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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

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:

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

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

YES  x    NO  ¨

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

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

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

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

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

Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 29, 2007:30, 2008:

Indicate number of shares outstanding of each of the registrant’s classes of common stock as of February 5, 2008:17, 2009:

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, 20082009 (Part III, Item 10-14)

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INDUSTRY GLOSSARY

For a more complete definition of certain terms defined below, as well as other terms and concepts applicable to successful efforts accounting, please refer to Rule 4-10(a) of Regulation S-X, promulgated pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended.

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ENERGEN CORPORATION

20072008 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

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

and Alabama Gas Corporation (Alagasco).

Forward-Looking Statements:Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, ourthe Company’s ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict.

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 facilitiesSee Item 1A, Risk Factors, 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 interruptiona discussion 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 and Drilling: There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future productionrisk factors that 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. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

Energen Resources’ Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future oil, gas and natural gas liquids prices could materially affect the Company’s financial position, results of operationsCompany and cash flows; furthermore, such risk mitigation activities may cause the Company’s financial position and results of operationsmaterial variances from forward-looking statement expectations. The Item 1A, Risk Factors, discussion is incorporated by reference to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position.

Alagasco’s Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and

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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 oil and gas production activities of Energen Resources and the gas distribution activities of Alagasco 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’s Service Territory: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.forward-looking statement disclosure.

PART I

General

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

Alagasco was formed in 1948 by the merger of Alabama Gas Company into Birmingham Gas Company, the predecessors of which had been in existence since the mid-1800s. Alagasco became publicly traded in 1953. Energen Resources was formed in 1971 as a subsidiary of Alagasco. Energen was incorporated in 1978 in preparation for the 1979 corporate reorganization in which Alagasco and Energen Resources became subsidiaries of Energen.

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

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Financial Information About Industry Segments

The information required by this item is provided in Note 19,18, Industry Segment Information, in the Notes to Financial Statements.

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Narrative Description of Business

General: Energen’s oil and gas operations focus on increasing production and adding proved reserves through the development and acquisition of oil and gas properties. In addition, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. All gas, oil and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Black Warrior, San Juan and Permian basins for its joint interest and third parties. These services include overall project management and day-to-day decision-making relative to project operations.

At the end of 2007,2008, Energen Resources’ proved oil and gas reserves totaled 1,7541,584 billion cubic feet equivalent (Bcfe). Substantially all of these reserves are located in the San Juan Basin in New Mexico and Colorado, the Permian Basin in west Texas and the Black Warrior Basin in Alabama. Approximately 8284 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 1815 years. Natural gas represents approximately 6466 percent of Energen Resources’ proved reserves, with oil representing approximately 2623 percent and natural gas liquids comprising the balance.

Growth Strategy: Energen has operated for more than ten years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $1.2 billion in property acquisitions, $1.3$1.8 billion in related development, and $209$248 million in exploration and related development. Energen Resources’ capital investment in 2008 and 2009 is currently expected to approximate $579$227 million primarily for existing properties. The Company also may allocate additional capital during this two-year period for other oil and gas activities such as property acquisitions, additional development of existing properties and the exploration and further development of potential shale playsshales acreage primarily in Alabama. The estimates above do not include amounts for capital related to potential acquisitions or development of these shale plays discussed below.

Energen Resources seeks to acquire onshore North American properties which offer proved undeveloped and/orand behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers properties with long-lived reserves and multiple pay-zone opportunities; however, Energen Resources will consider acquisitions of other types of properties which meet its investment requirements, including acquisitions with unproved properties. In addition, Energen Resources conducts exploration activities primarily in areas in which it has operations and remains open to exploration activities which complement its core expertise and meet its investment requirements. Following an acquisition, Energen Resources focuses on increasing production and reserves through development of the properties’ undeveloped reserves and behind-pipe reserve potential as well as engaging in other activities. These activities include development well drilling, exploration, behind-pipe recompletions, pay-adds, workovers, secondary recovery and operational enhancements. Energen Resources prefers to operate its properties in order to better control the nature and pace of development activities. Energen Resources operated approximately 91 percent of its proved reserves at December 31, 2007.2008.

In October 2006, Energen Resources sold to Chesapeake Energy Corporation (Chesapeake) a 50 percent interest in its unproved lease position of approximately 200,000 gross acres in various shale plays in Alabama for $75 million andplus a then expected $15 million carriedin net future drilling interest.cost. In addition, the two companies signed an agreement to form an area of mutual interest (AMI) through which they will pursue new leases, exploration, development and operations on a 50-50 basis, for at least the next 10 years. The AMI encompassed Alabama and parts of Georgia. During 2008, Energen Resources and Chesapeake continue to leaseleased shared acreage in the AMI, which encompasses AlabamaAMI. Through December 31, 2008, approximately $21.7 million of drilling costs have been incurred and some of Georgia,paid by Chesapeake. Of these drilling costs paid by Chesapeake, approximately $10.85 million relate to Energen Resources’ interest under the initial agreement. Chesapeake currently does not plan on participating in advance of drilling.future drilling costs; accordingly, all future drilling costs will be paid by Energen Resources. As of February 25, 2008,24, 2009, Energen Resources’ net acreage position in Alabama shaleshales totaled approximately 287,500343,000 acres and representsrepresenting multiple shale opportunities.

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

Energen Resources’ development activities can result in the addition of new proved reserves and can serve to reclassify proved undeveloped reserves to proved developed reserves. Proved reserve disclosures are provided annually, although changes to reserve classifications occur throughout the year. Accordingly, additions of new reserves from development activities can occur throughout the year and may result from numerous factors including, but not limited to, regulatory approvals for drilling unit downspacing that increase the number of

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available drilling locations; changes in the economic or operating environments that allow previously uneconomic locations to be added; technological advances that make reserve locations available for development; successful development of existing proved undeveloped reserve locations that reclassify adjacent probable locations to proved undeveloped reserve locations; increased knowledge of field geology and engineering parameters relative to oil and gas reservoirs; and changes in management’s intent to develop certain opportunities.

During the three years ended December 31, 2007,2008, the Company’s development efforts have added 364399 Bcfe of proved reserves from the drilling of 9751,087 gross development and service wells (including 2738 sidetrack wells) and 150176 well recompletions and pay-adds. In 2007,2008, Energen Resources’ successful development wells and other activities added approximately 127124 Bcfe of proved reserves; the companyCompany drilled 367406 gross development and service wells (including 2211 sidetrack wells), performed some 34103 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources’ production from continuing operations totaled 98.6102.4 Bcfe in 20072008 and is estimated to total 102106.5 Bcfe in 2008,2009, including 100104 Bcfe of estimated production from proved reserves owned at December 31, 2007. In 2009, production is estimated to be 108 Bcfe, including approximately 100 Bcfe produced from proved reserves currently owned.2008.

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

As of December 31, 2007,2008, the Company was participating in the drilling of 910 gross development and exploratory wells, with the Company’s interest equivalent to 58 wells. In addition to the development wells drilled, the Company drilled 84.1, 99.8 35.9 and 3335.9 net service wells during 2008, 2007 2006 and 2005,2006, respectively. As of December 31, 2007,2008, the Company was participating in the drilling of 12 gross service well,wells, with the Company’s interest equivalent to 0.9 well.1.5 wells.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2007,2008, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

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There were 175 wells with multiple completions in 2007.2008. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Alabama.

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

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degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change.

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

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

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

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 177184 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 2007,2008, Alagasco served an average of 416,967413,151 residential customers and 34,20033,911 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 10,200 miles of main and more than 11,900 miles of service lines, odorization and regulation facilities, and customer meters.

APSC Regulation:As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended in 2007, 2002, 1996, 1990, 1987 and 1985. On December 21, 2007, the APSC extended RSE for a seven-year period through December 31, 2014. Under the terms of the extension, RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing,

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

Under RSE, the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, whether Alagasco’s return on average equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. Prior to the December 21, 2007 extension,At September 30, 2008, RSE limited the utility’s equity upon which a return is permitted to 6057 percent of total capitalization and providedprovides for certain cost control

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measures designed to monitor Alagasco’s operations and maintenance (O&M) expense. The equity upon which a return is permitted will be phased down to 55 percent by September 30, 2009. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer fellon an aggregate basis falls within a range of 1.250.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range)(Index Range), no adjustment wasis required. If the change in O&M expense per customer exceededon an aggregate basis exceeds the index range,Index Range, three-quarters of the difference wasis returned to customers. To the extent the change wasis less than the index range,Index Range, the utility benefitedbenefits by one-half of the difference through future rate adjustments.

Subsequent to the extension, the equity on which a return will be permitted will be phased down to 57 percent by December 31, 2008 and 55 percent by December 31, 2009. The changes to the O&M expense cost control measurement subsequent to the extension are as follows: annual changes in O&M expense will be measured on an aggregate basis rather than per customer; the percentage change in O&M expense must fall within a range of 0.75 points above or below the percentage change in the index range; non-recurring and/or recurring items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the cost control measurement calculation; the O&M expense base for measurement purposes will continue to be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the index rangeIndex Range in two successive years, in which case the base for the following year will be set at the top of the index range.Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the cost control measurement calculation

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

The APSC approved an Enhanced Stability Reserve (ESR) beginning October 1997, with an approved maximum funding level of $4 million pre-tax, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting fromforce majeure events such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual large industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco’s return on equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR in an amount of no more than $40,000 monthly until the maximum funding level is achieved. Subsequent toUnder the terms of the 2007 RSE extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR.

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

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

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As of December 31, 2007,2008, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:

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/orand 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 sales customers. In 2007,2008, approximately 300 of Alagasco’s transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled more than $7.8$6.3 million.

The Competitive Fuel Clause (CFC) and Transportation Tariff also have been important to Alagasco’s ability to compete effectively for customer load in its service territory. The CFC allows Alagasco to adjust large customer rates on a case-by-case basis to compete with alternate fuels and alternate sources of gas. The GSA rider to Alagasco’s tariffTariff 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 20072008, substantially all of Alagasco’s large commercial and industrial customer deliveries involved the transportation of customer-owned gas. In addition, Alagasco served as gas purchasing agent for more thanapproximately 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 2007, 652008, 57 of the utility’s largest commercial and industrial transportation customers were under special contracts of varying lengths.

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

Growth: Customer growth presents a major challenge for Alagasco, given its mature, slow-growth service area. In 2007recent years, the higher price commodity environment has resulted in a decline in the utility’s customer base of approximately 1 percent annually. Recent lower commodity prices have not yet reversed this adverse trend at the utility. In 2008, Alagasco’s average number of customers decreased 1 percent. Alagasco will continue to concentrate on maintaining its current penetration levels in theand increasing residential new construction market and generating additionalsaturation levels for all end-use applications. Alagasco will continue to explore opportunities to increase revenue in the small and large commercial and industrial market segments.

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Seasonality:Alagasco’s gas distribution business is highly seasonal since a material portion of the utility’s total sales and delivery volumes isrelate to space heating customers. Alagasco’s rate tariffTariff includes a temperature adjustment riderTemperature Adjustment Rider primarily for residential, small commercial and small industrial customers that moderates the impact of departures from normal temperatures on Alagasco’s earnings. The calculation is performed monthly, and adjustments are made to customers’ bills inthrough the actual month the weather variation occurs.GSA.

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 inflows; however, remediation of the future; however,Huntsville, Alabama manufactured gas plant site discussed below, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

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

Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns) and five manufactured gas distribution sites (one of which it still owns). AnSubject to the following paragraph discussing the Huntsville, Alabama manufactured gas plant site, an investigation of the sites does not indicate the present need for remediation activities. Managementactivities and management expects that, should remediation of any such sites be required in the future, Alagasco’s share, if any, of such costs will not materially affect the Company’s financial position.position of Alagasco.

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

The Company has approximately 1,5421,530 employees, of which Alagasco employs 1,1691,130 and Energen Resources employs 373.400. The Company believes that its relations with employees are good.

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Index to Financial Statements

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

Third Party Facilities:Commodity Prices Energen Resources delivers to: The Company and Alagasco is servedare significantly influenced by third party facilities. These facilities include third partycommodity prices. Historical markets for natural gas, oil and natural gas gathering, transportation, processingliquids have been volatile. Energen Resources’ revenues, operating results, profitability and storage facilities. Energen Resources reliescash flows depend primarily upon such facilities for access to marketsthe prices realized for its production. Alagasco relies upon such facilities for access tooil, gas and natural gas supplies. Such facilitiesliquid production. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are typically limited in number and geographically concentrated. An extended interruption of accesspassed-through 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.customers.

Energen Resources’ ProductionAccess to Credit Markets: The Company and Drilling: There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures.its subsidiaries rely on access to credit markets. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success ratesavailability and cost overruns,of credit market access is significantly influenced by market events and these risksrating agency evaluations for both lenders and the Company. Recent market volatility and credit market disruption have demonstrated that credit availability and issuer credit ratings can be affected by leasechange rapidly. Events negatively affecting credit ratings and rigcredit market liquidity could increase borrowing costs or limit availability complex geology and other factors. Anticipated drilling plans and capital expenditures may also change dueof funds to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.the Company.

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

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

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

Index to Financial Statements

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

Energen Resources’ Production and Drilling: There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

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

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Energen Resources Customer Concentration: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The four largest oil, natural gas and natural gas liquids purchasers account for approximately 22 percent, 14 percent, 11 percent and 10 percent, respectively, of Energen Resources’ estimated 2008 production. Energen Resources’ other purchasers each bought less than 8 percent of production.

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

AccessComplex federal, state and local laws and regulations:Energen and Alagasco are subject to Credit Markets: The Companyextensive federal, state and its subsidiaries rely on access to credit markets. The availability and cost of credit market access islocal regulation which significantly influenced by rating agency evaluations ofinfluences operations. Although, the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of Alagasco. Events affecting credit market liquidityoperations and subject the Company to administrative, civil and criminal penalties. Further, these laws and regulations could change in ways that substantially increase borrowing costs or limit availability of funds.operations.

None

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Index to Financial Statements

The corporate headquarters of Energen, Alagasco and Energen Resources are located in leased office space in Birmingham, Alabama. See the discussion under Item 1-Business1, Business for further information related to Energen Resources’ and Alagasco’s business operations. Information concerning Energen Resources’ production and reserves is summarized in the table below and included in Note 18,17, Oil and Gas Operations (Unaudited), in the Notes to Financial Statements. See Item 7, -Management’sManagement’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the future outlook and expectations for Energen Resources and Alagasco.

Oil and Gas Operations

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

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

The following table sets forth the production volumes for the year ended December 31, 2007,2008, and proved reserves and reserves-to-production ratio by area as of December 31, 2007:2008:

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Index to Financial Statements

The following table sets forth proved reserves by area as of December 31, 2007:2008:

The following table sets forth proved developed reserves by area as of December 31, 2007:2008:

Energen Resources files Form EIA-23 with the Department of Energy which reports gross proved reserves, including the working interest share of other owners, for properties operated by the Company. The proved reserves reported in the table above represent our share of proved reserves for all properties, based on our ownership interest in each property. For properties operated by Energen Resources, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Company-owned proved reserves reported in the table above does not exceed five percent. Estimated proved reserves as of December 31, 20072008 are based upon studies for each of our properties prepared by Company engineers and reviewed by Ryder Scott Company, L.P. and T. Scott Hickman and Associates, Inc., independent oil and gas reservoir engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines.

The following table sets forth the total net productive gas and oil wells by area as of December 31, 2007,2008, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

Natural Gas Distribution

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

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

14

affiliates. It should be noted, however, that Energen and its affiliates

Index to Financial Statements

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

Jefferson County, Alabama

InAs discussed in prior filings, in January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources’ calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. RGGS seeks a declaratory judgmentThe lawsuit was settled during December 2008. Consistent with respect to the parties’ rights under the lease, reformationCompany’s evaluation of the lease, monetary damages and termination of Energen Resources’ rights undercase, 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. During 2007, Energen Resources’ production associated with the lease was approximately 10.5 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 nodid not incur any material accrual with respect to the litigation or purported lease termination.charge.

Enron Corporation

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

Legacy Litigation

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

Other

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

No matters were submitted to a vote of security holders during the fourth quarter of 2007.2008.

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Index to Financial Statements

EXECUTIVE OFFICERS OF THE REGISTRANTS

Energen Corporation

16

Index to Financial Statements

17

Index to Financial Statements

PART II

Quarterly Market Prices and Dividends Paid Per Share

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On February 8, 2008,17, 2009, there were 7,1356,902 holders of record of Energen’s common stock. At the date of this filing, Energen Corporation owned all the issued and outstanding common stock of Alabama Gas Corporation. Energen expects to pay annual cash dividends of $0.48$0.50 per share on the Company’s common stock in 2008.2009. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

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

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

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Index to Financial Statements

PERFORMANCE GRAPH

Energen Corporation — Comparison of Five-Year Cumulative Shareholder Returns

This graph compares the total shareholder returns of Energen, the Standard & Poor’s Composite Stock Index (S&P 500), the Standard & Poor’s Supercomposite Oil & Gas Exploration & Production Index (S15OILP), and the Standard & Poor’s Supercomposite Gas Utilities Index (S15GASUX). The graph assumes $100 invested at the per-share closing price of the common stock on the New York Exchange Composite Tape on December 31, 2002,2003, in the Company and each of the indices. Total shareholder return includes reinvested dividends.

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Index to Financial Statements

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

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

20

Index to Financial Statements

SELECTED BUSINESS SEGMENT DATA

Energen Corporation

21

Index to Financial Statements

RESULTS OF OPERATIONS

Consolidated Net Income

Energen Corporation’s net income for the year ended December 31, 20072008 totaled $309.2$321.9 million, or $4.28$4.47 per diluted share and compared favorably to the year ended December 31, 20062007 net income of $273.6$309.2 million, or $3.73$4.28 per diluted share. This 14.74.4 percent increase in earnings per diluted share (EPS) largely reflected the result of significantly higher prices for natural gas, oil and natural gas liquids and the impact of a 33.7 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen Resources Corporation, Energen’s oil and gas subsidiary, partially offset by the prior year after-tax gain of approximately $34.5 million, or $0.47 per diluted share, on the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shale to Chesapeake Energy Corporation (Chesapeake).higher lease operating expense and increased depreciation, depletion and amortization (DD&A) expense. For the year ended December 31, 2007,2008, Energen Resources earned $273.2$282.7 million, as compared with $237.6$273.2 million in the previous year. Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, generated net income of $36.8$40.2 million in the current year as compared with net income in the prior period of $37.3$36.8 million. For the year ended December 31, 2005,2006, Energen reported earningsnet income of $173$273.6 million, or $2.35$3.73 per diluted share.

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

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

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

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

2006 vs 2005:Energen Resources’ net income rose 75.6 percent to $237.6 million in 2006. Energen Resources’ income from continuing operations totaled $237.6 million in 2006 as compared with $135.2 million in 2005 primarily due to increased commodity prices of approximately $77 million after-tax along with the impact of increased production volumes of approximately $16 million after-tax, the $34.5 million after-tax gain on the sale to Chesapeake and the $6.7 million after-tax gain on the Enron bankruptcy settlement. These increases were partially offset by higher lease operating expense of approximately $19 million after-tax, increased DD&A expense of approximately $5 million after-tax and increased administrative expenses of approximately $5 million after-tax. Alagasco earnings increased to $37.3 million in 2006 from $37 million in 2005 largely as a result of $2 million after-tax increase arising from the utility’s ability to earn on a higher level of equity and reductions in the prior year under the utility’s rate setting mechanism of $1.9 million after-tax largely offset by a decrease in customer usage and a $0.9 million after-tax reduction associated with the CCM giveback. Alagasco achieved a ROE of 13.1 percent in 2006 compared with 13.5 percent in 2005.

Operating Income

Consolidated operating income in 2008, 2007 and 2006 and 2005 totaled $562.1 million, $522 million $477.3 million and $315.7$477.3 million, respectively. This growth in operating income has been influenced by strong financial performance from Energen Resources under Energen’s diversifiedarising from increased

Index to Financial Statements

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

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

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

In 2006, revenues from oil and gas operations increased primarily as a result of increased commodity prices and increased production volumes. Production increased primarily due to additional development activities in the San Juan Basin, accelerated workovers due to milder winter weather and increased volumes related to the purchase of Permian Basin oil properties in the fourth quarter of 2005. Negatively affecting production were normal production declines. Revenue per unit of production related to natural gas increased 16.2 percent to $6.96 per Mcf, oil revenue per unit of production rose 41.5 percent to $49.79 per barrel and natural gas liquids revenue per unit of production increased 20 percent to an average price of $0.66 per gallon during the year ended December 31, 2006. Production from continuing operations increased 5 percent to 95.6 Bcfe in 2006. Natural gas production rose 2.9 percent to 62.8 Bcf, oil volumes increased 9.9 percent to 3,645 MBbl and natural gas liquids production increased 8.2 percent to 76.3 MMgal.

Coalbed methane operating fees are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes and operating expenses. Revenues from operating fees were $8.6 million, $6.1 million and $6.6 million in 2008, 2007 and $8.7 million in 2007, 2006, and 2005, respectively. During 2006, Energen Resources recorded a $55.5 million pre-tax gain in other operating revenues for the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shaleshales to Chesapeake.

23

Index to Financial Statements

Operations and maintenance (O&M) expense increased $22.6 million and $28.7 million in 2008 and $31.5 million in 2007, and 2006, respectively. Lease operating expense (excluding production taxes) in 2008 increased $25.8 million largely due to higher workover expense, (approximately $10 million), increased transportation costs primarily related to increased San Juan production (approximately $5 million), additional compression costs (approximately $3 million), higher ad valorem taxes (approximately $2 million) and increased labor costs (approximately $2 million). In 2007, lease operating expense (excluding production taxes) increased $13.4 million largely due to additional compression costs (approximately $2 million), increased repair and maintenance expense in the San Juan and Permian basins (approximately $7 million), higher transportation related to increased San Juan Basin production (approximately $3 million) and a general rise in field service costs. In 2006, lease operatingAdministrative expense (excluding production taxes) increased by $30.6decreased $9.7 million in 2008 largely due to a varietylower benefit costs primarily related to the Company’s performance-based compensation plans. The year ended 2007 included settlement charges for the nonqualified supplemental retirement plans and the defined benefit pension plans of factors including the December 2005 acquisition of Permian Basin oil properties (approximately $9 million), additional maintenance expense primarily in the San Juan Basin designed to increase production (approximately $2 million), increased workover expense (approximately $6 million), higher transportation costs (approximately $4 million), an increased number of wells in period comparisons and other overall cost increases.$2.3 million. In 2007, administrative expense increased $16.6 million primarily due to a prior year2006 pre-tax gain of $10.7 million on the sale of Energen Resources’ bankruptcy claims against Enron and increased labor-related costs, including settlement charges for the nonqualified supplemental retirement plans and the defined benefit pension plans of $2.3 million. Administrativemillion as discussed above. Exploration expense decreased $2.6rose $6.4 million in 20062008 largely due to the $10.7 million pre-tax gain against Enron; this gain was partially offset by higher labor-related costs. Explorationwriteoff of two wells in the San Juan Basin where mechanical difficulties were encountered. In 2007, exploration expense declined $1.3 million in 2007 largely due to decreased exploratory efforts. In 2006, exploration expense rose $3.5 million.

DD&A expense increased $25.3 million in 2008 and $16.4 million in 2007 and $8.5 million in 2006.2007. The average DD&A rates were $1.33 per Mcfe in 2008, $1.13 per Mcfe in 2007 and $1.00 per Mcfe in 2006 and $0.96 per Mcfe2006. Higher development costs along with the impact in 2005.the fourth quarter of pricing year-end proved reserves resulted in an increase in the average 2008 DD&A rate of approximately $20.6 million. The increase in the average 2007 DD&A rate, which contributed approximately $13 million, was primarily due to higher development costs along with a decline in prior2006 year-end reserve prices. Increased production volumes also contributed approximately $4.2 million and $3 million to the increase in DD&A expense in the current year. The increase in the average 2006 rate contributed approximately $3.8 million2008 and was largely due to higher depletion rates on oil properties purchased in the Permian Basin in December 2005 and higher rates due to a downward revision to estimated reserves resulting from a reduction in year-end reserve prices. Partially offsetting the higher rate was increased production in lower rate areas. Increased production volumes contributed approximately $4.4 million due to the 2006 increase in DD&A expense.2007, respectively.

Energen Resources’ expense for taxes other than income taxes primarily reflected production-related taxes. Energen Resources recorded severance taxes of $62.6 million, $53.8 million and $49.5 million for 2008, 2007 and $52.32006, respectively. Higher severance taxes in 2008 resulted from increased commodity market prices and higher natural gas and oil production volumes. Higher commodity market prices and the impact of increased production volumes contributed approximately $13.7 million and $2 million, respectively. Partially offsetting the increase in severance taxes during 2008 was a $6.9 million adjustment related to 2005 through 2008 for 2007, 2006 and 2005, respectively.reduced severance taxes in New Mexico. Severance taxes increased $4.3 million in 2007 over the prior year. Higher commodity market prices and the impact of increased production volumes contributed approximately $3$2.7 million and $1.6 million, respectively. Decreased severance taxes in 2006 resulted from lower natural gas commodity market prices largely offset by higher production volumes and increased oil and natural gas liquids commodity market prices. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution:As discussed more fully in Note 2, Regulatory Matters, in the Notes to Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On December 21, 2007, the APSC issued an order and is allowed to extend the utility’s rate-setting mechanism. Under the terms of the extension, RSE will continue after December 31, 2014, unless, after notice to the company andearn a hearing, the APSC votes to modify or discontinue the RSE methodology. Alagasco’s allowed range of return on equity remainsof 13.15 percent to 13.65 percent throughout the term of the order. Prior to the December 21, 2007 extension,percent. At September 30, 2008, RSE limited the utility’s equity upon which a return is permitted to 6057 percent of total capitalization and provided for certain cost control measures designed to monitor Alagasco’s O&M expense. Subsequent to the extension, theThe equity onupon which a return will beis permitted will be phased downlimited to 57 percent by December 31, 2008 and 55 percent by December 31,September 30, 2009.

Prior to the extension, underUnder the inflation-based CCM established by the APSC, if the percentage change in O&M expense per customer fellon an aggregate basis falls within a range of 1.250.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range)(Index Range), no adjustment wasis required. If the change in O&M expense per customer exceededon an aggregate basis exceeds the index range,Index Range, three-quarters of the difference wasis returned to customers. To the extent the change wasis less than the index range,Index Range, the utility benefitedbenefits by one-half of the

Index to Financial Statements

difference through future rate adjustments. The changes to the O&M expense cost control measurement subsequent to the extension are as follows: annual changes in O&M expense will be measured on an aggregate basis rather than per customer; the

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percentage change in O&M expense must fall within a range of 0.75 points above or below the percentage change in the index range; certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the cost control measurement calculation; the O&M expense base for measurement purposes will continue to be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the index rangeIndex Range in two successive years, in which case the base for the following year will be set at the top of the index range.

Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the cost control measurement calculation. Alagasco generates revenues through the sale and transportation of natural gas. The transportation rate does not contain an amount representing the cost of gas, and Alagasco’s rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues, but the financial impactrevenues; as such Alagasco is moderated byallowed recovery of a temperature adjustment mechanism that requires Alagasco to adjust certain customer bills monthly to reflect changes in usage due tomoderate the impact of departures from normal temperatures.temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

Alagasco’s natural gas and transportation sales revenues totaled $654.8 million, $609.5 million and $663.4 million in 2008, 2007 and $600.72006, respectively. In 2008, sales revenue increased primarily due to an increase in gas costs of approximately $22 million and a weather-driven increase in customer usage of approximately $11 million. Adjustments from the utility’s rate setting mechanisms also contributed to the increase in revenues as Alagasco charged approximately $4 million against the ESR during the third quarter of 2008 due to a decline in usage by market sensitive large commercial and industrial customers. At the end of the 2008 rate year, the increase in O&M expense was below its inflation-based cost control measure; as a result the utility benefited by a $2.9 million pre-tax increase in revenues. At the end of the 2007 2006 and 2005, respectively.rate year, Alagasco had a $3.6 million pre-tax reduction in revenues to bring the return on average equity to midpoint in the allowed range of return. Sales revenue in 2007 declined largely due to a decrease in gas costs of approximately $28 million and a decline in customer usage of approximately $27 million. In 2006,2008, weather that was 13.3 percent colder than in the prior year contributed to a 4.7 percent increase in residential sales revenue increased primarilyvolumes while commercial and industrial volumes rose 3.2 percent. Transportation volumes declined 9.1 percent largely due to an increase in gas costs approximately $82 million partially offset by a decrease in customerdecreased usage of approximately $28 million.from construction industry related customers. In 2007, weather was 7.9 percent warmer than in the prior year. Residential sales volumes declined 7.4 percent while commercial and industrial volumes decreased 5.6 percent. Transportation volumes rose 1.4 percent. In 2006, weather that was 2.5 percent warmer than in the prior year along with customer conservation related to higherHigher gas costs contributed tocombined with an increase in gas purchase volumes resulted in a 9.310.5 percent declineincrease in residential sales volumes while commercial and industrial volumes decreased 10.2 percent. Transportation volumes increased 1.8 percent.cost of gas in 2008. In 2007, lower gas costs along with decreased gas purchase volumes contributed to a 14.7 percent decrease in cost of gas. Higher gas costs partially offset by a decline in gas purchase volumes resulted in a 17.2 percent increase in cost of gas in 2006.

O&M expense at the utility increased 1.9decreased 1.1 percent in 20072008 primarily due to increasedlower labor-related costs (approximately $2$3.9 million), including and decreased insurance costs (approximately $1.9 million) partially offset by increased consulting and technology fees (approximately $3.5 million) and higher bad debt expense (approximately $1 million). The year ended December 31, 2007 included settlement charges for the nonqualified supplemental retirement plans and the defined benefit pension plans of $3.4 million. In 2007, O&M expense at the utility increased 1.9 percent primarily due to increased labor-related costs (approximately $2 million), including settlement charges of $3.4 million as discussed above, largely offset by decreased bad debt expense (approximately $1 million). InFor the rate year ended September 30, 2006, O&M expense increased slightly primarily due to higher bad debt expense (approximately $1 million) and increased distribution maintenance expenses (approximately $1.7 million). These increases were offset by decreased labor-related expenses (approximately $4.5 million). Thethe increase in O&M expense per customer for the rate year ended September 30, 2006 was above the inflation-based CCM established by the APSC as part of the utility’s rate-setting mechanism;Index Range; as a result, three quarters of the differences,difference, or $1.5 million pre-tax, was returned to the customers through RSE (see Note 2, Regulatory Matters, in the Notes to Financial Statements).RSE. Alagasco’s O&M expense fell within the index rangeIndex Range for the rate yearsyear ended September 30, 2007 and 2005.2007.

Depreciation expense rose 3.7 percent and 6.5 percent in 2008 and 4.5 percent in 2007, and 2006, respectively, due to extension and replacement of the utility’s distribution and replacement of its support systems. Alagasco’s expense for taxes other than income primarily reflects various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

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Index to Financial Statements

Non-Operating Items

Consolidated:Interest expense in 2008 declined $5.1 million largely due to the May 2007 declinedvoluntary call of the $100 million Floating Rate Senior Notes due November 15, 2007 along with lower interest rates on short term borrowings. In 2007, interest expense decreased $1.6 million primarily due to lower borrowings at Energen Resources along with decreased interest expense associated with the May 2007 voluntary call of the $100 million Floating Rate Senior Notes due November 15, 2007.Notes. Also contributing to the decrease in interest expense at Alagasco was the January 2007 redemption of $34.4 million of 6.75% Notes maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026 partially offset by the issuance of $45 million in long-term debt with an interest rate of 5.9%. Interest expenseThe average daily outstanding balance under short-term credit facilities was $89.2 million in 2006 increased $1.9 million largely due to financing costs associated with higher storage gas inventories at Alagasco and an increase in interest rates associated with Energen’s $100 million Floating Rate Senior Notes.2008. The average daily outstanding balance under short-term credit facilities was $67.7 million in 2007. The average daily outstanding balance under short-term credit facilities was2007 as compared to $63.7 million in 2006 as compared to $17.7 million in 2005.2006. Income tax expense increased in the periods presented primarily due to higher pre-tax income. Also increasing income tax expense during 2008 was the approximate $8 million reduction in the after-tax benefit of the Section 199 deduction. Partially offsetting the increase in income tax expense in 2007 was the after-tax impact of the Section 199 deduction (approximatelyof approximately $7 million after-tax).million.

FINANCIAL POSITION AND LIQUIDITY

The Company’s net cash from operating activities totaled $569.2 million, $484.2 million and $482.9 million in 2008, 2007 and $335.1 million in 2007, 2006, and 2005, respectively. Operating cash flow in 2008, 2007 2006 and 20052006 benefited from higher realized commodity prices and production volumes at Energen Resources. NegativelyPositively affecting operating cash flows during 2008 was a decrease from the prior period in income taxes payable related to the tax effect of depreciation and basis differences. During 2007, was anoperating cash flows were negatively affected by the increase in income taxes payable related to the tax effect of the depreciation and basis differences inalong with the current period and the prior period2006 utilization of minimum tax credit. In 2006, income from operations before income taxes included a pre-tax gain of $55.5 million related to the Chesapeake acreage sale; the cash proceeds from the sale are included in the investing activities on the Consolidated Statements of Cash Flows, as described more fully below.sale. During 2008, working capital needs were primarily affected by increased gas costs and income tax receivables. Working capital needs at Alagasco were reduced by declining gas costs for 2007. During 2006, and 2005, working capital needs at Alagasco were largely affected by increased gas costs compared to the prior period and storage gas inventory. Other working capital items, which primarily are the result of changes in throughput and the timing of payments, combined to create the remaining increases for all years.

During 2008, the Company made net investments of $464.6 million. Energen Resources invested $19 million in property acquisitions including approximately $18.1 million of unproved leaseholds (including approximately $13 million related to Alabama shales), $386.7 million for development costs including approximately $262 million (excludes approximately $45 million of accrued development cost) to drill 285 net development and service wells and $19.5 million for exploration. Energen Resources had cash proceeds in 2008 of $16.2 million from the sale of certain properties. Utility expenditures in 2008 totaled $62.6 million and primarily represented extension and replacement of its distribution system and support facilities. During 2007, the Company made net investments of $431.9 million. Energen Resources invested $54.6 million in property acquisitions, including an $18 million acquisition in the Permian Basin and approximately $32 million of unproved leaseholds (including approximately $28 million related to Alabama shale)shales), $313.2 million for development costs including approximately $202 million to drill 345 gross236 net development and service wells and $7.5 million for exploration. Utility expenditures in 2007 totaled $58.2 million and primarily represented extension and replacement of its distribution system and support facilities.million. During 2006, the Company made net investments of $256.9 million. Energen Resources invested $46.4 million in property acquisitions, $186.3 million for development costs including approximately $130.6 million to drill 309 gross188 net development and service wells and $25.9 million for exploration. In December 2006, Energen Resources completed its purchase of gas properties located in the San Juan Basin from Dominion Resources, Inc. for approximately $30 million. Energen Resources sold certain properties during 2006, resulting in cash proceeds of $79.4$75.4 million including $75 million received from Chesapeake for a 50 percent interest in its lease position in certain unproved shaleshales acreage in Alabama. Utility expenditures in 2006 totaled $75.1 million.

Index to Financial Statements

During 2005, cash used in investing activities totaled $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 for approximately $168 million. During 2005, Energen Resources sold certain properties resulting in cash proceeds of $10.8 million. Utility expenditures in 2005 totaled $72.4 million.

During 2007,2008, the Company added approximately 151.2 Bcfe of reserves primarily from the Permian Basina North Louisiana/East Texas acquisition. Also during 2007,2008, Energen Resources added 127124 Bcfe of reserves from discoveries and other additions, primarily the result of improveddevelopment drilling technology that increased the number of proved undeveloped locations in both the San Juan Basinand Permian basins as well as continued downspacing in the Permian Basin.Basin. Energen Resources added approximately 167142 Bcfe and 224167 Bcfe of reserves in 2007 and 2006, and 2005, respectively.

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The Company used $100.2 million for net financing activities in 2008 primarily for the repayment of short-term debt borrowings. In addition, long-term debt was reduced by $10.9 million for current maturities in 2008. The Company used $53.9 million for net financing activities in 2007 primarily for the early redemption of $100 million Floating Rate Senior Notes due November 15, 2007, $34.4 million of 6.75% Notes maturing September 1, 2031, $10 million of Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026. Partially offsetting these uses of cash was the January 2007 issuance by Alagasco of $45 million in long-term debt with an interest rate of 5.9% due January 15, 2037. In 2006, net cash used for financing activities totaled $224.4 million largely due to $84.3 million incurred from the buy-back of Energen common stock under its stock repurchase plan along with the repayment of short-term borrowings. In addition, long-term debt was reduced by $15.9 million for current maturities in 2006. The Company provided $69.8 million from net financing activities in 2005. 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. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders.

Capital Expenditures

Oil and Gas Operations:Energen Resources spent a total of approximately $1$1.1 billion for capital projects during the years ended December 31, 2008, 2007 2006 and 2005.2006. Property acquisition expenditures totaled $289.5$120 million, development activities totaled $656.9$912.4 million, and exploratory expenditures totaled $38.5$52.9 million.

Natural Gas Distribution:During the years ended December 31, 2008, 2007 2006 and 2005,2006, Alagasco invested $208.3$198.3 million for capital projects: $164.5$154.4 million for expansion, replacements and support of its distribution system and $43.7$43.9 million for support facilities and the development and implementation of information systems.