net development and service wells and $19.5 million for exploration. Energen Resources had cash proceeds in 2008 of $16.2 million from the sale of certain properties. Utility expenditures in 2008 totaled $62.6 million and primarily represented extension and replacement of its distribution system and support facilities. During 2007, the Company made net investments of $431.9 million. Energen Resources invested $54.6 million in property acquisitions, including an $18 million acquisition in the Permian Basin and approximately $32 million of unproved leaseholds (including approximately $28 million related to Alabama shales), $313.2 million for development costs including approximately $202 million to drill 236 net development and service wells and $7.5 million for exploration. Utility expenditures in 2007 totaled $58.2 million. During 2006, the Company made net investments of $256.9 million. Energen Resources invested $46.4 million in property acquisitions, $186.3 million for development costs including approximately $130.6 million to drill 188 net development and service wells and $25.9 million for exploration. In December 2006, Energen Resources completed its purchase of gas properties located in the San Juan Basin from Dominion Resources, Inc. for approximately $30 million. Energen Resources sold certain properties during 2006, resulting in cash proceeds of $75.4 million including $75 million received from Chesapeake for a 50 percent interest in its lease position in certain unproved shales acreage in Alabama. Utility expenditures in 2006 totaled $75.1 million.

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During 2008, the Company added approximately 1.2 Bcfe of reserves primarily from a North Louisiana/East Texas acquisition. Also during 2008, Energen Resources added 124 Bcfe of reserves from discoveries and other additions, primarily the result of development drilling that increased the number of proved undeveloped locations in both the San Juan and Permian basins as well as continued downspacing in the Permian Basin. Energen Resources added approximately 142 Bcfe and 167 Bcfe of reserves in 2007 and 2006, respectively.

The Company used $100.2 million for net financing activities in 2008 primarily for the repayment of short-term debt borrowings. In addition, long-term debt was reduced by $10.9 million for current maturities in 2008. The Company used $53.9 million for net financing activities in 2007 primarily for the early redemption of $100 million Floating Rate Senior Notes due November 15, 2007, $34.4 million of 6.75% Notes maturing September 1, 2031, $10 million of Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026. Partially offsetting these uses of cash was the January 2007 issuance by Alagasco of $45 million in long-term debt with an interest rate of 5.9% due January 15, 2037. In 2006, net cash used for financing activities totaled $224.4 million largely due to $84.3 million incurred from the buy-back of Energen common stock under its stock repurchase plan along with the repayment of short-term borrowings. In addition, long-term debt was reduced by $15.9 million for current maturities in 2006. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders.

Capital Expenditures

Oil and Gas Operations: Energen Resources spent a total of approximately $1.1 billion for capital projects during the years ended December 31, 2008, 2007 and 2006. Property acquisition expenditures totaled $120 million, development activities totaled $912.4 million, and exploratory expenditures totaled $52.9 million.

Years ended December 31, (in thousands)	2008		2007		2006
Capital and exploration expenditures for:
Property acquisitions	$	18,996	$	54,626	$	46,428
Development		412,928		313,220		186,264
Exploration		19,504		7,456		25,936
Other		5,763		5,667		4,411
Total		457,191		380,969		263,039
Less exploration expenditures charged to income		7,620		1,490		3,361
Net capital expenditures	$	449,571	$	379,479	$	259,678

Natural Gas Distribution: During the years ended December 31, 2008, 2007 and 2006, Alagasco invested $198.3 million for capital projects: $154.4 million for expansion, replacements and support of its distribution system and $43.9 million for support facilities and the development and implementation of information systems.

Years ended December 31, (in thousands)	2008		2007		2006
Capital expenditures for:
Renewals, replacements, system expansion and other	$	43,284	$	50,924	$	60,244
Support facilities		20,036		7,938		15,913
Total	$	63,320	$	58,862	$	76,157

FUTURE CAPITAL RESOURCES AND LIQUIDITY

Recent Market Events

Capital and credit markets experienced extreme volatility and disruption during 2008. If such volatility and disruptions continue or worsen during 2009, the Company may experience material adverse effects upon its financial position, results of operations and cash flows. While such events did not have a material impact on 2008, these events have the potential for a negative impact including, but not limited to, the following areas:

Risk Management: The Company utilizes derivative instruments to hedge its exposure to commodity price fluctuations. These derivative instruments are entered into with investment grade counterparties and are assessed each reporting period as to hedge effectiveness. Specifically, the Company considers the likelihood that the counterparty will be able to perform under the terms of the derivative instrument. If the Company is unable to conclude that it is probable that such counterparty will be able to perform under

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the terms of the derivative instrument, then the Company would be required to cease hedge accounting and recognize all gains and losses from that point forward in its results of operations. Further, the Company is at risk of nonperformance for any derivative contracts which are in a gain position. The Company’s current counterparties with active positions are Morgan Stanley, Goldman Sachs, Citigroup, Bank of Montreal, Merrill Lynch, BP and Barclays Capital. The Company also maintains insurance policies which protect against certain business risks. Associated with these policies the Company has recognized insurance receivables for losses incurred. If these receivables were adversely affected, a loss would be recognized in the results of operations.

Access to Capital: The Company relies upon its excess cash flows supplemented by its short-term credit facilities to fund working capital needs. The Company currently has not experienced any disruption in the availability of its short-term credit facilities.

As detailed in the following table, the Company currently has available short-term credit facilities with seven investment grade financial institutions aggregating $480 million of which Energen has available $205 million, Alagasco has available $105 million and $170 million is available to either Company.

(in thousands)	Current Term	Energen		Alagasco		Total
Regions Bank	4/24/2009	$	145,000	$	55,000	$	200,000
Wachovia Bank, N.A.	10/31/2009		100,000		100,000		100,000
Compass Bank	8/6/2009		70,000		70,000		70,000
RBC Bank (USA)	10/21/2009		20,000		15,000		35,000
The Bank of New York Mellon	1/22/2010		25,000		-		25,000
The Northern Trust Company	10/14/2009		15,000		10,000		25,000
First Commercial	7/31/2009		-		25,000		25,000
		$	375,000	$	275,000	$	480,000

The above short-term credit facilities are 364-day committed bilateral agreements. Energen and Alagasco are subject to the risk that these facilities will not be renewed or will be renewed at less favorable terms. However, the Company believes that its expected cash flows, the diversity of credit facilities and its ability to adjust future capital spending provides adequate support for its liquidity needs.

Oil and Gas Operations

During 2009, Energen Resources anticipates some decline in various market driven costs due to the recently lower commodity price environment including, but not limited to, workover and maintenance expenses, ad valorem taxes, capital costs and other field-service-related expenses. The Company anticipates influences such as weather, natural disasters, changes in global economics and political unrest will continue to contribute to increased price volatility in the near term. Commodity price volatility will affect the Company’s revenue and associated cash flow available for investment.

The Company plans to continue investing significant capital in Energen Resources’s oil and gas production operations. For 2009, the Company expects its oil and gas capital spending to total approximately $227 million, including $214 million for existing properties. Included in this $214 million is approximately $103 million for the development of previously identified proved undeveloped reserves.

Capital expenditures by area during 2009 are planned as follows:

Year ended December 31, (in thousands)	2009
San Juan Basin	$	71,100
Permian Basin		112,200
Black Warrior Basin		12,100
North Louisiana/East Texas		18,100
Other		13,300
Total	$	226,800

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Energen anticipates having the following drilling rigs and net wells by area during 2009. The drilling rigs presented below are operated while the net wells include operated and non-operated wells.

	Drilling Rigs	Net Wells
San Juan Basin	4	48
Permian Basin	1 - 5	122
Black Warrior Basin	1 - 2	31
North Louisiana/East Texas	1 - 2	5
Total	7 - 13	206

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional development of existing properties and the exploration and further development of potential shales acreage primarily in Alabama. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above.

To finance capital spending at Energen Resources, the Company primarily expects to use internally generated cash flow supplemented by its short-term credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.

Alabama Shales

In October 2006, Energen Resources sold to Chesapeake Energy Corporation (Chesapeake) a 50 percent interest in its unproved lease position of approximately 200,000 gross acres in various shale plays in Alabama for $75 million plus a then expected $15 million in net future drilling cost. In addition, the two companies signed an agreement to form an area of mutual interest (AMI) through which they will pursue new leases, exploration, development and operations on a 50-50 basis, for at least the next 10 years. The AMI encompassed Alabama and parts of Georgia. During 2008, Energen Resources and Chesapeake leased shared acreage in the AMI. Through December 31, 2008, approximately $21.7 million of drilling costs have been incurred and paid by Chesapeake. Of these drilling costs paid by Chesapeake approximately $10.85 million relate to Energen Resources interest under the initial agreement. Chesapeake currently does not plan on participating in future drilling costs; accordingly, all future drilling costs will be paid by Energen Resources. As of February 24, 2009, Energen Resources’ net acreage position in Alabama shales totaled approximately 343,000 acres representing multiple shale opportunities.

As of December 31, 2008, Energen Resources had approximately $42 million of unproved leasehold costs related to its lease position in Alabama shales. Results of the initial well testing program which occurred during 2008 were neither positive nor conclusive. Included in the capital spending estimates above, the Company plans to invest approximately $10 million during 2009 to drill additional shale wells, test alternative completion techniques and complete other zones in the existing test wells.

Natural Gas Distribution

Alagasco’s use of commodity price hedges for a portion of its gas supply needs is reflected in the utility’s current rates. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider which permits the pass-through to customers for changes in the cost of gas supply. The GSA rider is designed to capture the Company’s cost of natural gas and provides for a pass-through of gas cost fluctuations to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management gains and losses. In recent years, the higher price commodity environment has resulted in a decline in the utility’s customer base of approximately 1% annually. The recent lower commodity price environment has not yet reversed this adverse trend at the utility. A return of natural gas prices to higher levels could result in a further decline in Alagasco’s customer base and usage and in significant increases in the utility’s GSA. Alagasco will continue to monitor its bad debt reserve and will make adjustments as required based on the evaluation of its receivables which are impacted by natural gas prices and the economy.

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Alagasco maintains an investment in storage gas that is expected to average approximately $59 million in 2009 but will vary depending upon the price of natural gas. During 2009, Alagasco plans to invest approximately $65 million in utility capital expenditures for normal distribution and support systems. The utility anticipates funding these capital requirements through internally generated cash flow and the utilization of short-term credit facilities. Alagasco received a cash benefit in February 2009 from an approximate $26.2 million income tax refund claim from 2007 which resulted from an approved change by the Internal Revenue Service in a tax accounting method relating to the Company’s recovery of its gas distribution property.

Stock Repurchases

Energen periodically considers stock repurchases as a capital investment. Energen may buy shares on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. During 2006, the Company purchased 2.2 million shares at an average price of $39.08 per share. The Company did not repurchase shares of common stock for this program during 2008 and 2007. The Company expects any future stock repurchases to be funded through internally generated cash flows or through the utilization of short-term credit facilities. During 2008, the Company had noncash purchases of approximately $27 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation plans. The Company utilized internally generated cash flows in payment of the related tax withholdings.

Short-Term Credit Facilities

Access to capital is an integral part of the Company’s business plan. While the Company expects to have ongoing access to its short-term credit facilities and the longer-term markets, continued access could be adversely affected by current and future economic and business conditions and credit rating downgrades. To help finance its growth plans and operating needs, the Company currently has available short-term credit facilities with seven investment grade financial institutions aggregating $480 million of which Energen has available $205 million, Alagasco has available $105 million and $170 million is available to either Company. At December 31, 2008, Energen has no borrowings on its short-term credit facilities while Alagasco had borrowings of $62 million.

The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations.

In February 2009, Standard & Poor’s (S&P) removed from “CreditWatch with negative implications” the long-term debt ratings of Energen and Alagasco following a review of four diversified energy companies and their subsidiaries. The investment-grade, consolidated rating for Energen and Alagasco was downgraded from BBB+ to BBB; the outlook is “stable.” S&P said the one-notch downgrade primarily reflected a greater weighting of Energen’s exploration and production activities in S&P’s business risk assessment. In addition, S&P said the rating reflected Energen’s “solid credit measures, a favorable discretionary cash flow outlook for 2009, and some cash flow diversification provided by its regulated utility subsidiary.” The downgrade does not have a material impact on the consolidated financial statements or the results of operations. Future borrowing costs and terms may be negatively impacted.

On September 25, 2007, Moody’s Investors Service (Moody’s) downgraded the debt rating of Energen to Baa3 senior unsecured from Baa2. Energen’s debt rating of Baa3 remains investment grade and reflects Moody’s assignment of increased risk exposure related to the growth of its oil and gas operations in contrast to its legacy natural gas distribution assets. Moody’s also confirmed the debt rating of Alagasco during this review as A1 senior unsecured.

Dividends

Energen expects to pay annual cash dividends of $0.50 per share on the Company’s common stock in 2009. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

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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, 2008.

	Payments Due before December 31,
(in thousands)	Total		2009		2010-2011		2012-2013		2014 and Thereafter
Short-term debt	$	62,000	$	62,000	$	-	$	-	$	-
Long-term debt (1)		562,557		-		155,000		51,000		356,557
Interest payments on debt		407,611		36,731		61,309		48,965		260,606
Purchase obligations (2)		117,668		49,019		42,638		15,278		10,733
Capital lease obligations		-		-		-		-		-
Operating leases		46,273		5,756		9,491		7,731		23,295
Asset retirement obligations (3)		502,480		6,586		6,554		3,853		485,487
Nonqualified supplemental retirement plans		31,927		3,888		4,539		5,045		18,455
Total contractual cash obligations	$	1,730,516	$	163,980	$	279,531	$	131,872	$	1,155,133

(1) Long-term cash obligations include $0.9 million of unamortized debt discounts as of December 31, 2008.

(2) Certain of the Company’s long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of $118 million through October 2015. 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 119.9 Bcf through April 2015.

(3) Represents the estimated future asset retirement obligation on an undiscounted basis.

Energen Resources operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement.

The Company has two defined non-contributory pension plans and provides certain postretirement healthcare and life insurance benefits. The Company is not required to make any funding payments during 2009 for the pension plans but expects to make discretionary contributions of at least $5 million. The Company expects to make discretionary payments of approximately $4.7 million to postretirement benefit program assets during 2009. The contractual obligations reported above exclude any payments the Company expects to make to postretirement benefit program assets.

The contractual obligations reported above exclude the Company’s liability of $16.8 million recognized under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” (FIN 48) related to the Company’s provision for uncertain tax positions. The Company cannot make a reasonably reliable estimate of the amount and period of related future payments for such liability.

OUTLOOK

Oil and Gas Operations: Energen Resources plans to continue to implement its growth strategy with capital spending in 2009 as outlined above. Production in 2009 is estimated to be 106.5 Bcfe, including approximately 104 Bcfe of estimated production from proved reserves owned at December 31, 2008. Production estimates above do not include amounts for potential future acquisitions or Alabama shales.

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Production volumes by area are expected to be as follows:

Years ended December 31, (Bcfe)	2009
San Juan Basin	53
Permian Basin	32
Black Warrior Basin	14
North Louisiana/East Texas	7
Total	106

During 2009, Energen Resources expects an annualized decline rate of approximately 5 percent for its proved developed producing properties owned at December 31, 2008. During the same period, total production from proved properties is expected to decrease approximately 1 percent and total production is expected to increase approximately 4 percent. The above proved developed producing properties decline rate is not necessarily indicative of the Company’s expectations for its terminal decline rate on a long term basis.

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

Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil, natural gas and natural gas liquids purchasers are expected to account for approximately 19 percent, 18 percent, and 13 percent, respectively, of Energen Resources’ estimated 2009 production. Energen Resources’ other purchasers are each expected to purchase less than 9 percent of production.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment and commercial 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. At December 31, 2008, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with all of its counterparties at December 31, 2008. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. Energen Resources does not hedge more than 80 percent of its estimated annual production and generally does not hedge this production more than two years forward. Production may be hedged for a longer period immediately following an acquisition in order to protect targeted returns.

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Energen Resources entered into the following transactions for 2009 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2009	15.6 Bcf	$8.34 Mcf	NYMEX Swaps
	31.8 Bcf	$7.58 Mcf	Basin Specific Swaps
2010	14.3 Bcf	$8.79 Mcf	NYMEX Swaps
	28.3 Bcf	$7.98 Mcf	Basin Specific Swaps
Oil
2009	2,700 MBbl	$72.93 Bbl	NYMEX Swaps
2010	2,160 MBbl	$97.60 Bbl	NYMEX Swaps
Oil Basis Differential
2009	2,136 MBbl	*	Basis Swaps
2010	1,440 MBbl	*	Basis Swaps
Natural Gas Liquids
2009	43.3 MMGal	$1.15 Gal	Liquids Swaps
*  Average contract prices not meaningful due to the varying nature of each contract

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil, natural gas and natural gas liquids may have on the fair value of its derivative instruments. This analysis measured the impact on the commodity derivative instruments and, thereby, did not consider the underlying exposure related to the commodity. At December 31, 2008, the Company was in a net gain position of $337.1 million for derivative contracts and estimates that a 10 percent increase or decrease in the commodities prices would have resulted in an approximate $78 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. 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 impact of related taxes on actual cash prices.

Effective January 1, 2008, the Company partially adopted SFAS No. 157, “Fair Value Measurements,” under the provisions of the Financial Accounting Standards Board (FASB) Staff Position 157-2, “Effective Date of FASB Statement No. 157.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. As defined under SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS No.157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value defined as follows:

Level 1	–	Unadjusted quoted prices in active markets for identical assets or liabilities;
Level 2	–	Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;
Level 3	–	Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumptions that market value participants would use in pricing the asset or liability.

Over-the-counter derivatives are valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of New York Mercantile Exchange (NYMEX) swaps. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and liquids swaps. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related

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counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen or Alagasco. As of the balance sheet date, the Company believes that these prices represent the best estimate of the exit price for these instruments and are representative of the prices for which the contract will ultimately settle or realize.

The following table sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	December 31, 2008
(in thousands)	Level 2*			Level 3*		Total
Current assets	$	91,687		$	104,812	$	196,499
Noncurrent assets		91,321			49,282		140,603
Current liabilities		(27,653	)		-		(27,653	)
Noncurrent liabilities		(8,821	)		-		(8,821	)
Net derivative asset	$	146,534		$	154,094	$	300,628

* Amounts classified in accordance with FASB Interpretation No. 39 (as amended), “Offsetting of Amounts Related to Certain Contracts” which permits offsetting of fair value of amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Alagasco has $27.7 million and $8.8 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively.

Level 3 assets as of December 31, 2008 represent approximately 4 percent of total assets. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $33 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations for Level 3 derivatives would be immaterial due to the derivative instruments qualifying as cash flow hedges under SFAS No. 133. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

Natural Gas Distribution: The extension of RSE in December 2007 provides Alagasco the opportunity to continue earning an allowed ROE between 13.15 percent and 13.65 percent through December 31, 2014. Under the terms of that extension, RSE will continue beyond that date, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue its operations. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment rider which permits the pass-through to customers for changes in the cost of gas supply. Also as discussed in Note 2, Regulatory Matters, in the Notes to Financial Statements, the utility’s CCM is based on the rate of inflation. Continued low inflation or the risk of deflation combined with a return to higher gas prices resulting in increased bad debt expense could impact the utility’s ability to manage its O&M expense 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. In addition, continued decreases in residential customers and continued declines in usage per customer in the residential and small commercial classes, as well as market sensitive load losses from large industrial and commercial customers, will make it more difficult for the utility to earn within its allowed range of return on equity. The utility continues to rely on rate flexibility to deter bypass of its distribution system by large industrial and commercial customers.

As required by SFAS No. 133, Alagasco recognizes all derivatives at fair value 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 Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability as required by SFAS No. 71. At December 31, 2008, Alagasco recorded a $27.7 million loss as a liability in accounts payable with a corresponding current regulatory asset representing the fair value of derivatives. Alagasco also recognized a noncurrent $8.8 million loss in deferred credits and other liabilities with a corresponding noncurrent regulatory asset related to derivative contracts.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Company’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Management has identified the following critical accounting policies in the application of existing accounting standards or in the implementation of new standards that involve significant judgments and estimates by the Company. The application of these accounting policies necessarily requires management’s most subjective or complex judgments regarding estimates and projected outcomes of future events that could have a material impact on the financial statements.

Oil and Gas Operations

Accounting for Natural Gas and Oil Producing Activities and Related Reserves: The Company utilizes the successful efforts method of accounting for its natural gas and oil producing activities. Under this accounting method, acquisition and development costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of total proved and proved developed reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have reviewed the estimates of proved reserves of natural gas, crude oil and natural gas liquids attributed to the Company’s net interests in oil and gas properties as of December 31, 2008. The independent reservoir engineers have issued reports covering approximately 99 percent of the Company’s ending proved reserves and in their judgment these estimates were reasonable in the aggregate. The Company’s production of undeveloped reserves requires the installation or completion of related infrastructure facilities such as pipelines and the drilling of development wells.

Changes in oil and gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property’s book value if an impairment is warranted. The table below reflects an estimated increase in 2009 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and gas reserve amounts at December 31, 2008:

	Percentage Change in Oil & Gas Reserves From Reported Reserves as of December 31, 2008
(dollars in thousands)	-5%	-10%
Estimated increase in DD&A expense for the year ended December 31, 2009, net of tax	$    5,453	$    11,525

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.

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

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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 estimates and can have a positive or negative impact on the Company’s need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact the Company’s original and ongoing assessments of potential impairment.

Energen Resources adheres to Statement of Financial Accounting Standards (SFAS) No.19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing any impairment of capitalized costs to unproved properties. The greatest portion of these costs generally relates to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. The Company considers a combination of geologic and engineering factors to evaluate the need for impairment of these costs.

Derivatives: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended requires all derivatives to be recognized on the balance sheet and measured at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources may also enter into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.

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: In December 2006, the Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)” (SFAS No. 158). This Standard retains the previous periodic expense calculation on an actuarial basis under the provisions of SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions.” In addition, SFAS No. 158 requires an employer to recognize the net funded status of defined benefit pensions and other postretirement benefit plans (benefit plans) as an asset or liability in its statement of financial position and to recognize changes in the funded status through comprehensive income in the year in which the changes occur. As required by SFAS No. 158, the pension benefit obligation is the projected benefit obligation (PBO), a measurement of earned benefit obligations at expected retirement salary levels; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation (APBO), a measurement of earned postretirement benefit obligations expected to be paid to employees upon retirement. Alagasco established a regulatory asset for the portion of the total benefit obligation to be recovered through rates in future periods in accordance with SFAS No. 71.

Actuarial assumptions attempt to anticipate future events and are used in calculating the expenses and liabilities related to these plans. The calculation of the liability related to the Company’s benefit plans includes assumptions regarding the appropriate weighted average discount rate, the expected long-term rate of return on the plans’ assets and the estimated weighted average rate of increase in the compensation level of its employee base for defined benefit pension plans. The key assumptions used in determining these calculations are disclosed in Note 5, Employee Benefit Plans, in the Notes to Financial Statements.

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In selecting the discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments; the discount rate used to determine net periodic costs was 6.50 percent for each of the plans for the year ended December 31, 2008. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions; the return on assets used to determine net periodic expense was 8.25 percent for each of the applicable plans for the year ended December 31, 2008. The estimated weighted average rate of increase in the compensation level for pay related plans was 4.07 percent for the year ended December 31, 2008.

The selection and use of actuarial assumptions affects the amount of benefit expense recorded in the Company’s financial statements. The table below reflects a hypothetical 25 basis point change in assumed actuarial assumptions to pre-tax benefit expense for the year ended December 31, 2008:

(in thousands)	Pension Expense	Postretirement Expense
Discount rate change	$  1,000	$    200
Return on assets	$     400	$    200
Compensation increase	$     600	$         -

The weighted average discount rate, return on plan assets and estimated rate of compensation increase used in the 2009 actuarial assumptions is 6.50 percent, 8.25 percent, and 3.90 percent, respectively.

Asset Retirement Obligation: The Company records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. 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 recognize the resulting gain or loss. Energen Resources has an obligation to remove tangible equipment and restore land at the end of oil and gas production operations. Alagasco has certain removal cost obligations related to its gas distribution assets and a conditional asset retirement obligation to purge and cap its distribution and transmission lines upon abandonment. The estimate of future restoration and removal costs includes numerous assumptions and uncertainties, including but not limited to, inflation factors, discount rates, timing of settlement, and changes in contractual, regulatory, political, environmental, safety and public relations considerations.

Uncertain Tax Positions: As of January 1, 2007, the Company accounts for uncertain tax positions in accordance with the provisions of FIN 48. The application of income tax law is inherently complex; laws and regulation in this area are voluminous and often ambiguous. As such, the Company is required to make many subjective assumptions and judgments regarding income tax exposures. Interpretations and guidance related to income tax laws and regulation change over time. It is possible that changes in the Company’s subjective assumptions and judgments could materially affect amounts recognized in the consolidated balance sheets and statements of income. Additional information related to the Company’s uncertain tax position is provided in Note 4, Income Taxes, in the Notes to the Financial Statements.

FORWARD-LOOKING STATEMENTS

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, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.

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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, the Company’s ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict.

See Item 1A, Risk Factors, for a discussion of risk factors that may affect the Company and cause material variances from forward-looking statement expectations. The Item 1A, Risk Factors, discussion is incorporated by reference to this forward-looking statement disclosure.

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD

See Note 15, Recently Issued Accounting Standards, in the Notes to Financial Statements for information regarding recently issued accounting standards.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ENERGEN CORPORATION

ALABAMA GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULES

		Page
1.	Financial Statements
	Energen Corporation
	Report of Independent Registered Public Accounting Firm	39
	Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006	41
	Consolidated Balance Sheets as of December 31, 2008 and 2007	42
	Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2008, 2007 and 2006	44
	Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	45
	Notes to Financial Statements	51
	Alabama Gas Corporation
	Report of Independent Registered Public Accounting Firm	40
	Statements of Income for the years ended December 31, 2008, 2007 and 2006	46
	Balance Sheets as of December 31, 2008 and 2007	47
	Statements of Shareholder’s Equity for the years ended December 31, 2008, 2007 and 2006	49
	Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	50
	Notes to Financial Statements	51
2.	Financial Statement Schedules
	Energen Corporation
	Schedule II - Valuation and Qualifying Accounts	84
	Alabama Gas Corporation
	Schedule II - Valuation and Qualifying Accounts	84

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

38

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energen Corporation:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Energen Corporation and its subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report On Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 15, Recently Issued Accounting Standards, and Note 5, Employee Benefit Plans, in the Notes to Financial Statements, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” and Statement of Financial Accounting Standard (SFAS) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)”, effective January 1, 2007 and December 31, 2006, respectively.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 24, 2009

39

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Alabama Gas Corporation:

In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Alabama Gas Corporation at December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008 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. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report On Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our audits (which was an integrated audit in 2008). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 24, 2009

40

CONSOLIDATED STATEMENTS OF INCOME

Energen Corporation

Years ended December 31, (in thousands, except share data)	2008			2007			2006
Operating Revenues
Oil and gas operations	$	914,132		$	825,592		$	730,542
Natural gas distribution		654,778			609,468			663,444
Total operating revenues		1,568,910			1,435,060			1,393,986
Operating Expenses
Cost of gas		351,774			318,429			373,097
Operations and maintenance		354,760			333,443			302,157
Depreciation, depletion and amortization		188,413			161,377			142,086
Taxes, other than income taxes		107,605			95,831			95,727
Accretion expense		4,290			3,948			3,619
Total operating expenses		1,006,842			913,028			916,686
Operating Income		562,068			522,032			477,300
Other Income (Expense)
Interest expense		(41,981	)		(47,100	)		(48,652	)
Other income		1,885			2,668			951
Other expense		(7,014	)		(959	)		(1,046	)
Total other expense		(47, 110	)		(45,391	)		(48,747	)
Income From Continuing Operations Before Income Taxes		514,958			476,641			428,553
Income tax expense		193,043			167,429			155,030
Income From Continuing Operations		321,915			309,212			273,523
Discontinued Operations, Net of Taxes
Income (loss) from discontinued operations		-			3			(6	)
Gain on disposal of discontinued operations		-			18			53
Income From Discontinued Operations		-			21			47
Net Income	$	321,915		$	309,233		$	273,570
Diluted Earnings Per Average Common Share
Continuing operations	$	4.47		$	4.28		$	3.73
Discontinued operations		-			-			-
Net Income	$	4.47		$	4.28		$	3.73
Basic Earnings Per Average Common Share
Continuing operations	$	4.50		$	4.32		$	3.77
Discontinued operations		-			-			-
Net Income	$	4.50		$	4.32		$	3.77
Diluted Average Common Shares Outstanding		72,030,210			72,180,861			73,278,277
Basic Average Common Shares Outstanding		71,600,925			71,591,551			72,504,897

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

41

CONSOLIDATED BALANCE SHEETS

Energen Corporation

(in thousands)	December 31, 2008		December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents	$	13,177	$	8,687
Accounts receivable, net of allowance for doubtful accounts of $12,868 and $12,244 at December 31, 2008 and 2007, respectively		414,362		254,154
Inventories, at average cost
Storage gas inventory		77,243		78,064
Materials and supplies		13,541		13,711
Liquified natural gas in storage		3,219		3,502
Regulatory asset		41,714		10,232
Income tax receivable		50,476		-
Deferred income taxes		-		54,166
Prepayments and other		29,309		26,514
Total current assets		643,041		449,030
Property, Plant and Equipment
Oil and gas properties, successful efforts method		2,959,665		2,530,049
Less accumulated depreciation, depletion and amortization		793,465		664,290
Oil and gas properties, net		2,166,200		1,865,759
Utility plant		1,166,967		1,108,392
Less accumulated depreciation		480,601		448,053
Utility plant, net		686,366		660,339
Other property, net		15,082		12,145
Total property, plant and equipment, net		2,867,648		2,538,243
Other Assets
Regulatory asset		97,511		32,238
Prepaid pension costs and postretirement assets		-		20,054
Long-term derivative instruments		140,603		2,428
Deferred charges and other		26,601		37,660
Total other assets		264,715		92,380
TOTAL ASSETS	$	3,775,404	$	3,079,653

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

42

CONSOLIDATED BALANCE SHEETS

Energen Corporation

(in thousands, except share data)	December 31, 2008			December 31, 2007
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	-		$	10,000
Notes payable to banks		62,000			134,000
Accounts payable		224,309			259,836
Accrued taxes		42,183			40,857
Customers’ deposits		22,081			21,425
Amounts due customers		15,124			20,534
Accrued wages and benefits		24,966			25,410
Regulatory liability		25,363			32,154
Royalty payable		12,275			22,563
Deferred income taxes		41,969			-
Other		39,831			39,451
Total current liabilities		510,101			606,230
Long-term debt		561,631			562,365
Deferred Credits and Other Liabilities
Asset retirement obligation		66,151			60,571
Pension and other postretirement liabilities		67,474			31,985
Regulatory liability		147,514			141,123
Deferred income taxes		482,058			238,706
Long-term derivative instruments		8,821			47,093
Other		18,364			12,922
Total deferred credits and other liabilities		790,382			532,400
Commitments and Contingencies
Shareholders’ Equity Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized		-			-
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized, 74,521,957 shares issued at December 31, 2008 and 74,190,786 shares issued at December 31, 2007		745			742
Premium on capital stock		454,778			434,999
Capital surplus		2,802			2,802
Retained earnings		1,405,970			1,119,816
Accumulated other comprehensive gain (loss), net of tax
Unrealized gain (loss) on hedges		200,867			(65,057	)
Pension and postretirement plans		(31,050	)		(21,167	)
Deferred compensation plan		2,948			16,121
Treasury stock, at cost; 2,977,947 shares and 3,374,336 shares at December 31, 2008 and 2007, respectively		(123,770	)		(109,598	)
Total shareholders’ equity		1,913,290			1,378,658
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,775,404		$	3,079,653

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

43

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

Energen Corporation

(in thousands, except share data)

	Common Stock											Accumulated Other			Deferred			Deferred						Total
	Number of	Par		Premium on			Capital		Retained			Comprehensive			Compensation			Compensation			Treasury			Shareholders’
	Shares		Value		Capital Stock			Surplus		Earnings			Income (Loss)			Restricted Stock			Plan			Stock			Equity
BALANCE DECEMBER 31, 2005	73,493,337	$	735	$	394,861		$	2,802	$	603,314		$	(105,819	)	$	(2,123	)	$	11,907		$	(12,999	)	$	892,678
Net income										273,570															273,570
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $79,827													130,244												130,244
Reclassification adjustment, net of tax of $7,614													12,423												12,423
Pension and postretirement plans, net of tax of $3,062													5,686												5,686
Comprehensive income																									421,923
Adjustment to initially apply SFAS No. 158, net of tax of ($8,161)													(15,156	)											(15,156	)
Purchase of treasury shares																						(87,566	)		(87,566	)
Shares issued for:
Employee benefit plans	205,907		2		1,444																	1,941			3,387
Deferred compensation obligation																			2,049			(2,049	)		-
Reclassification of restricted stock awards					(2,123	)										2,123									-
Amortization of restricted stock					2,252																				2,252
Stock based compensation					14,575																				14,575
Tax benefit from employee stock plans					1,980																				1,980
Cash dividends - $0.44 per share										(32,004	)														(32,004	)
BALANCE DECEMBER 31, 2006	73,699,244		737		412,989			2,802		844,880			27,378			-			13,956			(100,673	)		1,202,069
Net income										309,233															309,233
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($44,619)													(72,800	)											(72,800	)
Reclassification adjustment, net of tax of ($26,239)													(42,811	)											(42,811	)
Pension and postretirement plans, net of tax of $1,082													2,009												2,009
Comprehensive income																									195,631
Adjustment to initially apply FIN 48										(1,181	)														(1,181	)
Purchase of treasury shares																						(6,760	)		(6,760	)
Shares issued for:
Employee benefit plans	491,542		5		9,671																				9,676
Deferred compensation obligation																			2,165			(2,165	)		-
Amortization of restricted stock					891																				891
Stock based compensation					511																				511
Tax benefit from employee stock plans					10,937																				10,937
Cash dividends - $0.46 per share										(33,116	)														(33,116	)
BALANCE DECEMBER 31, 2007	74,190,786		742		434,999			2,802		1,119,816			(86,224	)		-			16,121			(109,598	)		1,378,658
Net income										321,915															321,915
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $120,742													197,000												197,000
Reclassification adjustment, net of tax of $42,243													68,924												68,924
Pension and postretirement plans, net of tax of ($5,324)													(9,883	)											(9,883	)
Comprehensive income																									577,956
Purchase of treasury shares																						(27,345	)		(27,345	)
Shares issued for:
Employee benefit plans	331,171		3		8,548																				8,551
Deferred compensation obligation																			(13,173	)		13,173			-
Amortization of restricted stock					596																				596
Stock based compensation					(6,458	)																			(6,458	)
Tax benefit from employee stock plans					17,093																				17,093
Adjustment to apply SFAS No. 158, net of tax of ($614)										(1,141	)														(1,141	)
Cash dividends - $0.48 per share										(34,620	)														(34,620	)
BALANCE DECEMBER 31, 2008	74,521,957	$	745	$	454,778		$	2,802	$	1,405,970		$	169,817		$	-		$	2,948		$	(123,770	)	$	1,913,290

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

44

CONSOLIDATED STATEMENTS OF CASH FLOWS

Energen Corporation

Years ended December 31, (in thousands)	2008			2007			2006
Operating Activities
Net income	$	321,915		$	309,233		$	273,570
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		188,413			161,377			142,086
Deferred income taxes		188,414			1,162			98,209
Change in derivative fair value		(2,580	)		(970	)		(2,043	)
Gain on sale of assets		(10,752	)		(506	)		(55,916	)
Other, net		(9,517	)		20,035			4,255
Net change in:
Accounts receivable, net		6,565			71,810			9,249
Inventories		1,274			(13,461	)		1,084
Accounts payable		(36,149	)		(74,927	)		64,178
Amounts due customers		(16,873	)		21,247			(38,940	)
Income tax receivable		(50,476	)		-			-
Other current assets and liabilities		(11,001	)		(10,833	)		(12,812	)
Net cash provided by operating activities		569,233			484,167			482,920
Investing Activities
Additions to property, plant and equipment		(460,237	)		(373,857	)		(302,177	)
Acquisitions, net of cash acquired		(17,914	)		(56,323	)		(27,814	)
Proceeds from sale of assets		16,224			1,295			75,429
Other, net		(2,656	)		(2,994	)		(2,337	)
Net cash used in investing activities		(464,583	)		(431,879	)		(256,899	)
Financing Activities
Payment of dividends on common stock		(34,620	)		(33,116	)		(32,004	)
Issuance of common stock		277			2,051			833
Purchase of treasury stock		-			-			(84,339	)
Reduction of long-term debt		(10,910	)		(155,289	)		(15,898	)
Proceeds from issuance of long-term debt		-			45,000			-
Debt issuance costs		-			(494	)		-
Net change in short-term debt		(72,000	)		76,000			(95,000	)
Tax benefit on stock compensation		17,093			10,937			1,980
Other		-			1,003			-
Net cash used in financing activities		(100,160	)		(53,908	)		(224,428	)
Net change in cash and cash equivalents		4,490			(1,620	)		1,593
Cash and cash equivalents at beginning of period		8,687			10,307			8,714
Cash and cash equivalents at end of period	$	13,177		$	8,687		$	10,307

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

45

STATEMENTS OF INCOME

Alabama Gas Corporation

Years ended December 31, (in thousands)	2008			2007			2006
Operating Revenues	$	654,778		$	609,468		$	663,444
Operating Expenses
Cost of gas		351,774			318,429			373,097
Operations and maintenance		127,877			129,351			126,948
Depreciation and amortization		48,874			47,136			44,244
Income taxes
Current		(26,075	)		15,415			19,745
Deferred		50,904			6,221			2,257
Taxes, other than income taxes		44,297			41,810			44,881
Total operating expenses		597,651			558,362			611,172
Operating Income		57,127			51,106			52,272
Other Income (Expense)
Allowance for funds used during construction		700			611			951
Other income		704			1,665			1,490
Other expense		(3,563	)		(868	)		(961	)
Total other income (expense)		(2,159	)		1,408			1,480
Interest Charges
Interest on long-term debt		11,961			11,956			12,836
Other interest charges		2,846			3,740			3,618
Total interest charges		14,807			15,696			16,454
Net Income	$	40,161		$	36,818		$	37,298

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

46

BALANCE SHEETS

Alabama Gas Corporation

(in thousands)	December 31, 2008			December 31, 2007
ASSETS
Property, Plant and Equipment
Utility plant	$	1,166,967		$	1,108,392
Less accumulated depreciation		480,601			448,053
Utility plant, net		686,366			660,339
Other property, net		151			157
Current Assets
Cash		9,728			7,335
Accounts receivable
Gas		146,886			139,761
Other		10,014			6,336
Allowance for doubtful accounts		(12,100	)		(11,500	)
Inventories, at average cost
Storage gas inventory		77,243			78,064
Materials and supplies		4,381			3,866
Liquified natural gas in storage		3,219			3,502
Regulatory asset		41,714			10,232
Income tax receivable		30,654			2,445
Deferred income taxes		22,152			25,179
Prepayments and other		2,622			2,247
Total current assets		336,513			267,467
Other Assets
Regulatory asset		97,511			32,238
Prepaid pension costs and postretirement assets		-			15,831
Deferred charges and other		6,046			7,226
Total other assets		103,557			55,295
TOTAL ASSETS	$	1,126,587		$	983,258

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

47

BALANCE SHEETS

Alabama Gas Corporation

(in thousands, except share data)	December 31, 2008		December 31, 2007
LIABILITIES AND CAPITALIZATION
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 issued at December 31, 2008 and 2007, respectively		20		20
Premium on capital stock		31,682		31,682
Capital surplus		2,802		2,802
Retained earnings		273,743		261,979
Total common shareholder’s equity		308,247		296,483
Long-term debt		207,557		208,467
Total capitalization		515,804		504,950
Current Liabilities
Notes payable to banks		62,000		62,000
Accounts payable		110,838		80,067
Affiliated companies		21,582		4,934
Accrued taxes		33,911		33,303
Customers’ deposits		22,081		21,425
Amounts due customers		15,124		20,534
Accrued wages and benefits		10,497		10,062
Regulatory liability		25,363		32,154
Other		9,703		10,417
Total current liabilities		311,099		274,896
Deferred Credits and Other Liabilities
Deferred income taxes		102,473		59,790
Pension and other postretirement liabilities		30,021		-
Regulatory liability		147,514		141,123
Long-term derivative instruments		8,821		-
Other		10,855		2,499
Total deferred credits and other liabilities		299,684		203,412
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,126,587	$	983,258

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

48

STATEMENTS OF SHAREHOLDER’S EQUITY

Alabama Gas Corporation

(in thousands, except share data)
	Common Stock			Premium on Capital Stock		Capital Surplus		Retained Earnings			Total Shareholder’s Equity
	Number of Shares	Par Value
Balance December 31, 2005	1,972,052	$	20	$	31,682	$	2,802	$	236,957		$	271,461
Net income									37,298			37,298
Cash dividends									(23,695	)		(23,695	)
Balance December 31, 2006	1,972,052		20		31,682		2,802		250,560			285,064
Net income									36,818			36,818
Cash dividends									(25,399	)		(25,399	)
Balance December 31, 2007	1,972,052		20		31,682		2,802		261,979			296,483
Net income									40,161			40,161
Cash dividends									(28,397	)		(28,397	)
Balance December 31, 2008	1,972,052	$	20	$	31,682	$	2,802	$	273,743		$	308,247

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

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STATEMENTS OF CASH FLOWS

Alabama Gas Corporation

Years ended December 31, (in thousands)	2008			2007			2006
Operating Activities
Net income	$	40,161		$	36,818		$	37,298
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		48,874			47,136			44,244
Deferred income taxes		50,904			6,221			2,257
Other, net		(8,573	)		3,036			(5,019	)
Net change in:
Accounts receivable, net		(9,734	)		19,501			37,260
Inventories		589			(8,698	)		2,384
Accounts payable		3,608			(27,702	)		1,240
Amounts due customers		(16,873	)		21,247			(38,940	)
Income tax receivable		(28,209	)		(4,041	)		1,355
Other current assets and liabilities		774			41			1,835
Net cash provided by operating activities		81,521			93,559			83,914
Investing Activities
Additions to property, plant and equipment		(62,637	)		(58,154	)		(75,107	)
Net advances from parent company		-			-			3,215
Other, net		(3,832	)		(2,460	)		(1,963	)
Net cash used in investing activities		(66,469	)		(60,614	)		(73,855	)
Financing Activities
Payment of dividends on common stock		(28,397	)		(25,399	)		(23,695	)
Reduction of long-term debt		(910	)		(45,289	)		(5,898	)
Proceeds from issuance of long-term debt		-			45,000			-
Debt issuance costs		-			(494	)		-
Net advances from parent company		16,648			(13,196	)		18,130
Net change in short-term debt		-			4,000			3,000
Other		-			1,003			-
Net cash used by financing activities		(12,659	)		(34,375	)		(8,463	)
Net change in cash and cash equivalents		2,393			(1,430	)		1,596
Cash and cash equivalents at beginning of period		7,335			8,765			7,169
Cash and cash equivalents at end of period	$	9,728		$	7,335		$	8,765

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

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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 development, acquisition, 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.

A. Principles of Consolidation

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

B. Oil and Gas Operations

Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. 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. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.

Operating Revenue: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no material production imbalances at December 31, 2008 and 2007.

Derivative Commodity Instruments: Energen Resources applies Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended which requires all derivatives be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item is measured 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 shareholders’ equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized in operating revenues immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 are recorded at fair value with gains or losses recognized in operating revenues in the period of change. All derivative transactions are included in operating activities on the Consolidated Statements of Cash Flows.

Energen Resources periodically enters into derivative commodity instruments to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment and commercial 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. In cases where

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these arrangements exist, the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Company’s credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company in the event credit ratings are below investment grade. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen.

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 New York Mercantile Exchange (NYMEX) hedge 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 pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, 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.

Effective January 1, 2008, the Company partially adopted SFAS No. 157, “Fair Value Measurements,” under the provisions of the Financial Accounting Standards Board (FASB) Staff Position 157-2, “Effective Date of FASB Statement No. 157.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. As defined under SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value defined as follows:

Level 1 –	Unadjusted quoted prices in active markets for identical assets or liabilities;
Level 2 –	Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;
Level 3 –	Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumptions that market participants would use in pricing the asset or liability.

Over-the-counter derivatives are valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of New York Mercantile Exchange (NYMEX) swaps. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and liquids swaps.

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Long-Lived Assets and Discontinued Operations: The Company applies SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which requires the Company to reflect gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for certain held-for-sale properties are reclassified and reported as discontinued operations for prior periods in accordance with SFAS No. 144. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.

C. Natural Gas Distribution

Utility Plant and Depreciation: Property, plant and equipment are stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets are charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided on the straight-line method over the estimated useful lives of utility property at rates approved by the Alabama Public Service Commission (APSC). Approved depreciation rates averaged approximately 4.4 percent in the year ended December 31, 2008 and 4.5 percent in the years ended December 31, 2007 and 2006, respectively.

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

Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had gas imbalances of $1.6 million at December 31, 2008. Alagasco had no material gas imbalances at December 31, 2007.

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.

Derivative Commodity Instruments: On December 4, 2000, the APSC authorized Alagasco to engage in energy-risk management activities. Accordingly, Alagasco may enter into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability as required by SFAS No. 71.

All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Alagasco.

Taxes on revenues: Collections and payments of excise taxes are reported on a gross basis. These amounts are included in taxes other than income taxes on the consolidated statements of income as follows:

Years ended December 31, (in thousands)	2008	2007		2006
Taxes on revenues	$  32,970	$	31,067	$	33,983

The collection and payment of utility gross receipts tax is presented on a net basis.

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D. Income Taxes

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

E. Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The Company determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.

F. Cash Equivalents

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

G. Earnings Per Share (EPS)

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, Reconciliation of Earnings Per Share).

H. Stock-Based Compensation

The Company applies SFAS No. 123R (revised 2004), “Share-Based Payment” (SFAS No. 123R), using the modified prospective application method for new awards effective January 1, 2006. SFAS No. 123R requires that all share-based compensation awards be measured at fair value at the date of grant and expensed over the requisite vesting period. SFAS No. 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates.

The Company previously recognized all stock-based employee compensation expense over the stated vesting periods for each award. For awards granted prior to January 1, 2006, the Company recorded any unrecognized expense on the date of an employee’s retirement. For new awards granted to retirement eligible employees effective January 1, 2006, the Company began recognizing the entire compensation expense in the period of grant. If this method of expense recognition had been applied to all awards during 2008 compensation expense would have been increased by approximately $1.2 million. If this method of expense recognition had been applied to all awards during 2007 and 2006 compensation expense would have been reduced by approximately $1.1 million and $2.1 million, respectively. The Company utilized the long-form method of calculating the available pool of windfall tax benefit. For 2008 and 2007, the Company recognized an excess tax benefit of $17.1 million and $10.9 million related to its stock-based compensation.

I. 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

54

date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, estimates of physical quantities of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that SFAS No. 71 will continue as the applicable accounting standard for the Company’s regulated operations and estimates used in determining the Company’s obligations under its employee pension plans and asset retirement obligations. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

J. Environmental Costs

Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended in 2007, 2002, 1996, 1990, 1987 and 1985. RSE’s current extension is for a seven-year period through December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes.

Alagasco’s allowed range of return on equity remains 13.15 percent to 13.65 percent throughout the term of the order. Under RSE the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, whether Alagasco’s return on average equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. As of September 30, 2007, Alagasco had a $3.6 million reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. Under the provisions of RSE, corresponding reductions in rates for 2007 were effective October 1, 2007 and December 1, 2007. Alagasco did not have a reduction in rates related to the return on average equity for rate years ended 2008 and 2006. A $24.7 million, $12 million and $14.3 million annual increase in revenues became effective December 1, 2008, 2007, and 2006, respectively.

At September 30, 2008, RSE limited the utility’s equity upon which a return is permitted to 57 percent of total capitalization. The equity upon which a return is permitted will be phased down to 55 percent by September 30, 2009.

Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 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 on an aggregate basis 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 O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation.

In the rate year ended September 30, 2008, the increase in O&M expense was below the Index Range; as a result the utility benefited by $2.9 million pre-tax with the related impact to rates effective December 1, 2008. Alagasco’s O&M expense fell within the Index Range for the rate year ended September 30, 2007. The increase in O&M expense per customer was above the Index Range for the rate year ended September 30, 2006; as a result, the utility had a $1.5 million pre-tax decrease in revenues with the related rate reduction effective December 1, 2006.

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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. Alagasco is allowed a temperature adjustment to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment such as the impact of wind velocity or cloud cover and the elasticity of demand as a result of higher commodity prices.

The APSC approved an Enhanced Stability Reserve (ESR), beginning rate 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. 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. An ESR balance of $4 million at December 31, 2007 is included in the consolidated financial statements. Under the terms of the 2007 RSE extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR. Due to revenue losses from market sensitive large commercial and industrial customers, Alagasco utilized the entire ESR of approximately $4 million pre-tax during the third quarter of 2008.

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, 2008 and 2007, the net acquisition adjustments were $7 million and $8.1 million, respectively.

3. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

(in thousands)	December 31, 2008	December 31, 2007
Energen Corporation:
Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.625%, for notes due December 15, 2010, to February 15, 2028	$    305,000	$    315,000
5% Notes, due October 1, 2013	50,000	50,000
Alabama Gas Corporation:
Medium-term Notes, Series A, interest of 7.57%, due September 20, 2011	5,000	5,000
5.20% Notes, due January 15, 2020	40,000	40,000
5.70% Notes, due January 15, 2035	37,557	38,467
5.368% Notes, due December 1, 2015	80,000	80,000
5.90% Notes, due January 15, 2037	45,000	45,000
Total	562,557	573,467
Less amounts due within one year	-	10,000
Less unamortized debt discount	926	1,102
Total	$    561,631	$    562,365

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

Years ending December 31, (in thousands)
2009	2010	2011	2012	2013
-	$  150,000	$  5,000	$  1,000	$  50,000

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

Years ending December 31, (in thousands)
2009	2010	2011	2012	2013
-	-	$  5,000	-	-

The Company is in compliance with the financial covenants under its 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. The Company’s outstanding debt is subject to a cross default provision under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee. In the event Alagasco or Energen Resources had a debt default of more than $10 million it would also be considered an event of default by Energen under the 1996 Indenture. All of the Company’s debt is unsecured. No conditions exist under long-term debt agreements which could restrict the Company’s ability to pay dividends.

In May 2007, Energen voluntarily called $100 million Floating Rate Senior Notes due November 15, 2007. In April 2007, Energen voluntarily redeemed $10 million of Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026. Associated with this redemption, the Company incurred a call premium of 4.045%. In January 2007, Alagasco issued $45 million of long-term debt with an interest rate of 5.9% due January 15, 2037. Alagasco used these long-term debt proceeds to redeem the $34.4 million of 6.75% Notes, maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026.

As of December 31, 2008, the Company had short-term credit lines and other credit facilities, with renewal terms at various dates during 2009, with various financial institutions aggregating $490 million of which Energen had available $205 million, Alagasco had available $115 million and $170 million was available to either Company for working capital needs. Alagasco has been authorized by the APSC to borrow up to $200 million at any one time outstanding under short-term lines of credit. As of December 31, 2008, the Company is in compliance with the financial covenants under the various short-term loan agreements. Certain of the Company’s credit facilities in the aggregate amount of $95 million; including $60 million for Energen and $35 million for Alagasco, have a covenant that the ratio of consolidated debt to consolidated capitalization will not exceed 0.65:1. The following is a summary of information relating to notes payable to banks:

(in thousands)	December 31, 2008	December 31, 2007
Energen outstanding	$                -	$      72,000
Alagasco outstanding	62,000	62,000
Notes payable to banks	62,000	134,000
Available for borrowings	428,000	281,000
Total	$    490,000	$    415,000
Energen maximum amount outstanding at any month-end	$    128,000	$    134,000
Energen average daily amount outstanding	$      89,210	$      67,734
Energen weighted average interest rates based on:
Average daily amount outstanding	2.82%	5.35%
Amount outstanding at year-end	1.35%	4.64%
Alagasco maximum amount outstanding at any month-end	$      75,000	$      62,000
Alagasco average daily amount outstanding	$      35,833	$      29,518
Alagasco weighted average interest rates based on:
Average daily amount outstanding	2.82%	5.39%
Amount outstanding at year-end	1.35%	4.62%

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Energen’s total interest expense was $41,981,000, $47,100,000 and $48,652,000 for the years ended December 31, 2008, 2007 and 2006, respectively. Total interest expense for Alagasco was $14,807,000, $15,696,000 and $16,454,000 for the years ended December 31, 2008, 2007 and 2006, respectively.

4. INCOME TAXES

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

Years ended December 31, (in thousands)	2008		2007		2006
Taxes estimated to be payable currently:
Federal	$	1,090	$	149,787	$	47,799
State		3,539		16,480		9,022
Total current		4,629		166,267		56,821
Taxes deferred:
Federal		172,137		838		93,605
State		16,277		324		4,604
Total deferred		188,414		1,162		98,209
Total income tax expense from continuing operations	$	193,043	$	167,429	$	155,030

For the year ended December 31, 2008, Energen recorded no income tax expense related to income from discontinued operations. For the years ended December 31, 2007 and 2006, Energen recorded a current income tax expense of $12,000 and $29,000, respectively, related to income from discontinued operations.

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

Years ended December 31, (in thousands)	2008			2007		2006
Taxes estimated to be payable currently:
Federal	$	(24,972	)	$	13,604	$	17,472
State		(1,103	)		1,811		2,273
Total current		(26,075	)		15,415		19,745
Taxes deferred:
Federal		46,869			5,510		1,999
State		4,035			711		258
Total deferred		50,904			6,221		2,257
Total income tax expense	$	24,829		$	21,636	$	22,002

Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows:

(in thousands)	December 31, 2008				December 31, 2007
	Current		Noncurrent		Current		Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	9,574	$	-	$	10,648	$	-
Enhanced stability reserve and other regulatory costs		-		-		1,497		-
Allowance for doubtful accounts		4,803		-		4,567		-
Insurance accruals		1,747		-		2,564		-
Compensation accruals		6,952		-		8,655		-
Inventories		1,142		-		1,230		-
Other comprehensive income		-		-		23,995		27,275
Gas supply adjustment related accruals		1,953		-		1,486		-

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State net operating losses and other carryforwards		842			2,777			-			3,024
Other		2,933			121			2,789			153
Total deferred tax assets		29,946			2,898			57,431			30,452
Valuation allowance		(353	)		(2,424	)		(2,137	)		(887	)
Total deferred tax assets		29,593			474			55,294			29,565
Deferred tax liabilities:
Depreciation and basis differences		-			426,031			-			261,137
Pension and other costs		-			17,102			-			6,094
Other comprehensive income		68,619			37,773			-			-
Enhanced stability reserve and other regulatory costs		1,014			-			-			-
Other		1,929			1,626			1,128			1,040
Total deferred tax liabilities		71,562			482,532			1,128			268,271
Net deferred tax assets (liabilities)	$	(41,969	)	$	(482,058	)	$	54,166		$	(238,706	)

Temporary differences and carryforwards which gave rise to Alagasco’s deferred tax assets and liabilities were as follows:

(in thousands)	December 31, 2008					December 31, 2007
	Current		Noncurrent			Current		Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	9,574	$	-		$	10,648	$	-
Enhanced stability reserve and other regulatory costs		-		-			1,497		-
Allowance for doubtful accounts		4,575		-			4,348		-
Insurance accruals		2,671		-			2,804		-
Compensation accruals		2,502		-			3,132		-
Inventories		1,142		-			1,230		-
Gas supply adjustment related accruals		1,953		-			1,486		-
State net operating losses and other carryforwards		842		-			-		-
Other		745		97			704		115
Total deferred tax assets		24,004		97			25,849		115
Deferred tax liabilities:
Depreciation and basis differences		-		84,458			-		48,892
Pension and other costs		-		18,112			-		11,013
Enhanced stability reserve and other regulatory costs		1,014		-			-		-
Other		838		-			670		-
Total deferred tax liabilities		1,852		102,570			670		59,905
Net deferred tax assets (liabilities)	$	22,152	$	(102,473	)	$	25,179	$	(59,790	)

The Company files a consolidated federal income tax return with all of its subsidiaries. The Company has a full valuation allowance recorded against a noncurrent deferred tax asset of $2,777,000 arising from certain state net operating loss and charitable contribution carryforwards. The Company intends to fully reserve this asset until it is determined that it is more likely than not that the asset can be realized through future taxable income in the respective state taxing jurisdictions. No other 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 remaining deferred tax assets on the consolidated balance sheets.

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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 percent to earnings before taxes from continuing operations as illustrated below:

Years ended December 31, (in thousands)	2008			2007			2006
Income tax expense from continuing operations at statutory federal income tax rate	$	180,235		$	166,824		$	149,994
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit		12,524			12,251			8,906
Qualified Section 199 production activities deduction		(455	)		(8,470	)		(1,114	)
401(k) stock dividend deduction		(574	)		(637	)		(682	)
Other, net		1,313			(2,539	)		(2,074	)
Total income tax expense from continuing operations	$	193,043		$	167,429		$	155,030
Effective income tax rate (%)		37.49			35.13			36.18

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 percent to earnings before taxes from continuing operations as illustrated below:

Years ended December 31, (in thousands)	2008		2007			2006
Income tax expense at statutory federal income tax rate	$	22,747	$	20,459		$	20,755
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit		1,826		1,643			1,666
Other, net		256		(466	)		(419	)
Total income tax expense	$	24,829	$	21,636		$	22,002
Effective income tax rate (%)		38.20		37.01			37.10

Energen adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109” (FIN 48) as of January 1, 2007. This Interpretation prescribed a recognition threshold and measurement attribute for the financial statement recognition, measurement and disclosure of a tax position taken or expected to be taken in a tax return. As a result of the implementation of FIN 48, the Company recognized an approximate $1.2 million increase in the liability for unrecognized tax benefits which was accounted for as a decrease to the January 1, 2007 retained earnings balance. A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)
Balance as of January 1, 2007	$	8,163
Additions based on tax positions related to the current year		1,162
Additions for tax positions of prior years		2,372
Reductions for tax positions of prior years (lapse of statute of limitations)		(3,180	)
Balance as of December 31, 2007		8,517
Additions based on tax positions related to the current year		2,732
Additions for tax positions of prior years		7,199
Reductions for tax positions of prior years (lapse of statute of limitations)		(1,643	)
Balance as of December 31, 2008	$	16,805

The increase in the additions for tax positions of prior years in 2008 is primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property that was recently approved by the Internal Revenue Service (IRS). The amount of unrecognized tax benefits at December 31, 2008 that would favorably impact the Company’s effective tax rate, if recognized, is $3.3 million. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2008, 2007, and 2006, the Company recognized approximately $164,000 of expense, $36,000 of expense, and $155,000 of income for interest (net of tax benefit) and penalties, respectively. The Company had approximately $681,000 and $517,000 for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2008, and 2007, respectively.

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The adoption of FIN 48 resulted in no adjustment to Alagasco’s January 1, 2007 retained earnings balance. A reconciliation of Alagasco’s beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)
Balance as of January 1, 2007	$	713
Additions for tax positions of prior years		578
Reductions for tax positions of prior years (lapse of statute of limitations)		(336	)
Balance as of December 31, 2007		955
Additions based on tax positions related to the current year		515
Additions for tax positions of prior years		5,804
Reductions for tax positions of prior years (lapse of statute of limitations)		(384	)
Balance as of December 31, 2008	$	6,890

The increase in the additions for tax positions of prior years in 2008 is primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property discussed above. The amount of unrecognized tax benefits at December 31, 2008 that would favorably impact Alagasco’s effective tax rate, if recognized, is $195,000. Alagasco recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2008, 2007, and 2006, Alagasco recognized approximately $131,000 of expense, $23,000 of expense and $36,000 of income for interest (net of tax benefit) and penalties, respectively. Alagasco had approximately $218,000 and $87,000 for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2008, and 2007, respectively.

The Company and Alagasco’s tax returns for years 2005-2007 remain open to examination by the IRS and major state taxing jurisdictions. The IRS has notified the Company and Alagasco of a forthcoming examination of its federal consolidated income tax returns for 2006 and 2007 that will commence in 2009. The Alabama Department of Revenue has also notified the Company and Alagasco of its intent to examine the 2005-2007 Alabama income tax returns. The change in the unrecognized tax benefit expected within the next 12 months is not considered material to the financial statements.

5. EMPLOYEE BENEFIT PLANS

The Company accounts for defined benefit pension plans and other postretirement benefit plans (benefit plans) in accordance with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R).” Periodic expense is calculated on an actuarial basis and the net funded status of benefit plans is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligation to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be provided through rates in the future in accordance with SFAS No. 71. SFAS No. 158 requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position effective for fiscal years ending after December 15, 2008. The Company previously used a September 30 valuation date for its benefit plans. During the fourth quarter of 2008, the Company changed the measurement date to December 31 using the alternative method. The Company recognized a one-time reduction to retained earnings of $1.8 million pre-tax and an increase to the current and noncurrent regulatory assets of Alagasco totaling approximately $0.1 million and $1.4 million pre-tax, respectively. The increase to regulatory assets which total $1.5 million will be recovered in rates over the average remaining service lives of each plan.

Pension Plans:

The Company has two defined benefit non-contributory qualified pension plans. These plans cover substantially all employees. Pension benefits for the majority of the Company’s employees are based on years of service and final earnings; one plan is based on years of service and flat dollar amounts. The Company’s policy is to use the projected unit credit actuarial method for financial reporting purposes. The Company also has nonqualified supplemental pension plans covering certain officers of the Company.

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The following table sets forth the combined funded status of the pension plans and their reconciliation with the related amounts in the Company’s consolidated financial statements:

(in thousands)
	December 31, 2008				September 30, 2007
Accumulated benefit obligation		$	156,304			$	161,437
Projected benefit obligation:
Balance at beginning of period		$	199,363			$	198,637
Service cost			8,951				6,812
Interest cost			14,751				11,106
Plan amendments			(365	)			2,538
Actuarial (gain) loss			(5,957	)			3,614
Benefits paid			(26,312	)			(23,344	)
Balance at end of period		$	190,431			$	199,363
Plan assets:
Fair value of plan assets at beginning of period		$	176,644			$	160,936
Actual return (loss) on plan assets			(38,643	)			22,245
Employer contributions			27,585				16,807
Benefits paid			(26,312	)			(23,344	)
Fair value of plan assets at end of period		$	139,274			$	176,644
Funded status of plan (September 30, 2007)			-			$	(22,718	)
Employer contributions (October 1 to December 31, 2007)			-				50
Funded status of plan (December 31)		$	(51,157	)		$	(22,668	)
Noncurrent assets		$	-			$	12,443
Current liabilities			(3,888	)			(3,126	)
Noncurrent liabilities			(47,269	)			(31,985	)
Net liability recognized (December 31)		$	(51,157	)		$	(22,668	)
Amounts recognized to accumulated other comprehensive income:
Prior service costs, net of tax of $0.7 million and $0.9 million		$	1,334			$	1,675
Net actuarial loss, net of tax of $14.8 million and $11.1 million			27,402				20,525
Total accumulated other comprehensive income (December 31)		$	28,736			$	22,200

Alagasco recognized a regulatory asset of $54.7 million and $21.2 million as of December 31, 2008 and 2007, respectively, for the portion of the obligation to be recovered through rates in future periods in accordance with SFAS No. 71. Additionally, Alagasco recognized an offset of $2 million to a regulatory liability as of December 31, 2007, for the portion of the plan obligation to be provided through rates in future periods in accordance with SFAS No. 71.

Related to the Company’s nonqualified supplemental retirement plans, the Company has designated assets of $18.3 million and $27.3 million as of December 31, 2008 and 2007, respectively. While intended for payment of this benefit, these assets remain subject to the claims of the Company’s creditors and are not included in the fair value of plan assets in the above table. Accordingly, these assets are not recognized in the funded status of the plan.

Other changes in pension plan assets and projected benefit obligations recognized in other comprehensive income were as follows:

Years ended December 31, (in thousands)	2008			2007
Net actuarial loss experienced during the year	$	14,061		$	1,312
Net actuarial loss recognized as expense		(3,472	)		(6,583	)
Prior service cost established during the year		(131	)		-
Prior service cost recognized as expense		(403	)		(321	)
Total recognized in other comprehensive income (December 31)	$	10,055		$	(5,592	)

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Estimated amounts to be amortized from accumulated other comprehensive income into pension cost during 2009 are as follows:

(in thousands)
Amortization of prior service cost	$	299
Amortization of net actuarial loss	$	2,378

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

	December 31, 2008		September 30, 2007
Discount rate	6.50	%	6.18	%
Rate of compensation increase for pay-related plans	3.90	%	4.07	%

The components of net pension expense were:

Years ended December 31, (in thousands)	2008			2007			2006
Components of net periodic benefit cost:
Service cost	$	7,160		$	6,812		$	6,452
Interest cost		11,802			11,106			10,715
Expected long-term return on assets		(13,156	)		(13,070	)		(11,990	)
Transition amortization		-			-			4
Prior service cost amortization		918			918			726
Actuarial loss		4,283			4,611			5,257
Settlement loss		677			5,656			326
Net periodic expense	$	11,684		$	16,033		$	11,490

Net retirement expense for Alagasco was $5,595,000, $6,812,000 and $6,158,000 for the years ended December 31, 2008, 2007 and 2006, respectively. The Company recognized settlement charges of $2.4 million in 2007 for the payment of lump sums from the nonqualified supplemental retirement plans. The Company also recognized settlement charges of $0.7 million in the fourth quarter of 2008 and $3.2 million in the third quarter of 2007 for the payment of lump sums from a defined benefit pension plan. This charge represented an acceleration of the unamortized actuarial losses as required under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.”

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

	December 31, 2008		December 31, 2007		December 31, 2006
Discount rate	6.18	%	5.77	%	5.50	%
Expected long-term return on plan assets	8.25	%	8.25	%	8.50	%
Rate of compensation increase for pay-related plans	4.07	%	4.22	%	3.60	%

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

	Target		December 31, 2008		December 31, 2007
Asset category:
Equity securities	49	%	47	%	51	%
Debt securities	28	%	30	%	29	%
Other	23	%	23	%	20	%
Total	100	%	100	%	100	%

Plan equity securities do not include the Company’s common stock. The Company is not required to make pension contributions in 2009 but expects to make discretionary contributions of at least $5 million. The Company expects to make benefit payments of approximately $3.9 million during 2009 to retirees from the nonqualified supplemental retirement plans.

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Defined benefit pension plan payments, which reflect expected future service, are anticipated to be paid as follows:

(in thousands)
2009	$	14,122
2010	$	13,914
2011	$	14,958
2012	$	16,443
2013	$	18,196
2014-2018	$	116,433

Postretirement Health Care and Life Insurance Benefits:

In addition to providing pension benefits, the Company provides certain postretirement health care and life insurance benefits. Substantially all of the Company’s employees may become eligible for certain benefits if they reach normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.

The status of the postretirement benefit programs was as follows:

(in thousands)
	December 31, 2008				September 30, 2007
Projected postretirement benefit obligation:
Balance at beginning of period		$	78,975			$	63,818
Service cost			2,046				1,022
Interest cost			6,143				3,693
Actuarial (gain) loss			(5,641	)			14,395
Benefits paid			(4,897	)			(3,953	)
Balance at end of period		$	76,626			$	78,975
Plan assets:
Fair value of plan assets at beginning of period		$	86,660			$	77,939
Actual return (loss) on plan assets			(27,926	)			11,493
Employer contributions			2,584				1,181
Benefits paid			(4,897	)			(3,953	)
Fair value of plan assets at end of period		$	56,421			$	86,660
Funded status of plan (September 30, 2007)			-			$	7,685
Employer contributions (October 1 to December 31, 2007)			-				234
Funded status of plan (December 31)		$	(20,205	)		$	7,919
Noncurrent assets (liabilities)		$	(20,205	)		$	7,919
Net asset (liability) recognized (December 31)		$	(20,205	)		$	7,919
Amounts recognized to accumulated other comprehensive income (loss):
Transition obligation, net of taxes of $496 and $585		$	921			$	1,086
Net actuarial (gain) loss, net of taxes of $750 and ($1,141)			1,393				(2,119	)
Total accumulated other comprehensive income (loss) (December 31)		$	2,314			$	(1,033	)

Alagasco recognized a regulatory asset of $16.4 million as of December 31, 2008 for the portion of the obligation to be recovered through rates in future periods in accordance with SFAS No. 71. Alagasco recognized a regulatory liability of $6.2 million as of December 31, 2007.

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Other changes in postretirement plan assets and projected benefit obligations recognized in other comprehensive income were as follows:

Years ended December 31, (in thousands)	2008			2007
Net actuarial loss experienced during the year	$	5,333		$	2,464
Amortization of net actuarial gain		157			279
Amortization of transition asset		(341	)		(246	)
Total recognized in other comprehensive income (December 31)	$	5,149		$	2,497

Estimated amounts to be amortized from accumulated other comprehensive income into benefit cost during 2009 are as follows:

(in thousands)
Amortization of transition obligation	$	273
Amortization of net actuarial gain	$	49

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

	December 31, 2008		September 30, 2007
Discount rate	6.50	%	6.40	%
Rate of compensation increase for pay-related plans	3.55	%	3.65	%

Net periodic postretirement benefit expense included the following:

Years ended December 31, (in thousands)	2008			2007			2006
Components of net periodic benefit cost:
Service cost	$	1,637		$	1,023		$	1,217
Interest cost		4,914			3,693			3,682
Expected long-term return on assets		(5,534	)		(5,002	)		(4,858	)
Actuarial gain		(781	)		(1,260	)		(884	)
Transition amortization		1,917			1,917			1,917
Net periodic expense	$	2,153		$	371		$	1,074

Net periodic postretirement benefit expense for Alagasco was $1,457,000, $300,000 and $971,000 for the years ended December 31, 2008, 2007 and 2006, respectively.

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

	December 31, 2008		December 31, 2007		December 31, 2006
Discount rate	6.40	%	5.95	%	5.50	%
Expected long-term return on plan assets	8.25	%	8.25	%	8.50	%
Rate of compensation increase	3.65	%	3.70	%	3.50	%

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

	December 31, 2008		September 30, 2007
Health care cost trend rate assumed for next year	9.50	%	9.50	%
Rate to which the cost trend rate is assumed to decline	5.50	%	5.50	%
Year that rate reaches ultimate rate	2013		2011

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

(in thousands)
	1-Percentage Point Increase
Effect on total of service and interest cost	$         510
Effect on net postretirement benefit obligation	$      5,007

The Company’s weighted-average postretirement benefit program asset allocations by asset category were as follows:

	Target		December 31, 2008		December 31, 2007
Asset category:
Equity securities	70	%	65	%	70	%
Debt securities	30	%	35	%	30	%
Total	100	%	100	%	100	%

Equity securities for the postretirement benefit programs do not include the Company’s common stock. The Company expects to make discretionary contributions of $4.7 million to postretirement benefit program assets during 2009.

The following postretirement benefit payments, which reflect expected future service, are anticipated to be paid:

(in thousands)
2009	$	4,430
2010	$	4,667
2011	$	4,925
2012	$	5,157
2013	$	5,381
2014-2018	$	31,113

The following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy beginning in 2007:

(in thousands)
2009	$	(327	)
2010	$	(340	)
2011	$	(349	)
2012	$	(356	)
2013	$	(358	)
2014-2018	$	(1,726	)

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

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

The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the

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Company to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily.

The Company based its expected return on long-term investment expectations. The Company considered past performance and current expectations for assets held by the plan as well as the expected long-term allocation of plan assets. At December 31, 2008, the expected return on plan assets was 8.25%.

The Company has a long-term disability plan covering most employees. The Company had expense for the years ended December 31, 2008, 2007 and 2006 of $346,000, $382,000 and $304,000, respectively.

6. COMMON STOCK PLANS

Energen Employee Savings Plan (ESP): A majority of Company employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. The Company may match a percentage of the contributions and make these contributions in Company common stock or in funds for the purchase of Company common stock. Vested employees may diversify 100 percent of their ESP Company stock account into other ESP investment options. The ESP also contains employee stock ownership plan provisions. At December 31, 2008, total shares reserved for issuance equaled 1,080,108. Expense associated with Company contributions to the ESP was $5,559,000, $5,237,000 and $4,891,000 for the years ended December 31, 2008, 2007 and 2006, respectively.

1997 Stock Incentive Plan and 1988 Stock Option Plan: The 1997 Stock Incentive Plan and the Energen 1988 Stock Option Plan provided for the grant of incentive stock options and non-qualified stock options to officers and key employees. The 1997 Stock Incentive Plan also provided for the grant of performance share awards and restricted stock. The Company has typically funded options, restricted stock obligations and performance share obligations through original issue shares. Under the 1997 Stock Incentive Plan, 5,600,000 shares of Company common stock were reserved for issuance with 1,804,432 remaining for issuance as of December 31, 2008. Under the 1988 Stock Option Plan, 1,080,000 shares of Company common stock reserved for issuance have been granted.

Performance Share Awards: The Energen 1997 Stock Incentive Plan provided for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of a four-year award period. The 1997 Stock Incentive Plan provided that payment of earned performance share awards be made in the form of Company common stock.

1997 Stock Incentive Plan performance share awards granted or modified after the adoption of SFAS No. 123R have been valued in a Monte Carlo model. The Monte Carlo model uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. For performance share awards granted prior to the adoption of SFAS No. 123R, the Company estimated fair value based on the quoted market price of the Company’s common stock and adjusted each period for the expected payout ratio.

No performance share awards were granted in 2008 or 2007. A summary of performance share award activity as of December 31, 2008, and transactions during the years ended December 31, 2008, 2007 and 2006 are presented below:

	1997 Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2005	477,720		$    40.26
Granted	111,990		43.81
Forfeitures	(847	)	43.81
Nonvested at December 31, 2006	588,863		40.81
Vested and paid	(225,960	)	30.53
Nonvested at December 31, 2007	362,903		49.87
Vested and paid	(134,220	)	54.25
Nonvested at December 31, 2008	228,683		$    30.80

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The Company recorded income of $2,308,000 for the year ended December 31, 2008 for performance share awards with a related deferred income tax expense of $873,000. The Company recorded expense of $4,254,000 and $8,779,000 for the years ended December 31, 2007 and 2006, respectively, for performance share awards with a related deferred income tax benefit of $1,608,000 and $3,319,000, respectively. As of December 31, 2008, there was $502,000 of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1 year.

Stock Options: The 1997 Stock Incentive Plan and the Energen 1988 Stock Option Plan provided for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the 1997 Stock Incentive Plan provided for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date.

A summary of stock option activity as of December 31, 2008, and transactions during the years ended December 31, 2008, 2007 and 2006 are presented below:

	1997 Stock Incentive Plan					1988 Stock Option Plan
	Shares		Weighted Average Exercise Price			Shares		Weighted Average Exercise Price
Outstanding at December 31, 2005	613,400			$	14.04	28,000			$	9.13
Exercised	(206,322	)			13.18	(7,000	)			9.13
Outstanding at December 31, 2006	407,078				14.69	21,000				9.13
Granted	239,545				46.71	-				-
Exercised	(180,284	)			15.59	(21,000	)			9.13
Outstanding at December 31, 2007	466,339				30.79	-				-
Granted	186,700				60.56	-				-
Exercised	(28,068	)			11.88
Forfeited	(4,454	)			10.17
Outstanding at December 31, 2008	620,517			$	40.75	-			$	-
Exercisable at December 31, 2006	324,318			$	12.98	21,000			$	9.13
Exercisable at December 31, 2007	226,794			$	13.97	-			$	-
Exercisable at December 31, 2008	276,530			$	24.05	-			$	-
Remaining reserved for issuance at December 31, 2008	1,804,432				-	-				-

During 2008, the Company granted 186,700 shares with a weighted-average grant-date fair value of $17.83. The Company granted options for 232,285 shares during the first quarter of 2007 and 7,260 shares during the second quarter of 2007 with weighted-average grant-date fair values of $17.33 and $20.05, respectively. The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values: a 6 year time of exercise; an annualized volatility rate of 24.3 percent in 2008; an annualized volatility rate of 27.3 percent and 25.2 percent for the first and second quarters of 2007, respectively; a risk-free interest rate of 2.87 percent for 2008; a risk-free interest rate of 4.75 percent and 5 percent for the first and second quarters of 2007, respectively; and a dividend yield of zero to reflect dividend protection in award provisions. The Company granted no stock options during 2006. The Company recorded stock option expense of $3,080,000, $3,124,000 and $196,000 during the years ended December 31, 2008, 2007 and 2006, respectively, with a related deferred tax benefit of $1,165,000, $1,181,000 and $41,000 respectively.

The total intrinsic value of stock options exercised during the year ended December 31, 2008, was $911,000. During the year ended December 31, 2008, the total intrinsic value of stock appreciation rights exercised was $172,000. During the year ended December 31, 2008, the Company received cash of $347,000 from the exercise of stock options and paid $123,000 in settlement of stock appreciation rights. Total intrinsic value for both outstanding and exercisable options as of December 31, 2008, was $2,909,000. The fair value of options vested for the year ended December 31, 2008 was $1,390,000. As of December 31, 2008, there was $1,278,000 of unrecognized compensation cost related to outstanding nonvested stock options.

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The following table summarizes options outstanding as of December 31, 2008:

1997 Stock Incentive Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$9.41	19,768	0.83 years
$13.72	46,062	1.83 years
$11.32	34,680	2.83 years
$14.86	65,280	4.08 years
$21.38	28,482	5.08 years
$46.45	232,285	8.00 years
$55.08	7,260	8.50 years
$60.56	186,700	9.00 years
$9.41-$60.56	620,517	6.79 years

The weighted average remaining contractual life of currently exercisable stock options is 4.60 years as of December 31, 2008.

Restricted Stock: In addition, the 1997 Stock Incentive Plan provided for the grant of restricted stock which have been valued based on the quoted market price of the Company’s common stock at the date of grant. A summary of restricted stock activity as of December 31, 2008, and transactions during the years ended December 31, 2008, 2007 and 2006 is presented below:

	1997 Stock Incentive Plan
	Shares		Weighted Average Price
Nonvested at December 31, 2005	242,444		$    20.48
Granted	44,750		40.10
Vested	(59,764	)	14.99
Forfeited	(1,600	)	29.16
Nonvested at December 31, 2006	225,830		25.76
Granted	6,805		46.45
Vested	(95,040	)	21.18
Nonvested at December 31, 2007	137,595		29.94
Vested	(26,240	)	23.36
Nonvested at December 31, 2008	111,355		$    31.49

The Company recorded expense of $596,000, $908,000 and $2,252,000 for the years ended December 31, 2008, 2007 and 2006, respectively, related to restricted stock, with a related deferred income tax benefit of $225,000, $343,000 and $851,000, respectively. As of December 31, 2008, there was $496,000 of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a remaining requisite service period of 0.68 years.

2004 Stock Appreciation Rights Plan: The Energen 2004 Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. These awards have a three year requisite service period. In 2008, 67,093 awards were granted with stock appreciation rights. These awards had a weighted average grant-date fair value of $2.73 as of December 31, 2008 which was calculated using the Black-Scholes pricing model. For purposes of this valuation the following assumptions were used to derive the fair value: an expected life of the award of 5.6 years; an annualized volatility rate of 34.1 percent; a risk-free interest rate of 1.70 percent; and a dividend yield of 1.6 percent. During 2007, 85,906 awards were granted with stock appreciation rights. These awards had a weighted average grant-date fair value of $3.87 as of December 31, 2008 which was calculated using the

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Black-Scholes pricing model. For purposes of this valuation the following assumptions were used to derive the fair value: an expected life of the award of 4.6 years; an annualized volatility rate of 34.1 percent; a risk-free interest rate of 1.46 percent; and a dividend yield of 1.6 percent. There were no awards granted with stock appreciation rights in 2006. Income associated with stock appreciation rights of $2,413,000 was recorded for the year ended December 31, 2008. Expense associated with stock appreciation rights of $1,933,000 and $1,218,000 was recorded for the years ended December 31, 2007 and 2006, respectively.

Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provided for the grant of stock equivalent units which may include market conditions. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. Effective January 1, 2006, the fair value of the stock equivalent units with a market condition was calculated using a Monte Carlo approach. Stock equivalent units with service conditions were valued based on the Company’s stock price at the end of the period adjusted to remove the present value of future dividends. Prior to the implementation of SFAS No. 123R, these awards were valued using the Company’s common stock price at each period end.

Energen Resources awarded 1,805 stock equivalent units with a two year vesting period and 1,014 stock equivalent units with a three year vesting period in 2008, none of which included a market condition. During 2007, Energen Resources awarded 5,242 stock equivalent units with a three year vesting period, none of which included a market condition. During 2006, Energen Resources awarded 25,720 stock equivalent units with a three year vesting period of which 22,545 included a market condition. Energen Resources recognized income of $2,042,000 during 2008 related to these units. Energen Resources recognized expense of $2,389,000 and $791,000 during 2007 and 2006, respectively, related to these units.

1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed 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 trust’s assets remain subject to the claims of the Company’s 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.

1992 Energen Corporation Directors Stock Plan: In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 11,218 shares, 11,503 shares and 11,517 shares were awarded during the years ended December 31, 2008, 2007 and 2006, respectively, leaving 202,724 shares reserved for issuance as of December 31, 2008.

Dividend Reinvestment and Direct Stock Purchase Plan: The Company’s Dividend Reinvestment and Direct Stock Purchase Plan included a direct stock purchase feature which allowed purchases by non-shareholders. As of December 31, 2008, 1,098,292 common shares were reserved under this Plan. Effective December 15, 2006, the Company suspended operations under the Plan and shareholders became eligible to reinvest dividends or make direct stock purchases using the Company’s stock transfer and dividend paying agent, The Bank of New York.

Stock Repurchase Program: By resolution adopted May 25, 1994, and supplemented by a resolution adopted April 26, 2000 and June 24, 2006, the Board authorized the Company to repurchase up to 12,564,400 shares of the Company’s common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2008 and 2007. For the year ended December 31, 2006, the Company repurchased 2,158,000 shares pursuant to its repurchase authorization. As of December 31, 2008, a total of 8,992,700 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company’s stock compensation plans. For the years ended December 31, 2008, 2007 and 2006, the Company acquired 446,045 shares, 209,388 shares and 82,707 shares, respectively, in connection with its stock compensation plans.

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7. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Certain of Alagasco’s long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $118 million through October 2015. Alagasco 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 119.9 Bcf through April 2015.

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company’s financial position, results of operations or cash flows; however, remediation of the Huntsville, Alabama manufactured gas plant site discussed below, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

A discussion of certain litigation in the state of Louisiana related to the restoration of oilfield properties is included below under Legal Matters.

Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns), and five manufactured gas distribution sites (one of which it still owns). Subject to the following paragraph discussing the Huntsville, Alabama manufactured gas plant site, an investigation of the sites does not indicate the present need for remediation activities and 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 financial position of Alagasco.

In October 2008, Alagasco received a request from the United States Environmental Protection Agency (EPA) for information pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) Section 104(e) and Section 7007 of the Resource Conservation and Recovery Act in connection with a former manufactured gas plant site located in Huntsville, Alabama. The site, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company anticipates that the EPA will consider Alagasco a potentially responsible party under CERCLA and is in discussions with EPA and the current site owner to develop an action plan for the site. Based on the limited information available at this time, Alagasco preliminarily estimates that it may incur costs associated with the site ranging from $2.9 million to $5.9 million. At the present time, the Company cannot conclude that any amount within this range is a better estimate than any other, and accordingly the Company has accrued a contingent liability of $2.9 million. The estimate assumes an action plan for surface soil. If it is determined that a greater scope of work is appropriate, then actual costs will likely exceed the preliminary estimate. Alagasco expects to recover such costs through insurance recovery and future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

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 jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Jefferson County, Alabama

As discussed in prior filings, in January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources’ calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. The lawsuit was settled during December 2008. Consistent with the Company’s evaluation of the case the Company did not incur any material charge.

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Enron Corporation

During 2006, Enron and Enron North America Corporation (ENA) settled with Energen Resources and Alagasco related to the Enron and ENA bankruptcy proceedings. Under the settlement, Energen Resources was allowed claims in the bankruptcy cases against Enron and ENA of $12.5 million each. In December 2006, Energen Resources sold its claims against Enron and ENA for a gain of $6.7 million after-tax. All other claims have been released.

Legacy Litigation

During recent years, numerous lawsuits have been filed against oil production companies in Louisiana for restoration of oilfield properties. These suits are referred to in the industry as “legacy litigation” because they usually involve operations that were conducted on the affected properties many years earlier. Energen Resources is or has been a party to several legacy litigation lawsuits, most of which result from the operations of predecessor companies. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from legacy litigation in excess of the Company’s accrued provision for estimated liability are not considered material to the Company’s financial position.

Other

Various other pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability.

Lease Obligations: Alagasco leases the Company’s headquarters building over a 25-year term and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Energen’s total lease payments related to leases included as operating lease expense were $21,403,000, $18,212,000 and $15,845,000 for the years ended December 31, 2008, 2007 and 2006, respectively. Minimum future rental payments required after 2008 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2009	2010	2011	2012	2013	2014 and thereafter
$    5,756	$    5,290	$    4,201	$    4,215	$    3,516	$    23,295

Alagasco’s total payments related to leases included as operating expense were $3,139,000, $3,180,000 and $3,310,000 for the years ended December 31, 2008, 2007 and 2006, respectively. Minimum future rental payments required after 2008 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2009	2010	2011	2012	2013	2014 and thereafter
$    3,159	$    3,122	$    3,121	$    3,137	$    3,158	$    23,295

8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial Instruments: The stated 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 long-term debt, including the current portion, with a carrying value of $562,557,000 would be $538,803,000 at December 31, 2008. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, with a carrying value of $207,557,000 would be $190,086,000 at December 31, 2008. The fair values were based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the consolidated balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At December 31, 2008, the fixed price purchased under these guarantees had a maximum term outstanding through December 2009 with an aggregate purchase price of $11.3 million and a market value of $8.3 million.

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Risk Management: At December 31, 2008, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with all of its counterparties at December 31, 2008. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. The three largest counterparties Morgan Stanley, Goldman Sachs and Citigroup represented approximately 37 percent, 29 percent and 19 percent, respectively, of Energen Resources’ gain on fair value of derivatives.

The following table details the fair values of risk management assets and liabilities by business segment on the consolidated balance sheets:

(in thousands)	December 31, 2008						December 31, 2007
	Oil and Gas Operations		Natural Gas Distribution		Total		Oil and Gas Operations		Natural Gas Distribution		Total
Derivative assets:
Accounts receivable	$	196,499	$	-	$	196,499	$	14,002	$	-	$	14,002
Long-term derivative instruments		140,603		-		140,603		2,428		-		2,428
Total derivative assets	$	337,102	$	-	$	337,102	$	16,430	$	-	$	16,430
Derivative liabilities:
Accounts payable	$	-	$	27,653	$	27,653	$	79,916	$	376	$	80,292
Long-term derivative instruments		-		8,821		8,821		47,093		-		47,093
Total derivative liabilities	$	-	$	36,474	$	36,474	$	127,009	$	376	$	127,385

The Company had a net $123.1 million deferred tax liability and a net $39.9 million deferred tax asset included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in other comprehensive income as of December 31, 2008 and 2007, respectively.

As of December 31, 2008, $114.2 million of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, net of tax, are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. 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 gain in 2008 for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, the Company recorded an after-tax gain of $0.1 million in 2008 on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of December 31, 2008, the Company had 0.1 billion cubic feet (Bcf) of gas hedges which expire during 2009 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. During 2008, the Company discontinued hedge accounting and reclassified gains of $0.4 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur.

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As of December 31, 2008, Energen Resources entered into the following transactions for 2009 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2009	15.6 Bcf	$8.34 Mcf	NYMEX Swaps
	31.8 Bcf	$7.58 Mcf	Basin Specific Swaps
2010	14.3 Bcf	$8.79 Mcf	NYMEX Swaps
	28.3 Bcf	$7.98 Mcf	Basin Specific Swaps
Oil
2009	2,700 MBbl	$72.93 Bbl	NYMEX Swaps
2010	2,160 MBbl	$97.60 Bbl	NYMEX Swaps
Oil Basis Differential
2009	2,136 MBbl	*	Basis Swaps
2010	1,440 MBbl	*	Basis Swaps
Natural Gas Liquids
2009	43.3 MMGal	$1.15 Gal	Liquids Swaps
*  Average contract prices not meaningful due to the varying nature of each contract

The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2010.

The following table sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:

	December 31, 2008
(in thousands)	Level 2*			Level 3*		Total
Current assets	$	91,687		$	104,812	$	196,499
Noncurrent assets		91,321			49,282		140,603
Current liabilities		(27,653	)		-		(27,653	)
Noncurrent liabilities		(8,821	)		-		(8,821	)
Net derivative asset	$	146,534		$	154,094	$	300,628

* Amounts classified in accordance with FASB Interpretation No. 39 (as amended), “Offsetting of Amounts Related to Certain Contracts” which permits offsetting of fair value of amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Alagasco has $27.7 million and $8.8 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively.

The table below sets forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:

(in thousands)	Year ended December 31, 2008
Balance at beginning of period	$          (9,998	)
Unrealized gains relating to instruments held at the reporting date	158,171
Settlements during period	5,921
Balance at end of period	$       154,094

Concentration of Credit Risk: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality for its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The four largest oil and gas purchasers accounted for approximately 16 percent, 14 percent, 11 percent and 10 percent of Energen Resources’ accounts receivable for commodity sales as of December 31, 2008. Energen Resources’ other purchasers each accounted for less than 9 percent of this accounts receivable as of December 31, 2008. During the year ended December 31, 2008, two purchasers accounted for approximately 23 percent of the Company’s total operating revenues.

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Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 447,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.

9. RECONCILIATION OF EARNINGS PER SHARE

Years ended December 31,
(in thousands, except per share amounts)			2008			2007					2006
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	321,915	71,601	$	4.50	$	309,233	71,592	$	4.32	$	273,570	72,505	$	3.77
Effect of dilutive securities
Performance share awards			106					351					408
Stock options			225					158					252
Non-vested restricted stock			98					80					113
Diluted EPS	$	321,915	72,030	$	4.47	$	309,233	72,181	$	4.28	$	273,570	73,278	$	3.73

The Company had no securities that were excluded from the computation of diluted EPS for years ended December 31, 2008 and 2006. For the year ended December 31, 2007, the Company had 239,545 options that were excluded from the computation of diluted EPS, as their effect was non-dilutive.

10. ASSET RETIREMENT OBLIGATIONS

The Company applies 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. 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 may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company

In 2008, 2007 and 2006, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2005	$	50,270
Liabilities incurred		1,176
Liabilities settled		(1,085	)
Accretion expense		3,619
Balance of ARO as of December 31, 2006		53,980
Liabilities incurred		3,505
Liabilities settled		(862	)
Accretion expense		3,948
Balance of ARO as of December 31, 2007		60,571
Liabilities incurred		3,736
Liabilities settled		(2,446	)
Accretion expense		4,290
Balance of ARO as of December 31, 2008	$	66,151

The Company also applies FIN 47, “Accounting for Conditional Asset Retirement Obligations,” which clarifies that if a legal obligation to perform an asset retirement activity exists but performance is conditional upon a future event, the liability is required to be recognized in accordance with SFAS 143 if the obligation can be reasonably measured. Alagasco recorded a conditional asset retirement obligation on a discounted basis of $17 million and $14.4 million to purge and cap its gas pipelines upon abandonment as a regulatory liability under SFAS No. 71 as of December 31, 2008 and 2007, respectively. The costs associated with asset retirement obligations under FIN 47 are currently either being recovered in rates or are probable of recovery in future rates.

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Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. In accordance with SFAS No. 71, the accumulated asset removal costs of $129.6 million and $121.6 million for December 31, 2008 and 2007, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the consolidated balance sheets.

11. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental information concerning Energen’s cash flow activities was as follows:

Years ended December 31, (in thousands)	2008		2007		2006
Interest paid, net of amount capitalized	$	39,814	$	44,368	$	48,879
Income taxes paid	$	38,235	$	154,187	$	60,308
Noncash investing activities:
Accrued development and exploration costs	$	70,319	$	44,196	$	30,369
Capitalized depreciation	$	98	$	97	$	99
Allowance for funds used during construction	$	700	$	611	$	951
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	8,275	$	7,940	$	2,410
Treasury stock acquired in connection with tax withholdings	$	27,345	$	6,760	$	1,309

Under SFAS No. 143, the Company recorded a non-cash adjustment for accretion expense of $4.3 million, $3.9 million and $3.6 million during 2008, 2007 and 2006, respectively.

Supplemental information concerning Alagasco’s cash flow activities was as follows:

Years ended December 31, (in thousands)	2008		2007		2006
Interest paid, net of amount capitalized	$	12,611	$	12,848	$	14,683
Income taxes paid	$	3,012	$	24,579	$	21,027
Noncash investing activities:
Accrued property, plant and equipment costs	$	2,510	$	2,625	$	3,203
Capitalized depreciation	$	98	$	97	$	99
Allowance for funds used during construction	$	700	$	611	$	951

12. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

During the year ended December 31, 2008, Energen Resources capitalized approximately $18.1 million of unproved leasehold costs, approximately $13 million of which was related to the Company’s acreage position in Alabama shales. Energen used its available cash and existing lines of credit to finance these unproved leasehold costs.

Energen Resources recorded a $10.3 million pre-tax gain in other operating revenues from the March 2008 property sale of certain Permian Basin oil properties. The Company received approximately $15.5 million pre-tax in cash from the sale of this property.

In May 2007, Energen Resources purchased oil properties in the Permian Basin for $18 million. To finance the acquisition, Energen used its available cash and existing lines of credit.

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13. REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	December 31, 2008				December 31, 2007
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	132	$	72,560	$	-	$	21,160
Accretion and depreciation for asset retirement obligation		-		13,145		-		11,024
Gas supply adjustment		11,173		-		9,711		-
Risk management activities		27,653		8,821		376		-
RSE adjustment		2,688		-		-		-
Enhanced stability reserve		-		2,917		-		-
Other		68		68		145		54
Total regulatory assets	$	41,714	$	97,511	$	10,232	$	32,238
Regulatory liabilities:
Enhanced stability reserve	$	-	$	-	$	3,951	$	-
RSE adjustment		137		-		3,445		-
Unbilled service margin		25,192		-		24,725		-
Asset removal costs, net		-		129,579		-		121,573
Asset retirement obligation		-		17,024		-		14,367
Pension liability and postretirement benefits, net		-		-		-		4,188
Other		34		911		33		995
Total regulatory liabilities	$	25,363	$	147,514	$	32,154	$	141,123

As described in Note 2, Regulatory Matters, Alagasco’s rates are established under the RSE rate-setting process and are based on average equity for the period. Alagasco’s rates are not adjusted to exclude a return on its investment in regulatory assets during the recovery period.

14. TRANSACTIONS WITH RELATED PARTIES

The Company allocates certain corporate costs to Energen Resources and Alagasco based on the nature of the expense to be allocated using various factors including, but not limited to, total assets, earnings, or number of employees. The Company’s cash management program seeks to minimize borrowing from outside sources through inter-company lending. Under this program, Alagasco may borrow from but does not lend to affiliates. Alagasco had net payables to affiliates of $21,582,000 and $4,934,000 at December 31, 2008 and 2007, respectively. Interest income and expense between affiliates is calculated monthly based on the market weighted average interest rate. The weighted average interest rate during 2008 and 2007 was 2.82 percent and 5.39 percent, respectively.

15. RECENTLY ISSUED ACCOUNTING STANDARDS

The Company partially adopted the provisions of SFAS No. 157 as of January 1, 2008 as permitted by Financial Accounting Standards Board (FASB) Staff Position No. 157-2 (FSP 157-2), “Effective Date of FASB Statement No. 157.” SFAS No. 157 defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. FSP 157-2 amends SFAS No. 157 to allow an entity to delay the application of SFAS No. 157 until periods beginning January 1, 2009 for certain non-financial assets and liabilities. The additional disclosures for recurring financial instruments required under SFAS No. 157 are included in Note 8, Financial Instruments and Risk Management.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to measure financial instruments and certain other items at fair value to mitigate volatility in reported earnings. This Statement is effective for fiscal years beginning after November 15, 2007. The Company has not elected the fair value option for any of its assets or liabilities and, therefore, implementation of this standard did not have a material impact on the consolidated financial position and results of operations.

77

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations,” which was issued to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. Under SFAS No. 141R, a company is required to recognize the assets acquired, liabilities assumed, contractual contingencies, and any contingent consideration measured at their fair value at the acquisition date. SFAS No. 141R is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning after December 15, 2008. The effect of adopting SFAS No. 141R may be significant, as compared to the Company’s prior accounting, for future acquisitions.

The FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” in December 2007. SFAS No. 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest, and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The effect of this Standard on the Company is currently being evaluated.

In March 2008, the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” SFAS No. 161 expands quarterly disclosure requirements in SFAS No. 133 about an entity’s derivative instruments and hedging activities. SFAS No. 161 is effective for years beginning after November 1, 2008. The effect of this Standard on the Company is currently being evaluated.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. This Statement is effective 60 days following certain approvals by the Securities and Exchange Commission. The effect of this Standard on the Company is currently being evaluated.

In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) No. 03-06-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in the calculation of EPS under the two-class method as described in SFAS No. 128, “Earnings per Share.” This FSP is effective for fiscal years and interim periods beginning after December 15, 2008. The Company does not anticipate this FSP to have a material impact on the consolidated financial statements or the results of operations.

In October 2008, the FASB issued FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in an inactive market. This FSP was effective upon issuance and did not have a material impact on the consolidated financial statements or the results of operations.

In December 2008, the FASB issued FSP No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. FSP No. 132(R)-1 requires additional disclosures to aid in the understanding of: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies, (2) the major categories of plan assets, (3) the inputs and valuation techniques used to measure the fair value of plan assets, (4) the effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period, and (5) significant concentrations of risk within plan assets. This FSP is effective for fiscal years ending after December 15, 2009 and is not expected to have a material impact on the consolidated financial statements or the results of operations.

78

On December 31, 2008, the Securities and Exchange Commission (SEC) issued its final rule Modernization of Oil and Gas Reporting (Final Rule), which revises the disclosures required by oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the Final Rule changes the requirements for determining quantities of oil and gas reserves. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves, with a view to helping investors evaluate their investments in oil and gas companies. The amendments are designed to modernize the requirements for the determination of oil and gas reserves, aligning them with current practices and updating them for changes in technology. The Final Rule applies to annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the Final Rule. The Company is currently studying the impact of the Final Rule.

16. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

The Company’s business is seasonal in character. The following data summarizes quarterly operating results.

	Year ended December 31, 2008
(in thousands, except per share amounts)	First		Second			Third			Fourth
Operating revenues	$	521,646	$	341,266		$	330,205		$	375,793
Operating income	$	195,339	$	116,933		$	130,678		$	119,118
Net income	$	116,688	$	66,878		$	73,064		$	65,285
Diluted earnings per average common share	$	1.62	$	0.93		$	1.01		$	0.91
Basic earnings per average common share	$	1.63	$	0.93		$	1.02		$	0.91
	Year ended December 31, 2007
(in thousands, except per share amounts)	First		Second			Third			Fourth
Operating revenues	$	492,661	$	314,922		$	276,022		$	351,455
Operating income	$	173,198	$	115,905		$	98,632		$	134,297
Income from continuing operations	$	103,881	$	67,903		$	58,014		$	79,414
Net income	$	103,882	$	67,903		$	58,034		$	79,414
Diluted earnings per average common share
Continuing operations	$	1.44	$	0.94		$	0.80		$	1.10
Net income	$	1.44	$	0.94		$	0.80		$	1.10
Basic earnings per average common share
Continuing operations	$	1.45	$	0.95		$	0.81		$	1.11
Net income	$	1.45	$	0.95		$	0.81		$	1.11
Alagasco’s business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco’s quarterly operating results.
	Year ended December 31, 2008
(in thousands)	First		Second			Third			Fourth
Operating revenues	$	296,751	$	109,486		$	82,452		$	166,089
Operating income (loss)	$	74,488	$	(1,472	)	$	(5,891	)	$	14,831
Net income (loss)	$	43,674	$	(3,093	)	$	(5,804	)	$	5,384
	Year ended December 31, 2007
(in thousands)	First		Second			Third			Fourth
Operating revenues	$	298,628	$	111,566		$	67,599		$	131,675
Operating income (loss)	$	68,437	$	4,970		$	(13,673	)	$	13,008
Net income (loss)	$	40,329	$	1,378		$	(10,541	)	$	5,652

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17. OIL AND GAS OPERATIONS (Unaudited)

The following schedules detail historical financial data of the Company’s oil and gas operations.

Capitalized Costs

(in thousands)	December 31, 2008	December 31, 2007
Proved	$    2,899,322	$    2,477,587
Unproved	60,343	52,462
Total capitalized costs	2,959,665	2,530,049
Accumulated depreciation, depletion, and amortization	793,465	664,290
Capitalized costs, net	$    2,166,200	$    1,865,759

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:

Years ended December 31, (in thousands)	2008		2007		2006
Property acquisition:
Proved	$	864	$	22,439	$	24,388
Unproved		18,132		32,187		22,040
Exploration		21,180		8,860		26,767
Development		415,682		315,852		187,734
Total costs incurred	$	455,858	$	379,338	$	260,929

Results of Continuing Operations From Producing Activities: The following table sets forth results of the Company’s oil and gas continuing operations from producing activities:

Years ended December 31, (in thousands)	2008		2007		2006
Gross revenues	$	906,006	$	825,645	$	675,830
Production (lifting costs)		236,679		202,078		184,362
Exploration expense		9,296		2,894		4,181
Depreciation, depletion and amortization		136,404		111,567		95,522
Accretion expense		4,290		3,948		3,619
Income tax expense		194,953		177,083		140,619
Results of continuing operation from producing activities	$	324,384	$	328,075	$	247,527

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

Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. and T. Scott Hickman and Associates, Inc., independent oil and gas reservoir engineers, have reviewed the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2008. Ryder Scott Company, L.P. reviewed the reserve estimates for coalbed methane in the Black Warrior and San Juan basins and substantially all of the Permian Basin reserves. T. Scott Hickman and Associates, Inc. reviewed the reserves for the North Louisiana and East Texas regions and the conventional reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 99 percent of the Company’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

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Year ended December 31, 2008	Gas MMcf		Oil MBbl		NGL MBbl		Total Bcfe
Proved reserves at beginning of period	1,115,918		74,625		31,664		1,753.7
Revisions of previous estimates	(73,105	)	(15,813	)	(3,359	)	(188.1	)
Purchases	1,211		6		-		1.2
Extensions and discoveries	62,232		7,937		2,407		124.3
Production	(67,573	)	(4,114	)	(1,683	)	(102.4	)
Sales	(230	)	(607	)	(76	)	(4.3	)
Proved reserves at end of period	1,038,453		62,034		28,953		1,584.4
Proved developed reserves at end of period	868,873		51,929		24,869		1,329.7
Year ended December 31, 2007	Gas MMcf		Oil MBbl		NGL MBbl		Total Bcfe
Proved reserves at beginning of period	1,096,429		74,893		29,504		1,722.8
Revisions of previous estimates	2,977		(4,573	)	1,999		(12.5	)
Purchases	483		2,202		145		14.6
Extensions and discoveries	80,328		5,982		1,855		127.4
Production	(64,299	)	(3,879	)	(1,839	)	(98.6	)
Proved reserves at end of period	1,115,918		74,625		31,664		1,753.7
Proved developed reserves at end of period	903,510		61,209		28,348		1,440.9
Year ended December 31, 2006	Gas MMcf		Oil MBbl		NGL MBbl		Total Bcfe
Proved reserves at beginning of period	1,080,161		74,962		31,934		1,721.5
Revisions of previous estimates	(40,458	)	(3,518	)	(1,449	)	(70.2	)
Purchases	19,561		81		24		20.2
Extensions and discoveries	99,988		7,013		812		146.9
Production	(62,823	)	(3,645	)	(1,817	)	(95.6	)
Proved reserves at end of period	1,096,429		74,893		29,504		1,722.8
Proved developed reserves at end of period	866,874		55,210		26,932		1,359.7

Energen Resources had downward reserve revisions during 2008 which totaled 188.1 Bcfe. The Black Warrior Basin had downward reserve revisions totaling 13.0 Bcfe of which approximately 3.1 Bcfe related to changes in year-end pricing and approximately 9.9 Bcfe was associated with high water production from several wells. In the San Juan Basin, downward reserve revisions of 72.7 Bcfe were largely due to 52 Bcfe of estimated price revisions plus higher operating expense and fuel usage and partially offset by improved performance. Downward reserve revisions of 92.6 Bcfe in the Permian Basin were largely due to 61 Bcfe of estimated price related revisions and delayed waterflood responses estimated at 36 Bcfe partially offset by improved performance.

Energen Resources purchased 1.2 Bcfe of reserves during 2008 primarily related to the acquisition of gas properties in East Texas.

During 2008, Energen Resources had extensions and discoveries of 124.3 Bcfe of which 68 percent were proved undeveloped reserves and 32 percent were proved developed reserves. Extension drilling resulted in discoveries of 124 Bcfe with exploratory drilling providing 0.3 Bcfe of discoveries. The Black Warrior Basin added 9.5 Bcfe of reserves primarily through the drilling or identification of 57 well locations. The San Juan Basin added 43.7 Bcfe of reserves through the drilling or identification of 173 well locations; additionally, 12 sidetrack wells added 6.6 Bcfe of reserves. The Permian Basin added 38.8 Bcfe of reserves through the drilling or identification of 159 well locations.

Energen Resources had downward reserve revisions during 2007 which totaled 12.5 Bcfe. The Black Warrior Basin had downward reserve revisions totaling 3 Bcfe of which approximately 6.1 Bcfe related to changes in year-end pricing which accelerated reversions in ownership partially offset by an estimated 3.1 Bcfe of upward revisions associated with improved performance. In the San Juan Basin, upward reserve revisions of 9.2 Bcfe were largely due to 25 Bcfe of estimated price revisions partially offset by a 16 Bcfe decrease for the removal of proved undeveloped locations due to new reservoir interpretations. Downward reserve revisions of 21.4 Bcfe in the Permian Basin were largely a result of delayed waterflood responses estimated at 34.1 Bcfe partially offset by upward price revisions of approximately 12.7 Bcfe.

81

Energen Resources purchased 14.6 Bcfe of reserves during 2007 primarily related to the acquisition of oil properties in the Permian Basin.

During 2007, Energen Resources had extensions and discoveries of 127.4 Bcfe of which 65 percent were proved undeveloped reserves and 35 percent were proved developed reserves. Extension drilling resulted in discoveries of 109.7 Bcfe with exploratory drilling providing 17.7 Bcfe of discoveries. The Black Warrior Basin added 20.5 Bcfe of reserves primarily through the drilling or identification of 55 well locations. The San Juan Basin added 47.2 Bcfe of reserves through the drilling or identification of 92 well locations; additionally, 18 sidetrack wells added 12.9 Bcfe of reserves. The Permian Basin added 30.1 Bcfe of reserves through the drilling or identification of 128 well locations.

For the year ended December 31, 2006, Energen Resources had downward reserve revisions which totaled 70.2 Bcfe and were primarily the result of reduced year-end pricing. Purchases for 2006 added 20.2 Bcfe of reserves and related primarily to an acquisition of gas properties in the San Juan Basin. Extension and discoveries during 2006 totaled 146.9 Bcfe of reserves, the majority of which related to extension drilling.

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, 2008, 2007 and 2006, the Company had a deferred hedging gain of $324 million, a deferred hedging loss of $104.9 million, and a deferred hedging gain of $81.5 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.

Years ended December 31, (in thousands)	2008		2007		2006
Future gross revenues	$	8,212,212	$	15,789,245	$	11,012,667
Future production costs		3,692,060		4,682,021		3,909,649
Future development costs		485,806		471,655		556,131
Future income tax expense		1,070,005		3,501,519		2,062,210
Future net cash flows		2,964,341		7,134,050		4,484,677
Discount at 10% per annum		1,337,724		3,869,337		2,338,576
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	1,626,617	$	3,264,713	$	2,146,101
Discounted future net cash flows before income taxes	$	1,902,594	$	4,470,808	$	2,827,411

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:

Years ended December 31, (in thousands)	2008			2007			2006
Balance at beginning of year	$	3,264,713		$	2,146,101		$	2,911,655
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs		(2,571,311	)		1,556,198			(1,489,312	)
Net changes due to revisions in quantity estimates		(250,491	)		(32,074	)		(123,057	)
Development costs incurred, previously estimated		177,343			215,155			86,554
Accretion of discount		326,471			214,610			291,166
Changes in timing and other		461,876			(135,935	)		159,945
Total revisions		(1,856,112	)		1,817,954			(1,074,704	)
New field discoveries and extensions, net of future production and development costs		36,266			327,564			253,277
Sales of oil and gas produced, net of production costs		(843,202	)		(598,720	)		(549,559	)
Purchases		1,085			28,468			39,481
Sales		(26,861	)		-			-
Net change in income taxes		1,050,728			(456,654	)		565,951
Net change in standardized measure of discounted future net cash flows		(1,638,096	)		1,118,612			(765,554	)
Balance at end of year	$	1,626,617		$	3,264,713		$	2,146,101

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18. 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, Summary of Significant Accounting Policies. Certain reclassifications have been made to conform the prior years’ financial statements to the current year presentation.

Years ended December 31, (in thousands)	2008			2007			2006
Operating revenues from continuing operations
Oil and gas operations	$	914,132		$	825,592		$	730,542
Natural gas distribution		654,778			609,468			663,444
Total	$	1,568,910		$	1,435,060		$	1,393,986
Operating income (loss) from continuing operations
Oil and gas operations	$	482,588		$	451,567		$	405,149
Natural gas distribution		81,956			72,742			74,274
Subtotal		564,544			524,309			479,423
Eliminations and corporate expenses		(2,476	)		(2,277	)		(2,123	)
Total	$	562,068		$	522,032		$	477,300
Depreciation, depletion and amortization expense from continuing operations
Oil and gas operations	$	139,539		$	114,241		$	97,842
Natural gas distribution		48,874			47,136			44,244
Total	$	188,413		$	161,377		$	142,086
Interest expense
Oil and gas operations	$	27,587		$	32,673		$	33,542
Natural gas distribution		14,807			15,696			16,454
Subtotal		42,394			48,369			49,996
Eliminations and other		(413	)		(1,269	)		(1,344	)
Total	$	41,981		$	47,100		$	48,652
Income tax expense (benefit) from continuing operations
Oil and gas operations	$	169,862		$	147,418		$	134,938
Natural gas distribution		24,829			21,636			22,002
Subtotal		194,691			169,054			156,940
Other		(1,648	)		(1,625	)		(1,910	)
Total	$	193,043		$	167,429		$	155,030
Capital expenditures
Oil and gas operations	$	449,571		$	379,479		$	259,678
Natural gas distribution		63,320			58,862			76,157
Total	$	512,891		$	438,341		$	335,835
Identifiable assets
Oil and gas operations	$	2,650,136		$	2,065,229		$	1,822,216
Natural gas distribution		1,126,587			983,258			1,006,096
Subtotal		3,776,723			3,048,487			2,828,312
Eliminations and other		(1,319	)		31,166			8,575
Total	$	3,775,404		$	3,079,653		$	2,836,887
Property, plant and equipment, net
Oil and gas operations	$	2,181,131		$	1,877,747		$	1,612,764
Natural gas distribution		686,517			660,496			639,650
Total	$	2,867,648		$	2,538,243		$	2,252,414

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SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

Energen Corporation

Years ended December 31, (in thousands)	2008			2007			2006
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	12,244		$	13,961		$	11,573
Additions:
Charged to income		6,716			5,610			6,972
Recoveries and adjustments		(245	)		(202	)		(232	)
Net additions		6,471			5,408			6,740
Less uncollectible accounts written off		(5,847	)		(7,125	)		(4,352	)
Balance at end of year	$	12,868		$	12,244		$	13,961
Alabama Gas Corporation
Years ended December 31, (in thousands)	2008			2007			2006
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	11,500		$	13,200		$	10,800
Additions:
Charged to income		6,590			5,610			6,972
Recoveries and adjustments		(199	)		(197	)		(227	)
Net additions		6,391			5,413			6,745
Less uncollectible accounts written off		(5,791	)		(7,113	)		(4,345	)
Balance at end of year	$	12,100		$	11,500		$	13,200

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

None

ITEM 9A. CONTROLS AND PROCEDURES

Energen Corporation

a. Disclosure Controls and Procedures

Our chief executive officer and chief financial officer of Energen Corporation have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, they have concluded that our disclosure controls and procedures are effective as of December 31, 2008 at a reasonable assurance level.

b. Management’s Report On Internal Control Over Financial Reporting

Management of Energen Corporation is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Energen Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written policies and procedures that:

i pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Energen Corporation;

ii provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Energen Corporation are being made only in accordance with authorization of management and directors of Energen Corporation; and

iii provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2008. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Energen Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management determined that, as of December 31, 2008, Energen Corporation maintained effective internal control over financial reporting. The effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 24, 2009

85

c. Changes in Internal Control Over Financial Reporting

Our chief executive officer and chief financial officer of Energen Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Alabama Gas Corporation

a. Disclosure Controls and Procedures

Our chief executive officer and chief financial officer of Alabama Gas Corporation have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective as of December 31, 2008 at a reasonable assurance level.

b. Management’s Report On Internal Control Over Financial Reporting

Management of Alabama Gas Corporation is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Alabama Gas Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written policies and procedures that:

i pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Alabama Gas Corporation;

ii provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Alabama Gas Corporation are being made only in accordance with authorization of management and directors of Alabama Gas Corporation; and

iii provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of December 31, 2008. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Alabama Gas Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management determined that, as of December 31, 2008, Alabama Gas Corporation maintained effective internal control over financial reporting. The effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 24, 2009

86

c. Changes in Internal Control Over Financial Reporting

Our chief executive officer and chief financial officer of Alabama Gas Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

87

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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 22, 2009. The definitive proxy statement will be filed on or about March 27, 2009.

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 22, 2009.

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

a. Security Ownership of Certain Beneficial Owners

The information regarding the security ownership of the beneficial owners of more than five percent of Energen’s common stock is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 22, 2009.

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 22, 2009.

c. Securities Authorized for Issuance Under Equity Compensation Plans

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information regarding certain relationships and related transactions, and director independence is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 22, 2009.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 22, 2009.

88

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

89

Energen Corporation

Alabama Gas Corporation

INDEX TO EXHIBITS

Item 14(a)(3)

Exhibit Number	Description
*3(a)	Restated Certificate of Incorporation of Energen Corporation (composite, as amended April 29, 2005) which was filed as Exhibit 3(a) to Energen’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005
*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 23, 2008) which was filed as Exhibit 99.1 to Energen’s Current Report on Form 8-K, dated July 25, 2008
*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
*3(e)	Bylaws of Alabama Gas Corporation (as amended through October 24, 2007) which was filed as Exhibit 3 to Energen’s Quarterly Report on Form 10-Q for the period ended October 31, 2007
*4(a)	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(a)(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
*4(a)(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
*4(a)(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
*4(a)(iv)	Officers’ Certificate, dated October 3, 2003, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 5 percent Notes due October 1, 2013, which was filed as Exhibit 4 to Energen’s Current Report on Form 8-K, dated October 3, 2003
*4(b)	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 Corporations’ Registration Statement on Form S-3 (Registration No. 33-70466)
*4(b)(i)	Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.70 percent Notes due January 15, 2035, which was filed as Exhibit 4.3 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005

90

*4(b)(ii)	Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.20 percent Notes due January 15, 2020, which was filed as Exhibit 4.4 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005
*4(b)(iii)	Officers’ Certificate, dated November 17, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.368 percent Notes due December 1, 2015, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed November 17, 2005
*4(b)(iv)	Officers’ Certificate, dated January 16, 2007, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.90 percent Notes due January 15, 2037, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 16, 2007
*10(a)	Service Agreement Under Rate Schedule CSS (No. SSNG1), between Southern Natural Gas Company and Alabama Gas Corporation, dated as of September 1, 2005, which was filed as Exhibit 10(a) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(b)	Firm Transportation Service Agreement Under Rate Schedule FT and/or FT-NN (No. FSNG1), between Southern Natural Gas Company and Alabama Gas Corporation dated as of September 1, 2005, which was filed as Exhibit 10(b) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(c)	Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alabama Gas Corporation, which was filed as Exhibit 10(b) to Energen’s Annual Report on Form 10-K for the year ended September 30, 1993
10(c)(i)	Amended Exhibits A and B, effective October 1, 2008, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas Corporation
*10(d)	Service Agreement between Transcontinental Gas Pipeline Corporation and Transco Energy Marketing Company as Agent for Alabama Gas Corporation, dated August 1, 1991 which was filed as Exhibit 3(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2003
*10(e)	Amendment to Service Agreement between Transcontinental Gas Pipeline Corporation and Alabama Gas Corporation, dated December 2, 2005, which was filed as Exhibit 10(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(f)	Occluded Gas Lease, dated January 1, 1986 and First through Seventh Amendments, which was filed as Exhibit 10(f) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
10(f)(i)	Eighth Amendment to Occluded Gas Lease, dated January 1, 2009
*10(g)	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
*10(h)	Form of Severance Compensation Agreement between Energen Corporation and it’s executive officers which was filed as Exhibit 99.1 to Energen’s Current Report on Form 8-K, dated January 29, 2007
*10(i)	Energen Corporation 1997 Stock Incentive Plan (as amended effective January 1, 2007) which was filed as Exhibit 10 to Energen’s Quarterly Report on Form 10-Q for the period ended March 31, 2007

91

*10(j)	Form of Stock Option Agreement under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(a) to Energen’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004
*10(k)	Form of Restricted Stock Agreement under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(b) to Energen’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004
*10(l)	Form of Performance Share Award under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(c) to Energen’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004
*10(m)	Energen Corporation 1997 Deferred Compensation Plan (amended and restated effective January 1, 2008)
*10(n)	Energen Corporation 1992 Directors Stock Plan (as amended December 12, 2007)
*10(o)	Energen Corporation Annual Incentive Compensation Plan, as amended effective October 25, 2006 which was filed as Exhibit 99.1 to Energen’s Current Report on Form 8-K, filed October 30, 2006
21	Subsidiaries of Energen Corporation
23(a)	Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP)
23(b)	Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company, L.P.)
23(c)	Consent of Independent Oil and Gas Reservoir Engineers (T. Scott Hickman and Associates, Inc.)
24(a)	Power of Attorney – Energen Corporation
24(b)	Power of Attorney – Alabama Gas Corporation
31(a)	Energen Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)
31(b)	Energen Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)
31(c)	Alabama Gas Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d- 14(a)
31(d)	Alabama Gas Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)
32	Certification pursuant to Section 1350

*Incorporated by reference

92

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)

February 24, 2009	By	/s/ James T. McManus, II
	James T. McManus, II
	Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation

93

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:

February 24, 2009	By    /s/James T. McManus, II
	James T. McManus, II
	Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation
February 24, 2009	By    /s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr.
	Vice President, Chief Financial Officer and
	Treasurer of Energen Corporation and Alabama Gas Corporation
February 24, 2009	By    /s/ Russell E. Lynch, Jr.
	Russell E. Lynch, Jr.
	Vice President and Controller of Energen
	Corporation
February 24, 2009	By    /s/ William D. Marshall
	William D. Marshall
	Vice President and Controller of Alabama Gas
	Corporation
February 24, 2009	*
	Julian W. Banton
	Director
February 24, 2009	*
	Kenneth W. Dewey
	Director
February 24, 2009	*
	James S. M. French
	Director
February 24, 2009	*
	Judy M. Merritt
	Director
February 24, 2009	*
	Wm. Michael Warren, Jr.
	Director
February 24, 2009	*
	David W. Wilson
	Director
	*By    /s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr.,
	Attorney-in-Fact

94

EX-10.(C)(I)

SOUTHERN NATURAL GAS COMPANY	Exhibit 10(c)(i)
FIRM TRANSPORTATION SERVICE AGREEMENT
CONTRACT CODE FSNG1
EXHIBIT A

SERVICE	SERVICE	START	PRIMARY	RECEIPT POINTS		MDRQ
TYPE	TYPE CODE	DATE	TERM	POINT CODE	POINT NAME	(MCF)
FT/FTNN	2	11/1/1993	8/31/2010	605500	COLUMBIA GULF - SHADYSIDE TO SNG	208
				606400	SESH - CENTERPOINT TO SNG	219
					TOTAL PKG	427
FT	29	5/1/2004	8/31/2010	605500	COLUMBIA GULF - SHADYSIDE TO SNG	16,129
				606400	SESH - CENTERPOINT TO SNG	16,931
					TOTAL PKG	33,060
FT	31	5/1/2004	8/31/2010	018450	VKGC - MAIN PASS 289 TO SNG	2,057
				606400	SESH - CENTERPOINT TO SNG	2,159
					TOTAL PKG	4,216
FT	42	12/1/2006	9/30/2013	060000	ELBA TO SNG	30,000
FT/FTNN	43	10/1/2008	8/31/2010	030970	BAYOU POSTILLION #7 - PVOG	19,941
				605500	COLUMBIA GULF - SHADYSIDE TO SNG	12,750
				606500	SESH - GULF SOUTH TO SNG	32,539
					TOTAL PKG	65,230
					TOTAL CONTRACT	132,933

By:		By:
	ALABAMA GAS CORPORATION		SOUTHERN NATURAL GAS COMPANY

Effective Date: 10/01/2008

Supersedes the previous Exhibit A

The MDRQ for Service Type Code 42 is in effect solely during the period October 1 through May 31 each year of the term.

SOUTHERN NATURAL GAS COMPANY

FIRM TRANSPORTATION SERVICE AGREEMENT

CONTRACT CODE FSNG1

EXHIBIT B

				PRIMARY		EVERGREEN
SERVICE TYPE	SERVICE TYPE CODE	START DATE	PRIMARY TERM	NOTICE REQUIRED	EVERGREEN TERM	NOTICE REQUIRED	DELIVERY POINTS		MDDQ (MCF)	FT (MCF)	FTNN (MCF)
							POINT CODE	POINT NAME
FT/FTNN	2	11/1/1993	8/31/2010	365 DAYS	YEARLY	365 DAYS	658500	ALA - BIRMINGHAM AREA	1,182	427	755
FT	29	5/1/2004	8/31/2010	365 DAYS	YEARLY	365 DAYS	658500	ALA - BIRMINGHAM AREA	17,060
							940002	ALA - TUSCALOOSA AREA	15,000
							940006	ALA - TALLADEGA AREA	1,000
								TOTAL PKG	33,060	33,060	0
FT	31	5/1/2004	8/31/2010	365 DAYS	YEARLY	365 DAYS	940035	ALA - JASPER AREA	4,216	4,216
FT	42	12/1/2006	9/30/2013	730 DAYS	YEARLY	365 DAYS	805400	ALA - MONT #5 (NORTH)	15,000
							805500	ALA - MONT #6 (SOUTH)	15,000
								TOTAL PKG	30,000	30,000	0
FT/FTNN	43	10/1/2008	8/31/2010	365 DAYS	YEARLY	365 DAYS	654700	ALA - GADSDEN AREA	33,000
							658500	ALA - BIRMINGHAM AREA	122,725
							659700	ALA - ANNISTON AREA	36,150
							659900	ALA - DEMOPOLIS AREA	6,589
							801600	ALA - GREENE COUNTY	75
							803700	ALA - SELMA #1	575
							803800	ALA - SELMA #2	9,827
							805300	ALA - MONTGOMERY #4	8,341
							805500	ALA - MONT #6 (SOUTH)	16,595
							806000	ALA - RUSSELL MILLS	261
							813600	ALA - OPELIKA #3	5,695
							817400	ALA - BRENT & CENTERVILLE	1,200
							834100	ALA - PLANT MILLER	2

Page 2 of 8

SOUTHERN NATURAL GAS COMPANY

FIRM TRANSPORTATION SERVICE AGREEMENT

CONTRACT CODE FSNG1

EXHIBIT B

				PRIMARY		EVERGREEN
SERVICE	SERVICE	START	END	NOTICE	EVERGREEN	NOTICE	DELIVERY POINTS		MDDQ	FT	FTNN
TYPE	TYPE CODE	DATE	DATE	REQUIRED	TERM	REQUIRED	POINT CODE	POINT NAME	(MCF)	(MCF)	(MCF)
							909700	ALA - PHENIX CITY AREA	9,000
							940002	ALA - TUSCALOOSA AREA	20,992
							940005	ALA - LINCOLN AREA	1,900
							940006	ALA - TALLADEGA AREA	5,850
							940011	ALA - OPELIKA AREA	15,420
							940021	ALA -FAIRFAX-SHAWMUT AREA	5,682
							940022	ALA - MONTGOMERY AREA	4,585
							940024	ALA - TUSKEGEE AREA	8,103
							940035	ALA - JASPER AREA	1,084
							940046	ALA - REFORM AREA	600
							940056	ALA - PELL CITY AREA	1,903
								TOTAL PKG	316,154	65,230	250,924
								TOTAL CONTRACT	384,612	132,933	251,679
ALABAMA GAS CORPORATION							SOUTHERN NATURAL GAS COMPANY

Effective Date: 10/01/2008    

Supersedes the previous Exhibit B

The MDDQ for FSNG1 shall be reduced by an average of 85,366 mcf for each of the months of April through September each year.

Such reduction was authorized as mitigation in Docket Numbers RS92-10 and/or RP99-496 and is set forth at the delivery point

and corresponding receipt point level in Sonet Premier. (Service Type Code 42 is excluded from this provision.)

The MDDQ for Service Type Code 42 is in effect solely during the period October 1 through May 31 each year of the term.

Page 3 of 8

Service Agreement: FSNG1

Effective: 10/1/2008

Supersedes the previous Exhibit B

EXHIBIT B

SHIPPER: Alabama Gas Corporation

These pages of the Exhibit B of Service Agreement FSNG1 detail the firm contract pressure obligations underlying

each delivery point MDDQ to Exhibit B of FSNG1.

								For Information Only: Stand Alone Meter Station Design Capability
Point Name	Point Code	Meter Station Code	MDDQ (mcf/d)	6% MDDQ (mcf/hr)	Daily Delivery Capacity (mcf/d)	Pressure Obligation (psig)	Line Pressure Max/Min	Max Daily Capability (mcf/d)	Max Hourly Capability (mcf/hr)	Pressure Used for Station Capability (psig)
Gadsden Area	654700		33,000	1,980
Ragland		841200			333	50		672	28	50
Ashville		841400			714	Line	>100#	45,432	1,893	430
Gadsden 5		841900			683	195		1,582	66	195
Gadsden 1		842200			19,616	145		76,664	3,194	145
Gadsden 2		842300			3,502	145		8,592	358	145
Gadsden 3		842400			3,162	Line	>150#	12,120	505	295
Gadsden 4		843000			3,131	145		4,302	179	145
Gadsden 6		843600			1,859	150		7,155	298	150
Birmingham Area	658500		140,967	8,458
Oak Grove		821200			290	100		1,200	50	100
Forestdale		821800			1,472	150		6,000	168	250
North B’ham		822600			25,283	Line	200# - 300#	121,608	5,067	350
Tarrant		822800			3,967	Line	>150#	37,920	1,580	320
Roebuck		825700			33,998	Line	>425#	118,656	4,944	475
Leeds #1		826400			2,228	75		6,384	266	75
Leeds #2		826500			2,974	300		12,288	512	300
Pleasant Grove		828600			6,405	Line	>575#	24,144	1,006	575
Bessemer #1		829200			5,560	Line	>560#	38,640	1,610	560
Bessemer #2		829300			3,453	Line	>485#	26,232	1,093	485
Genery Gap		830400			15,669	Line	>370#	90,624	3,776	500
Helena-Alagas		830900			3,767	Line	>325#	14,832	618	340
Alabaster #1		831400			879	Line	>335#	8,184	341	340
Alabaster #2		831500			975	Line	>340#	3,840	160	340

Page 4 of 8

Service Agreement: FSNG1

Effective: 10/1/2008

Supersedes the previous Exhibit B

EXHIBIT B

SHIPPER: Alabama Gas Corporation

These pages of the Exhibit B of Service Agreement FSNG1 detail the firm contract pressure obligations underlying

each delivery point MDDQ to Exhibit B of FSNG1.

								For Information Only: Stand Alone Meter Station Design Capability
Point Name	Point Code	Meter Station Code	MDDQ (mcf/d)	6% MDDQ (mcf/hr)	Daily Delivery Capacity (mcf/d)	Pressure Obligation (psig)	Line Pressure Max/Min	Max Daily Capability (mcf/d)	Max Hourly Capability (mcf/hr)	Pressure Used for Station Capability (psig)
Alabaster #3		831600			618	Line	>330#	13,296	554	330
Columbiana		832600			1,184	100		3,696	154	140
Montevallo		833400			1,660	Line	>150#	10,392	433	340
Ensley		837400			11,598	Line	>150#	63,240	2,635	315
Barrett Co		838100			396	50		720	30	150
Bullock		838300			162	50		720	30	150
Harbison Walker		838700			697	200		3,120	130	174
Fairfield		839200			17,732	Line	>175#	44,136	1,839	315
Anniston Area	659700		36,150	2,169
Anniston #1		845600			12,081	110		36,312	1,513	100
Anniston #2		845700			4,776	150		44,136	1,839	120
Anniston #3		845800			17,671	250		51,576	2,149	250
Heflin		847000			1,031	55		1,656	69	55
Chocoloco		848100			591	Line		11,664	486	400
Demopolis Area	659900		6,589	395
Demopolis #1		801400			727	60		3,792	158	60
Demopolis #2		801500			1,926	75		3,984	166	75
Greensboro		802400			1,534	200		2,904	121	200
Uniontown		802600			700	125		1,872	78	125
Marion		803400			1,702	165		2,976	124	165
Phenix City Area	909700		9,000	540
Phenix City #1		810600			4,565	Line	<175#	21,144	881	175

Page 5 of 8

Service Agreement: FSNG1

Effective: 10/1/2008

Supersedes the previous Exhibit B

EXHIBIT B

SHIPPER: Alabama Gas Corporation

These pages of the Exhibit B of Service Agreement FSNG1 detail the firm contract pressure obligations underlying

each delivery point MDDQ to Exhibit B of FSNG1.

								For Information Only: Stand Alone Meter Station Design Capability
Point Name	Point Code	Meter Station Code	MDDQ (mcf/d)	6% MDDQ (mcf/hr)	Daily Delivery Capacity (mcf/d)	Pressure Obligation (psig)	Line Pressure Max/Min	Max Daily Capability (mcf/d)	Max Hourly Capability (mcf/hr)	Pressure Used for Station Capability (psig)
Phenix City #2		810700			2,726	200		5,688	237	200
Phenix City #3		810800			1,709	Line	<200#	9,720	405	175
Tuscaloosa Area	940002		35,992	2,160
Tuscaloosa #1		816400			14,184	Line	250# - 400#	104,832	4,368	340
Tuscaloosa #2		816500			15,503	Line	>300#	25,608	1,067	440
Tuscaloosa #3		816600			6,305	125		7,560	315	175
Lincoln Area	940005		1,900	114
Vincent		827800			905	200		2,280	95	200
Lincoln #2		828200			615	250		768	32	250
Riverside East		844800			100	100		288	12	180
Lincoln #1		845000			280	48		1,008	42	48
Talladega Area	940006		6,850	411
Talladega Raceway		845400			313	200		4,368	182	55
Talladega #1		847600			4,211	50		17,496	729	50
Talladega #2		847700			2,326	148		12,048	502	145
Opelika Area	940011		15,420	925
Lochapoka		809500			1,197	Line		14,640	610	500
Auburn		812600			8,704	125		10,872	453	250
Opelika #1		813400			5,132	Line	<600#	15,000	625	525
Opelika #2		813500			387	Line	<600#	17,136	714	575

Page 6 of 8

Service Agreement: FSNG1

Effective: 10/1/2008

Supersedes the previous Exhibit B

EXHIBIT B

SHIPPER: Alabama Gas Corporation

These pages of the Exhibit B of Service Agreement FSNG1 detail the firm contract pressure obligations underlying

each delivery point MDDQ to Exhibit B of FSNG1.

									For Information Only: Stand Alone Meter Station Design Capability
Point Name	Point Code	Meter Station Code	MDDQ (mcf/d)	6% MDDQ (mcf/hr)	Daily Delivery Capacity (mcf/d)	Pressure Obligation (psig)	Line Pressure Max/Min		Max Daily Capability (mcf/d)	Max Hourly Capability (mcf/hr)	Pressure Used for Station Capability (psig)
Fairfax/Shaw Area	940021		5,682	341
Fairfax Mills-WP		814400			83	Line			3,384	141	47
Fairfax City		814500			1,934	100			6,360	265	100
Shawmut- Lang		815200			2,583	Line	< 600	#	17,424	726	400
LaFayette		814200			1,082	150			3,456	144	150
Montgomery Area	940022		4,585	275
Montgomery #2		805100			3,325	600			53,952	2,248	575
Montgomery #3		805200			1,015	175			8,472	353	240
Eclectic		806800			245	100			2,496	104	430
Tuskegee Area	940024		8,103	486
Tuskegee #1		808800			6,466	100			7,488	312	100
Tuskegee #2		808900			1,314	Line			16,320	680	500
Notasulga		809400			323	175			720	30	145
Jasper	940035		5,300	318
Jasper #1		835600			4,627	150			8,808	367	150
Parrish Oak		836201			673	144			1,512	63	144
Pell City Area	940056		1,903	114
Eden		827200			400	75			552	23	75
Pell City		827400			742	70			1,632	68	200
Oak Ridge		827600			761	70			864	36	70

Page 7 of 8

Service Agreement: FSNG1

Effective: 10/1/2008

Supersedes the previous Exhibit B

EXHIBIT B

SHIPPER: Alabama Gas Corporation

These pages of the Exhibit B of Service Agreement FSNG1 detail the firm contract pressure obligations underlying

each delivery point MDDQ to Exhibit B of FSNG1.

								For Information Only: Stand Alone Meter Station Design Capability
Point Name	Point Code	Meter Station Code	MDDQ (mcf/d)	6% MDDQ (mcf/hr)	Daily Delivery Capacity (mcf/d)	Pressure Obligation (psig)	Line Pressure Max/Min	Max Daily Capability (mcf/d)	Max Hourly Capability (mcf/hr)	Pressure Used for Station Capability (psig)
Reform Area	940046		600	36
Reform		818800			590	48		1,008	42	48
Reform #2		819400			10	150		1,080	45	150
Greene County	801600		75	5		Line		419,712	17,488	850
Selma #1	803700		575	34		275		26,400	1,100	245
Selma #2	803800		9,827	590		600		30,888	1,287	600
Ala-Int Paper	803900		0	0		Line		58,800	2,450	950
Plant Tenaska	804200		0	0		Line		265,152	11,048	950
Montgomery #4	805300		8,341	500		Line		77,640	3,235	850
Montgomery #5	805400		15,000	900		700 to 720		89,700	3,738	700
Montgomery #6	805500		31,595	1,896		700 to 720		116,600	4,858	700
Russell Mills	806000		261	16		Line		10,200	425	450
Opelika #3	813600		5,695	342		Line		41,760	1,740	1,000
Brent/Centerville	817400		1,200	72		200		3,576	149	200
Plant Miller	834100		2	0		115		41,640	1,735	140
Farm Taps	847900		0	0		Line		NA	NA	NA
GRAND TOTAL:			384,612	23,077

Page 8 of 8

EX-10.(F)(I)

Exhibit 10(f)(i)

EIGHTH AMENDMENT

TO OCCLUDED GAS LEASE

THIS AGREEMENT made and entered into by and between RGGS Land & Minerals, LTD, L.P., a Delaware corporation (“Lessor”) a successor in interest to United States Steel Corporation and Energen Resources Corporation, an Alabama corporation, formerly known as Taurus Exploration, Inc. (“Lessee”), Lessor and Lessee are sometimes collectively referred to as the “Parties”.

WITNESSETH:

WHEREAS, United States Steel Corporation and Taurus Exploration, Inc. entered into an Occluded Gas Lease dated January 1, 1986 covering certain lands in Jefferson and Tuscaloosa Counties, Alabama (the “Lease”); and

WHEREAS, the Parties have previously amended the Lease by amendments dated April 30, 1987, January 1, 1989, June 1, 1990, December 11, 1990, January 1, 1993, December 16, 2002 and March 1, 2003 respectively; and

WHEREAS, Lessor and Lessee desire to make this Eighth Amendment to the Occluded Gas Lease for the purpose of amending the method for determining the Treatment Factor, and further addressing measurement of gas;

NOW THEREFORE, Lessor and Lessee, intending to be legally bound, do hereby agree as follows:

Paragraph 1.20 of Article I of the Occluded Gas Lease shall be amended to read as follows:

1.20        Treatment Factor: as used herein, the amount determined by either subparagraph A) or B) below to allow Lessee to recover all costs of obtaining and/or constructing facilities that are not included in the Payout account, i.e. for gathering, compression, treatment dehydration, and transportation to the delivery point at which gas enters either an interstate pipeline or the Alagasco system:

A)        At all times, that the Average Monthly Sales Price (as hereinafter defined) is greater than $5.00 per MMBtu, the Treatment Factor shall be the amount of $0.78 per MMBtu or such other amount that is in effect from time to time, adjusted; (a) as of January 1 of each year beginning January 1, 1987 upward by 20% of the difference between (1) 95% (to read 100% until the expiration of the first 5 years of this Lease or until Article 1.22(a) (8) [2] comes into effect, whichever comes first) of the OCD-2 Rate in effect as of said date and (2) the sum of the Wellhead Price under Article 1.22(a) and the Treatment Factor, both as in effect as of the day prior to the adjustment; provided however, that the cumulative amount of all such increases shall not exceed $.01 per MMBtu times the number of

1

years elapsed between the commencement of this Lease and date of the adjustment; and (b) as of the first day of each month shall be adjusted by 5.5% of any increase or decrease in the Average Wellhead Price in effect for production from the immediately preceding month as compared to the Average Wellhead Price in effect for production from the second preceding month; in no case, however shall the Treatment Factor be reduced other than as a result of this 1.20.

B)        Effective January 1, 2009, if the Average Monthly Sales Price for any month falls below $5.00 per MMBtu, (the “Below Threshold Month”) then the Treatment Factor for the Below Threshold Month shall be suspended and the Lessor shall be charged during said month an amount equal to the Actual Recovery Costs (as hereinafter defined).

For purposes of this Paragraph 1.20 only, the term “Average Monthly Sales Price” shall be defined as the average price received by Lessee for sales of that month’s total production.

For purposes of this Paragraph 1.20 only, the term “Actual Recovery Costs” shall be defined as all costs beyond the wellhead for operating the systems used for gathering, compression, treatment, dehydration, and transportation to the delivery point at which gas enters either an interstate pipeline or the Alagasco system, and which are not a part of the net profits calculation including but not limited to:

i) Actual fuel costs, based on Average Monthly Sales Price for the Below Threshold Month;

ii) All O&M costs including but not limited to labor, supervision, contract services, compressor rent, field office expenses, fuel (other than fuel included pursuant to B(i) above) and power, lubricants, material and parts and dehydration; and,

iii) For owned units, compressor rent at current market rates for similarly sized compressors.

The first paragraph of Paragraph 7.2 is amended to read as follows (with the examples as inserted in the Fourth Amendment to remain unchanged):

7.2        Lessee shall maintain and operate at its sole expense measuring stations located at each wellhead. Said measuring stations shall be equipped with turbine or rotary meters or other types of meters with totalizer as agreed to by Lessor and Lessee so as to accomplish the accurate measurement of volumes of Occluded Gas produced hereunder. To avoid the expense of wellhead temperature compensation equipment, Lessee may allocate back to the individual well the full production stream, measured at the Sales Meters, as defined in Section 7.10 below, plus fuel. Such allocation will be based on each wellhead meter’s production as a percentage of total.

2

Paragraph 7.10 is hereby added to Article 7 as follows:

7.10        Lessee will provide to Lessor a monthly comparison detailing the send out volumes from the Lessee-owned compressor meters (the “Compressor Meters”) and the volumes from the corresponding third-party owned sales meters (the “Sales Meters”). When the Compressor Meters volume exceeds the Sales Meters volume by more than two percent (2%) in the aggregate, then the Lessee shall check the Compressor Meters for accuracy and request that the Sales Meters be checked for accuracy:

i) If it is determined that the Compressor Meters are in error, they will be corrected in accordance with Paragraph 7.7 hereof;

ii) If it is determined that the Sales Meters are in error, then the Lessee will seek appropriate adjustments from the purchaser of the Occluded Gas in accordance with the terms of the gas sales agreement governing such purchases.

iii) If it is determined that both the Sales Meters and the Compressor Meters are correct then the Lessee shall make an adjustment to the amounts paid to the Lessor to account for the differences in the volumes so that the Lessor shall not bear the risk of the unaccounted for gas outside the two percent (2%) tolerance. Such adjustments shall be made for a period of time extending to the date of the last monthly comparison.

Notwithstanding the preceding, at any time the Treatment Factor is equal to the Actual Recovery Costs, Lessor will bear its share of the unaccounted for volumes and no additional volume payments will be made under this provision.

In all other respects the terms and conditions of the Occluded Gas Lease, as previously amended, shall remain unchanged.

The parties hereto further agree that the foregoing amendment to the Occluded Gas Lease shall be effective on Effective Date and shall not have retroactive effect.

IN WITNESS WHEREOF, this Agreement shall be effective as of the 1^st day of January 2009 (the “Effective Date”).

WITNESS:	RGGS LAND & MINERALS, LTD., L.P.
	Name:
	Title:
	Date:
	WITNESS:    ENERGEN RESOURCES
CORPORATION
	Name:	John S. Richardson
	Title:	Executive Vice President and Chief Operating Officer
	Date:

3

EX-21

Exhibit 21

SUBSIDIARIES OF ENERGEN CORPORATION

Alabama Gas Corporation*

Energen Resources Corporation*

* Incorporated in the State of Alabama

EX-23.(A)

Exhibit 23(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-119926) and Forms S-8 (File No. 33-46641, File No. 33-48505, File No. 333-26111, File No. 333-45107 and File No. 333-84170) of Energen Corporation of our report dated February 24, 2009 relating to the consolidated financial statements, financial statement schedule, and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 24, 2009

EX-23.(B)

Exhibit 23(b)

CONSENT

We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2008 which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-119926) and Forms S-8 (File No. 33-46641, File No. 33-48505, File No. 333-26111, File No. 333-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2008 which appears in this Form 10-K.

/s/ Ryder Scott Company, L.P.

Houston, Texas

February 24, 2009

EX-23.(C)

Exhibit 23(c)

CONSENT

We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2008 which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-119926) and Forms S-8 (File No. 33-46641, File No. 33-48505, File No. 333-26111, File No. 333-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2008 which appears in this Form 10-K.

/s/ T. Scott Hickman & Associates, Inc.

Midland, Texas

February 24, 2009

EX-24.(A)

Exhibit 24(a)

POWER OF ATTORNEY

Each of the undersigned directors of Energen Corporation, an Alabama corporation, hereby nominates, constitutes and appoints James T. McManus, II, and Charles W. Porter, Jr., and each of them, the true and lawful attorneys of the undersigned to sign the name of the undersigned as director to the Annual Report on Form 10-K for the year ended December 31, 2008 of said corporation to be filed with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, and to any and all amendments to said report.

The undersigned hereby grants to said attorneys full power of substitution, resubstitution and revocation, all as fully as the undersigned could do if personally present, hereby ratifying all that said attorneys or their substitutes may lawfully do by virtue hereof.

IN WITNESS WHEREOF, the undersigned directors of Energen Corporation have executed this Power of Attorney as of the 28^th day of January, 2009.

/s/ Stephen D. Ban

/s/ Julian W. Banton

/s/ Kenneth W. Dewey

/s/ James S. M. French

/s/ T. Michael Goodrich

/s/ Judy M. Merritt

/s/ Stephen A. Snider

/s/ Wm. Michael Warren, Jr.

/s/ David W. Wilson

/s/ Gary C. Youngblood

EX-24.(B)

Exhibit 24(b)

POWER OF ATTORNEY

Each of the undersigned directors of Alabama Gas Corporation, an Alabama corporation, hereby nominates, constitutes and appoints James T. McManus, II, and Charles W. Porter, Jr., and each of them, the true and lawful attorneys of the undersigned to sign the name of the undersigned as director to the Annual Report on Form 10-K for the year ended December 31, 2008 of said corporation to be filed with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, and to any and all amendments to said report.

The undersigned hereby grants to said attorneys full power of substitution, resubstitution and revocation, all as fully as the undersigned could do if personally present, hereby ratifying all that said attorneys or their substitutes may lawfully do by virtue hereof.

IN WITNESS WHEREOF, the undersigned directors of Alabama Gas Corporation have executed this Power of Attorney as of the 28^th day of January, 2009.

/s/ Stephen D. Ban

/s/ Julian W. Banton

/s/ Kenneth W. Dewey

/s/ James S. M. French

/s/ T. Michael Goodrich

/s/ Judy M. Merritt

/s/ Stephen A. Snider

/s/ Wm. Michael Warren, Jr.

/s/ David W. Wilson

/s/ Gary C. Youngblood

EX-31.(A)

CERTIFICATION Exhibit 31(a)

I, James T. McManus, II, certify that:

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

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

February 24, 2009	By    /s/ James T. McManus, II
	James T. McManus, II
	Chairman, Chief Executive Officer and President of Energen Corporation

EX-31.(B)

CERTIFICATION Exhibit 31(b)

I, Charles W. Porter, Jr., certify that:

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

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

February 24, 2009	By    /s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr.
	Vice President, Chief Financial
	Officer and Treasurer of Energen
	Corporation

EX-31.(C)

CERTIFICATION Exhibit 31(c)

I, James T. McManus, II, certify that:

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

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

February 24, 2009	By    /s/ James T. McManus, II
	James T. McManus, II
	Chairman and Chief Executive Officer of Alabama Gas Corporation

EX-31.(D)

CERTIFICATION Exhibit 31(d)

I, Charles W. Porter, Jr., certify that:

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

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

February 24, 2009	By    /s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr.
	Vice President, Chief Financial
	Officer and Treasurer of Alabama
	Gas Corporation

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Energen Corporation and Alabama Gas Corporation (the “Registrants”) on Form 10-K for the period ended December 31, 2008, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to each registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of February 24, 2009

By /s/ James T. McManus, II

James T. McManus, II

Chairman, Chief Executive

Officer and President of Energen

Corporation; Chairman and Chief

Executive Officer of Alabama

Gas Corporation

By /s/ Charles W. Porter, Jr.

Charles W. Porter, Jr.

Vice President, Chief Financial

Officer and Treasurer of Energen

Corporation and Alabama Gas
Corporation

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