Edgar Filing: ENERGEN CORP

Plan B

September 30,

2005

September 30,

2004

Discount rate

Form 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, 2005

¨	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
Energen Corporation Preferred Stock Purchase Rights		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 (Section 229.405 of this chapter) is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act).


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

Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30, 2005:


Energen Corporation		$2,552,980,558

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

Indicate number of shares outstanding of each of the registrant’s classes of common stock as of March 2, 2006:


		Energen Corporation		73,469,820 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, 2006 (Part III, Item 10-13)

INDUSTRY GLOSSARY

For a more complete definition of certain terms defined below, please refer to Rule 4-10(a) of Regulation S-X,

promulgated pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended.


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

Basin-Specific		A type of derivative contract whereby the contract’s settlement price is based on specific geographic basin indices.

Behind Pipe Reserves		Oil or gas reserves located above or below the currently producing zone(s) that cannot be extracted until a recompletion or pay-add occurs.

Call Option		A contract that gives the investor the right, but not the obligation, to buy the underlying commodity at a certain price on an agreed upon date.

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

Exploratory Well		A well drilled to 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.

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.

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.


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.

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

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

Reserves-to- Production Ratio		Ratio expressing years of supply determined by dividing the remaining recoverable reserves at year end by actual annual production volumes.

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

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

Transportation		Moving gas through 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

2005 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS


		Page
PART I

Item 1.	Business	5

Item 1A.	Risk Factors	11

Item 1B.	Unresolved Staff Comments	12

Item 2.	Properties	13

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	16

Item 6.	Selected Financial Data	17

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	32

Item 8.	Financial Statements and Supplementary Data	33

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	81

Item 9A.	Controls and Procedures	81

PART III

Item 10.	Directors and Executive Officers of the Registrants	83

Item 11.	Executive Compensation	83

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	83

Item 13.	Certain Relationships and Related Transactions	83

Item 14.	Principal Accountant Fees and Services	83

PART IV

Item 15.	Exhibits and Financial Statement Schedules	84

Signatures		89

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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 acquisition, 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, our 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.

Third Party Facilities: The forward-looking statements also assume generally uninterrupted access to third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources Corporation, the Company’s oil and gas subsidiary, 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/or the Company.

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

Energen Resources Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas 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.

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.

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 our 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/or the Company’s financial position, results of operations and cash flows.

Alagasco 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.

PART I

ITEM 1. BUSINESS

General

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

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

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 provided 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.

Financial Information About Industry Segments

The information required by this item is provided in Note 22, Industry Segment Information, in the Notes to Financial Statements.

Narrative Description of Business

•

Oil and Gas Operations

General: Energen’s oil and gas operations focus on increasing production and adding proved reserves through the acquisition and development of oil and gas properties. To a lesser extent, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. Substantially all gas, oil and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Black Warrior, 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 2005, Energen Resources’ proved oil and gas reserves totaled 1,722 billion cubic feet equivalent (Bcfe). Substantially all of these reserves are located in the San Juan Basin in New Mexico, the Permian Basin in west Texas and the Black Warrior Basin in Alabama. Approximately 81 percent of Energen Resources’ year-end reserves are proved developed reserves. Energen Resources’ reserves are long-lived, with a year-end reserves-to-production ratio of 19 years. Natural gas represents approximately 63 percent of Energen Resources’ proved reserves, with oil representing approximately 26 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, $838 million in related development, and $119 million in exploration and related development. Energen Resources’ capital investment for oil and gas activities over the five-year period ending December 31, 2010, is currently expected to approximate $372 million for development on existing properties and $38 million for exploratory and other activities. As an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. These investments would result in capital expenditures different than those outlined above. The Company is prepared to invest approximately $1 billion over the next five years for property acquisitions that meet Energen’s acquisition criteria.

Energen Resources’ approach to the oil and gas business calls for the company to pursue onshore North American property acquisitions which offer proved undeveloped (PUD) and/or behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers operated natural gas properties with long-lived reserves and multiple pay-zone opportunities; however, Energen Resources will consider acquisitions of other types of properties which meet its investment requirements. In addition, Energen Resources may conduct limited exploration activities primarily in areas in which it has operations and remains open to considering 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’ PUD and behind-pipe reserve potential as well as engaging in other activities. These activities include development well drilling, limited 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’ development activities can result in the addition of new proved reserves and can serve to reclassify proved undeveloped reserves to proved developed reserves. Proved reserve disclosures are provided annually, although changes to reserve classifications occur throughout the year. Accordingly, additions of new reserves from development activities can occur throughout the year and may result from numerous factors including, but not limited to, regulatory approvals for drilling unit downspacing which increase the number of available drilling locations; changes in the economic or operating environments which allow previously uneconomic locations to be added; technological advances which make reserve locations available for development; successful development of existing PUD locations which reclassify adjacent probable locations to PUD locations; increased knowledge of field geology and engineering parameters relative to oil and gas reservoirs; and changes in management’s intent to develop certain opportunities.

During the three years ended December 31, 2005, the Company’s development efforts have added 295 Bcfe of proved reserves from the drilling of 929 gross development wells and 333 well recompletions and pay-adds. In 2005, Energen Resources’ successful development wells and other activities added approximately 90 Bcfe of proved reserves. The company drilled 294 gross development wells, performed some 77 well recompletions and pay-adds, and conducted other operational enhancements in 2005. Energen Resources’ production from continuing operations totaled 91 Bcfe in 2005 and is estimated to total 92 Bcfe in 2006, including 91 Bcfe of estimated production from proved reserves owned at December 31, 2005.

Risk Management: Energen Resources attempts to lower the risks associated with its oil and natural gas business. A key component of the company’s efforts to manage risk is its acquisition versus exploration orientation and its preference for long-lived reserves. In pursuing an acquisition, Energen Resources primarily uses the then-current oil and gas futures prices in its evaluation models, the prevailing swap curve and, for the longer-term, its own pricing assumptions. 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. In the case of an acquisition, Energen Resources may hedge further forward to protect targeted returns.

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 from time to time enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, put options and swaps on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change.

See the Forward-Looking 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.

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

During 2004, the State of New Mexico issued new regulations related to below-grade storage pits. Such pits are used to temporarily hold produced fluids until they can be disposed of permanently. Under the new regulations, the storage pits must be constructed above ground or with secondary containment and visual leak detection, and all such pits will require an annual certification attesting that the storage pits do not leak. As a result of this regulation, the Company expensed $1 million as lease operating expense during 2005. During 2004, the Company capitalized $0.5 million as part of its acquisition of properties in the San Juan Basin and expensed $1.6 million as lease operating expense under this regulation. The Company does not anticipate any further remediation charges on existing properties related to the new regulations.

•

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 191 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 2005, Alagasco served an average of 425,110 residential customers and 34,936 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 10,000 miles of main and more than 11,700 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 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended RSE for a six-year period through January 1, 2008. Under the APSC order, Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the returns on equity of all major energy utilities operating under a similar methodology. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year).

Under RSE, the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, whether Alagasco’s return on average equity at the end of the rate year will be within the allowed range. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. RSE limits the utility’s equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco’s operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments.

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

The APSC approved an Enhanced Stability Reserve (ESR) beginning October 1997, with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco’s return on equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR in an amount of no more than $40,000 monthly until the maximum funding level is achieved.

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

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

As of December 31, 2005, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:


		December 31, 2005 (Mcfd)
		December 31, 2005 (Mcfd)
Southern firm transportation		154,892
Southern storage and no notice transportation		251,679
Transco firm transportation		70,000
Various intrastate transportation		20,240

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

In 1994 Alagasco implemented the P Rate in response to the competitive challenge of interstate pipeline capacity release. Under this tariff provision, Alagasco releases much of its excess pipeline capacity and repurchases it as agent for its transportation customers under 12 month contracts. The transportation customers benefit from lower pipeline costs; Alagasco’s core market customers benefit, as well, since the utility uses the revenues received from the P Rate to decrease gas costs for its residential and its small commercial and industrial customers. In 2005, approximately 300 of Alagasco’s transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled more than $7.9 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 2005 substantially all of Alagasco’s large commercial and industrial customer deliveries were the transportation of customer-owned gas. In addition, Alagasco served as gas purchasing agent for more than 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 2005, 50 of the utility’s largest commercial and industrial transportation customers were under special contracts of varying lengths.

Natural gas service available to Alagasco customers falls into two broad categories: interruptible and firm. Interruptible service contractually is subject to interruption by Alagasco for various reasons; the most common occurrence is curtailment of industrial customers during periods of peak core market heating demand. Interruptible service typically is provided to large commercial and industrial transportation customers who can reduce their gas consumption by adjusting production schedules or by switching to alternate fuels for the duration of the service interruption. More expensive firm service, on the other hand, generally is not subject to interruption and is provided to residential and 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 2005, Alagasco’s average number of customers decreased slightly. Alagasco will continue to concentrate on maintaining its current penetration levels in the residential new construction market and generating additional revenue in the small and large commercial and industrial market segments.

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

Environmental Matters: Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns) and five manufactured gas distribution sites (one of which it still owns). An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco’s share, if any, of such costs will not materially affect the Company’s financial position, results of operations or cash flows.

Employees

The Company has approximately 1,500 employees, of which Alagasco employs 1,200 and Energen Resources employs 300. The Company believes that its relations with employees are good.

ITEM 1A. RISK FACTORS

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/or the Company.

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

Energen Resources Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas 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 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.

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 our 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/or the Company’s financial position, results of operations and cash flows.

Energen Resources Customer Concentration: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil 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 and gas purchasers account for approximately 29 percent, 19 percent and 14 percent, respectively, of Energen Resources’ estimated 2006 production. Energen Resources’ other purchasers each bought less than 8 percent of production.

Alagasco 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.

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 rating agency evaluations of the Company and of Alagasco.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

The corporate headquarters of Energen, Alagasco and Energen Resources are located in leased office space in Birmingham, Alabama. Energen Resources maintains offices in Midland, Lehman, Seminole, Westbrook and Penwell, Texas, in Farmington, New Mexico, in Oak Grove, Vance and Tuscaloosa, Alabama and in Arcadia, Louisiana. For a description of Energen Resources’ oil and gas properties, see the discussion under Item 1-Business. Information concerning Energen Resources’ production and reserves is summarized in the table below and included in Note 21, Oil and Gas Operations (Unaudited), in the Notes to Financial Statements.


	Year Ended December 31, 2005 Production Volumes (MMcfe)	December 31, 2005 Proved Reserves (MMcfe)
San Juan Basin	37,610	901,542
Permian Basin	26,510	501,436
Black Warrior Basin	16,183	244,730
North Louisiana/East Texas	10,329	67,960
Other	467	5,869

Total	91,099	1,721,537

The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 10,000 miles of main and more than 11,700 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, two payment centers, four district offices, six 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 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.

Cochran County, Texas

In January 2005, a lawsuit was tried in Cochran County, Texas in which the plaintiff alleged preferential purchase right claims against Energen Resources with respect to certain properties acquired by Energen Resources in 2002. The jury rendered a verdict in Energen Resources’ favor on all counts. Subsequently, in March 2005, the Judge issued a decision overruling the jury verdict. Energen Resources is pursuing an appeal of the Judge’s order and expects to prevail. Under the Judge’s order, Energen Resources potential pre-tax charge to income would be approximately $3.3 million as of December 31, 2005, none of which has been accrued. This amount includes the net cash flows attributable to the property since its acquisition.

Jefferson County, Alabama

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. RGGS seeks a declaratory judgment with respect to the parties’ rights under the lease, reformation of the lease, monetary damages and termination of Energen Resources’ rights under the lease. The Occluded Gas Lease dated January 1, 1986 was originally between Energen Resources and United States Steel Corporation (U.S. Steel) as lessor. RGGS became the lessor under the lease as a result of a 2004 conveyance from U.S. Steel to RGGS. Approximately 120,000 acres in Jefferson and Tuscaloosa counties, Alabama, are subject to the lease. Separately on February 6, 2006, Energen Resources

received notice of immediate lease termination from RGGS. As of December 31, 2005, Energen’s consolidated balance sheet included approximately $96 million in net oil and gas properties associated with the lease. During 2005, Energen Resources’ production associated with the lease was approximately 11 Bcf.

RGGS has adopted positions contrary to the seventeen years of course of dealing between Energen Resources and its original contracting partner, U.S. Steel. The Company believes that RGGS’ assertions are without merit and that the notice of lease termination is ineffective. Energen Resources intends to vigorously defend its rights under the lease. The Company remains in possession of the lease, believes that the likelihood of a judgment in favor of RGGS is remote, and has made no accrual with respect to the litigation or purported lease termination.

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 2005.

EXECUTIVE OFFICERS OF THE REGISTRANTS

Energen Corporation


Name	Age	Position (1)
Wm. Michael Warren, Jr.	58	Chairman of the Board and Chief Executive Officer (2)

James T. McManus, II	47	President and Chief Operating Officer of Energen, President of Energen Resources (3)

Geoffrey C. Ketcham	55	Executive Vice President, Chief Financial Officer and Treasurer (4)

Dudley C. Reynolds	53	President and Chief Operating Officer of Alagasco (5)

Grace B. Carr	50	Vice President and Controller (6)

J. David Woodruff, Jr.	49	General Counsel and Secretary and Vice President-Corporate Development (7)


*Notes:*	(1)	All executive officers of Energen have been employed by Energen or a subsidiary for the past five years. Officers serve at the pleasure of the Board of Directors.
	(2)	Mr. Warren has been employed by the Company in various capacities since 1983. In January 1992 he was elected President and Chief Operating Officer of Energen and all of its subsidiaries, in October 1995 he was elected Chief Executive Officer of Alagasco and Energen Resources, in February 1997 he was elected Chief Executive Officer of Energen and, effective January 1, 1998, he was elected Chairman of the Board of Energen and each of its subsidiaries. Mr. Warren serves as a Director of Energen and each of its subsidiaries. He is also a Director of Protective Life Corporation.
	(3)	Mr. 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.
	(4)	Mr. Ketcham has been employed by the Company in various financial and strategic planning capacities since 1981. He has served as Executive Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries since April 1991.
	(5)	Mr. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003.
	(6)	Ms. Carr was employed by the Company in various capacities from January 1985 to April 1989. She was not employed from May 1989 through December 1997. She was elected Controller of Energen in January 1998 and elected Vice President and Controller of Energen in October 2001.
	(7)	Mr. Woodruff has been employed by the Company in various capacities since 1986. He was elected Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries in April 1991 and Vice President-Corporate Development of Energen in October 1995. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003.

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, 2003	16.03	14.04	16.03	.09
June 30, 2003	17.15	15.80	16.65	.09
September 30, 2003	18.55	15.68	18.09	.0925
December 31, 2003	21.00	18.07	20.52	.0925

March 31, 2004	22.36	19.94	20.63	.0925
June 30, 2004	24.28	20.06	24.00	.0925
September 30, 2004	25.98	22.93	25.78	.09625
December 31, 2004	30.04	25.44	29.48	.09625

March 31, 2005	34.09	27.06	33.30	.10
June 30, 2005	35.64	28.65	35.05	.10
September 30, 2005	43.56	33.85	43.26	.10
December 31, 2005	44.31	34.50	36.32	.10

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On February 1, 2006, there were 7,662 holders of record of Energen’s common stock. At the date of this filing, Energen Corporation owns all the issued and outstanding common stock of Alabama Gas Corporation.

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


Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options	Weighted Average Exercise Price		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders	641,400	$	13.83	2,500,289
Equity compensation plans not approved by security holders	—		—	—

Total	641,400	$	13.83	2,500,289

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, 2005 through October 31, 2005	—		—	—	—
November 1, 2005 through November 30, 2005	5,214	$	37.68	—	—
December 1, 2005 through December 31, 2005	2,549	$	36.90	—	2,150,700

Total	7,763	$	37.42	—	2,150,700

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

**	By resolution adopted May 24, 1994, and supplemented by a resolution adopted April 26, 2000, the Board of Directors authorized the Company to repurchase up to 3,564,400 shares of the Company’s common stock. The resolutions do not have an expiration date.

Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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


*(dollars in thousands, except per share amounts)*	Year Ended December 31, 2005		Year Ended December 31, 2004		Year Ended December 31, 2003		Year Ended December 31, 2002		Three Months Ended December 31, 2001*		Year Ended September 30, 2001
INCOME STATEMENT
Operating revenues	$	1,128,394	$	936,857	$	841,631	$	667,419	$	143,553	$	762,124
Income from continuing operations before cumulative effect of change in accounting principle	$	172,886	$	127,305	$	110,104	$	70,204	$	2,261	$	57,645
Net income	$	173,012	$	127,463	$	110,654	$	68,639	$	3,658	$	67,896
Diluted earnings per average common share from continuing operations before cumulative effect of change in accounting principle	$	2.35	$	1.74	$	1.54	$	1.04	$	0.04	$	0.93
Diluted earnings per average common share	$	2.35	$	1.74	$	1.55	$	1.01	$	0.06	$	1.09

BALANCE SHEET
Total property, plant and equipment, net	$	2,068,011	$	1,783,059	$	1,433,451	$	1,351,554	$	1,093,201	$	1,084,052
Total assets	$	2,618,226	$	2,181,739	$	1,778,232	$	1,643,012	$	1,342,346	$	1,313,885
Long-term debt	$	683,236	$	612,891	$	552,842	$	512,954	$	544,133	$	544,110
Total shareholders’ equity	$	892,678	$	803,666	$	699,032	$	582,810	$	474,205	$	480,767

COMMON STOCK DATA
Annual dividend rate at period-end	$	0.40	$	0.385	$	0.37	$	0.36	$	0.35	$	0.35
Cash dividends paid per common share	$	0.40	$	0.3775	$	0.365	$	0.355	$	0.0875	$	0.3425
Shares outstanding at period-end (000)		73,493		73,166		72,447		69,491		62,497		62,250
Price range:
High	$	44.31	$	30.04	$	21.00	$	15.00	$	12.60	$	20.13
Low	$	27.06	$	19.94	$	14.04	$	10.83	$	10.75	$	10.75
Close	$	36.32	$	29.48	$	20.52	$	14.55	$	12.33	$	11.25

*	On December 5, 2001, the Board of Directors of the Company approved a change in the Company’s fiscal year end from September 30 to December 31, effective January 1, 2002. A transition report was filed on Form 10-Q for the period October 1, 2001, to December 31, 2001.

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

SELECTED BUSINESS SEGMENT DATA

Energen Corporation


*(dollars in thousands)*	Year Ended December 31, 2005		Year Ended December 31, 2004		Year Ended December 31, 2003		Year Ended December 31, 2002		Three Months Ended December 31, 2001*			Year Ended September 30, 2001
OIL AND GAS OPERATIONS
Operating revenues from continuing operations
Natural gas	$	365,635	$	276,482	$	235,022	$	145,443	$	34,213		$	131,875
Oil		116,651		98,409		87,192		72,132		11,126			43,867
Natural gas liquids		38,455		30,902		25,938		21,843		4,282			24,540
Other		6,953		4,324		4,380		3,570		(2,746	)		7,980

Total	$	527,694	$	410,117	$	352,532	$	242,988	$	46,875		$	208,262

Production volumes from continuing operations
Natural gas (MMcf)		61,048		57,164		55,304		45,891		11,420			43,956
Oil (MBbl)		3,316		3,434		3,411		2,989		464			1,873
Natural gas liquids (MMgal)		70.5		68.2		66.6		71.9		18.0			58.6

Production volumes from continuing operations (MMcfe)		91,020		87,513		85,291		74,093		16,766			63,572

Total production volumes (MMcfe)		91,099		87,606		86,157		77,973		18,022			68,478

Proved reserves
Natural gas (MMcf)		1,080,161		1,019,436		886,307		803,748		714,395			627,051
Oil (MBbl)		74,962		54,500		52,528		49,833		19,128			20,878
Natural gas liquids (MBbl)		31,934		34,613		27,245		26,697		25,944			24,931

Total (MMcfe)		1,721,537		1,554,114		1,364,945		1,262,928		984,827			901,905

Other data from continuing operations Lease operating expense (LOE)
LOE and other	$	104,241	$	79,191	$	67,833	$	56,932	$	12,917		$	53,451
Production taxes		52,271		37,285		27,686		18,186		3,379			22,800

Total	$	156,512	$	116,476	$	95,519	$	75,118	$	16,296		$	76,251

Depreciation, depletion and amortization	$	89,340	$	80,896	$	79,495	$	70,285	$	15,266		$	51,036
Capital expenditures	$	353,712	$	403,936	$	163,338	$	305,476	$	25,052		$	136,886
Operating income	$	243,876	$	180,379	$	153,325	$	78,680	$	2,033		$	61,364

NATURAL GAS DISTRIBUTION
Operating revenues
Residential	$	384,753	$	340,229	$	320,938	$	277,088	$	63,724		$	367,109
Commercial and industrial		166,957		138,686		126,638		104,247		22,445			147,636
Transportation		43,291		40,221		38,250		38,395		9,765			33,972
Other		5,699		7,604		3,273		4,701		744			5,145

Total	$	600,700	$	526,740	$	489,099	$	424,431	$	96,678		$	553,862

Gas delivery volumes (MMcf)
Residential		24,601		25,383		27,248		26,358		5,128			31,064
Commercial and industrial		12,498		12,323		12,564		11,838		2,193			14,054
Transportation		49,850		54,385		55,623		59,644		12,973			53,989

Total		86,949		92,091		95,435		97,840		20,294			99,107

Average number of customers
Residential		425,110		425,673		427,413		425,630		422,461			428,663
Commercial, industrial and transportation		34,936		35,248		35,463		35,601		35,161			35,882

Total		460,046		460,921		462,876		461,231		457,622			464,545

Other data
Depreciation and amortization	$	42,351	$	39,881	$	37,171	$	33,682	$	8,151		$	30,933
Capital expenditures	$	73,276	$	58,208	$	57,906	$	65,815	$	12,873		$	56,090
Operating income	$	72,922	$	66,199	$	66,848	$	59,370	$	8,034		$	50,288

*	On December 5, 2001, the Board of Directors of the Company approved a change in the Company’s fiscal year end from September 30 to December 31, effective January 1, 2002. A transition report was filed on Form 10-Q for the period October 1, 2001, to December 31, 2001.

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

CRITICAL ACCOUNTING POLICIES

The Company’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Management has identified the following critical accounting policies in the application of existing accounting standards or in the implementation of new standards that involve significant judgments and estimates by the Company. The application of these accounting policies necessarily requires managements’ most subjective or complex judgments regarding estimates and projected outcomes of future events which 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, 2005. The independent reservoir engineers have issued reports covering approximately 91 percent of the Company’s ending proved reserves and in their judgment these estimates are reasonable in the aggregate. The Company’s production of undeveloped reserves requires the installation or completion of related infrastructure facilities such as pipelines and the drilling of development wells.

Changes in oil and gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property’s book value if an impairment is warranted. The table below reflects the estimated increase in 2006 depreciation, depletion and amortization expense associated with assumed downward changes in oil and gas reserve quantities from the reported amounts at December 31, 2005.


	Percentage Change in Oil & Gas Reserves From Reported Reserves as of December 31, 2005
*(dollars in thousands)*	-5%		-10%
Estimated change in depreciation expense for the year ended December 31, 2006, net of tax	$	3,000	$	6,300

Asset Impairments: Oil and gas developed 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’s oil and gas subsidiary, Energen Resources Corporation, 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.

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 from time to time enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. 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: Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, 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 Pension Plans: The Company calculates net periodic pension expense and liabilities on an actuarial basis under the provisions of SFAS No. 87, “Employers’ Accounting for Pensions.” The key assumptions used in determining these calculations are disclosed in Note 5, Employee Benefit Plans, in the Notes to Financial Statements. 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 defined benefit pension plans requires assumptions regarding the appropriate weighted average discount rate, estimated weighted average rate of increase in the compensation level of its employee base and the expected long-term rate of return on the plans’ assets. The selection and use of such assumptions affects the amount of expense recorded in the Company’s financial statements related to its defined benefit pension plans. In selecting the discount rate, consideration is 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 for actuarial purposes covering a majority of employees was 5.75 percent for the year ended December 31, 2005. A

hypothetical 25 basis point change in the discount rate would impact total pension expense by approximately $1,010,000. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The return on assets used for actuarial purposes was 8.5 percent for the year ended December 31, 2005. A hypothetical 25 basis point change in the return on assets would impact total pension expense by approximately $320,000. The estimated weighted average rate of increase in the compensation level of the Company’s employees was 4 percent for the year ended December 31, 2005. A hypothetical 25 basis point change in the estimated rate of increase in the compensation level of applicable employees would impact total pension expense by approximately $670,000. The discount rate, return on plan assets and estimated rate of compensation increase used in the actuarial assumptions for 2006 is 5.5 percent, 8.5 percent, and 3.5 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 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.

RESULTS OF OPERATIONS

Consolidated Net Income

Energen Corporation’s net income for the year ended December 31, 2005 totaled $173 million, or $2.35 per diluted share and compared favorably to the year ended December 31, 2004 net income of $127.5 million, or $1.74 per diluted share. This 35.1 percent increase in earnings per diluted share (EPS) largely reflected the result of significantly higher prices for natural gas, oil and natural gas liquids as well as the impact of a 3.5 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen Resources. For the year ended December 31, 2005, Energen Resources earned $135.3 million, as compared with $94.1 million in the previous year. Alagasco generated a 9.4 percent increase in net income, earning $37 million in the current year as compared with net income in the prior period of $33.8 million. For the year ended December 31, 2003, Energen reported earnings of $110.7 million, or $1.55 per diluted share.

2005 vs 2004: Energen Resources’ net income rose 43.8 percent to $135.3 million in 2005. Energen Resources’ income from continuing operations totaled $135.2 million in 2005 as compared with $93.9 million in 2004. Discontinued operations in 2005 generated income of $126,000 as compared with income of $158,000 in 2004. The primary factors positively influencing income from continuing operations included increased commodity prices of approximately $62 million after-tax along with the impact of increased production volumes of approximately $10 million after-tax. These increases were partially offset by higher lease operating expense of approximately $16 million after-tax, higher production taxes of approximately $9 million after-tax, increased depreciation, depletion and amortization (DD&A) expense of approximately $5 million after-tax and increased administrative expenses of approximately $5 million after-tax.

Alagasco earned net income of $37 million in 2005 as compared with net income of $33.8 million in 2004. This increase in earnings largely reflected the utility’s ability to earn on a higher level of equity. Alagasco’s return on average equity (ROE) was 13.5 percent in 2005 compared with 12.8 percent in 2004.

2004 vs 2003: For the year ended December 31, 2004, Energen Resources’ net income totaled $94.1 million as compared with $78.9 million for the 12 months ended December 31, 2003. Energen Resources’ income from continuing operations totaled $93.9 million in 2004 as compared with $78.4 million in 2003, primarily due to higher commodity prices of approximately $31 million after-tax along with the impact of increased production volumes of approximately $6 million after-tax. The primary negative influences on income from continuing operations were higher lease operating expense of approximately $7 million after-tax, higher production taxes of approximately $6 million after-tax and increased administrative expenses of approximately $4 million after-tax.

Alagasco earnings increased to $33.8 million in 2004 from $33 million in 2003 largely as a result of the utility earning on a higher level of equity. Alagasco achieved a ROE of 12.8 percent in 2004 compared with 13.5 percent in 2003.

Operating Income

Consolidated operating income in 2005, 2004 and 2003 totaled $315.7 million, $244.8 million and $217.6 million, respectively. This growth in operating income has been influenced by strong financial performance from Energen Resources under Energen’s diversified growth strategy, implemented in fiscal 1996. Alagasco also contributed to this growth in operating income consistent with increases in the levels of equity upon which it has been able to earn a return.

Oil and Gas Operations: Revenues from oil and gas operations rose in the current year largely as a result of increased commodity prices and increased production volumes. Increases in production primarily related to the August 2004 purchase of San Juan Basin coalbed methane properties and increased drilling of wells in North Louisiana. Negatively affecting production was a normal production decline in excess of new production coming on-line primarily in the Permian Basin. Revenue per unit of production for natural gas production increased 23.8 percent to $5.99 per thousand cubic feet (Mcf), oil revenue per unit of production rose 22.8 percent to $35.18 per barrel and natural gas liquids revenue per unit of production increased 22.2 percent to an average price of $0.55 per gallon during 2005. Production from continuing operations increased 4 percent to 91 Bcfe during 2005. Natural gas production rose 6.8 percent to 61 billion cubic feet (Bcf) and oil volumes declined 3.4 percent to 3,316 thousand barrels (MBbl). Production of natural gas liquids increased 3.4 percent to 70.5 million gallons (MMgal).

In 2004, revenues from oil and gas operations increased primarily as a result of increased commodity prices, an increase in volumes related to the August 2004 acquisition of coalbed methane properties and additional drilling of coalbed methane wells in the San Juan and Black Warrior basins. Revenue per unit of production related to natural gas increased 13.9 percent to $4.84 per Mcf, oil revenues per unit of production rose 12.1 percent to $28.66 per barrel and natural gas liquids revenue per unit of production increased 15.4 percent to an average price of $0.45 per gallon during the year ended December 31, 2004. Production from continuing operations rose 2.6 percent to 87.5 Bcfe in 2004. Natural gas production increased 3.4 percent to 57.2 Bcf, oil volumes increased slightly to 3,434 MBbl and natural gas liquids production increased 2.4 percent to 68.2 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 $8.7 million, $6.6 million and $6.1 million in 2005, 2004 and 2003, respectively.


*Years ended December 31, (in thousands, except sales price data)*	2005			2004			2003
Operating revenues from continuing operations
Natural gas	$	365,635		$	276,482		$	235,022
Oil		116,651			98,409			87,192
Natural gas liquids		38,455			30,902			25,938
Operating fees		8,674			6,648			6,077
Other		(1,721	)		(2,324	)		(1,697	)

Total operating revenues from continuing operations	$	527,694		$	410,117		$	352,532

Production volumes from continuing operations
Natural gas (MMcf)		61,048			57,164			55,304
Oil (MBbl)		3,316			3,434			3,411
Natural gas liquids (MMgal)		70.5			68.2			66.6

Revenue per unit of production including effects of all derivative instruments
Natural gas (per Mcf)	$	5.99		$	4.84		$	4.25
Oil (per barrel)	$	35.18		$	28.66		$	25.56
Natural gas liquids (per gallon)	$	0.55		$	0.45		$	0.39

Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (per Mcf)	$	6.03		$	4.87		$	4.27
Oil (per barrel)	$	35.18		$	29.70		$	25.61
Natural gas liquids (per gallon)	$	0.55		$	0.45		$	0.39

Revenue per unit of production excluding effects of all derivative instruments
Natural gas (per Mcf)	$	7.81		$	5.68		$	4.97
Oil (per barrel)	$	51.61		$	38.33		$	29.19
Natural gas liquids (per gallon)	$	0.74		$	0.59		$	0.44

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144,”Accounting for Impairment or Disposal of Long-Lived Assets”. During 2005, Energen Resources recorded a pre-tax gain of $213,000 primarily from a property sale located in the Permian Basin. Energen Resources had no property sales during 2004. In 2003, Energen Resources recorded a pre-tax gain of $9.4 million in discontinued operations from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million.

Operations and maintenance (O&M) expense increased $31.1 million and $19 million in 2005 and 2004, respectively. Lease operating expense (excluding production taxes) in 2005 increased $25.1 million primarily due to increased workover and maintenance expenses, increased ad valorem taxes, higher transportation costs and other overall price increases related to higher commodity prices. Partially offsetting these increases were lower compliance costs related to prior year regulations for below-grade storage pits. In 2004, lease operating expense (excluding production taxes) increased by $11.4 million primarily due to increased workover and maintenance expense, costs associated with storage pit regulatory requirements and higher transportation costs. Administrative expense increased $7.5 million in 2005 largely due to labor-related costs. In 2004, administrative expense increased $6.6 million primarily due to labor-related costs as well as costs related to the San Juan Basin property acquisition. Exploration expense decreased $1.4 million in 2005 largely due to decreased exploratory efforts. In 2004, exploration expense increased $1 million.

DD&A expense increased $8.4 million in 2005 and $1.4 million in 2004. The average depletion rates were $0.96 per Mcfe in 2005, $0.90 per Mcfe in 2004 and $0.92 per Mcfe in 2003. The increase in the 2005 rate was largely due to a higher depletion rate on coalbed methane properties purchased in the prior year as well as to the current year production mix that reflects a higher percentage of the Company’s shorter-lived North Louisiana/East Texas production. Increased production volumes also contributed to the increase in DD&A expense during 2005.

Energen Resources’ expense for taxes other than income primarily reflected production-related taxes. Energen Resources recorded severance taxes of $52.3 million, $37.3 million and $27.7 million for 2005, 2004 and 2003, respectively. Increased severance taxes were the result of increased commodity prices and production.

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). On June 10, 2002, the APSC issued an order to extend the utility’s rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the company and a hearing, the Commission votes to either modify or discontinue its operation.

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

Alagasco’s natural gas and transportation sales revenues totaled $600.7 million, $526.7 million and $489.1 million in 2005, 2004 and 2003, respectively. Sales revenue in 2005 and 2004 increased primarily due to an increase in commodity gas costs. In 2005, weather was 3.6 percent colder than in the prior year. Residential sales volumes declined 3.1 percent while commercial and industrial volumes increased 1.4 percent. Large transportation volumes decreased 8.3 percent primarily related to higher gas prices. During 2004, weather that was 6 percent warmer than in the prior year contributed to a 6.8 percent decline in residential sales volumes and a 1.9 percent decrease in commercial and industrial volumes. Large transportation volumes decreased 2.2 percent. In 2005, higher commodity gas costs along with increased gas purchase volumes contributed to a 21.6 percent increase in cost of gas. Higher commodity gas cost generated a 10.9 percent increase in cost of gas in 2004.

O&M expense at the utility increased 3.4 percent in 2005 largely due to higher bad debt expense and distribution maintenance expenses. These increases were partially offset by decreased labor-related expense, primarily as a result of additional labor costs capitalized in the current year. In 2004, O&M expense increased 6.9 percent primarily due to increased labor-related costs. The increase in O&M expense per customer for the rate years ended September 30, 2004 and 2003 were above the inflation-based Cost Control Measurement (CCM) established by the APSC as part of the utility’s rate-setting mechanism; as a result, three quarters of the differences, or $1.2 million and $0.1 million pre-tax, respectively, were returned to the customers through RSE (see Note 2, Regulatory Matters, in the Notes to Financial Statements). Alagasco’s O&M expense fell within the index range for the rate year ended September 30, 2005.

Depreciation expense rose 6.2 percent and 7.3 percent in 2005 and 2004, respectively, due to normal growth of the utility’s distribution and 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)*	2005			2004			2003
Natural gas transportation and sales revenues	$	600,700		$	526,740		$	489,099
Cost of natural gas		(318,269	)		(261,800	)		(236,037	)
Operations and maintenance		(126,041	)		(121,896	)		(114,078	)
Depreciation		(42,351	)		(39,881	)		(37,171	)
Income taxes		(22,360	)		(19,703	)		(19,675	)
Taxes, other than income taxes		(41,117	)		(36,964	)		(34,965	)

Operating income	$	50,562		$	46,496		$	47,173

Natural gas sales volumes (MMcf)
Residential		24,601			25,383			27,248
Commercial and industrial		12,498			12,323			12,564

Total natural gas sales volumes		37,099			37,706			39,812
Natural gas transportation volumes (MMcf)		49,850			54,385			55,623

Total deliveries (MMcf)		86,949			92,091			95,435

Non-Operating Items

Consolidated: Interest expense in 2005 increased $4.1 million primarily due to the issuance of $100 million of Floating Rate Senior Notes by Energen in November 2004, Alagasco’s issuance of $80 million of long-term debt in January 2005 and Alagasco’s $80 million issuance of long-term debt in November 2005. Positively impacting interest expense was Alagasco’s redemption of $56.7 million, $18 million and $30 million of long-term debt in December 2005, August 2005 and April 2004, respectively. Interest expense in 2004 increased $0.5 million largely due to a full year’s interest on $50 million of long-term debt issued by Energen in October 2003 and increased short-term borrowings due to the acquisition of San Juan Basin coalbed methane properties in August 2004. The average daily outstanding balance under short-term credit facilities was $17.7 million in 2005. The average daily outstanding balance under short-term credit facilities was $92.6 million in 2004 as compared to $81.1 million in 2003.

Income tax expense increased in the periods presented primarily due to higher pre-tax income. As of December 31, 2005, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $34.8 million.

Exposure to Natural Disaster

The Company’s production properties and distribution system did not suffer significant damage from Hurricanes Katrina and Rita which occurred in the third quarter of 2005. Energen Resources experienced minimal loss of production and Alagasco had no significant supply disruptions as a result of these hurricanes. These events, however, highlight the potential for a period of production shut-in for Energen Resources resulting from a prolonged interruption of service in areas which have a concentration of fractionation plants and refineries through which a substantial portion of the Company’s natural gas liquids and oil production flow. Alagasco’s customer base is geographically concentrated in central Alabama. Damage to Alagasco’s delivery infrastructure, Energen Resources’ production infrastructure or to third party facilities which serve Alagasco and/or Energen Resources due to a natural disaster or other event could result in significant adverse financial consequences to Alagasco and/or the Company.

FINANCIAL POSITION AND LIQUIDITY

The Company’s net cash from operating activities totaled $335.1 million, $291.1 million and $243.1 million in 2005, 2004 and 2003, respectively. Operating cash flow in 2005, 2004 and 2003 benefited from higher realized commodity prices and production volumes at Energen Resources. During the periods presented, working capital needs at Alagasco were primarily 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 2005, the Company made net investments of $400.7 million. Energen Resources invested $188.4 million in property acquisitions, $157.5 million for development costs including approximately $123 million to drill 294 gross development wells and $5.1 million for exploration. In December 2005, Energen Resources completed its purchase of oil properties located in the Permian Basin from a private company for a contract price of approximately $168 million. The acquisition added approximately 131 Bcfe of proved reserves and had an effective date of November 1, 2005. Energen Resources sold certain properties during 2005, resulting in cash proceeds of $10.8 million. Utility expenditures in 2005 totaled $73.3 million and primarily represented system distribution expansion and support facilities. Cash used in investing activities totaled $453.4 million in 2004. Energen Resources invested $274.4 million in property acquisitions, $124.6 million for development costs including approximately $89 million to drill 288 gross development wells and $5 million for exploration. In August 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $273 million adding approximately 245 Bcfe of proved reserves. Utility expenditures in 2004 totaled $58.2 million. During 2003, the Company made net investments of $190.4 million. Energen Resources invested $40.5 million in property acquisitions, $121.9 million for development costs including approximately $89 million to drill 347 gross development wells and $0.4 million for exploration. Energen Resources sold certain properties during 2003, resulting in cash proceeds of $29.1 million. Utility expenditures in 2003 totaled $57.9 million.

During 2005, the Company added approximately 131 Bcfe of reserves from the Permian Basin acquisition. Energen Resources expects this acquisition to utilize approximately $9 million, net of development costs, of pretax cash flows in 2006. Over the five-year period ending December 31, 2010, the Company expects this acquisition to contribute approximately $14 million, net of development costs, to pretax cash flows. Also during 2005, Energen Resources added 90 Bcfe of reserves from discoveries and other additions, primarily the result of improved drilling technology that increased the number of available drilling locations for certain wells in the San Juan Basin as well as continued downspacing in the Permian Basin. Energen Resources added approximately 315 Bcfe and 236 Bcfe of reserves in 2004 and 2003, respectively.

In 2005, net cash provided from financing activities totaled $69.8 million. In January 2005, Alagasco issued $40 million of long-term debt with an interest rate of 5.2 percent due January 15, 2020 and $40 million of long-term debt with an interest rate of 5.7 percent due January 15, 2035. In November 2005, Alagasco issued $80 million of long-term debt with an interest rate of 5.368 percent due December 1, 2015. Long-term debt was reduced by $84.8

million including Alagasco’s redemption of $18 million in Medium-Term Notes maturing June 27, 2007 to July 5, 2022 in August 2005 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 in December 2005. The Company provided $164.6 million from financing activities in 2004. Energen issued $100 million of Floating Rate Senior Notes in November 2004. Long-term debt was reduced by $40.1 million in 2004, including $30 million of Medium-Term Notes called by Alagasco in April 2004. In 2003, net cash used in financing activities totaled $55.4 million. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration which generated net proceeds of $32.1 million. Energen issued $50 million of long-term debt in October 2003. Long-term debt was reduced by $23 million for current maturities in 2003. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders and the issuance of common stock through the dividend reinvestment and direct stock purchase plan as well as the employee benefit plans.

Capital Expenditures

Oil and Gas Operations: Energen Resources spent a total of $924.3 million for capital projects during the years ended December 31, 2005, 2004 and 2003. Property acquisition expenditures totaled $503.3 million, development activities totaled $403.9 million, and exploratory expenditures totaled $10.5 million.


*Years ended December 31, (in thousands)*	2005		2004		2003
Capital and exploration expenditures for:
Property acquisitions	$	188,403	$	274,400	$	40,486
Development		157,458		124,588		121,889
Exploration		5,065		5,036		397
Other		3,037		1,988		1,548

Total		353,963		406,012		164,320
Less exploration expenditures charged to income		251		2,076		982

Net capital expenditures	$	353,712	$	403,936	$	163,338

Natural Gas Distribution: During the years ended December 31, 2005, 2004 and 2003, Alagasco invested $189.4 million for capital projects: $134.1 million for normal expansion, replacements and support of its distribution system and $55.3 million for support facilities, including the replacement of liquifaction equipment and the development and implementation of information systems.


*Years ended December 31, (in thousands)*	2005		2004		2003
Capital expenditures for:
Renewals, replacements, system expansion and other	$	53,381	$	40,876	$	39,883
Support facilities		19,895		17,332		18,023

Total	$	73,276	$	58,208	$	57,906

FUTURE CAPITAL RESOURCES AND LIQUIDITY

The Company plans to continue to implement its diversified growth strategy that focuses on expanding Energen Resources’ oil and gas operations through the acquisition of producing properties with development potential while maintaining the strength of the Company’s utility foundation. For the five calendar years ended December 31, 2005, Energen’s EPS grew at an average compound rate of 19.8 percent a year. Over the next five years, Energen is targeting an average diluted EPS growth rate over each rolling five-year period of approximately 7 to 8 percent a year.

Over the five-year planning period ending December 31, 2010, Energen Resources’ plans to spend approximately $372 million for development of existing properties and $38 million for exploratory and other activities. During the five year period, Energen Resources anticipates spending approximately $271 million on development of previously identified proved undeveloped reserves and incurring approximately $29 million in exploratory exposure. In 2006, Energen Resources plans to invest approximately $153 million in capital expenditures primarily for development and exploratory activities. Included in this $153 million is approximately $87 million for the development of previously identified proved undeveloped reserves. Approximately $6 million is estimated for

exploratory exposure in 2006. Capital investment at Energen Resources in 2007 is expected to approximate $87 million for development and exploration. Of this $87 million, development of previously identified proved undeveloped reserves is estimated to be $71 million and exploratory exposure is estimated to be $6 million.

Notwithstanding the estimated expenditures mentioned above, as an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria which could result in capital expenditures different than those outlined above. The Company is prepared to invest approximately $1 billion over the next five years in addition to the estimates given above, for property acquisitions that meet Energen’s acquisition criteria. In addition, Energen Resources may conduct limited exploration activities primarily in areas in which it has operations and remains open to considering exploration activities which complement its core expertise and meet its investment requirements. To finance Energen Resources’ investment program, the Company expects primarily to utilize its short-term credit facilities to supplement internally generated cash flow. The Company may also periodically issue long-term debt and equity to replace short-term obligations, enhance liquidity and provide for permanent financing. Energen currently has available short-term credit facilities aggregating $320 million to help finance its growth plans and operating needs. Energen Resources’ continued ability to invest in property acquisitions is subject to market conditions and industry trends.

Energen Resources has experienced various market driven conditions generally caused by the increased commodity price environment including, but not limited to, higher workover and maintenance expenses, increased taxes 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.

For the 2005-2006 winter heating season, Alagasco has hedged or intends to use storage for its estimated, weather-normalized, core-market gas supply purchases. The Company’s efforts to minimize commodity price volatility through hedging is reflected in Alagasco’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. Sustained high prices may decrease Alagasco’s customer base and could result in a decline of per customer use and number of customers. The utility 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. In December 2005, the APSC requested Alagasco and the other major natural gas utility under its jurisdiction to refrain from additional rate increases through the winter heating season ending March 31, 2006, citing concerns over the potential negative impact on customers from the high natural gas prices being experienced across the country following hurricanes Katrina and Rita. Alagasco agreed to comply with the APSC’s request and subsequently reduced rates in response to moderating gas prices.

Alagasco maintains an investment in storage gas that is expected to average approximately $67 million in 2006 but may vary depending upon the price of natural gas. During 2006 and 2007, Alagasco plans to invest approximately $62 million and $65 million, respectively, in utility capital expenditures for normal distribution and support systems. Over the Company’s five-year planning period ending December 31, 2010, Alagasco anticipates capital investments of approximately $322 million. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. In January 2005, Alagasco issued $80 million in long-term debt to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance $30 million of Medium-Term Notes recalled by Alagasco in April 2004. In November 2005, Alagasco issued an additional $80 million of long-term debt largely to refinance $18 million of Medium-Term Notes maturing June 27, 2007 to July 5, 2022 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 recalled by Alagasco in August 2005 and December 2005, respectively.

Access to capital is an integral part of the Company’s business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets,

continued access could be adversely affected by future economic and business conditions or credit rating downgrades. Energen and Alagasco’s corporate credit ratings are currently rated BBB+ with a stable outlook by Standard & Poor’s. Moody’s Investors Service has currently rated Energen as Baa 2 senior unsecured and Alagasco as A1 senior unsecured.

Dividends

Energen expects to pay annual cash dividends of $0.44 per share on the Company’s common stock in 2006. 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.

On April 27, 2005, Energen’s shareholders approved a 2-for-1 split of the Company’s common stock. The split was effected in the form of a 100 percent stock dividend and was effective on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split.

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, 2005.


	Payments Due before December 31,
*(in thousands)*	Total		2006		2007-2008		2009-2010		2011 and Thereafter
Short-term debt	$	153,000	$	153,000	$	—	$	—	$	—
Long-term debt ⁽¹⁾		699,654		15,000		110,000		150,000		424,654
Interest payments on debt ⁽²⁾		545,177		44,897		81,352		76,178		342,750
Purchase obligations ⁽³⁾		243,049		48,066		95,542		70,224		29,217
Capital lease obligations		—		—		—		—		—
Operating leases		49,685		3,839		6,817		6,313		32,716

Total contractual cash obligations	$	1,690,565	$	264,802	$	293,711	$	302,715	$	829,337

(1)	Long-term cash obligations include $1.4 million of unamortized debt discounts as of December 31, 2005.

(2)	Includes interest on fixed rate debt and an estimate of adjustable rate debt. The adjustable rate interest is calculated based on the indexed rate in effect at December 31, 2005.

(3)

Certain of the Company’s long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of $243 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 166.1 Bcf through April 2015.

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 post-retirement healthcare and life insurance benefits. The Company is not required to make any funding payments during 2006 for the pension plans and does not currently plan to make discretionary contributions. The Company may reevaluate discretionary payments to its pension plans in the fourth quarter of 2006 based on the outcome of the September 30, 2006, measurement of pension obligations. Additionally, the Company expects to make discretionary payments of $1.4 million to post-retirement benefit program assets during 2006.

OUTLOOK

Oil and Gas Operations: Energen Resources plans to continue to implement its growth strategy with capital spending in 2006 and 2007 as outlined above. Production in 2006 is estimated to reach approximately 92 Bcfe, including 91 Bcfe of estimated production from proved reserves owned at December 31, 2005. In 2007, production is estimated to be approximately 89 Bcfe, including approximately 88 Bcfe produced from proved reserves currently owned. Production estimates above do not include amounts for potential future acquisitions.

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

Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil 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 and gas purchasers account for approximately 29 percent, 19 percent and 14 percent, respectively, of Energen Resources’ estimated 2006 production. Energen Resources’ other purchasers each bought less than 8 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 regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company. In cases where 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. At December 31, 2005, Energen Resources was in a net loss position with all counterparties but was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of December 31, 2005. The two largest counterparties represented approximately 48 percent and 22 percent of Energen Resources’ fair value of derivatives. The Company believes the creditworthiness of these counterparties is satisfactory. Energen Resources’ other counterparties each represented less than 14 percent of the fair value of derivatives. 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.

Energen Resources entered into the following transactions for 2006 and subsequent years:


Production Period	Total Hedged Volumes	Average Contract Price		Description
Natural Gas
2006	16.3 Bcf	$	8.08 Mcf	NYMEX Swaps
	21.9 Bcf	$	6.48 Mcf	Basin Specific Swaps
2007	3.0 Bcf	$	9.72 Mcf	Basin Specific Swaps
	*9.0 Bcf	$	7.46 Mcf	Basin Specific Swaps
	*5.0 Bcf	$	9.34 Mcf	NYMEX Swaps

Oil
2006	2,844 MBbl	$	52.88 Bbl	NYMEX Swaps
2007	600 MBbl	$	59.65 Bbl	NYMEX Swaps
	*600 MBbl	$	67.05 Bbl	NYMEX Swaps
2008	900 MBbl	$	57.71 Bbl	NYMEX Swaps
2009	900 MBbl	$	56.25 Bbl	NYMEX Swaps

Oil Basis Differential
2006	1,915 MBbl		**	Basis Swaps
2007	*600 MBbl		**	Basis Swaps

Natural Gas Liquids
2006	30.2 MMGal	$	0.56 Gal	Liquids Swaps
2007	*10.1 MMGal	$	0.80 Gal	Liquids Swaps

*	Contracts entered into subsequent to December 31, 2005

**	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, 2005, the Company estimated that a 10 percent increase or decrease in the commodities prices would have resulted in a $73.2 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.

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

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, 2005, Alagasco recorded a $6.3 million loss as a liability in accounts payable with a corresponding current regulatory asset of $6.3 million representing the fair value of derivatives. The gains or losses related to these derivative contracts, as adjusted for any changes in the fair value, will be recognized in the GSA during the first quarter of 2006.

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 acquisition, 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.

Third Party Facilities: The forward looking statements also assume generally uninterrupted access to 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/or the Company.

Energen Resources Hedging: Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas 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 and fixed price contracts. A substantial failure to meet sales volume targets whether caused by miscalculations, weather events, natural disaster, accident, 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 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.

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment (SFAS No. 123R),” which requires a fair value base method of accounting using pricing models that reflect the specific economics of a company’s transactions. This statement is effective for the first annual reporting period beginning after June 15, 2005. The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 as amended, which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation effective January 1, 2003. The Company will adopt SFAS No. 123R using the modified prospective application method for new awards effective January 1, 2006. Although, the Company is currently evaluating its stock-based compensation and the application of SFAS No. 123R, it does not anticipate that the adoption of SFAS No. 123R will have a material impact on the financial condition or results of operations of the Company. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards will be made in the form of Company common stock with no portion of an award paid in cash. Accordingly, the Company will value such awards at fair value under the provisions of SFAS No. 123R as of the date of modification or grant.

During April 2005, the FASB issued FSP No. 19-1, “Accounting for Suspended Well Costs,” which allows exploratory wells to be capitalized when the well has a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. This interpretation was effective for the first reporting period beginning after April 4, 2005. The Company has adopted this standard and has no exploratory wells with capitalized costs that exceed more than one year.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 (Accounting Changes) and FASB Statement No. 3 (Reporting Accounting Changes in Interim Financial Statements)”. Opinion No. 20 required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

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.

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	34

	Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003	36

	Consolidated Balance Sheets as of December 31, 2005 and 2004	37

	Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2005, 2004 and 2003	39

	Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	40

	Notes to Financial Statements	46

	Alabama Gas Corporation

	Report of Independent Registered Public Accounting Firm	35

	Statements of Income for the years ended December 31, 2005, 2004 and 2003	41

	Balance Sheets as of December 31, 2005 and 2004	42

	Statements of Shareholder’s Equity for the years ended December 31, 2005, 2004 and 2003	44

	Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	45

	Notes to Financial Statements	46

2.	Financial Statement Schedules

	Energen Corporation Schedule II - Valuation and Qualifying Accounts	80

	Alabama Gas Corporation Schedule II - Valuation and Qualifying Accounts	80

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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energen Corporation:

We have completed an integrated audit of Energen Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides 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.

PricewaterhouseCoopers LLP

Birmingham, Alabama

March 15, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

In our opinion, the financial statements of Alabama Gas Corporation listed in the accompanying index present fairly, in all material respects, the financial position of Alabama Gas Corporation at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Birmingham, Alabama

March 15, 2006

CONSOLIDATED STATEMENTS OF INCOME

Energen Corporation


*Years ended December 31, (in thousands, except share data)*	2005			2004			2003
Operating Revenues
Oil and gas operations	$	527,694		$	410,117		$	352,532
Natural gas distribution		600,700			526,740			489,099

Total operating revenues		1,128,394			936,857			841,631

Operating Expenses
Cost of gas		315,622			259,889			233,823
Operations and maintenance		268,727			234,150			208,132
Depreciation, depletion and amortization		131,691			120,777			116,666
Taxes, other than income taxes		93,983			74,933			63,498
Accretion expense		2,647			2,265			1,890

Total operating expenses		812,670			692,014			624,009

Operating Income		315,724			244,843			217,622

Other Income (Expense)
Interest expense		(46,800	)		(42,743	)		(42,262	)
Other income		2,163			2,945			8,744
Other expense		(710	)		(2,215	)		(9,977	)

Total other expense		(45,347	)		(42,013	)		(43,495	)

Income From Continuing Operations Before Income Taxes		270,377			202,830			174,127
Income tax expense		97,491			75,525			64,023

Income From Continuing Operations		172,886			127,305			110,104

Discontinued Operations, Net of Taxes
Income (loss) from discontinued operations		(6	)		163			1,134
Gain (loss) on disposal of discontinued operations		132			(5	)		(584	)

Income From Discontinued Operations		126			158			550

Net Income	$	173,012		$	127,463		$	110,654

Diluted Earnings Per Average Common Share*
Continuing operations	$	2.35		$	1.74		$	1.54
Discontinued operations		—			—			0.01

Net Income	$	2.35		$	1.74		$	1.55

Basic Earnings Per Average Common Share*
Continuing operations	$	2.37		$	1.75		$	1.55
Discontinued operations		—			0.01			0.01

Net Income	$	2.37		$	1.76		$	1.56

Diluted Average Common Shares Outstanding*		73,714,602			73,117,253			71,433,752

Basic Average Common Shares Outstanding*		73,051,903			72,546,512			70,868,972

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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

CONSOLIDATED BALANCE SHEETS

Energen Corporation


*(in thousands)*	December 31, 2005		December 31, 2004
ASSETS

Current Assets
Cash and cash equivalents	$	8,714	$	4,489
Accounts receivable, net of allowance for doubtful accounts of $11,573 and $10,472 at December 31, 2005 and 2004, respectively		285,765		217,360
Inventories, at average cost
Storage gas inventory		71,179		51,093
Materials and supplies		7,926		7,843
Liquified natural gas in storage		3,795		3,688
Regulatory asset		6,633		—
Deferred income taxes		72,113		36,285
Prepayments and other		22,366		29,150

Total current assets		478,491		349,908

Property, Plant and Equipment
Oil and gas properties, successful efforts method		1,930,291		1,591,119
Less accumulated depreciation, depletion and amortization		466,643		381,734

Oil and gas properties, net		1,463,648		1,209,385

Utility plant		999,011		941,862
Less accumulated depreciation		401,232		373,589

Utility plant, net		597,779		568,273

Other property, net		6,584		5,401

Total property, plant and equipment, net		2,068,011		1,783,059

Other Assets
Regulatory asset		33,436		19,650
Deferred charges and other		38,288		29,122

Total other assets		71,724		48,772

TOTAL ASSETS	$	2,618,226	$	2,181,739

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

CONSOLIDATED BALANCE SHEETS

Energen Corporation


*(in thousands, except share data)*	December 31, 2005			December 31, 2004
LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities
Long-term debt due within one year	$	15,000		$	10,000
Notes payable to banks		153,000			135,000
Accounts payable		306,618			159,871
Accrued taxes		44,324			34,541
Customers’ deposits		20,767			19,549
Amounts due customers		6,181			10,363
Accrued wages and benefits		33,634			31,610
Regulatory liability		53,496			47,060
Other		55,289			50,624

Total current liabilities		688,309			498,618

Long-term debt		683,236			612,891

Deferred Credits and Other Liabilities
Asset retirement obligation		50,270			34,841
Accrued benefit liability		15,739			14,216
Regulatory liability		119,808			111,928
Deferred income taxes		148,040			95,417
Other		20,146			10,162

Total deferred credits and other liabilities		354,003			266,564

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, 73,493,337 shares outstanding at December 31, 2005, and 73,165,958 shares outstanding at December 31, 2004		735			732
Premium on capital stock		394,861			380,965
Capital surplus		2,802			2,802
Retained earnings		603,314			459,626
Accumulated other comprehensive loss, net of tax
Unrealized loss on hedges		(92,112	)		(25,466	)
Minimum pension liability		(13,707	)		(11,864	)
Deferred compensation on restricted stock		(2,123	)		(2,675	)
Deferred compensation plan		11,907			28,919
Treasury stock, at cost*; 1,066,935 shares and 1,000,952 shares at December 31, 2005 and 2004, respectively		(12,999	)		(29,373	)

Total shareholders’ equity		892,678			803,666

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	2,618,226		$	2,181,739

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

Energen Corporation


	Common Stock										Accumulated Other Comprehensive Income (Loss)
*(in thousands, except share data)*	Number of Shares	Par Value		Premium on Capital Stock		Capital Surplus		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Deferred Compensation Restricted Stock			Deferred Compensation Plan			Treasury Stock			Total Shareholders’ Equity
BALANCE DECEMBER 31, 2002	69,490,954	$	695	$	320,078	$	2,802	$	274,900		$	(14,811	)	$	(770	)	$	10,348		$	(10,432	)	$	582,810
Net income									110,654															110,654
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($29,019)												(45,388	)											(45,388	)
Reclassification adjustment, net of tax of $21,830												34,145												34,145
Minimum pension liability, net of tax of ($2,445)												(4,541	)											(4,541	)

Comprehensive income																								94,870

Purchase of treasury shares																					(1,046	)		(1,046	)
Shares issued for:
Stock offerings	2,000,000		20		32,111																			32,131
Dividend reinvestment plan	107,980		1		1,865																491			2,357
Employee benefit plans	848,128		8		12,029																594			12,631
Deferred compensation obligation																		6,715			(6,715	)		—
Issuance of restricted stock															(1,564	)								(1,564	)
Amortization of restricted stock															1,076									1,076
Stock based compensation					270																			270
Tax benefit from employee stock plans					1,416																			1,416
Cash dividends - $0.365 per share									(25,919	)														(25,919	)

BALANCE DECEMBER 31, 2003	72,447,062		724		367,769		2,802		359,635			(30,595	)		(1,258	)		17,063			(17,108	)		699,032
Net income									127,463															127,463
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($34,012)												(56,430	)											(56,430	)
Reclassification adjustment, net of tax of $32,286												52,678												52,678
Minimum pension liability, net of tax of ($1,608)												(2,983	)											(2,983	)

Comprehensive income																								120,728

Purchase of treasury shares																					(836	)		(836	)
Shares issued for:
Dividend reinvestment plan	2,550		—		53																—			53
Employee benefit plans	716,346		8		9,112																427			9,547
Deferred compensation obligation																		11,856			(11,856	)		—
Issuance of restricted stock															(2,807	)								(2,807	)
Amortization of restricted stock															1,390									1,390
Stock based compensation					465																			465
Tax benefit from employee stock plans					1,275																			1,275
Long-range performance plan					2,291																			2,291
Cash dividends - $0.3775 per share									(27,472	)														(27,472	)

BALANCE DECEMBER 31, 2004	73,165,958		732		380,965		2,802		459,626			(37,330	)		(2,675	)		28,919			(29,373	)		803,666
Net income									173,012															173,012
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($100,484)												(163,947	)											(163,947	)
Reclassification adjustment, net of tax of $59,636												97,301												97,301
Minimum pension liability, net of tax of ($990)												(1,843	)											(1,843	)

Comprehensive income																								104,523

Purchase of treasury shares																					(2,459	)		(2,459	)
Shares issued for:
Employee benefit plans	327,379		3		8,958																1,821			10,782
Deferred compensation obligation																		(17,012	)		17,012			—
Issuance of restricted stock															(1,249	)								(1,249	)
Amortization of restricted stock															1,801									1,801
Stock based compensation					465																			465
Tax benefit from employee stock plans					2,487																			2,487
Long-range performance plan					1,986																			1,986
Cash dividends - $0.40 per share									(29,324	)														(29,324	)

BALANCE DECEMBER 31, 2005	73,493,337	$	735	$	394,861	$	2,802	$	603,314		$	(105,819	)	$	(2,123	)	$	11,907		$	(12,999	)	$	892,678

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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

CONSOLIDATED STATEMENTS OF CASH FLOWS

Energen Corporation


*Years ended December 31, (in thousands)*	2005			2004			2003
Operating Activities
Net income	$	173,012		$	127,463		$	110,654
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		131,719			120,960			117,785
Deferred income taxes		58,608			67,423			54,632
Deferred investment tax credits		—			(308	)		(448	)
Change in derivative fair value		2,328			212			735
Gain on sale of assets		(1,928	)		(135	)		(9,987	)
Loss on properties held for sale		—			—			10,404
Other, net		(5,912	)		(11,908	)		(11,084	)
Net change in:
Accounts receivable, net		(70,944	)		(39,645	)		(24,811	)
Inventories		(20,276	)		(10,818	)		(16,132	)
Accounts payable		39,330			19,536			12,860
Amounts due customers		12,890			(1,166	)		4,052
Other current assets and liabilities		16,297			19,518			(5,533	)

Net cash provided by operating activities		335,124			291,132			243,127

Investing Activities
Additions to property, plant and equipment		(230,715	)		(177,705	)		(179,107	)
Acquisitions, net of cash acquired		(179,268	)		(274,400	)		(40,486	)
Proceeds from sale of assets		10,832			461			29,149
Other, net		(1,573	)		(1,770	)		30

Net cash used in investing activities		(400,724	)		(453,414	)		(190,414	)

Financing Activities
Payment of dividends on common stock		(29,324	)		(27,472	)		(25,919	)
Issuance of common stock		10,782			9,600			47,119
Purchase of treasury stock		(2,459	)		(836	)		(1,046	)
Reduction of long-term debt		(84,796	)		(40,083	)		(23,000	)
Proceeds from issuance of long-term debt		160,000			100,000			49,778
Debt issuance costs		(2,378	)		(565	)		(322	)
Net change in short-term debt		18,000			124,000			(102,000	)

Net cash provided by (used in) financing activities		69,825			164,644			(55,390	)

Net change in cash and cash equivalents		4,225			2,362			(2,677	)
Cash and cash equivalents at beginning of period		4,489			2,127			4,804

Cash and cash equivalents at end of period	$	8,714		$	4,489		$	2,127

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

STATEMENTS OF INCOME

Alabama Gas Corporation


*Years ended December 31, (in thousands)*	2005			2004			2003
Operating Revenues	$	600,700		$	526,740		$	489,099

Operating Expenses
Cost of gas		318,269			261,800			236,037
Operations and maintenance		126,041			121,896			114,078
Depreciation		42,351			39,881			37,171
Income taxes
Current		20,556			9,690			6,577
Deferred		1,804			10,321			13,546
Deferred investment tax credits		—			(308	)		(448	)
Taxes, other than income taxes		41,117			36,964			34,965

Total operating expenses		550,138			480,244			441,926

Operating Income		50,562			46,496			47,173

Other Income (Expense)
Allowance for funds used during construction		792			1,247			948
Other income		1,371			1,979			4,132
Other expense		(701	)		(2,195	)		(5,269	)

Total other income (expense)		1,462			1,031			(189	)

Interest Charges
Interest on long-term debt		13,752			10,672			12,815
Other interest charges		1,308			3,065			1,152

Total interest charges		15,060			13,737			13,967

Net Income	$	36,964		$	33,790		$	33,017

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

BALANCE SHEETS

Alabama Gas Corporation


*(in thousands)*	December 31, 2005			December 31, 2004
ASSETS
Property, Plant and Equipment
Utility plant	$	999,011		$	941,862
Less accumulated depreciation		401,232			373,589

Utility plant, net		597,779			568,273

Other property, net		169			325

Current Assets
Cash		7,169			3,467
Accounts receivable
Gas		194,447			142,736
Other		7,524			11,952
Affiliated companies		3,215			2,190
Allowance for doubtful accounts		(10,800	)		(9,600	)
Inventories, at average cost
Storage gas inventory		71,179			51,093
Materials and supplies		4,144			4,281
Liquified natural gas in storage		3,795			3,688
Regulatory asset		6,633			—
Deferred income taxes		13,284			15,233
Prepayments and other		11,203			21,901

Total current assets		311,793			246,941

Other Assets
Regulatory asset		33,436			19,650
Deferred charges and other		6,857			4,558

Total other assets		40,293			24,208

TOTAL ASSETS	$	950,034		$	839,747

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

BALANCE SHEETS

Alabama Gas Corporation


*(in thousands, except share data)*	December 31, 2005		December 31, 2004
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 outstanding at December 31, 2005 and 2004, respectively		20		20
Premium on capital stock		31,682		31,682
Capital surplus		2,802		2,802
Retained earnings		236,957		223,515

Total common shareholder’s equity		271,461		258,019
Long-term debt		209,654		129,450

Total capitalization		481,115		387,469

Current Liabilities
Long-term debt due within one year		5,000		10,000
Notes payable to banks		55,000		82,000
Accounts payable		112,443		81,591
Accrued taxes		32,770		27,410
Customers’ deposits		20,767		19,549
Amounts due customers		6,181		10,363
Accrued wages and benefits		11,449		10,393
Regulatory liability		53,496		47,060
Other		8,694		9,237

Total current liabilities		305,800		297,603

Deferred Credits and Other Liabilities
Deferred income taxes		39,949		40,070
Regulatory liability		119,808		111,928
Customer advances for construction and other		3,362		2,677

Total deferred credits and other liabilities		163,119		154,675

Commitments and Contingencies

TOTAL LIABILITIES AND CAPITALIZATION	$	950,034	$	839,747

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

STATEMENTS OF SHAREHOLDER’S EQUITY

Alabama Gas Corporation


	Common Stock										Total Shareholder’s Equity
*(in thousands, except share data)*	Number of Shares	Par Value		Premium on Capital Stock		Capital Surplus		Retained Earnings			Total Shareholder’s Equity
Balance December 31, 2002	1,972,052	$	20	$	31,682	$	2,802	$	182,852		$	217,356
Net income									33,017			33,017

Balance December 31, 2003	1,972,052		20		31,682		2,802		215,869			250,373
Net income									33,790			33,790
Cash dividends									(26,144	)		(26,144	)

Balance December 31, 2004	1,972,052		20		31,682		2,802		223,515			258,019
Net income									36,964			36,964
Cash dividends									(23,522	)		(23,522	)

Balance December 31, 2005	1,972,052	$	20	$	31,682	$	2,802	$	236,957		$	271,461

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

STATEMENTS OF CASH FLOWS

Alabama Gas Corporation


*Years ended December 31, (in thousands)*	2005			2004			2003
Operating Activities
Net income	$	36,964		$	33,790		$	33,017
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		42,351			39,881			37,171
Deferred income taxes		1,804			10,321			13,546
Deferred investment tax credits		—			(308	)		(448	)
Other, net		(3,025	)		(8,968	)		(13,774	)
Net change in:
Accounts receivable, net		(48,623	)		(12,784	)		(15,923	)
Inventories		(20,056	)		(9,406	)		(17,268	)
Accounts payable		24,560			25,823			49
Amounts due customers		12,890			(1,166	)		4,052
Other current assets and liabilities		9,371			8,128			(4,140	)

Net cash provided by operating activities		56,236			85,311			36,282

Investing Activities
Additions to property, plant and equipment		(72,388	)		(56,922	)		(56,255	)
Net advances to parent company		(1,025	)		(39,480	)		35,858
Other, net		(1,551	)		(1,655	)		(263	)

Net cash used in investing activities		(74,964	)		(98,057	)		(20,660	)

Financing Activities
Payment of dividends on common stock		(23,522	)		(26,144	)		—
Reduction of long-term debt		(84,796	)		(30,083	)		(15,000	)
Proceeds from issuance of long-term debt		160,000			—			—
Debt issuance costs		(2,252	)		—			—
Net change in short-term debt		(27,000	)		71,000			(2,000	)

Net cash provided (used) by financing activities		22,430			14,773			(17,000	)

Net change in cash and cash equivalents		3,702			2,027			(1,378	)
Cash and cash equivalents at beginning of period		3,467			1,440			2,818

Cash and cash equivalents at end of period	$	7,169		$	3,467		$	1,440

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

NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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. Gains and losses in the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for current and prior periods.

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, 2005 and 2004.

Derivative Commodity Instruments: 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 regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company. In cases where 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.

Energen Resources applies Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended which requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the 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.

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

All hedge transactions are 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. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2009.

C.	*Natural Gas Distribution*

Utility Plant and Depreciation: Property, plant and equipment is stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets is charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided on the straight-line method over the estimated useful lives of utility property at rates established by the Alabama Public Service Commission (APSC). Approved depreciation rates averaged approximately 4.5 percent in the years ended December 31, 2005, 2004 and 2003.

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 no material gas imbalances at December 31, 2005 and 2004.

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 from time to time enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability as required by SFAS No. 71.

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)*	2005		2004		2003
Taxes on revenues	$	30,899	$	27,002	$	25,218

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 reviews the allowance for doubtful accounts monthly. Account balances are charged off 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*

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).

H.	*Stock-Based Compensation*

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


*Years ended December 31, (in thousands)*	2005			2004			2003
Net income
As reported	$	173,012		$	127,463		$	110,654
Stock based compensation expense included in reported net income, net of tax		8,131			7,219			4,553
Stock based compensation expense determined under the fair value based method, net of tax		(6,238	)		(5,658	)		(3,904	)

Pro forma	$	174,905		$	129,024		$	111,303

Diluted earnings per average common share*
As reported	$	2.35		$	1.74		$	1.55
Pro forma	$	2.37		$	1.76		$	1.56

Basic earnings per average common share*
As reported	$	2.37		$	1.76		$	1.56
Pro forma	$	2.39		$	1.78		$	1.57

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

The Company used the Black-Scholes pricing model to calculate the fair values of the options awarded, which are included in the pro forma results above. Option awards are granted with an exercise price equal to the market price of the Company’s stock on the date of grant. For purposes of this valuation the following assumptions were used to derive the fair values: a seven-year option life based on historical experience; an annualized volatility rate, based on historical volatility, of 32.72 percent and 34.67 percent for the years ended December 31, 2004 and 2003, respectively; a risk-free interest rate of 3.64 percent and 2.36 percent for the years ended December 31, 2004 and 2003, respectively; and a dividend yield of 1.81 percent on options without dividend equivalents for the year ended December 31, 2004. Options with dividend equivalents assume no dividend yield for all periods presented. The weighted-average grant-date fair value for options granted without dividend equivalents during the year ended December 31, 2004 was $7.11. The weighted-average grant-date fair value for options granted with dividend equivalents during the year ended December 31, 2003 was $6.05. There were no options granted in the year ended December 31, 2005.

The 1997 Stock Incentive Plan provides for the grant of restricted stock and performance share awards. The Company values restricted stock grants based on the stock price at the date of grant. As of December 31, 2005, the performance share awards could be paid in cash or a combination of Company common stock or cash. The Company valued the performance awards to be paid in common stock based on the common stock price at the date of grant and the expected payout ratio at the end of each reporting period. The Company valued the performance awards to be paid in cash based on the Company’s period-end stock price and the expected payout ratio at the end of each reporting period. Upon adoption of SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), the Company will continue to value the restricted stock grants based on the stock price at the date of grant. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards will be made in the form of Company common stock with no portion of an award paid in cash. Accordingly, the Company will value such awards at fair value under the provisions of SFAS No. 123R as of the date of modification or grant.

The Company recognized all stock-based employee compensation expense over the stated vesting periods for each award. In the event of an employee’s retirement, the Company accelerated the recognition of expense for all eligible unvested awards. Upon the adoption of SFAS No. 123R, effective January 1, 2006, the Company will recognize the entire compensation expense for awards to retirement eligible employees in the period of grant. If this method of expense recognition had been applied during 2003 and 2004, the Company would have recognized approximately an additional $1.4 million and $1.2 million, respectively, of compensation expense related to the timing of recognition for retirement eligible employees. During 2005, compensation expense would have been reduced by approximately $0.8 million related to this timing of recognition for retirement eligible employees.

In the periods presented, the Company recognized forfeitures in the reporting period in which the forfeiture occurred. Upon the adoption of SFAS No. 123R, the Company will estimate forfeitures based on its historical experience. The forfeiture estimates will be updated periodically based on actual experience.

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 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

All of Alagasco’s utility operations are conducted in the state of Alabama. Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended with modifications in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended Alagasco’s rate-setting methodology, RSE, without change, for a six-year period through January 1, 2008. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operations. Alagasco 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, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the equity returns of all major energy utilities operating under a similar methodology. Under RSE 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, 2005 and 2003, Alagasco had a $3.3 million and a $3 million, respectively, reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. Alagasco did not have a reduction in rates related to the return on average equity for rate year ended 2004. A $15.8 million, $12.3 million and $11.2 million annual increase in revenues became effective December 1, 2005, 2004, and 2003, respectively. RSE limits the utility’s equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco’s operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. The increase in O&M expense per customer was above the index range for the rate years ended September 30, 2004 and 2003; as a result, the utility returned to customers $1.2 million pre-tax and $0.1 million pre-tax, respectively, through rate adjustments under the provisions of RSE. Alagasco’s O&M expense fell within the index range for the rate year ended September 30, 2005.

Alagasco calculates a temperature adjustment to customers’ monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco’s earnings. Adjustments to customers’ bills are made in the same billing cycle in which the weather variation occurs. The temperature adjustment applies primarily to residential,

small commercial and small industrial customers. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers’ bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply.

The APSC approved an Enhanced Stability Reserve (ESR), beginning 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. During the year ended December 31, 2004, Alagasco charged $0.3 million against the ESR related to extraordinary maintenance cost resulting from certain weather events within Alagasco’s service territory. 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. ESR balances of $3.7 million at December 31, 2005 and 2004, are included in the consolidated financial statements.

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, 2005 and 2004, the net acquisition adjustments were $10.4 million and $11.5 million, respectively.

3. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:


*(in thousands)*	December 31, 2005		December 31, 2004
Energen Corporation:
Medium-term Notes, interest ranging from 6.95% to 8.09%, for notes redeemable September 25, 2006, to February 15, 2028	$	335,000	$	335,000
5% Notes, redeemable October 1, 2013		50,000		50,000
Floating Rate Senior Notes (4.69% at December 31, 2005), redeemable November 15, 2007		100,000		100,000
Alabama Gas Corporation:
Medium-term Notes, interest ranging from 7.34% to 7.97%, for notes redeemable September 20, 2006, to September 23, 2026		20,000		65,000
6.25% Notes, redeemable September 1, 2016		—		39,725
6.75% Notes, redeemable September 1, 2031		34,725		34,725
5.20% Notes, redeemable January 15, 2020		40,000		—
5.70% Notes, redeemable January 15, 2035		39,929		—
5.368% Notes, redeemable December 1, 2015		80,000		—

Total		699,654		624,450
Less amounts due within one year		15,000		10,000
Less unamortized debt discount		1,418		1,559

Total	$	683,236	$	612,891

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


Years ending December 31, *(in thousands)*
2006	2007		2008		2009	2010
$ 15,000	$	100,000	$	10,000	—	$	150,000

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


Years ending December 31, *(in thousands)*
2006	2007	2008	2009	2010
$ 5,000	—	—	—	—

At December 31, 2005, the Company was not subject to restrictions on the payment of dividends. The Company is in compliance with the 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. Payments with respect to Alagasco’s 6.25 percent Notes and 6.75 percent Notes are insured by Ambac Assurance Corporation. Under the insurance agreement, Alagasco cannot dispose of distribution plant assets if, after such disposition, its distribution plant will be less than $200 million. Alagasco’s distribution plant exceeded $200 million at December 31, 2005. In addition, $300 million of 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.

Energen and Alagasco had short-term credit lines and other credit facilities with various financial institutions totaling $320 million and $275 million, respectively, available as of December 31, 2005, for working capital needs. Alagasco has been authorized to borrow a maximum of $200 million of its available credit lines at any one time by the APSC. The Company is in compliance with the covenants under the various short-term loan agreements and except as discussed below, debt covenants address routine matters. One of the Company’s credit facilities in the amount of $45 million includes a covenant that the ratio of consolidated debt to consolidated capitalization will not exceed 0.65:1. As of December 31, 2005, the Company was in compliance with this requirement. The following is a summary of information relating to notes payable to banks:


*(in thousands)*	December 31, 2005			December 31, 2004
Energen outstanding	$	98,000		$	53,000
Alagasco outstanding		55,000			82,000

Notes payable to banks		153,000			135,000
Available for borrowings		167,000			152,000

Total	$	320,000		$	287,000

Energen maximum amount outstanding at any month-end	$	153,000		$	220,000
Energen average daily amount outstanding	$	17,688		$	92,622
Energen weighted average interest rates based on:
Average daily amount outstanding		3.57	%		2.29	%
Amount outstanding at year-end		4.81	%		2.85	%

Alagasco maximum amount outstanding at any month-end	$	55,000		$	82,000
Alagasco average daily amount outstanding	$	4,833		$	26,301
Alagasco weighted average interest rates based on:
Average daily amount outstanding		3.63	%		2.29	%
Amount outstanding at year-end		4.78	%		2.83	%

Energen’s total interest expense was $46,800,000, $42,743,000 and $42,262,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Total interest expense for Alagasco was $15,060,000, $13,737,000 and $13,967,000 for the years ended December 31, 2005, 2004 and 2003, respectively.

4. INCOME TAXES

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


*Years ended December 31, (in thousands)*	2005		2004		2003
Taxes estimated to be payable currently:
Federal	$	29,765	$	7,261	$	8,811
State		6,078		1,149		1,282

Total current		35,843		8,410		10,093

Taxes deferred:
Federal		59,685		58,956		47,805
State		1,963		8,159		6,125

Total deferred		61,648		67,115		53,930

Total income tax expense from continuing operations	$	97,491	$	75,525	$	64,023

For the year ended December 31, 2005, Energen recorded a current income tax expense of $3,117,000 and a deferred tax benefit of $3,040,000 related to income from discontinued operations. For the year ended December 31, 2004, Energen recorded a current income tax expense of $96,000 related to income from discontinued operations. For the year ended December 31, 2003, Energen recorded a current income tax expense of $100,000 and a deferred income tax expense of $254,000 related to income from discontinued operations.

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


*Years ended December 31, (in thousands)*	2005		2004		2003
Taxes estimated to be payable currently:
Federal	$	18,430	$	8,581	$	5,827
State		2,126		1,109		750

Total current		20,556		9,690		6,577

Taxes deferred:
Federal		1,597		8,834		11,549
State		207		1,179		1,549

Total deferred		1,804		10,013		13,098

Total income tax expense	$	22,360	$	19,703	$	19,675

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

Energen Corporation


*(in thousands)*	December 31, 2005						December 31, 2004
*(in thousands)*	Current			Noncurrent			Current		Noncurrent
Deferred tax assets:
Minimum tax credit	$	—		$	34,786		$	—	$	56,688
Pension and other costs		—			8,693			—		7,883
Unbilled and deferred revenue		10,263			—			10,017		—
Enhanced stability reserve and other regulatory costs		1,393			—			1,888		—
Allowance for doubtful accounts		4,304			—			3,880		—
Insurance accruals		3,552			—			2,102		—
Compensation accruals		6,704			—			6,408		—
Inventories		865			—			775		—
Other comprehensive income		51,920			11,916			14,377		7,621
Other, net		2,665			2,626			2,769		592

Total deferred tax assets		81,666			58,021			42,216		72,784
Valuation allowance		(1,596	)		(452	)		—		—

Total deferred tax assets		80,070			57,569			42,216		72,784

Deferred tax liabilities:
Depreciation and basis differences		—			196,916			—		160,318
Pension and other costs		7,164			—			5,909		—
Minimum pension liability		—			8,693			—		7,883
Other, net		793			—			22		—

Total deferred tax liabilities		7,957			205,609			5,931		168,201

Net deferred tax assets (liabilities)	$	72,113		$	(148,040	)	$	36,285	$	(95,417	)

Alabama Gas Corporation


	December 31, 2005					December 31, 2004
*(in thousands)*	Current		Noncurrent			Current		Noncurrent
Deferred tax assets:
Pension and other costs	$	—	$	8,693		$	—	$	7,883
Unbilled and deferred revenue		10,263		—			10,017		—
Enhanced stability reserve and other regulatory costs		1,393		—			1,888		—
Allowance for doubtful accounts		4,083		—			3,630		—
Insurance accruals		2,305		—			2,672		—
Compensation accruals		3,303		—			3,779		—
Inventories		865		—			775		—
Other, net		1,812		534			1,462		527

Total deferred tax assets		24,024		9,227			24,223		8,410

Deferred tax liabilities:
Depreciation and basis differences		—		40,483			—		40,597
Pension and other costs		10,042		—			8,970		—
Minimum pension liability		—		8,693			—		7,883
Other, net		698		—			20		—

Total deferred tax liabilities		10,740		49,176			8,990		48,480

Net deferred tax assets (liabilities)	$	13,284	$	(39,949	)	$	15,233	$	(40,070	)

The Company files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2005, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $34.8 million. The Company has a full valuation allowance recorded against a deferred tax asset of $2,048,000 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.

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)*	2005			2004			2003
Income tax expense from continuing operations at statutory federal income tax rate	$	94,632		$	70,991		$	60,944
Increase (decrease) resulting from:
Enhanced oil recovery tax credits		(503	)		(456	)		(469	)
Deferred investment tax credits		—			(308	)		(448	)
State income taxes, net of federal income tax benefit		5,197			6,004			5,097
Qualified Section 199 production activities deduction		(1,060	)		—			—
Other, net		(775	)		(706	)		(1,101	)

Total income tax expense from continuing operations	$	97,491		$	75,525		$	64,023

Effective income tax rate (%)		36.06			37.24			36.77

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)*	2005			2004			2003
Income tax expense at statutory federal income tax rate	$	20,763		$	18,723		$	18,442
Increase (decrease) resulting from:
Deferred investment tax credits		—			(308	)		(448	)
State income taxes, net of federal income tax benefit		1,673			1,504			1,480
Other, net		(76	)		(216	)		201

Total income tax expense	$	22,360		$	19,703		$	19,675

Effective income tax rate (%)		37.69			36.83			37.34

5. EMPLOYEE BENEFIT PLANS

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

The status of the plans was as follows:


	*Plan A*
*(in thousands)*	2005			2004
Accumulated benefit obligation (September 30)	$	122,135		$	111,017

Projected benefit obligation:
Balance at beginning of period	$	135,114		$	115,633
Service cost		6,117			5,424
Interest cost		7,545			6,654
Plan amendments		(1,072	)		—
Actuarial loss		11,120			16,659
Benefits paid		(13,451	)		(9,256	)

Balance at end of period (September 30)		145,373			135,114

Plan assets:
Fair value of plan assets at beginning of period		91,794			89,936
Actual return on plan assets		13,004			10,341
Employer contributions		20,594			773
Benefits paid		(13,451	)		(9,256	)

Fair value of plan assets at end of period (September 30)		111,941			91,794

Amounts recognized in the consolidated balance sheets:
Funded status of plan		(33,432	)		(43,320	)
Prepaid pension costs		(21,300	)		(8,615	)
Unrecognized actuarial loss		54,481			50,377
Unrecognized prior service cost		251			1,558
Employer contributions (October 1 to December 31)		11,674			20,594

Accrued pension asset (December 31)	$	11,674		$	20,594


	*Plan B*
*(in thousands)*	2005			2004
Accumulated benefit obligation (September 30)	$	27,153		$	25,114

Projected benefit obligation:
Balance at beginning of period	$	25,114		$	24,287
Service cost		618			583
Interest cost		1,405			1,383
Plan amendments		356			—
Actuarial loss		1,324			357
Benefits paid		(1,664	)		(1,496	)

Balance at end of period (September 30)		27,153			25,114

Plan assets:
Fair value of plan assets at beginning of period		25,118			20,835
Actual return on plan assets		3,710			2,533
Employer contributions		1,106			3,246
Benefits paid		(1,664	)		(1,496	)

Fair value of plan assets at end of period (September 30)		28,270			25,118

Amounts recognized in the consolidated balance sheets:
Funded status of plan		1,117			4
Prepaid pension costs		(7,257	)		(6,516	)
Unrecognized actuarial loss		4,574			4,925
Unrecognized prior service cost		1,566			1,587
Employer contributions (October 1 to December 31)		509			1,106

Accrued pension asset (December 31)	$	509		$	1,106

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


	*Plan A*
	September 30, 2005		September 30, 2004
Discount rate	5.50	%	5.75	%
Rate of compensation increase	3.50	%	4.00	%

The components of net pension expense were:


	*Plan A*
*Years ended December 31, (in thousands)*	2005			2004			2003
Components of net periodic benefit cost:
Service cost	$	6,177		$	5,425		$	3,955
Interest cost		7,545			6,654			6,640
Expected long-term return on assets		(8,796	)		(7,801	)		(6,858	)
Prior service cost amortization		235			235			235
Actuarial loss		2,748			1,732			628

Net periodic expense	$	7,909		$	6,245		$	4,600


	*Plan B*
*Years ended December 31, (in thousands)*	2005			2004			2003
Components of net periodic benefit cost:
Service cost	$	618		$	583		$	491
Interest cost		1,405			1,383			1,417
Expected long-term return on assets		(2,158	)		(2,089	)		(1,561	)
Prior service cost amortization		378			354			354
Actuarial loss		122			108			—

Net periodic expense	$	365		$	339		$	701

Net pension expense for Alagasco was $6,288,000, $5,175,000 and $4,370,000 for the years ended December 31, 2005, 2004 and 2003, respectively.

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


	*Plan A*
	December 31, 2005		December 31, 2004		December 31, 2003
Discount rate	5.75	%	6.00	%	6.75	%
Expected long-term return on plan assets	8.50	%	8.75	%	9.00	%
Rate of compensation increase	4.00	%	4.00	%	4.50	%


	*Plan B*
	December 31, 2005		December 31, 2004		December 31, 2003
Discount rate	5.75	%	6.00	%	6.75	%
Expected long-term return on plan assets	8.50	%	8.75	%	9.00	%

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


	*Plan A*
	Target		December 31, 2005		December 31, 2004
Asset category:
Equity securities	59	%	58	%	60	%
Debt securities	31	%	29	%	30	%
Other	10	%	13	%	10	%

Net periodic expense	100	%	100	%	100	%


	*Plan B*
	Target		December 31, 2005		December 31, 2004
Asset category:
Equity securities	77	%	75	%	75	%
Debt securities	23	%	22	%	21	%
Other	—		3	%	4	%

Net periodic expense	100	%	100	%	100	%

Plan A and Plan B equity securities do not include the Company’s common stock. The Company is not required to make pension contributions in 2006 and does not currently plan to make discretionary contributions to Plan A or Plan B assets. The Company may reevaluate discretionary contributions in the fourth quarter of 2006 based on the outcome of the September 30, 2006 measurement of pension obligations.

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


*(in thousands)*	*Plan A*		*Plan B*
2006	$	9,429	$	2,675
2007	$	9,021	$	2,036
2008	$	9,786	$	2,390
2009	$	10,084	$	2,414
2010	$	12,168	$	2,432
2011-2015	$	71,165	$	11,913

Under SFAS No. 87, “Employers’ Accounting for Pensions,” Energen recognized an additional minimum pension liability for the accumulated benefit obligation in excess of plan assets at December 31, 2005 and 2004, of $31.5 million and $27.8 million, respectively, based on the Company’s September 30 measurement date. Alagasco established a regulatory asset of $22.8 million and $19.7 million as of December 31, 2005 and 2004, respectively, for the portion of the total benefit obligation to be recovered through rates in future periods in accordance with

SFAS No. 71. An intangible asset was recorded for the unrecognized prior service cost of $251,000 and $1.6 million at December 31, 2005 and 2004, respectively. The balance of $5.5 million and $4.3 million at December 31, 2005 and 2004, respectively, was recorded as a component of accumulated other comprehensive income, net of tax. The Company made discretionary contributions of $12.2 million in the fourth quarter of 2005 and $21.7 million in the fourth quarter of 2004.

The Company has supplemental retirement plans with certain key executives providing payments on retirement, termination, death or disability. Expense under these agreements for the years ended December 31, 2005, 2004 and 2003 was $2,899,000, $1,929,000, and $386,000, respectively. For its supplemental retirement plans, the Company used a September 30 measurement date. At September 30, 2005 and 2004, the accumulated post-retirement benefit obligation related to these agreements was $22 million and $18.3 million, respectively, and the projected benefit obligation was $28.5 million and $25.5 million, respectively. The Company recorded a minimum pension liability for supplemental retirement plans of $15.7 million and $14.2 million at December 31, 2005 and 2004, respectively. An intangible asset was recorded for the unrecognized prior service cost of $3.1 million and $2.5 million at December 31, 2005 and 2004, respectively, and the balance was recorded as a component of accumulated other comprehensive income, net of tax, of $8.2 million and $7.6 million at December 31, 2005 and 2004, respectively. An accrued post-retirement benefit liability of $6.2 million and $3.5 million was recorded at December 31, 2005 and 2004, respectively. The Company has established and funded a trust of $9 million and $6.1 million as of December 31, 2005 and December 31, 2004, respectively. While intended for payment of this benefit, the trust’s assets remain subject to the claims of the Company’s creditors. The Company is not required to make contributions to the supplemental retirement plans during 2006 but expects to fund approximately $1.5 million during 2006.

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

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


	*Salaried Employees*
*(in thousands)*	September 30, 2005			September 30, 2004
Projected post-retirement benefit obligation:
Balance at beginning of period	$	35,124		$	39,475
Service cost		925			1,339
Interest cost		1,969			2,303
Actuarial gain		(4,393	)		(5,580	)
Benefits paid		(2,255	)		(2,413	)

Balance at end of period (September 30)		31,370			35,124

Plan assets:
Fair value of plan assets at beginning of period		33,726			29,290
Actual return on plan assets		3,979			3,838
Employer contributions		2,829			3,011
Benefits paid		(2,255	)		(2,413	)

Fair value of plan assets at end of period (September 30)		38,279			33,726

Amounts recognized in the consolidated balance sheets:
Funded status of plan		6,909			(1,398	)
Unrecognized actuarial gain		(13,268	)		(5,557	)
Unrecognized net transition obligation		5,761			6,444
Employer contributions (October 1 to December 31)		405			706

Accrued benefit asset (liability) (December 31)	$	(193	)	$	195


	*Union Employees*
*(in thousands)*	September 30, 2005			September 30, 2004
Projected post-retirement benefit obligation:
Balance at beginning of period	$	36,864		$	33,809
Service cost		498			498
Interest cost		2,061			1,913
Plan amendment		(444	)		—
Actuarial loss		2,060			2,891
Benefits paid		(2,180	)		(2,247	)

Balance at end of period (September 30)		38,859			36,864

Plan assets:
Fair value of plan assets at beginning of period		31,758			28,628
Actual return on plan assets		4,315			3,902
Employer contributions		1,380			1,475
Benefits paid		(2,180	)		(2,247	)

Fair value of plan assets at end of period (September 30)		35,273			31,758

Amounts recognized in the consolidated balance sheets:
Funded status of plan		(3,586	)		(5,106	)
Unrecognized actuarial gain		(6,358	)		(6,036	)
Unrecognized prior service costs		—			58
Unrecognized net transition obligation		9,565			11,241
Employer contributions (October 1 to December 31)		221			321

Accrued benefit asset (liability) (December 31)	$	(158	)	$	478

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


	*Salaried Employees*
	September 30, 2005		September 30, 2004
Discount rate	5.50	%	5.75	%
Rate of compensation increase	3.50	%	4.00	%

Net periodic post-retirement benefit expense included the following:


	*Salaried Employees*
*Years ended December 31, (in thousands)*	2005			2004			2003
Components of net periodic benefit cost:
Service cost	$	925		$	1,339		$	823
Interest cost		1,969			2,303			2,045
Expected long-term return on assets		(1,702	)		(1,626	)		(1,298	)
Actuarial gain		(127	)		—			—
Transition amortization		682			682			682

Net periodic expense	$	1,747		$	2,698		$	2,252


	*Union Employees*
*Years ended December 31, (in thousands)*	2005			2004			2003
Components of net periodic benefit cost:
Service cost	$	498		$	498		$	412
Interest cost		2,061			1,913			2,010
Expected long-term return on assets		(2,633	)		(2,627	)		(2,102	)
Actuarial gain		(147	)		(414	)		(283	)
Prior service cost		4			4			16
Transition amortization		1,285			1,285			1,285

Net periodic expense	$	1,068		$	659		$	1,338

Net periodic post-retirement benefit expense for Alagasco was $2,273,000, $2,573,000 and $2,902,000 for the years ended December 31, 2005, 2004 and 2003, respectively.

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


	*Salaried Employees*
	December 31, 2005		December 31, 2004		December 31, 2003
Discount rate	5.75	%	5.94	%	6.75	%
Expected long-term return on plan assets	8.50	%	8.75	%	9.00	%
Rate of compensation increase	4.00	%	4.00	%	4.50	%


	*Union Employees*
	December 31, 2005		December 31, 2004		December 31, 2003
Discount rate	5.75	%	5.94	%	6.75	%
Expected long-term return on plan assets	8.50	%	8.75	%	9.00	%

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


	*Salaried Employees*
	September 30, 2005		September 30, 2004
Health care cost trend rate assumed for next year	10.00	%	11.00	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2010		2010


	*Union Employees*
	September 30, 2005		September 30, 2004
Health care cost trend rate assumed for next year	10.00	%	11.00	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2010		2010

Assumed health care cost trend rates used in determining the accumulated post-retirement 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:


	*Salaried Employees*
*(in thousands)*	1-Percentage Point Increase		1-Percentage Point Decrease
Effect on total of service and interest cost	$	286	$	(228	)
Effect on net post-retirement benefit obligation	$	1,463	$	(1,266	)


	*Union Employees*
*(in thousands)*	1-Percentage Point Increase		1-Percentage Point Decrease
Effect on total of service and interest cost	$	234	$	(187	)
Effect on net post-retirement benefit obligation	$	3,555	$	(2,904	)

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


	*Salaried Employees*
	Target		December 31, 2005		December 31, 2004
Asset category:
Equity securities	70	%	70	%	70	%
Debt securities	20	%	20	%	20	%
Other	10	%	10	%	10	%

Net periodic expense	100	%	100	%	100	%


	*Union Employees*
	Target		December 31, 2005		December 31, 2004
Asset category:
Equity securities	70	%	71	%	70	%
Debt securities	20	%	20	%	20	%
Other	10	%	9	%	10	%

Net periodic expense	100	%	100	%	100	%

Equity securities for the post-retirement benefit programs do not include the Company’s common stock. The Company expects to make discretionary contributions of $1.4 million to post-retirement benefit program assets during 2006.

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


*(in thousands)*	Salaried Employees		Union Employees
2006	$	1,984	$	2,026
2007	$	2,056	$	2,141
2008	$	2,119	$	2,260
2009	$	2,164	$	2,329
2010	$	2,214	$	2,435
2011-2015	$	11,676	$	13,050

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 2006:


*(in thousands)*	Salaried Employees			Union Employees
2006	$	(157	)	$	(213	)
2007	$	(167	)	$	(229	)
2008	$	(174	)	$	(241	)
2009	$	(178	)	$	(249	)
2010	$	(178	)	$	(251	)
2011-2015	$	(814	)	$	(1,193	)

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

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

The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets, and funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment mangers are performing satisfactorily.

The Company has a long-term disability plan covering most salaried employees. The Company had expense for the years ended December 31, 2005, 2004 and 2003 of $198,000, $938,000 and $265,000, respectively.

6. COMMON STOCK PLANS*

A majority of Company employees are eligible to participate in the Energen Employee Savings Plan (ESP) by electing to contribute a portion of their compensation to the ESP. The Company matches a percentage of the contributions and may make additional contributions of Company common stock (new issue or treasury shares) or funds for the purchase of Company common stock. Prior to January 1, 2004, employees were allowed to invest their elective contributions in Company stock. Company stock is no longer an investment option for new elective contributions. Vested employees may diversify 100 percent of their ESP Company stock account into other ESP investment options regardless of whether the Company stock was acquired through elective contribution, Company match, Company contribution or reinvestment of earnings. At December 31, 2005, total shares reserved for issuance equaled 1,080,108. Expense associated with Company contributions to the ESP was $4,650,000, $4,210,000 and $4,199,000 for the years ended December 31, 2005, 2004 and 2003, respectively.

The 1997 Stock Incentive Plan adopted in October 2001 provided for the award of performance units, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of a four-year award period. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards will be made in the form of Company common stock with no portion of an award paid in cash. Prior to the amendment, payment of performance awards could be made in cash or in a combination of Company common stock or cash. Under the 1997 Stock Incentive Plan, 117,540, 136,300 and 235,000 performance units were awarded in the years ended December 31, 2005, 2004 and 2003, respectively. The Company recorded expense of $9,338,000, $8,708,000 and $5,653,000 for the years ended December 31, 2005, 2004 and 2003, respectively, under the Plan.

The 1997 Stock Incentive Plan and the Energen Corporation 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 Plans provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. In addition, the 1997 Stock Incentive Plan provided for the grant of restricted stock with 44,040, 131,520 and 106,950 shares awarded in the years ended December 31, 2005, 2004 and 2003, respectively. The sale or transfer of the shares is limited during certain periods. The Company recorded expense of $1,800,000, $1,390,000 and $1,076,000 for the years ended December 31, 2005, 2004 and 2003, respectively, related to restricted stock. Under the 1988 Stock Option Plan, 1,080,000 shares of Company common stock reserved for issuance have been granted. At December 31, 2005, the remaining shares reserved for issuance totaled 2,251,841 under the 1997 Stock Incentive Plan. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date.

Transactions under the plans are summarized as follows:


	1997 Stock Incentive Plan				1988 Stock Option Plan
	Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Outstanding at December 31, 2002	970,986		$	11.00	271,028		$	7.29
Granted	244,160			14.86	—			—
Exercised	(244,306	)		10.99	(65,028	)		7.58

Outstanding at December 31, 2003	970,840			11.97	206,000			7.20

Granted	82,760			21.38	—			—
Exercised	(349,960	)		10.83	(148,000	)		7.12
Forfeited	(8,400	)		12.26	—			—

Outstanding at December 31, 2004	695,240			13.72	58,000			7.39

Exercised	(80,140	)		11.26	(30,000	)		5.77
Forfeited	(1,700	)		14.86	—			—

Outstanding at December 31, 2005	613,400		$	14.04	28,000		$	9.13

Exercisable at December 31, 2003	486,000		$	10.85	206,000		$	7.20
Exercisable at December 31, 2004	497,100		$	10.62	58,000		$	7.39
Exercisable at December 31, 2005	415,260		$	10.48	28,000		$	9.13

Remaining reserved for issuance at December 31, 2005	2,251,841			—	—			—

Total options granted under the 1997 Stock Option Plan during 2004 and 2003 included 82,760 shares and 133,560 shares which had a weighted average grant-date fair value of $7.11 and $6.05, respectively. The Company recorded expense of $465,000, $465,000 and $269,000 during the years ended December 31, 2005, 2004 and 2003, respectively, for these shares. The Company granted no options during 2005.

The following table summarizes information about options outstanding as of December 31, 2005:


1997 Stock Incentive Plan			1988 Stock Option Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life	Range of Exercise Prices		Shares	Weighted Average Remaining Contractual Life
$9.13-$9.41	98,724	2.96 years	$	9.13	28,000	1.92 years
$13.72	123,200	4.83 years		—	—	—
$11.32	72,656	5.83 years		—	—	—
$14.86	236,060	7.08 years		—	—	—
$21.38	82,760	8.08 years		—	—	—

$9.13-$21.38	613,400	5.96 years	$	9.13	28,000	1.92 years

Of the total shares granted during 2004 and 2003, 25,000 and 110,600, respectively, had stock appreciation rights. The 2004 grants were issued under the 2004 Stock Appreciation Rights Plan which provides for the payment of cash incentives measured by long-term appreciation in the Company’s stock. The 2003 grants were issued under the 1997 Stock Incentive Plan as discussed above which provided for the issuance of stock appreciation rights. Expense associated with stock appreciation rights of $1,326,000, $916,000 and $209,000 was recorded for the years ended December 31, 2005, 2004 and 2003, respectively.

In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan to pay part of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 12,116, 10,800 and 15,000 shares were awarded during the years ended December 31, 2005, 2004 and 2003, respectively, leaving 236,962 shares reserved for issuance as of December 31, 2005.

The Company’s Dividend Reinvestment and Direct Stock Purchase Plan includes a direct stock purchase feature which allows purchases by non-shareholders. As of December 31, 2005, 1,098,292 common shares were reserved under this Plan.

By resolution adopted May 25, 1994, and supplemented by a resolution adopted April 26, 2000, the Board authorized the Company to repurchase up to 3,564,400 shares of the Company’s common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2005 and 2004. For the year ended December 31, 2003, the Company repurchased 1,300 shares pursuant to its repurchase authorization. As of December 31, 2005, a total of 2,150,700 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, 2005, 2004 and 2003, the Company acquired 67,957, 36,044 and 58,464 shares, respectively, in connection with its stock compensation plans.

On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan) designed to protect shareholders from coercive or unfair takeover tactics. Under certain circumstances, the 1998 Plan provides shareholders with the right to acquire the Company’s Series 1998 Junior Participating Preferred Stock (or, in certain cases, securities of an acquiring person) at a significant discount. Terms and conditions are set forth in a Rights Agreement between the Company and its Rights Agent. Under the 1998 Plan, one right is associated with each outstanding share of common stock. Rights outstanding under the 1998 Plan at December 31, 2005, were convertible into 734,933 shares of Series 1998 Junior Participating Preferred Stock (1/100 share of preferred stock for each full right) subject to adjustment upon occurrence of certain take-over related events. No rights were exercised or exercisable during the period. The price at which the rights would be exercised is $70 per right, subject to adjustment upon occurrence of certain take-over related events. In general, absent certain take-over related events as described in the Plan, the rights may be redeemed prior to the July 27, 2008, expiration for $0.01 per right.

In 1997 the Company adopted the 1997 Deferred Compensation Plan to allow officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Company’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the 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.

During the quarter ended September 30, 2005, the Company reduced Treasury Stock and Deferred Compensation Plan, both reflected in shareholders’ equity, by approximately $25 million to correct the carrying value of the equity-based deferred compensation previously reported at market value to historical cost as prescribed by the Emerging Issues Task Force No. 97-14, “Accounting for Deferred Compensation Arrangements Where Amounts Earned Are Held in a Rabbi Trust and Invested.” This change had no impact on current or previously reported net income, cash flows or total shareholders’ equity.

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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 $243 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 166.1 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 and is not expected to do so in the future; however, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

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

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

Cochran County, Texas

In January 2005, a lawsuit was tried in Cochran County, Texas in which the plaintiff alleged preferential purchase right claims against Energen Resources with respect to certain properties acquired by Energen Resources in 2002. The jury rendered a verdict in Energen Resources’ favor on all counts. Subsequently, in March 2005, the Judge issued a decision overruling the jury verdict. Energen Resources is pursuing an appeal of the Judge’s order and expects to prevail. Under the Judge’s order, Energen Resources’ potential pre-tax charge to income would be approximately $3.3 million as of December 31, 2005, none of which has been accrued. This amount includes the net cash flows attributable to the property since its acquisition.

Jefferson County, Alabama

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 $13,628,000, $10,638,000 and $8,412,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Minimum future rental payments required after 2005 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:


Years Ending December 31, *(in thousands)*
2006	2007		2008		2009		2010		2011 and thereafter
$3,839	$	3,598	$	3,219	$	3,216	$	3,097	$	32,716

Alagasco’s total payments related to leases included as operating expense were $3,148,000, $2,728,000 and $2,602,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Minimum future rental payments required after 2005 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:


Years Ending December 31, *(in thousands)*
2006	2007		2008		2009		2010		2011 and thereafter
$3,141	$	3,129	$	3,069	$	3,077	$	3,097	$	32,716

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 $699,654,000 would be $734,756,000 at December 31, 2005. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, with a carrying value of $214,654,000 would be $210,844,000 at December 31, 2005. The fair values were based on current market prices.

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, 2005, the fixed price purchased under these guarantees had a maximum term outstanding through December 2006 with an aggregate purchase price of $4.7 million and a market value of $5.0 million.

Alagasco had an agreement with a financial institution whereby it could sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program. Effective February 1, 2004, Alagasco no longer sells its installment receivables. Alagasco sold installment receivables of $302,000 and $4,992,000 in the years ended December 31, 2004 and 2003, respectively. At December 31, 2005 and 2004, the balances of these installment receivables were $1,589,000 and $4,076,000, respectively. Receivables sold under this agreement were considered financial instruments with off-balance sheet risk. Alagasco’s exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables. The fair value of these guarantees is recorded as a non-current other liability.

Price Risk: The Company applies SFAS No. 133 as amended which requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the 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 in operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in operating revenues immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change.

Energen Resources periodically enters into cash flow derivative commodity instruments to hedge its price exposure on its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources or Alagasco collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. In cases where 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 or Alagasco’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 or Alagasco in the event credit ratings are below investment grade. At December 31, 2005, Energen Resources was in a net loss position with all counterparties but was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of December 31, 2005. The Company believes the creditworthiness of these counterparties is satisfactory. The two largest counterparties represented approximately 48 percent and 22 percent of Energen Resources’ fair value of derivatives. Energen Resources’ other counterparties each represented less than 14 percent of the fair value of derivative.

As of December 31, 2005, $84.7 million of deferred net losses 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 $2.4 million after-tax loss in 2005 for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, the Company recorded an after-tax loss of $14.1 million in 2005 on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of December 31, 2005, all of the Company’s hedges met the definition of a cash flow hedge. During 2005, the Company discontinued hedge accounting and reclassified losses of $0.8 million after-tax from OCI into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur.

The Company had $56.5 million and $15.6 million included in current and noncurrent deferred income taxes on the consolidated balance sheets related to items included in other comprehensive income as of December 31, 2005 and 2004, respectively. At December 31, 2005 and 2004, the Company had $145.9 million and $40.7 million, respectively, of current losses recorded in accounts payable and $11.9 million and $3.2 million, respectively, of non-current losses recorded in deferred credits and other liabilities related to derivative contracts.

As of December 31, 2005, Energen Resources entered into the following transactions for 2006 and subsequent years:


Production Period	Total Hedged Volumes	Average Contract Price		Description
Natural Gas
2006	16.3 Bcf	$	8.08 Mcf	NYMEX Swaps
	21.9 Bcf	$	6.48 Mcf	Basin Specific Swaps
2007	3.0 Bcf	$	9.72 Mcf	Basin Specific Swaps

Oil
2006	2,844 MBbl	$	52.88 Bbl	NYMEX Swaps
2007	600 MBbl	$	59.65 Bbl	NYMEX Swaps
2008	900 MBbl	$	57.71 Bbl	NYMEX Swaps
2009	900 MBbl	$	56.25 Bbl	NYMEX Swaps

Oil Basis Differential
2006	1,915 MBbl		**	Basis Swaps

Natural Gas Liquids
2006	30.2 MMGal	$	0.56 Gal	Liquids Swaps

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

All hedge transactions are subject to the Company’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items 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 and measured. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2009.

At December 31, 2005, Alagasco recognized a $6.3 million loss as a liability in accounts payable with a corresponding current regulatory asset of $6.3 million representing the fair value of derivatives. At December 31, 2004, Alagasco recorded an $8.1 million gain as an asset in prepayments and other with a corresponding current regulatory liability of $8.1 million representing the fair value of derivatives.

Concentration of Credit Risk: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. 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 three largest oil and gas purchasers accounted for approximately 23 percent, 22 percent and 15 percent of Energen Resources’ accounts receivable for commodity sales as of December 31, 2005. Energen Resources’ other purchasers each accounted for less than 9 percent of this accounts receivable as December 31, 2005. During the year ended December 31, 2005, two purchases accounted for approximately 13 percent and 11 percent of the Company’s total operating revenues.

Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 460,000 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)*	2005					2004					2003
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	173,012	73,052	$	2.37	$	127,463	72,547	$	1.76	$	110,654	70,869	$	1.56
Effect of dilutive securities
Long-range performance shares			208					212					146
Stock options			334					330					402
Restricted stock			121					28					17

Diluted EPS	$	173,012	73,715	$	2.35	$	127,463	73,117	$	1.74	$	110,654	71,434	$	1.55

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

For the years ended December 31, 2005, 2004 and 2003, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

10. ASSET RETIREMENT OBLIGATIONS

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 will settle the obligation for its recorded amount and will record the resulting gain or loss.

In 2005, 2004 and 2003, 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, 2002	$	27,235

Liabilities incurred during the year ended December 31, 2003		1,139
Liabilities settled during the year ended December 31, 2003		(3,749	)
Accretion expense		1,890

Balance of ARO as of December 31, 2003		26,515

Liabilities incurred during the year ended December 31, 2004		1,172
Liabilities settled during the year ended December 31, 2004		(413	)
Revision in estimated cash flows		5,302
Accretion expense		2,265

Balance of ARO as of December 31, 2004		34,841

Liabilities incurred during the year ended December 31, 2005		10,102
Liabilities settled during the year ended December 31, 2005		(689	)
Revision in estimated cash flows		3,369
Accretion expense		2,647

Balance of ARO as of December 31, 2005	$	50,270

As of December 31, 2005, the Company adopted 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 obligations of $13.5 million to purge and cap its gas pipelines upon abandonment as a regulatory liability under SFAS No. 71 as of December 31, 2005. 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. Accordingly, the adoption of FIN 47 did not have an impact on the Company’s income statements.

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 $105.4 million and $110.9 million for December 31, 2005 and 2004, 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)*	2005		2004		2003
Interest paid, net of amount capitalized	$	43,849	$	40,557	$	39,963
Income taxes paid	$	32,879	$	8,352	$	10,929
Noncash investing activities:
Capitalized depreciation	$	96	$	94	$	123
Allowance for funds used during construction	$	792	$	1,247	$	948

Under SFAS No. 143, the Company recorded a non-cash adjustment for accretion expense of $2.6 million, $2.3 million and $1.9 million during 2005, 2004 and 2003, respectively.

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


*Years ended December 31, (in thousands)*	2005		2004		2003
Interest paid, net of amount capitalized	$	12,664	$	11,248	$	12,477
Income taxes paid	$	22,456	$	11,034	$	12,754
Noncash investing activities:
Capitalized depreciation	$	96	$	94	$	123
Allowance for funds used during construction	$	792	$	1,247	$	948

12. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS

The Company applies SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which retains the previous asset impairment requirements of SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,” for loss recognition when the carrying value of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In addition, SFAS No. 144 requires that gains and losses in the sale of certain oil and gas properties and writedowns of certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for prior periods in accordance with SFAS No. 144. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale must be reported at the lower of the carrying amount or fair value. During 2005, Energen Resources recorded a pre-tax gain of $213,000 primarily from a property sale located in the Permian Basin. Energen Resources had no property sales during 2004 or properties reclassified as held-for-sale as of December 31, 2004. In 2003, Energen Resources recorded a pre-tax gain of $9.4 million in discontinued operations from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million.

The following are the results of operations from discontinued operations:


*Years ended December 31,* *(in thousands, except per share data)*	2005			2004			2003
Oil and gas revenues	$	82		$	531		$	4,176

Pretax income (loss) from discontinued operations	$	(10	)	$	262		$	1,860
Income tax expense (benefit)		(4	)		99			726

Income (Loss) from Discontinued Operations		(6	)		163			1,134

Impairment charge on held-for-sale property		—			—			(10,404	)
Gain (loss) on disposal of discontinued operations		213			(8	)		9,448
Income tax expense (benefit)		81			(3	)		(372	)

Gain (Loss) on Disposal of Discontinued Operations		132			(5	)		(584	)

Total Income from Discontinued Operations	$	126		$	158		$	550

Diluted Earnings Per Average Common Share*
Income from Discontinued Operations	$	—		$	—		$	0.02
Gain (Loss) on Disposal of Discontinued Operations		—			—			(0.01	)

Total Income from Discontinued Operations	$	—		$	—		$	0.01

Basic Earnings Per Average Common Share*
Income from Discontinued Operations	$	—		$	0.01		$	0.02
Gain (Loss) on Disposal of Discontinued Operations		—			—			(0.01	)

Total Income from Discontinued Operations	$	—		$	0.01		$	0.01

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

13. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

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

Year Ended December 31, 2005

(in thousands, except per share amounts)

First

Second

Third

Fourth

Operating revenues

361,008

241,624

190,681

335,081

Operating income

105,130

70,747

41,071

98,776

Income from continuing operations

58,942

37,572

19,073

57,299

Net income

59,046

37,573

19,086

57,307

Diluted earnings per average common share*

Continuing operations

0.80

0.51

0.26

0.77

Net income

0.80

0.51

0.26

0.78

Basic earnings per average common share*

Continuing operations

0.81

0.51

0.26

0.78

Net income

0.81

0.51

0.26

0.78


	*Year Ended December 31, 2004*
*(in thousands, except per share amounts)*	First		Second		Third		Fourth
Operating revenues	$	351,257	$	188,046	$	166,343	$	231,211
Operating income	$	105,968	$	46,065	$	32,213	$	60,597
Income from continuing operations	$	60,152	$	22,224	$	13,677	$	31,252
Net income	$	60,185	$	22,270	$	13,740	$	31,268
Diluted earnings per average common share*
Continuing operations	$	0.82	$	0.30	$	0.19	$	0.43
Net income	$	0.82	$	0.30	$	0.19	$	0.43
Basic earnings per average common share*
Continuing operations	$	0.83	$	0.31	$	0.19	$	0.43
Net income	$	0.83	$	0.31	$	0.19	$	0.43

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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, 2005

(in thousands)

First

Second

Third

Fourth

Operating revenues

258,128

107,197

64,421

170,954

Operating income (loss)

66,404

5,630

(11,025

)

11,913

Net income (loss)

39,004

1,073

(8,810

)

5,697


	*Year Ended December 31, 2004*
*(in thousands)*	First		Second		Third			Fourth
Operating revenues	$	255,202	$	92,744	$	62,162		$	116,632
Operating income (loss)	$	62,014	$	4,575	$	(10,130	)	$	9,740
Net income (loss)	$	36,319	$	559	$	(7,745	)	$	4,657

14. ACQUISITION OF OIL AND GAS PROPERTIES

On December 15, 2005, Energen Resources completed a purchase of Permian Basin oil properties from a private company. The contract purchase price was approximately $168 million with an effective date of November 1, 2005. Approximately 80 percent of the 21.9 million barrels of proved oil reserves are undeveloped. More than 90 percent of the estimated proved reserves are oil. Energen used its available cash and existing lines of credit to finance the acquisition.

On August 2, 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $273 million. The effective date of the acquisition was August 1, 2004. Energen Resources acquired approximately 245 Bcfe of proved natural gas and natural gas liquids reserves. Approximately 51 percent of the proved reserves were estimated to be behind pipe and undeveloped. Approximately 80 percent of the acquisition reserves were gas with natural gas liquids comprising the balance. Energen used its short-term credit facilities and internally generated cash flows to finance the acquisition. A portion of the short-term debt incurred to finance the acquisition was repaid when Energen issued $100 million of Floating Rate Senior Notes in November 2004.

Summarized below are the consolidated results of operations for the years ended December 31, 2004 and 2003, on an unaudited pro forma basis as if the purchase of assets in the San Juan Basin had occurred at the beginning of 2003. The pro forma information is based on the Company’s consolidated results of operations for the years ended December 31, 2004 and 2003, and on the data provided by the seller. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor are they indicative of results of the future operations of the combined enterprises.


*Years ended December 31,* *(Unaudited) (in thousands, except per share data)*	2004		2003
Operating revenues	$	949,203	$	860,404
Income from continuing operations	$	128,109	$	111,281
Net income	$	128,267	$	111,831
Diluted earnings per average common share*	$	1.75	$	1.57
Basic earnings per average common share*	$	1.77	$	1.58

*	Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

15. REGULATORY ASSETS AND LIABILITIES

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

Energen Corporation


*(in thousands)*	December 31, 2005				December 31, 2004
*(in thousands)*	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension asset	$	—	$	22,807	$	—	$	19,650
Accretion and depreciation for asset retirement obligation		—		10,183		—		—
Risk management activities		6,291		—		—		—
Other		342		446		—		—

Total regulatory assets	$	6,633	$	33,436	$	—	$	19,650

Regulatory liabilities:
Enhanced stability reserve Gas supply adjustment Risk management activities RSE adjustment Unbilled service margin Asset removal costs, net Asset retirement obligation Other	$	3,690 22,326 — 2,943 24,537 — — —	$	— — — — — 105,404 13,451 953	$	3,671 6,964 8,097 1,251 27,077 — — —	$	— — — — — 110,912 — 1,016

Total regulatory liabilities	$	53,496	$	119,808	$	47,060	$	111,928

As described in Note 2, 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.

16. STOCK DIVIDEND

On April 27, 2005, Energen’s shareholders approved a 2-for-1 split of the Company’s common stock. The split was effected in the form of a 100 percent stock dividend and was payable on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split. Effective April 29, 2005, the Restated Certificate of Incorporation of Energen Corporation was amended to increase the Company’s authorized common stock, par value $0.01 per share, from 75,000,000 shares to 150,000,000 shares.

17. EQUITY AND DEBT OFFERINGS

In January 2005, Alagasco issued $40 million of long-term debt with an interest rate of 5.2 percent due January 15, 2020 and $40 million of long-term debt with an interest rate of 5.7 percent due January 15, 2035. In November 2005, Alagasco issued $80 million of long-term debt with an interest rate of 5.368 percent due December 1, 2015. Alagasco used these long-term debt proceeds to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance $30 million of Medium-Term Notes recalled by Alagasco in April 2004. Alagasco’s long-term debt proceeds were also used to refinance $18 million of Medium-Term Notes maturing June 27, 2007 to July 5, 2022 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 recalled by Alagasco in August 2005 and December 2005, respectively.

In November 2004, Energen issued $100 million of Floating Rate Senior Notes (Senior Notes) due November 15, 2007. The interest rate is the three-month LIBOR Rate plus .35 percent, reset quarterly. At December 31, 2005, the interest rate was 4.69 percent on the Senior Notes. The Senior Note proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.

18. TRANSACTIONS WITH RELATED PARTIES

Alagasco purchased natural gas of $2,731,000, $2,112,000 and $3,195,000 from affiliates for the years ended December 31, 2005, 2004 and 2003, respectively. These amounts are included in gas purchased for resale. All transactions were at market based pricing.

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 matches short-term cash surpluses with the needs of its affiliates, to minimize borrowing from outside sources. Alagasco had net receivables from affiliates of $3,215,000 and $2,190,000 at December 31, 2005 and 2004, respectively. Interest income and expense between affiliates is calculated monthly based on the market weighted average interest rate. The weighted average interest rate during 2005 and 2004 was 3.63 percent and 2.29 percent, respectively.

19. OTHER INCOME AND EXPENSE

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


*Years ended December 31, (in thousands)*	2005		2004		2003
Allowance for funds used during construction	$	792	$	1,247	$	948
Merchandise revenues		—		671		7,696
Other		1,371		1,027		100

Total other income	$	2,163	$	2,945	$	8,744

Cost of goods sold	$	268	$	1,701	$	8,549
Other merchandise expense		442		514		1,428

Total other expense	$	710	$	2,215	$	9,977

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


*Years ended December 31, (in thousands)*	2005		2004		2003
Allowance for funds used during construction	$	792	$	1,247	$	948
Merchandise revenues		—		637		3,876
Other		1,371		1,342		256

Total other income	$	2,163	$	3,226	$	5,080

Cost of goods sold	$	268	$	1,701	$	5,142
Other		433		494		127

Total other expense	$	701	$	2,195	$	5,269

The sale of merchandise inventory items are reflected in other income and expense. Effective February 1, 2004, Alagasco no longer participates in direct sales of natural gas merchandise. Alagasco continues to work closely with various contractors and retail companies to meet the merchandise requirements of its customers.

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

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), which requires a fair value base method of accounting using pricing models that reflect the specific economics of a company’s transactions. This statement is effective for the first annual reporting period beginning after June 15, 2005. The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 as amended, which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation effective January 1, 2003. The Company will adopt SFAS No. 123R using the modified prospective application method for new awards effective January 1, 2006. Although, the Company is currently evaluating its stock-based compensation and the application of SFAS No. 123R, it does not anticipate that the adoption of SFAS No. 123R will have a material impact on the financial condition or results of operations of the Company. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards will be made in the form of Company common stock with no portion of an award paid in cash. Accordingly, the Company will value such awards at fair value under the provisions of SFAS No. 123R as of the date of modification or grant.

21. OIL AND GAS OPERATIONS (Unaudited)

The following schedules detail historical financial data of the Company’s oil and gas operations. Certain reclassifications have been made to conform the prior years’ financial statements to the current-year presentation. Terms appearing in the schedules prescribed by the Securities and Exchange Commission (SEC) are briefly described as follows:

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

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

Production (Lifting) Costs include costs incurred to operate and maintain wells.

Gross Revenues are reported after deduction of royalty interest payments.

Gross Well or Acre is a well or acre in which a working interest is owned.

Net Well or Acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.

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

Productive Well is an exploratory or a development well that is not a dry well.

Capitalized Costs


*(in thousands)*	December 31, 2005		December 31, 2004
Proved	$	1,911,588	$	1,587,512
Unproved		18,703		3,607

Total capitalized costs		1,930,291		1,591,119
Accumulated depreciation, depletion, and amortization		466,643		381,734

Capitalized costs, net	$	1,463,648	$	1,209,385

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 December31, (in thousands)*	2005		2004		2003
Property acquisition:
Proved	$	170,338	$	273,735	$	40,219
Unproved		18,065		665		267
Exploration		5,490		5,060		468
Development		158,025		125,211		122,094

Total costs incurred	$	351,918	$	404,671	$	163,048

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)*	2005		2004		2003
Gross revenues	$	529,415	$	412,441	$	354,229
Production (lifting costs)		156,512		116,476		95,519
Exploration expense		676		2,100		1,053
Depreciation, depletion and amortization		87,398		79,119		78,049
Accretion expense		2,647		2,265		1,890
Income tax expense		102,102		80,293		66,287

Results of continuing operation from producing activities	$	180,080	$	132,188	$	111,431

Average Sales Price, Production Cost and Depreciation Rate From Continuing Operations


*Years ended December 31,*	2005		2004		2003
Revenue per unit of production including the effects of all derivative instruments:
Gas (Mcf)	$	5.99	$	4.84	$	4.25
Oil (per barrel)	$	35.18	$	28.66	$	25.56
Natural gas liquids (per gallon)	$	0.55	$	0.45	$	0.39
Revenue per unit of production including the effects of qualifying cash flow hedges:
Gas (Mcf)	$	6.03	$	4.87	$	4.27
Oil (per barrel)	$	35.18	$	29.70	$	25.61
Natural gas liquids (per gallon)	$	0.55	$	0.45	$	0.39
Revenue per unit of production excluding the effects of all derivative instruments:
Gas (Mcf)	$	7.81	$	5.68	$	4.97
Oil (per barrel)	$	51.61	$	38.33	$	29.19
Natural gas liquids (per gallon)	$	0.74	$	0.59	$	0.44
Average production (lifting) cost (per Mcfe)	$	1.15	$	0.90	$	0.80
Average production tax (per Mcfe)	$	0.57	$	0.43	$	0.32
Average depreciation rate (per Mcfe)	$	0.96	$	0.90	$	0.92

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

*Years ended December 31,*	2005		2004		2003
Exploratory:
Productive		4.1		7.5		0.7
Dry		—		0.4		0.3

Total		4.1		7.9		1.0

Development:
Productive		153.9		145.5		194.2
Dry		1.7		1.0		3.0

Total		155.6		146.5		197.2

As of December 31, 2005, the Company was participating in the drilling of 4 gross development wells, with the Company’s interest equivalent to 2.4 wells. In addition to the development wells drilled, the Company drilled 33, 45.9 and 41.6 net service wells during 2005, 2004 and 2003, respectively. As of December 31, 2005, the Company was participating in the drilling of 2 gross service wells, with the Company’s interest equivalent to 1.1 wells.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2005, and developed and undeveloped acreage as of the latest practicable date prior to year-end:


	Gross	Net
Gas wells	3,869	2,102
Oil wells	2,589	1,386

Developed acreage	836,065	572,517
Undeveloped acreage	146,876	124,472

There were 43 wells with multiple completions in 2005. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Alabama.

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, 2005. 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 91 percent of the Company’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.


Year ended December 31, 2005	Gas MMcf		Oil MBbl		NGL MBbl
Proved reserves at beginning of period	1,019,436		54,500		34,613
Revisions of previous estimates	43,221		186		(1,484	)
Purchases	3,974		21,614		58
Discoveries and other additions	75,742		1,979		429
Production	(61,117	)	(3,316	)	(1,681	)
Sales	(1,095	)	(1	)	(1	)

Proved reserves at end of period	1,080,161		74,962		31,934

Proved developed reserves at end of period	891,978		54,901		27,681


Year ended December 31, 2004	Gas MMcf		Oil MBbl		NGL MBbl
Proved reserves at beginning of period	886,307		52,528		27,245
Revisions of previous estimates	(42,052	)	594		(5	)
Purchases	194,607		24		8,422
Discoveries and other additions	37,832		4,788		575
Production	(57,258	)	(3,434	)	(1,624	)

Proved reserves at end of period	1,019,436		54,500		34,613

Proved developed reserves at end of period	810,083		47,792		28,079


Year ended December 31, 2003	Gas MMcf		Oil MBbl		NGL MBbl
Proved reserves at beginning of period	803,748		49,833		26,697
Revisions of previous estimates	(10,847	)	1,237		(826	)
Purchases	93,700		1,172		—
Discoveries and other additions	80,124		5,051		4,068
Production	(55,796	)	(3,458	)	(1,602	)
Sales	(24,622	)	(1,307	)	(1,092	)

Proved reserves at end of period	886,307		52,528		27,245

Proved developed reserves at end of period	714,866		40,802		23,552

During 2005, Energen Resources sold approximately 1.1 Bcfe of proved reserves, recording a net pre-tax gain of $1.7 million on certain properties in the Permian and Black Warrior basins. Energen Resources had no property sales during 2004. During 2003, Energen Resources sold approximately 39 Bcfe of proved reserves, recording a net pre-tax loss of $1 million, which includes a $10.4 million writedown on assets held-for-sale and subsequently sold during the year partially offset by gains on property sales of $9.4 million.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of the Company’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. At December 31, 2005, 2004 and 2003, the Company had a deferred hedging loss of $148.6 million, $41.1 million and $35.6 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.


*Years ended December 31, (in thousands)*	2005		2004		2003
Future gross revenues	$	14,252,735	$	8,791,050	$	7,211,830
Future production costs		4,168,061		2,797,556		2,189,464
Future development costs		357,408		222,519		204,513

Future net cash flows before income taxes		9,727,266		5,770,975		4,817,853
Discount at 10% per annum		5,681,737		3,228,215		2,685,843

Discounted future net cash flows before income taxes		4,045,529		2,542,760		2,132,010
Discounted future income tax expense		1,133,874		651,342		558,931

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	2,911,655	$	1,891,418	$	1,573,079

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)*	Year Ended December 31, 2005			Year Ended December 31, 2004			Year Ended December 31, 2003
Balance at beginning of year	$	1,891,418		$	1,573,079		$	1,244,257

Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs		1,288,366			147,380			365,816
Net changes due to revisions in quantity estimates		90,952			(58,378	)		(14,804	)
Development costs incurred, previously estimated		101,740			83,404			80,878
Accretion of discount		254,276			213,201			158,655
Other		(69,803	)		9,093			39,134

Total revisions		1,665,531			394,700			629,679
New field discoveries and extensions, net of future production and development costs		235,832			133,714			200,880
Sales of oil and gas produced, net of production costs		(595,439	)		(417,846	)		(311,189	)
Purchases		199,319			300,183			74,201
Sales		(2,474	)		—			(48,107	)
Net change in income taxes		(482,532	)		(92,412	)		(216,642	)

Net change in standardized measure of discounted future net cash flows		1,020,237			318,339			328,822

Balance at end of year	$	2,911,655		$	1,891,418		$	1,573,079

22. INDUSTRY SEGMENT INFORMATION

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


*(in thousands)*	Year Ended December 31, 2005			Year Ended December 31, 2004			Year Ended December 31, 2003
Operating revenues from continuing operations
Oil and gas operations	$	530,341		$	412,028		$	354,746
Natural gas distribution		600,700			526,740			489,099
Eliminations and other		(2,647	)		(1,911	)		(2,214	)

Total	$	1,128,394		$	936,857		$	841,631

Operating income (loss) from continuing operations
Oil and gas operations	$	243,876		$	180,379		$	153,325
Natural gas distribution		72,922			66,199			66,848

Subtotal		316,798			246,578			220,173
Eliminations and corporate expenses		(1,074	)		(1,735	)		(2,551	)

Total	$	315,724		$	244,843		$	217,622

Depreciation, depletion and amortization expense from continuing operations
Oil and gas operations	$	89,340		$	80,896		$	79,495
Natural gas distribution		42,351			39,881			37,171

Total	$	131,691		$	120,777		$	116,666

Interest expense
Oil and gas operations	$	32,778		$	29,660		$	28,577
Natural gas distribution		15,060			13,737			13,967

Subtotal		47,838			43,397			42,544
Eliminations and other		(1,038	)		(654	)		(282	)

Total	$	46,800		$	42,743		$	42,262

Income tax expense (benefit) from continuing operations
Oil and gas operations	$	76,362		$	56,982		$	46,511
Natural gas distribution		22,360			19,703			19,675

Subtotal		98,722			76,685			66,186
Other		(1,231	)		(1,160	)		(2,163	)

Total	$	97,491		$	75,525		$	64,023

Capital expenditures
Oil and gas operations	$	353,712		$	403,936		$	163,338
Natural gas distribution		73,276			58,208			57,906

Total	$	426,988		$	462,144		$	221,244

Identifiable assets
Oil and gas operations	$	1,637,244		$	1,315,967		$	959,815
Natural gas distribution		946,819			837,557			794,493

Subtotal		2,584,063			2,153,524			1,754,308
Eliminations and other		34,163			28,215			23,924

Total	$	2,618,226		$	2,181,739		$	1,778,232

Property, plant and equipment, net
Oil and gas operations	$	1,470,063		$	1,214,461		$	891,682
Natural gas distribution		597,948			568,598			541,769

Total	$	2,068,011		$	1,783,059		$	1,433,451

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

Energen Corporation


*Years ended December 31, (in thousands)*	2005			2004			2003
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	10,472		$	9,852		$	8,874

Additions:
Charged to income		6,076			4,819			5,820
Recoveries and adjustments		(431	)		(290	)		(616	)

Net additions		5,645			4,529			5,204

Less uncollectible accounts written off		(4,544	)		(3,909	)		(4,226	)

Balance at end of year	$	11,573		$	10,472		$	9,852

Alabama Gas Corporation


*Years ended December 31, (in thousands)*	2005			2004			2003
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	9,600		$	9,100		$	8,200

Additions:
Charged to income		6,076			4,819			5,668
Recoveries and adjustments		(342	)		(403	)		(601	)

Net additions		5,734			4,416			5,067

Less uncollectible accounts written off		(4,534	)		(3,916	)		(4,167	)

Balance at end of year	$	10,800		$	9,600		$	9,100

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

None

ITEM 9A. CONTROLS AND PROCEDURES

a. Conclusion Regarding Disclosure Controls and Procedures

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

b. 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:

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

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.

Management assessed the effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2005. 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, 2005, Energen Corporation maintained effective internal control over financial reporting. Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, our independent registered public accounting firm, as stated in their report which appears herein.

March 14, 2006

c. Changes in Internal Control Over Financial Reporting

Our chief executive officer and chief financial officer 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.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 26, 2006. The definitive proxy statement will be filed on or about March 28, 2006.

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 26, 2006.

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 26, 2006.

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 26, 2006.

c. Securities Authorized for Issuance Under Equity Compensation Plans

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information regarding certain relationships and related transactions is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 26, 2006.

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 26, 2006.

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

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 March 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 October 30, 2002) which was filed as Exhibit 4(c) to Energen’s Registration Statement on Form S-8 (Registration No. 33-46641)

*3(d)		Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for the year ended September 30, 1995

*3(e)		Bylaws of Alabama Gas Corporation (as amended through October 30, 2002) which was filed as Exhibit 3(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2003

*4(a)		Rights Agreement, dated as of July 27, 1998, between Energen Corporation and First Chicago Trust Company of New York, Rights Agent, which was filed as Exhibit 1 to Energen’s Registration Statement on Form 8-A, dated July 10, 1998

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

*4(b)(i)		Officers’ Certificate, dated September 13, 1996, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Series A Notes which was filed as Exhibit 4(d)(i) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001

*4(b)(ii)		Officers’ Certificate, dated July 8, 1997, pursuant to Section 301 of the Energen 1996 Indenture amending the terms of the Series A Notes which was filed as Exhibit 4(d)(ii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001

*4(b)(iii)		Amended and Restated Officers’ Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes which was filed as Exhibit 4(d)(iii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001

*4(b)(iv)		Officers’ Certificate, dated October 3, 2003, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 5 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)(v)		Officers’ Certificate, dated November 19, 2004, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Floating Rate Senior Notes due November 15, 2004, which was filed as Exhibit 4.2 to Energen’s Current Report on Form 8-K, dated November 19, 2004


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

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

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

*4(d)(iii)		Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alagasco 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’ Current Report on Form 8-K filed January 14, 2005

*4(d)(iv)		Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alagasco 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’ Current Report on Form 8-K filed January 14, 2005

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

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

*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(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

10(f)		Occluded Gas Lease, dated January 1, 1986 and First through Seventh Amendments

*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 10(d) to Energen’s Annual Report on Form 10-K for the year ended September 30, 1999

*10(i)		Severance Compensation Agreement with William Michael Warren, Jr., dated January 25, 2006, which was filed as Exhibit 99.1 to Energen’s Current Report on Form 8K filed January 27, 2006

*10(j)		Energen Corporation 1988 Stock Option Plan (as amended November 25, 1997) which was filed as Exhibit 10(e) to Energen’s Annual Report on Form 10-K for the year ended September 30, 1998


*10(k)		Energen Corporation 1992 Long-Range Performance Share Plan (as amended effective October 1, 1999) which was filed as Exhibit 10(f) to Energen’s Annual Report on Form 10-K for the year ended September 30, 1999

*10(l)		Energen Corporation 1997 Stock Incentive Plan (as amended effective January 1, 2006) which was filed as Exhibit 99.3 to Energen’s Current Report on Form 8-K filed January 27,2006

*10(m)		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(n)		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(o)		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(p)		Energen Corporation 1997 Deferred Compensation Plan (as amended effective January 1, 2001) which was filed as Exhibit 10(n) to Energen’s Annual Report Form 10K for the year ended December 31, 2005

*10(q)		Amendment No. 1 to the Energen Corporation 1997 Deferred Compensation Plan (as amended January 1, 2001) which was filed as Exhibit 10(o) to Energen’s Annual Report Form 10K for the year ended December 31, 2005.

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

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

*10(t)		Energen Corporation Officer Split Dollar Life Insurance Plan, effective October 1, 1999 which was filed as Exhibit 10(l) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810)

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

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

*10(w)		Energen Board of Directors resolution adopted as of May 14, 2004, terminating the Energen Corporation Officer Split Dollar Life Insurance Plan which was filed as Exhibit 10(u) to Energen’s Annual Report on Form 10K for the year ended December 31, 2005

21		Subsidiaries of Energen Corporation

23(a)		Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP)


23(b)		Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP)

23(c)		Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company, L.P.)

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

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

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

32		Certification pursuant to Section 1350

*	Incorporated by reference

SIGNATURE

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

ENERGEN CORPORATION

(Registrant)

ALABAMA GAS CORPORATION

(Registrant)


March 14, 2006	By	/s/ Wm. Michael Warren, Jr.
		Wm. Michael Warren, Jr.
		Chairman and Chief Executive Officer of
		Energen, Chairman and Chief Executive
		Officer of Alabama Gas Corporation

SIGNATURES

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


March 14, 2006	By	/s/ Wm. Michael Warren, Jr.
		Wm. Michael Warren, Jr.
		Chairman and Chief Executive Officer of Energen,
		Chairman and Chief Executive Officer of Alabama
		Gas Corporation

March 14, 2006	By	/s/ Geoffrey C. Ketcham
		Geoffrey C. Ketcham
		Executive Vice President, Chief Financial Officer and
		Treasurer of Energen and Alabama Gas Corporation

March 14, 2006	By	/s/ Grace B. Carr
		Grace B. Carr
		Vice President and Controller of Energen

March 14, 2006	By	/s/ Paula H. Rushing
		Paula H. Rushing
		Vice President-Finance of Alabama Gas
		Corporation

March 14, 2006	By	/s/ Julian W. Banton
		Julian W. Banton
		Director

March 14, 2006	By	/s/ James S. M. French
		James S. M. French
		Director

March 14, 2006	By	/s/ T. Michael Goodrich
		T. Michael Goodrich
		Director

March 14, 2006	By	/s/ Judy M. Merritt
		Judy M. Merritt
		Director

March 14, 2006	By	/s/ David W. Wilson
		David W. Wilson
		Director