UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2010

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

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

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

Telephone Number 205/326-2700

http://www.energen.com

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

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

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

Indicate by check mark if the registrants are a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    YES   x    NO  ¨

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Energen Corporation            YES  x    NO  ¨

Alabama Gas Corporation    YES  ¨    NO  ¨

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

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

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

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

Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30, 2010:

Energen Corporation $3,178,428,000

Indicate number of shares outstanding of each of the registrant’s classes of common stock as of February 16, 2011:

Energen Corporation	72,058,777 shares
Alabama Gas Corporation	1,972,052 shares

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

DOCUMENTS INCORPORATED BY REFERENCE

Energen Corporation Proxy Statement to be filed on or about March 18, 2011 (Part III, Item 10-14)

INDUSTRY GLOSSARY

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

Basis	The difference between the futures price for a commodity and the corresponding cash spot price. This commonly is related to factors such as product quality, location and contract pricing.
Basin-Specific	A type of derivative contract whereby the contract’s settlement price is based on specific geographic basin indices.
Behind Pipe Reserves	Oil or gas reserves located above or below the currently producing zone(s) that cannot be extracted until a recompletion or pay-add occurs.
Cash Flow Hedge	The designation of a derivative instrument to reduce exposure to variability in cash flows from the forecasted sale of oil, gas or natural gas liquids production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale.
Collar	A financial arrangement that effectively establishes a price range between a floor and a ceiling for the underlying commodity. The purchaser bears the risk of fluctuation between the minimum (or floor) price and the maximum (or ceiling) price.
Development Costs	Costs necessary to gain access to, prepare and equip development wells in areas of proved reserves.
Development Well	A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Downspacing	An increase in the number of available drilling locations as a result of a regulatory commission order.
Dry Well	An exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Exploration Expenses	Costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties, exploratory geological and geophysical activities, and costs of impaired and expired leaseholds.
Exploratory Well	A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
Futures Contract	An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price. Such contracts offer liquidity and minimal credit risk exposure but lack the flexibility of swap contracts.
Hedging	The use of derivative commodity instruments such as futures, swaps, options and collars to help reduce financial exposure to commodity price volatility.
Gross Revenues	Revenues reported after deduction of royalty interest payments.
Gross Well or Acre	A well or acre in which a working interest is owned.
Liquified Natural Gas (LNG)	Natural gas that is liquified by reducing the temperature to negative 260 degrees Fahrenheit. LNG typically is used to supplement traditional natural gas supplies during periods of peak demand.
Long-Lived Reserves	Reserves generally considered to have a productive life of approximately 10 years or more, as measured by the reserves-to-production ratio.
Natural Gas Liquids (NGL)	Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and other hydrocarbons.
Net Well or Acre	A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.

Odorization	The adding of odorant to natural gas which is a characteristic odor so that leaks can be readily detected by smell.
Operational Enhancement	Any action undertaken to improve production efficiency of oil and gas wells and/or reduce well costs.
Operator	The company responsible for exploration, development and production activities for a specific project.
Pay-Add	An operation within a currently producing wellbore that attempts to access and complete an additional pay zone(s) while maintaining production from the existing completed zone(s).
Pay Zone	The formation from which oil and gas is produced.
Production (Lifting) Costs	Costs incurred to operate and maintain wells.
Productive Well	An exploratory or a development well that is not a dry well.
Proved Developed Reserves	The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves	Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves (PUD)	The portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
Recompletion	An operation within an existing wellbore whereby a completion in one pay zone is abandoned in order to attempt a completion in a different pay zone.
Reserves-to- Production Ratio	Ratio expressing years of supply determined by dividing the remaining recoverable reserves at year end by actual annual production volumes. The reserve-to-production ratio is a statistical indicator with certain limitations, including predictive value. The ratio varies over time as changes occur in production levels and remaining recoverable reserves.
Secondary Recovery	The process of injecting water, gas, etc., into a formation in order to produce additional oil otherwise unobtainable by initial recovery efforts.
Service Well	A well employed for the introduction into an underground stratum of water, gas or other fluid under pressure or disposal of salt water produced with oil or other waste.
Sidetrack Well	A new section of wellbore drilled from an existing well.
Swap	A contractual arrangement in which two parties, called counterparties, effectively agree to exchange or “swap” variable and fixed rate payment streams based on a specified commodity volume. The contracts allow for flexible terms such as specific quantities, settlement dates and location but also expose the parties to counterparty credit risk.
Transportation	Moving gas through pipelines on a contract basis for others.
Throughput	Total volumes of natural gas sold or transported by the gas utility.
Working Interest	Ownership interest in the oil and gas properties that is burdened with the cost of development and operation of the property.
Workover	A major remedial operation on a completed well to restore, maintain, or improve the well’s production such as deepening the well or plugging back to produce from a shallow formation.
-e	Following a unit of measure denotes that the oil and natural gas liquids components have been converted to cubic feet equivalents at a rate of 6 thousand cubic feet per barrel.

ENERGEN CORPORATION

2010 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

	PART I	Page
Item 1.	Business		3
Item 1A.	Risk Factors		11
Item 1B.	Unresolved Staff Comments		12
Item 2.	Properties		13
Item 3.	Legal Proceedings		16
Item 4.	[Removed and Reserved]		16
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		19
Item 6.	Selected Financial Data		21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		23
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		39
Item 8.	Financial Statements and Supplementary Data		40
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		93
Item 9A.	Controls and Procedures		93
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		96
Item 11.	Executive Compensation		96
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		96
Item 13.	Certain Relationships and Related Transactions, and Director Independence		96
Item 14.	Principal Accountant Fees and Services		96
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		97
Signatures			103

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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: The disclosure and analysis in this 2010 Annual Report on Form 10-K contains forward-looking statements that express management’s expectations of future plans, objectives and performance of the Company and its subsidiaries. Such statements constitute forward-looking statements within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended, and are noted in the Company’s disclosure as permitted by the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address the Company’s future business and financial performance and financial condition, and often contain words such as “expect”, “anticipate”, “intend”, “plan”, “believe”, “seek”, “see”, “project”, “will”, “estimate”, “may”, and other words of similar meaning.

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, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, gas and natural gas liquids, fluctuations in the weather, drilling risks, costs associated with compliance with environmental obligations, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other factors and uncertainties discussed elsewhere in this 10-K and in the Company’s other public filings and press releases, all of which are difficult to predict. While it is not possible to predict or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors that may affect the Company’s future business and financial performance.

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

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.

PART I

ITEM 1. BUSINESS

General

Energen Corporation, based in Birmingham, Alabama, is a diversified energy holding company engaged 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.

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The Company maintains a Web site with the address www.energen.com. The Company does not include the information contained on its Web site as part of this report nor is the information incorporated by reference into this report. The Company makes available free of charge through its Web site the annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports. 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 Business Conduct Guidelines, Corporate Governance Guidelines, Audit Committee Charter, Officers’ Review Committee Charter, Governance and Nominations Committee Charter and Finance Committee Charter, each of which is available in print upon shareholder request.

Financial Information About Industry Segments

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

Narrative Description of Business

• Oil and Gas Operations

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

At the end of 2010, Energen Resources’ proved oil and gas reserves totaled 1,818 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 77 percent of Energen Resources’ year-end reserves are proved developed reserves. Energen Resources’ reserves are long-lived, with a year-end reserves-to-production ratio of 16 years. Natural gas, oil and natural gas liquids represent approximately 53 percent, 34 percent and 13 percent, respectively, of Energen Resources’ proved reserves.

Growth Strategy: Energen has operated for more than fifteen years under a strategy to grow the oil and gas operations of Energen Resources largely through the acquisition and exploitation of proved and high-quality unproved reserves. The company traditionally prefers properties located onshore in North America that offer long-lived reserves and multiple pay-zone opportunities. Energen Resources also conducts exploration activities in and around the basins in which it operates; exploration in other areas is possible if the opportunities complement its core expertise and meet its investment requirements. Following an acquisition, Energen Resources focuses on increasing production and reserves through 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 drilling and development activities. Energen Resources operated approximately 93 percent of its proved reserves at December 31, 2010.

Since the end of fiscal year 1995, Energen Resources has invested approximately $1.6 billion to acquire proved and unproved reserves, $2.3 billion in related development and $509 million in exploration. Energen Resources’ capital spending plans for 2011 target a total investment of approximately $667 million, the bulk of which will focus on drilling and related development activities on its existing properties. The company may choose to allocate additional capital during the year for property acquisitions and/or increased drilling and development activities.

During 2010, Energen Resources incurred write-offs of unproved capitalized leasehold costs associated with its Alabama shale acreage. The non-cash costs totaled $39.7 million pre-tax and were charged to exploration expense, which is included in O&M expense, after the Company determined that the shale acreage was not economically viable. During the year ended December 31, 2010, Energen Resources also recorded $15.5 million pre-tax in write-offs of well costs related to Alabama shale leasehold.

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During 2009 Energen Resources was unsuccessful in the completion of a Chattanooga shale well. The costs related to this well of approximately $5.6 million pre-tax were expensed during the fourth quarter of 2009. Also expensed during the fourth quarter, was approximately $1.2 million pre-tax of costs associated with a well originally drilled by Chesapeake in an area of the Chattanooga shale. The Company recognized unproved leasehold impairments of $2.1 million associated with these wells.

Energen Resources’ development activities can result in the addition of new proved reserves and can serve to reclassify proved undeveloped reserves to proved developed reserves. Proved reserve disclosures are provided annually, although changes to reserve classifications occur throughout the year. Accordingly, additions of new reserves from development activities can occur throughout the year and may result from numerous factors including, but not limited to, regulatory approvals for drilling unit downspacing that increase the number of available drilling locations; changes in the economic or operating environments that allow previously uneconomic locations to be added; technological advances that make reserve locations available for development; successful development of existing proved undeveloped reserve locations that reclassify adjacent probable locations to proved undeveloped reserve locations; increased knowledge of field geology and engineering parameters relative to oil and gas reservoirs; and changes in management’s intent to develop certain opportunities.

During the three years ended December 31, 2010, the Company’s development efforts have added 392 Bcfe of proved reserves from the drilling of 956 gross development and service wells (including 21 sidetrack wells) and 318 well recompletions and pay-adds. In 2010, Energen Resources’ successful development wells and other activities added approximately 161 Bcfe of proved reserves; the Company drilled 329 gross development and service wells (including 7 sidetrack wells), performed some 124 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources’ production totaled 113 Bcfe in 2010 and is estimated to total 124 Bcfe in 2011, including 118 Bcfe of estimated production from proved reserves owned at December 31, 2010.

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

Years ended December 31,	2010		2009		2008
Development:
Productive		210.0		130.4	199.2
Dry		1.0		0.0	0.9
Total		211.0		130.4	200.1
Exploratory:
Productive		3.4		1.0	1.8
Dry		5.0		2.5	1.7
Total		8.4		3.5	3.5

As of December 31, 2010, the Company was participating in the drilling of 14 gross development and exploratory wells, with the Company’s interest equivalent to 11 wells. In addition to the development wells drilled, the Company drilled 39.8, 32.5 and 84.1 net service wells during 2010, 2009 and 2008, respectively. As of December 31, 2010, the Company was participating in the drilling of 1 gross service well, with the Company’s interest equivalent to 0.02 wells.

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Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2010, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

	Gross	Net
Gas wells	4,343	2,397
Oil wells	3,964	2,413
Developed acreage	758,772	558,189
Undeveloped acreage	157,084	111,052

There were 7 wells with multiple completions in 2010. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Texas.

Risk Management: Energen Resources attempts to lower the commodity price risk associated with its oil and natural gas business through the use of swaps and basis hedges. Energen Resources does not hedge more than 80 percent of its estimated annual production. Energen Resources recognized all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in operating revenues immediately.

The Company may also enter into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding New York Mercantile Exchange hedge and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

See the Forward-Looking Statements preceding Item 1, Business, and Item 1A, Risk Factors, for further discussion with respect to price and other risks.

• Natural Gas Distribution

General: Alagasco is the largest natural gas distribution utility in the state of Alabama. Alagasco purchases natural gas through interstate and intrastate 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 large 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 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 180 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.5 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2010, Alagasco served an average of 404,697 residential customers and 32,632 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 11,155 miles of main and more than 11,925 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’s current extension is for a seven-year period ended December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and

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a hearing, 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. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the CCM calculation.

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed 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.

The APSC approved an Enhanced Stability Reserve (ESR) beginning October 1997, with a maximum funding level of $4 million pre-tax, to which Alagasco could charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses caused Alagasco’s year-end return on average equity (RCE) to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent. Prior to June 28, 2010, the APSC provided for accretions to the ESR of no more than $40,000 monthly until the maximum funding level was achieved, following a year in which a charge against the ESR was made. The APSC’s June 28, 2010 order approved Alagasco’s lower depreciation rates and approved standing authority for Alagasco to charge items to the ESR in excess of its funded balance and to allocate each year from the refundable negative salvage costs that are being refunded to customers over the nine year period the amount necessary to clear the debit balance in the ESR each September 30, subject to APSC-approved guidelines. The APSC also approved the amortization of the charges to the ESR into rates over a five year period in cases where the ESR is unfunded or underfunded, subject to APSC-approved guidelines. As a result of these changes in the funding mechanism for the ESR, the APSC suspended the $40,000 per month accruals to the ESR during the nine year period when the refundable negative salvage costs are being refunded to customers.

Following a vote on September 7, 2010, the APSC, by order dated November 1, 2010, approved expansion of the ESR to include extraordinary O&M charges related to environmental response costs and to self insurance costs that exceed $1 million per occurrence. In addition, the APSC raised the thresholds on items that may be charged to the ESR as follows: (1) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single event that results in more than $275,000 of increased O&M; (2) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a combination of extraordinary O&M events that result in more than $412,500 of increased O&M; and (3)

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individual large commercial and industrial customer revenue variances that exceed $350,000. Charges to the ESR relating to extraordinary O&M expenses can only be made when the Company’s year-end return on average common equity for RSE, not including the ESR charge, is below the midpoint of the APSC-approved return on equity range and only to the extent necessary to bring the RCE to the midpoint of the range. Charges to the ESR relating to individual large commercial and industrial customer revenue losses can only be made if such losses cause the RCE to fall below the bottom of the APSC-approved return on equity range, currently at 13.15 percent, and then only to the extent necessary to bring the RCE up to the midpoint of the range. In the event that Alagasco’s RCE at September 30 of the related year is above the midpoint, any debit balance in the ESR shall remain in the ESR for recovery in subsequent years subject to the established guidelines. Additionally, the APSC, while confirming the five year amortization period established in the June 28, 2010 order for charges to the ESR in cases where the ESR is unfunded or underfunded, limited the amortization expense to $660,000 annually, with any excess amortization expense over $660,000 in any rate year being carried over and amortized in future rate years until full amortization of the ESR debit balance is complete. The APSC also raised the $40,000 per month accruals to $55,000 per month, but suspended the accruals pending further order of the APSC. Finally, the APSC established guidelines for the documentation, reporting and approval of rate recovery of items charged to the ESR.

In connection with the above, Alagasco expects to recover certain manufactured gas plant site remediation costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory account, as more fully described in Environmental Matters.

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 two 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.

As of December 31, 2010, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:

	December 31, 2010
	(Mcfd)
Southern firm transportation	112,933
Southern storage and no notice transportation	231,679
Transco firm transportation	70,000
Various intrastate transportation	20,216

Competition: The price of natural gas is a significant competitive factor in Alagasco’s service territory, particularly among large commercial and industrial transportation customers. Propane, coal and fuel oil are readily available, and many industrial customers have the capability to switch to alternate fuels and alternate sources of gas. In the residential and small commercial and industrial markets, electricity is the principal competitor. With the support of the APSC, Alagasco has implemented a variety of programs to help it compete for gas load in all market segments. The Company has been effective at utilizing these programs to avoid load loss to competitive fuels.

Alagasco’s Transportation Tariff allows the Company to transport gas for large commercial and industrial customers rather than buying and reselling it to them and is based on Alagasco’s sales profit margin so that operating margins are unaffected. During 2010, substantially all of Alagasco’s large commercial and industrial customer deliveries involved the transportation of customer-owned gas.

8

Natural gas service available to Alagasco customers falls into two broad categories: interruptible and firm. Interruptible service contractually is subject to interruption at Alagasco’s discretion. The most common reason for such interruption is curtailment during periods of peak core market heating demand. Customers who contract for interruptible service can generally adjust production schedules or switch to alternate fuels during periods of service interruption or curtailment. More expensive firm service, on the other hand, generally is not subject to interruption and is provided to residential and small commercial and industrial customers. These core market customers depend on natural gas primarily for space heating.

Growth: Alagasco is a mature utility operating in a slow-growth service area. Over the last five years, Alagasco’s customer count has declined at a rate of approximately 1 percent annually despite above-average levels of penetration along existing distribution lines. To increase its customer base, the utility is capitalizing on opportunities to expand its distribution lines to areas with economic growth potential and pursuing the acquisition of mutually beneficial municipally owned gas systems in Alabama.

Another aspect of growth is usage per customer. Throughout the country, customer use of natural gas has declined over the years in large part due to energy-efficiencies in home construction and appliances and conservation. Alagasco’s marketing emphasis in this area is directed toward retention and increasing end-use applications by existing customers.

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

• Environmental Matters and Climate Change

Various federal, state and local 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. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs. Remediation of the Huntsville, Alabama manufactured gas plant site, as discussed below, may also result in unanticipated costs.

Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend and interpret existing laws and regulations. Such law and regulation changes may occur with little prior notification, subject the Company to cost increases, and impose restrictions and limitations on the Company’s operations. Currently, there are various proposed law and regulatory changes with the potential to materially impact the Company. Such proposals include, but are not limited to, measures dealing with hydraulic fracturing, emission limits and reporting and the repeal of certain oil and gas tax incentives and deductions. Due to the nature of the political and regulatory processes and based on its consideration of existing proposals, the Company is unable to determine whether such proposed laws and regulations are reasonably likely to occur or to be enacted or to determine, if enacted, the magnitude of the potential impact of such laws.

Existing federal, state and local environmental laws and regulations also have the potential to increase costs, reduce liquidity, delay operations and otherwise alter business operations. These existing laws and regulations include, but are not limited to, the Clean Air Act; the Clean Water Act; Oil Pollution Prevention: Spill Prevention Control and Countermeasure regulations; Toxic Substances Control Act; Resource Conservation and Recovery Act and the Federal Endangered Species Act. Compliance with these and other environmental laws and regulations is undertaken as part of the Company’s routine operations. The Company does not separately track costs associated with these routine compliance activities.

Climate change, whether arising through natural occurrences or through the impact of human activities, may have a significant impact upon the operations of Energen Resources and Alagasco. Volatile weather patterns and the resulting environmental impact may adversely impact the results of operations, financial position and cash flows of the Company. The Company is unable to predict the timing or manifestation of climate change or reliably estimate the impact to the Company. However, climate change could affect the operations of the Company as follows:

• sustained increases or decreases to the supply and demand of oil, natural gas and natural gas liquids;

9

• positive or negative changes to usage and customer count at Alagasco from prolonged increases or decreases in average temperature due to the geographic concentration of Alagasco’s customers in central and north Alabama;

• potential disruption to third party facilities to which Energen Resources delivers and from which Alagasco is served. Such facilities include third party oil and gas gathering, transportation, processing and storage facilities and are typically limited in number and geographically concentrated.

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

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

In June 2009, Alagasco received a General Notice Letter from the United States Environmental Protection Agency (EPA) identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, 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 and the current site owner have agreed to enter into a Consent Order and 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 of approximately $4.3 million. During the years ended December 31, 2010 and 2009, the Company incurred costs of $0.7 million and $0.2 million, respectively, associated with the site. As of December 31, 2010, the Company has accrued a contingent liability of $3.4 million in addition to the costs previously incurred. The estimate assumes an action plan for excavation of affected soil and sediment only. 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 and future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

• Employees

The Company has approximately 1,530 employees, of which Alagasco employs 1,110 and Energen Resources employs 420. The Company believes that its relations with employees are good.

10

ITEM 1A. RISK FACTORS

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

Commodity Prices: The Company and Alagasco are significantly influenced by commodity prices. Historical markets for natural gas, oil and natural gas liquids have been volatile. Energen Resources’ revenues, operating results, profitability and cash flows depend primarily upon the prices realized for its oil, gas and natural gas liquid production. Additionally, downward commodity price trends may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.

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

Energen Resources’ Hedging: Although Energen Resources makes use of futures, swaps, options, collars 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, collars 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. In addition, the recent adoption of financial reform legislation could have an adverse effect on the ability of Energen Resources to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

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. In addition, the recent adoption of financial reform legislation could have an adverse effect on the ability of Alagasco to use derivative instruments which could have a material adverse effect on our 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 a small number of 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 a limited number of customers in the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. 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.

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 Energen Resources, Alagasco 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. Further, the Company’s insurance retention levels are such that significant events could adversely affect Energen Resources’, Alagasco’s and the Company’s financial position, results of operations and cash flows. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and the Company’s financial position, results of operations and cash flows.

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

Federal, State and Local Laws and Regulations: Energen and Alagasco are subject to extensive federal, state and local regulation which significantly influences operations. Although the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations. Such changes can subject the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company’s operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

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ITEM 2. PROPERTIES

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

Oil and Gas Operations

Energen Resources focuses on increasing its production and proved reserves through the acquisition and development of onshore North American 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, 2010, and proved reserves and reserves-to-production ratio by area as of December 31, 2010:

	Year ended December 31, 2010		December 31, 2010		December 31, 2010
	Production Volumes (MMcfe)		Proved Reserves (MMcfe)		Reserves-to- Production Ratio
San Juan Basin		56,268		815,224	14.49 years
Permian Basin		36,958		797,083	21.57 years
Black Warrior Basin		13,123		154,457	11.77 years
North Louisiana/East Texas		6,125		45,142	7.37 years
Other		515		5,659	10.99 years
Total		112,989		1,817,565	16.09 years

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The following table sets forth proved reserves by area as of December 31, 2010:

	Gas MMcf		Oil MBbl		NGL MBbl
San Juan Basin		657,106		1,028	25,325
Permian Basin		93,217		102,035	15,276
Black Warrior Basin		154,457		-	-
North Louisiana/East Texas		44,614		88	-
Other		4,993		111	-
Total		954,387		103,262	40,601

The following table sets forth proved developed reserves by area as of December 31, 2010:

	Gas MMcf		Oil MBbl		NGL MBbl
San Juan Basin		531,968		989	22,393
Permian Basin		60,710		70,843	6,416
Black Warrior Basin		146,376		-	-
North Louisiana/East Texas		42,245		87	-
Other		4,993		111	-
Total		786,292		72,030	28,809

The following table sets forth proved undeveloped reserves by area as of December 31, 2010:

	Gas MMcf		Oil MBbl		NGL MBbl
San Juan Basin		125,138		39	2,932
Permian Basin		32,507		31,192	8,860
Black Warrior Basin		8,081		-	-
North Louisiana/East Texas		2,369		1	-
Total		168,095		31,232	11,792

The following table sets forth the reconciliation of proved undeveloped reserves:

Bcfe	Year ended December 31, 2010
Balance at beginning of period	256.6
Undeveloped reserves transferred to developed reserves*	(65.8)
Revisions	(26.8)
Extensions, discoveries and acquisitions	262.2
Balance at end of period	426.2

* Approximately $134.5 million in capital was spent in the year ended December 31, 2010 related to proved undeveloped reserves that were moved to developed.

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, 2010 are based upon studies for each of our properties prepared by Company engineers and audited by Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman), independent oil and gas reservoir engineers. Calculations were prepared using standard geological and engineering methods and in accordance with Securities and Exchange Commission (SEC) guidelines.

A Senior Vice President at Ryder Scott is the technical person primarily responsible for overseeing the audit of the reserves. The Senior Vice President has a Bachelor of Science degree in Mechanical Engineering and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has been an employee of Ryder Scott since 1982 and also serves as chief technical advisor of unconventional reserves

14

evaluation. A Petroleum Consultant at T. Scott Hickman is the technical person primarily responsible for overseeing the audit of the reserves. He has a Bachelor of Science degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. He has been employed by T. Scott Hickman since 1983. The Vice President of Acquisitions and Reservoir Engineering is the technical person primarily responsible for overseeing reserves on behalf of Energen Resources. His background includes a Bachelor of Science degree in Mechanical Engineering and membership in the Society of Petroleum Engineers. He is a registered Professional Engineer in the State of Alabama with more than 30-years experience evaluating oil and natural gas properties and estimating reserves.

The Company relies upon certain internal controls when preparing its reserve estimations. These internal controls include review by the reservoir engineering managers to ensure the correct reserve methodology has been applied for each specific property and that the reserves are properly categorized in accordance with SEC guidelines. The reservoir engineering managers also affirm the accuracy of the data used in the reserve and associated rate forecast, provide a review of the procedures used to input pricing data and a review of the working and net interest factors to ensure that factors are adequately reflected in the engineering analysis.

Net production forecasts are compared to historical sales volumes to check for reasonableness and operating costs and severance taxes calculated in the reserve report are compared to historical accounting data to help ensure proper cost estimates are used. A reserve table is generated comparing previous years reserves to current year reserve estimates to determine variances. This table is reviewed by the Vice President of Acquisitions and Reservoir Engineering and the Chief Operating Officer of Energen Resources. Revisions and additions are investigated and explained.

Reserve estimates of proved reserves are sent to independent reservoir engineers for audit and verification. For 2010, approximately 96 percent of all proved reserves were audited by the independent reservoir engineers which audit engineering procedures, check the reserve estimates for reasonableness and check that the reserves are properly classified.

The following table sets forth the standard pressure base in pounds-force per square inch absolute (psia) for each state in which Energen Resources has wells:

Alabama, Texas	14.65 psia
Colorado	14.73 psia
Louisiana, New Mexico	15.025 psia

The following table sets forth the total net productive gas and oil wells by area as of December 31, 2010, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

	Net Wells		Net Developed Acreage		Net Undeveloped Acreage
San Juan Basin		1,439		278,554	11,910
Permian Basin		2,398		105,539	97,170
Black Warrior Basin		786		147,040	602
North Louisiana/East Texas		175		20,679	1,089
Other		12		6,377	281
Total		4,810		558,189	111,052

The net undeveloped acreage largely relates to the recent purchase of oil properties in the Permian Basin.

15

Energen Resources sells oil, natural gas, and natural gas liquids under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Energen Resources is contractually committed to deliver approximately 53.3 Bcf (net) of natural gas through March 2012. The Company expects to fulfill delivery commitments through production of existing proved reserves.

	Gas MMcf
San Juan Basin		43,034
Black Warrior Basin		10,117
North Louisiana/East Texas		135
Total		53,286

Natural Gas Distribution

The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 10,585 miles of main and more than 11,155 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, four division commercial offices, three division business centers, one district office, nine service centers, and other related property and equipment, some of which are leased by Alagasco.

ITEM 3. LEGAL PROCEEDINGS

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

Legacy Litigation

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

Other

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

ITEM 4. [REMOVED AND RESERVED]

16

EXECUTIVE OFFICERS OF THE REGISTRANTS

Energen Corporation

Name	Age	Position (1)
James T. McManus, II	52	Chairman, Chief Executive Officer and President of Energen and Chairman and Chief Executive Officer of Alagasco (2)
Charles W. Porter, Jr.	46	Vice President, Chief Financial Officer and Treasurer of Energen and Alagasco (3)
John S. Richardson	53	President and Chief Operating Officer of Energen Resources (4)
Dudley C. Reynolds	58	President and Chief Operating Officer of Alagasco (5)
J. David Woodruff, Jr.	54	Vice President, General Counsel and Secretary of Energen and Alagasco (6)
Russell E. Lynch, Jr.	37	Vice President and Controller of Energen (7)

Notes:	(1)	All executive officers of Energen have been employed by Energen or a subsidiary for the past five years. Officers serve at the pleasure of the Board of Directors.
	(2)	Mr. McManus has been employed by the Company in various capacities since 1986. He was elected Executive Vice President and Chief Operating Officer of Energen Resources in October 1995 and President of Energen Resources in April 1997. He was elected President and Chief Operating Officer of Energen effective January 1, 2006 and Chief Executive Officer of Energen and each of its subsidiaries effective July 1, 2007. He was elected Chairman of the Board of Energen and each of its subsidiaries effective January 1, 2008. Mr. McManus serves as a Director of Energen and each of its subsidiaries.
	(3)	Mr. Porter has been employed by the Company in various financial capacities since 1989. He was elected Controller of Energen Resources in 1998. In 2001, he was elected Vice President – Finance of Energen Resources. He was elected Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries effective January 1, 2007.
	(4)	Mr. Richardson has been employed by the Company in various capacities since 1985. He was elected Vice President – Acquisitions and Engineering of Energen Resources in 1997. He was elected Executive Vice President and Chief Operating Officer of Energen Resources effective January 1, 2006. He was elected President and Chief Operating Officer of Energen Resources effective January 23, 2008.
	(5)	Mr. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003.

17

(6)	Mr. Woodruff has been employed by the Company in various capacities since 1986. He was elected Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries in April 1991. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003. He also served as Vice President-Corporate Development of Energen from 1995 to 2010.
(7)	Mr. Lynch has been employed by the Company in various capacities since 2001. He became Energen’s Manager of Financial Accounting and Treasury in 2004 and Director of Financial Accounting in 2007. He was elected Vice President and Controller of Energen effective January 1, 2009.

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PART II

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

Quarterly Market Prices and Dividends Paid Per Share

Quarter ended (in dollars)	High		Low		Close		Dividends Paid
March 31, 2009		33.91		23.18		29.13	.125
June 30, 2009		41.62		28.21		39.90	.125
September 30, 2009		45.78		35.38		43.10	.125
December 31, 2009		48.89		41.20		46.80	.125
March 31, 2010		49.16		41.63		46.53	.13
June 30, 2010		49.94		40.25		44.33	.13
September 30, 2010		47.53		42.09		45.72	.13
December 31, 2010		48.69		43.32		48.26	.13

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On February 16, 2011, there were 6,215 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 $0.54 per share on the Company’s common stock in 2011. 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 as of December 31, 2010:

Plan Category	Number of Securities to be Issued for Outstanding Options and Performance Share Awards		Weighted Average Exercise Price		Number of Securities Remaining Available for Future  Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders*		1,276,043	$	40.16	1,973,928
Equity compensation plans not approved by security holders		-		-	-
Total		1,276,043	$	40.16	1,973,928

* These plans include 1,089,604 shares associated with the Company’s 1997 Stock Incentive Plan, 175,324 shares associated with the 1992 Energen Corporation Directors Stock Plan and 709,000 shares associated with the 1997 Deferred Compensation Plan.

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

Period	Total Number of Shares Purchased			Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans		Maximum Number of Shares that May Yet Be Purchased Under the Plans**
October 1, 2010 through October 31, 2010		382	*	$	45.79		-	8,992,700
November 1, 2010 through November 30, 2010		-			-		-	8,992,700
December 1, 2010 through December 31, 2010		1,227	*		44.31		-	8,992,700
Total		1,609		$	44.66		-	8,992,700

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

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

19

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, 2005, in the Company and each of the indices. Total shareholder return includes reinvested dividends.

As of December 31,	2005		2006		2007		2008		2009		2010
S&P 500 Index	$	100	$	116	$	122	$	77	$	97	$	112
Energen	$	100	$	131	$	180	$	83	$	135	$	140
S15OILP Index	$	100	$	104	$	148	$	93	$	134	$	153
S15GASUX	$	100	$	125	$	142	$	108	$	136	$	160

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ITEM 6. SELECTED FINANCIAL DATA

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

SELECTED FINANCIAL AND COMMON STOCK DATA

Energen Corporation

Years ended December 31, (dollars in thousands, except per share amounts)	2010		2009		2008		2007		2006
INCOME STATEMENT*
Operating revenues	$	1,578,534	$	1,440,420	$	1,568,910	$	1,435,060	$1,393,986
Income from continuing operations	$	290,807	$	256,325	$	321,915	$	309,212	$   273,523
Net income	$	290,807	$	256,325	$	321,915	$	309,233	$   273,570
Diluted earnings per average common share from continuing operations	$	4.04	$	3.57	$	4.47	$	4.28	$         3.73
Diluted earnings per average common share	$	4.04	$	3.57	$	4.47	$	4.28	$         3.73
BALANCE SHEET
Total property, plant and equipment, net	$	3,719,227	$	3,144,469	$	2,867,648	$	2,538,243	$2,252,414
Total assets	$	4,363,560	$	3,803,118	$	3,775,404	$	3,079,653	$2,836,887
Long-term debt	$	405,254	$	410,786	$	561,361	$	562,365	$   582,490
Total shareholders’ equity	$	2,154,043	$	1,988,243	$	1,913,920	$	1,378,658	$1,202,069
COMMON STOCK DATA
Cash dividends paid per common share	$	0.52	$	0.50	$	0.48	$	0.46	$         0.44
Diluted average common shares outstanding (000)		72,051		71,885		72,030		72,181	73,278
Price range:
High	$	49.94	$	48.89	$	79.57	$	70.41	$       47.60
Low	$	40.25	$	23.18	$	23.00	$	43.78	$       32.16
Close	$	48.26	$	46.80	$	29.33	$	64.23	$       46.94

* The years ended December 31, 2010 and 2009 include after-tax write-offs of $24.8 million, or $0.34 per diluted share, and $1.3 million, or $0.02 per diluted share, respectively, of unproved leasehold costs associated with the remainder of Energen Resources’ Alabama shale acreage. An after-tax gain of $34.5 million, or $0.47 per diluted share, on the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shales to Chesapeake Energy Corporation is included in the year ended December 31, 2006.

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SELECTED BUSINESS SEGMENT DATA

Energen Corporation

Years ended December 31, (dollars in thousands)	2010			2009		2008		2007		2006
OIL AND GAS OPERATIONS
Operating revenues from continuing operations
Natural gas	$	483,935		$	460,370	$	536,283	$	499,406	$    437,560
Oil		404,625			284,750		292,908		251,497	181,459
Natural gas liquids		65,161			67,254		68,216		68,623	50,258
Other		5,041			10,172		16,725		6,066	61,265
Total	$	958,762		$	822,546	$	914,132	$	825,592	$    730,542
Production volumes from continuing operations
Natural gas (MMcf)		70,924			72,337		67,573		64,300	62,824
Oil (MBbl)		5,131			4,690		4,114		3,879	3,645
Natural gas liquids (MMgal)		79.0			75.2		70.7		77.2	76.3
Production volumes from continuing operations (MMcfe)		112,989			111,224		102,354		98,606	95,596
Total production volumes (MMcfe)		112,989			111,224		102,354		98,605	95,595
Total production volumes (MBOE)		18,832			18,537		17,059		16,435	15,933
Proved reserves
Natural gas (MMcf)		954,387			897,546		1,038,453		1,115,918	1,096,429
Oil (MBbl)		103,262			77,963		62,034		74,625	74,893
Natural gas liquids (MBbl)		40,601			30,257		28,953		31,664	29,504
Total (MMcfe)		1,817,565			1,546,866		1,584,375		1,753,652	1,722,811
Total (MBOE)		302,928			257,811		264,063		292,275	287,135
Other data from continuing operations Lease operating expense (LOE)
LOE and other	$	182,180		$	181,777	$	174,127	$	148,280	$    134,853
Production taxes		42,721			35,652		62,552		53,798	49,509
Total	$	224,901		$	217,429	$	236,679	$	202,078	$    184,362
Depreciation, depletion and amortization	$	203,821		$	184,089	$	139,539	$	114,241	$      97,842
Capital expenditures	$	717,782		$	427,399	$	449,571	$	379,479	$    259,678
Operating income	$	406,729		$	353,645	$	482,588	$	451,567	$    405,149
NATURAL GAS DISTRIBUTION
Operating revenues
Residential	$	414,870		$	399,760	$	408,280	$	388,291	$    426,066
Commercial and industrial		159,658			162,141		177,719		164,903	181,900
Transportation		57,049			54,312		51,116		49,255	45,950
Other		(11,805	)		1,661		17,663		7,019	9,528
Total	$	619,772		$	617,874	$	654,778	$	609,468	$    663,444
Gas delivery volumes (MMcf)
Residential		24,463			20,921		21,632		20,665	22,310
Commercial and industrial		10,985			9,934		10,934		10,593	11,226
Transportation		46,479			40,903		46,789		51,448	50,760
Total		81,927			71,758		79,355		82,706	84,296
Average number of customers
Residential		404,697			409,214		413,151		416,967	420,558
Commercial, industrial and transportation		32,632			33,264		33,911		34,200	34,456
Total		437,329			442,478		447,062		451,167	455,014
Other data
Depreciation and amortization	$	44,042		$	50,995	$	48,874	$	47,136	$      44,244
Capital expenditures	$	93,566		$	77,809	$	63,320	$	58,862	$      76,157
Operating income	$	88,383		$	83,984	$	81,956	$	72,742	$      74,274

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

RESULTS OF OPERATIONS

Consolidated Net Income

Energen Corporation’s net income for the year ended December 31, 2010 totaled $290.8 million, or $4.04 per diluted share compared to the year ended December 31, 2009 net income of $256.3 million, or $3.57 per diluted share. This 13.2 percent increase in earnings per diluted share (EPS) largely reflected significantly higher prices for natural gas and oil and the impact of a net 1.8 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen Resources Corporation, Energen’s oil and gas subsidiary. Negatively affecting net income was higher exploration expense due to a non-cash write-off of $24.8 million after-tax (approximately $0.34 per diluted share) of unproved leasehold costs associated with the remainder of its Alabama shale acreage combined with a related $9.7 million after-tax write-off of well costs, increased depreciation, depletion and amortization (DD&A) expense and increased production taxes. Energen Resources also reported an after-tax gain of $3.1 million on the sale of certain oil properties in the Permian Basin during 2009. For the year ended December 31, 2010, Energen Resources earned $245.3 million, as compared with $212.1 million in the previous year. Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, generated net income of $46.9 million in the current year as compared with net income in the prior period of $45.4 million. For the year ended December 31, 2008, Energen reported net income of $321.9 million, or $4.47 per diluted share.

2010 vs 2009: Energen Resources’ net income totaled $245.3 million in 2010 as compared with $212.1 million in 2009. The primary factors positively influencing income included increased commodity prices of approximately $75 million after-tax and increased production volumes of approximately $13 million after-tax. These increases were partially offset by higher exploration expense of approximately $34 million after-tax, increased DD&A expense of approximately $12 million after-tax, higher production taxes of approximately $4 million after-tax and the 2009 after-tax gain on the $3.1 million sale of certain oil properties in the Permian Basin.

Alagasco earned net income of $46.9 million in 2010 as compared with net income of $45.4 million in 2009. This increase in earnings largely reflected the utility’s ability to earn on a higher level of equity. Alagasco’s return on average equity (ROE) was 14.1 percent in 2010 compared with 14 percent in 2009.

2009 vs 2008: For the year ended December 31, 2009, Energen Resources’ net income totaled $212.1 million and as compared to $282.7 million in the prior year primarily due to decreased commodity prices of approximately $105 million after-tax, higher DD&A expense of approximately $28 million after-tax, higher administrative expense of approximately $7 million after-tax, the $6.4 million after-tax gain on the sale of certain Permian Basin oil properties in 2008 and higher lease operating expense of approximately $5 million after-tax. These decreases were partially offset by the impact of greater production volumes of approximately $52 million after-tax, lower production taxes of approximately $17 million after-tax and the after-tax gain of $3.1 million on the sale of certain oil properties in the Permian Basin.

Alagasco earnings increased to $45.4 million in 2009 from $40.2 million in 2008 which largely reflects the timing of revenue recovery associated with core-market sales as well as increased investment gains combined with the utility’s ability to earn on a higher level of equity. Alagasco achieved an ROE of 14 percent in 2009 compared with 12.9 percent in 2008.

Operating Income

Consolidated operating income in 2010, 2009 and 2008 totaled $493.4 million, $435.4 million and $562.1 million, respectively. Growth in operating income for 2010 was influenced by the financial performance from Energen Resources arising from increased commodity prices and production. The decrease in operating income for 2009 is primarily due to significantly lower commodity prices partially offset by increased production at Energen Resources. During 2010, Alagasco contributed to this growth in operating income consistent with an increase in the level of equity upon which it has been able to earn a return combined with timing differences associated with rate recovery. Alagasco’s operating income remained relatively flat in 2009.

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Oil and Gas Operations: Revenues from oil and gas operations rose in the current year largely as a result of significantly higher commodity prices along with the impact of increased oil and natural gas liquids production volumes partially offset by lower natural gas production volumes. Production increased due to increased volumes related to the June 2009 purchase of certain Permian Basin oil properties, the September 2010 purchase of certain Permian Basin oil properties, acquiring proved reserves of approximately 18 million barrels of oil equivalents (MMBOE), and additional development activities in the San Juan and Permian basins, partially offset by normal production declines and drilling delays. During 2010, revenue per unit of production for natural gas production increased 7.2 percent to $6.82 per thousand cubic feet (Mcf), oil revenue per unit of production rose 29.9 percent to $78.86 per barrel and natural gas liquids revenue per unit of production decreased 6.7 percent to $0.83 per gallon. Production rose 1.5 percent to 113 Bcfe during 2010. Natural gas production fell 2 percent to 70.9 billion cubic feet (Bcf) while oil volumes rose 9.4 percent to 5,131 thousand barrels (MBbl). Production of natural gas liquids increased 5.1 percent to 79 million gallons (MMgal).

In 2009, revenues from oil and gas operations declined largely as a result of significantly lower commodity prices partially offset by the impact of increased production volumes. Production increased due to increased volumes related to the June 2009 purchase of certain Permian Basin oil properties along with 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 declined 19.9 percent to $6.36 per Mcf, oil revenue per unit of production fell 14.7 percent to $60.72 per barrel and natural gas liquids revenue per unit of production decreased 7.3 percent to $0.89 per gallon during 2009. Production rose 8.7 percent to 111.2 Bcfe during 2009. Natural gas production increased 7.1 percent to 72.3 Bcf and oil volumes rose 14 percent to 4,690 MBbl. Production of natural gas liquids increased 6.4 percent to 75.2 MMgal.

Operating fees from coalbed methane operations 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.

Years ended December 31, (in thousands, except sales price data)	2010		2009		2008
Operating revenues
Natural gas	$	483,935	$	460,370	$	536,283
Oil		404,625		284,750		292,908
Natural gas liquids		65,161		67,254		68,216
Operating fees		3,650		3,091		8,599
Other		1,391		7,081		8,126
Total operating revenues	$	958,762	$	822,546	$	914,132
Production volumes
Natural gas (MMcf)		70,924		72,337		67,573
Oil (MBbl)		5,131		4,690		4,114
Natural gas liquids (MMgal)		79.0		75.2		70.7
Revenue per unit of production including effects of all derivative instruments
Natural gas (per Mcf)	$	6.82	$	6.36	$	7.94
Oil (per barrel)	$	78.86	$	60.72	$	71.20
Natural gas liquids (per gallon)	$	0.83	$	0.89	$	0.96
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (per Mcf)	$	6.82	$	6.36	$	7.92
Oil (per barrel)	$	78.86	$	60.65	$	71.45
Natural gas liquids (per gallon)	$	0.83	$	0.89	$	0.96
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (per Mcf)	$	4.22	$	3.52	$	7.94
Oil (per barrel)	$	75.06	$	57.32	$	94.97
Natural gas liquids (per gallon)	$	0.86	$	0.66	$	1.14
Average production (lifting) cost (per Mcfe)	$	1.47	$	1.51	$	1.58
Average production tax (per Mcfe)	$	0.38	$	0.32	$	0.61
Average DD&A rate (per Mcfe)	$	1.77	$	1.63	$	1.33

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Operations and maintenance (O&M) expense increased $55.1 million and $19.1 million in 2010 and 2009, respectively. In 2010, lease operating expense (excluding production taxes) increased $0.4 million largely due to the June 2009 and September 2010 Permian Basin oil property acquisitions (approximately $5.5 million), increased marketing and transportation costs (approximately $2.7 million), additional electrical costs (approximately $1.4 million), higher ad valorem taxes (approximately $0.9 million) and increased labor costs (approximately $0.8 million) largely offset by lower workover expense (approximately $7.5 million), decreased nonoperated costs (approximately $1.8 million) and decreased other O&M expense (approximately $1.6 million). Lease operating expense (excluding production taxes) in 2009 increased $7.7 million largely due to the June 2009 Permian Basin oil property acquisition (approximately $6.4 million), higher labor costs (approximately $1.6 million), increased marketing and transportation costs (approximately $0.7 million) and increased ad valorem taxes (approximately $0.5 million) partially offset by decreased electrical costs (approximately $1.3 million). Administrative expense rose $0.3 million in 2010 primarily due to increased labor costs (approximately $2 million) partially offset by decreased legal expenses (approximately $1.9 million). In 2009, administrative expense rose $10.5 million primarily due to increased benefit costs largely related to the Company’s performance-based compensation plans (approximately $8.9 million) and increased legal expenses (approximately $0.8 million). Exploration expense rose $54.4 million during 2010 largely due to charges of $39.7 million for unproved capitalized leasehold costs and $15.5 million for well costs, all related to Alabama shale leasehold. In 2009, exploration expense increased $0.9 million. Exploration expense in 2009 includes the writeoff of two Chattanooga shale wells; the writeoff for one well was $5.6 million and the writeoff for the other well, originally drilled by Chesapeake, for $0.9 million. In addition, exploration expense includes approximately $2.1 million of unproved leasehold impairments related to the Alabama shales.

DD&A expense increased $19.7 million in 2010 and $44.6 million in 2009. The average DD&A rates were $1.77 per Mcfe in 2010, $1.63 per Mcfe in 2009 and $1.33 per Mcfe in 2008. The increase in the 2010 and 2009 per unit DD&A rates, which contributed approximately $14.2 million and $33.1 million, respectively, to the increase in DD&A expense, was primarily due to higher development costs in 2010 and 2009 and reserve revisions associated with lower year-end reserve pricing for 2009. Increased production volumes also contributed approximately $5.2 million and $11.3 million to the increase in DD&A expense in 2010 and 2009, respectively.

Energen Resources’ expense for taxes other than income taxes primarily reflected production-related taxes. Energen Resources recorded severance taxes of $42.7 million, $35.7 million and $62.6 million for 2010, 2009 and 2008, respectively. Severance taxes were $7.1 million higher in 2010 resulting from increased commodity market prices and higher oil and natural gas liquids production volumes. Higher commodity market prices and the impact of increased production volumes contributed approximately $6.5 million and $0.6 million to the increase in severance taxes, respectively. Severance taxes decreased $26.9 million in 2009 over the prior year. Lower commodity market prices contributed approximately $32.3 million to the decrease in production-related taxes. Partially offsetting the decreases in production-related taxes were higher production volumes which contributed approximately $5.4 million. 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 APSC and is allowed to earn a range of return on average equity of 13.15 percent to 13.65 percent. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Given existing economic conditions, Alagasco expects only modest growth in equity as annual dividends are typically paid by the utility.

Under the inflation-based CCM established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the cost control measurement calculation.

25

Alagasco generates revenues through the sale and transportation of natural gas. The transportation rate does not contain an amount representing the cost of gas, and Alagasco’s rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues; as such Alagasco’s tariff provides a temperature adjustment mechanism that is designed 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 and is adjusted through the Gas Supply Adjustment rider (GSA).

Alagasco’s natural gas and transportation sales revenues totaled $619.8 million, $617.9 million and $654.8 million in 2010, 2009 and 2008, respectively. Sales revenue in 2010 rose largely due to a weather-driven increase in customer usage of approximately $42.8 million partially offset by a decrease in gas costs of approximately $31.8 million and adjustments from the utility’s rate mechanisms. In the current year-to-date, Alagasco had reduction in revenues of $17.4 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. As of September 30, 2009, Alagasco had a $1.5 million pre-tax reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. In 2010, weather that was 24.8 percent colder than in the prior year contributed to a 16.9 percent increase in residential sales volumes and a 10.6 percent rise in commercial and industrial volumes. Transportation volumes rose 13.6 percent primarily due to lower usage in the prior year by large commercial and industrial customers. In 2009, sales revenue declined largely due to a decrease in gas costs of approximately $36 million and a decline in customer usage of approximately $9 million. Adjustments from the utility’s rate setting mechanisms also contributed to the decline in revenues as Alagasco had a $1.5 million pre-tax reduction in 2009 as discussed above. Alagasco charged approximately $4 million against the ESR during the third quarter of 2008 due to a decline in usage by certain 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. Weather was 4.7 percent warmer than in the prior year during 2009. Residential sales volumes declined 3.3 percent while commercial and industrial volumes decreased 9.1 percent. Transportation volumes fell 12.6 percent largely due to decreased large customer and industrial usage. A significant increase in gas purchase volumes partially offset by a decrease in gas costs resulted in a 3.6 percent increase in cost of gas in 2010. In 2009, lower gas costs along with decreased gas purchase volumes contributed to a 13 percent decrease in cost of gas.

O&M expense at the utility fell 4.5 percent in 2010 largely due to lower consulting and technology costs (approximately $0.5 million) and decreased bad debt expense (approximately $9 million) which reflects improved economic conditions during the later months of 2010, enhanced credit and collection processes and the correction of a $3 million error identified by Alagasco during the first quarter of 2010 in the calculation of the estimate of the allowance for doubtful accounts as of December 31, 2009. See Note 1, Summary of Significant Accounting Policies, in the Notes to Financial Statements for further discussion. Partially offsetting these decreases were higher labor-related costs (approximately $2.3 million) and increased distribution operation expenses (approximately $2.3 million). In 2009, O&M expense at the utility increased 5.4 percent primarily due to increased bad debt expense (approximately $4.2 million), higher labor-related costs (approximately $3.2 million) and increased marketing expenses (approximately $2.7 million) partially offset by lower distribution operation expenses (approximately $2.1 million) and net decreased consulting and technology costs (approximately $0.5 million). In the rate year ended September 30, 2010, $2.5 million of extraordinary bad debt expense was excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2010 and 2009. For the rate year ended September 30, 2008, the increase in O&M expense per customer was below the Index Range; as a result, the utility benefited by $2.9 million pre-tax with the related impact to rates effective December 1, 2008.

Depreciation expense decreased 13.6 percent in 2010 primarily due to revised depreciation rates effective June 1, 2010, partially offset by the extension and replacement of the utility’s distribution system and replacement of its support systems. The revised depreciation rates decreased depreciation expense by approximately $9.2 million for the year ended December 31, 2010 from expense amounts calculated using the prior depreciation rate. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates,

26

Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July, 2010 and $2.7 million through lower tariff rates in December, 2010, and will return to eligible customers an additional estimated $112.8 million, which includes approximately $22.3 million between January 1, 2011 and December 31, 2011. The remainder will be refunded to customers on a declining basis through lower tariff rates over an eight year period originally beginning December 1, 2011. The total amount refundable to eligible customers is subject to adjustments over the entire nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. On November 1, 2010, the APSC specifically approved adjustments to the total amount refundable to include items originally approved in the APSC’s 1998 order establishing the ESR, environmental response costs, and self insurance costs that exceed $1 million per occurrence. The refunds as of December, 2010 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the past five years. Depreciation expense rose 4.3 percent in 2009 due to extension and replacement of the utility’s distribution and replacement of its support systems. Approved depreciation rates averaged approximately 3.6 percent in the year ended December 31, 2010, and approximately 4.4 percent in the years ended December 31, 2009 and 2008.

Alagasco’s expense for taxes other than income primarily reflects various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Years ended December 31, (in thousands)	2010			2009			2008
Natural gas transportation and sales revenues	$	619,772		$	617,874		$	654,778
Cost of natural gas		(316,988	)		(306,054	)		(351,774	)
Operations and maintenance		(128,830	)		(134,847	)		(127,877	)
Depreciation		(44,042	)		(50,995	)		(48,874	)
Income taxes		(29,875	)		(27,353	)		(24,829	)
Taxes, other than income taxes		(41,529	)		(41,994	)		(44,297	)
Operating income	$	58,508		$	56,631		$	57,127
Natural gas sales volumes (MMcf)
Residential		24,463			20,921			21,632
Commercial and industrial		10,985			9,934			10,934
Total natural gas sales volumes		35,448			30,855			32,566
Natural gas transportation volumes (MMcf)		46,479			40,903			46,789
Total deliveries (MMcf)		81,927			71,758			79,355

Non-Operating Items

Consolidated: Interest expense declined $0.2 million in 2010. In 2009, interest expense fell $2.6 million largely due to lower borrowings at Energen Resources combined with lower interest rates on short-term debt. The average daily outstanding balance under credit facilities was $19.7 million in 2010. The average daily outstanding balance under credit facilities was $33.6 million in 2009 as compared to $89.2 million in 2008. Income tax expense increased in 2010 primarily due to higher pre-tax income. In 2009 income tax expense decreased largely due to lower pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

The Company’s net cash from operating activities totaled $671 million, $679.5 million and $569.2 million in 2010, 2009 and 2008, respectively. Net income increased during 2010 largely due to higher realized commodity prices along with an increase in production volumes at Energen Resources. The Company’s working capital needs were also influenced by accrued taxes along with commodity prices, and the timing of payments. During 2010, the income tax receivable increased approximately $39.9 million associated with the impact of bonus depreciation and the write-off of Alabama shale leasehold. Net income decreased for 2009 primarily due to lower realized commodity prices partially offset by higher production volumes at Energen Resources and lower production taxes. These decreases were more than offset by lower working capital requirements which were influenced primarily by accrued taxes along with the effect of lower commodity prices and the timing of payments. Operating cash flow in

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2008 benefited from higher realized commodity prices and production volumes at Energen Resources. Operating cash flows during 2008 were positively impacted by the tax effect of depreciation and basis differences. During 2010 and 2009, working capital needs at Alagasco were largely affected by decreased gas costs compared to the prior period, accrued taxes and storage gas inventory. Alagasco received a cash benefit in February 2009 from an approximate $26.2 million income tax refund claim from 2007 which resulted from an approved change by the Internal Revenue Service in a tax accounting method relating to the Company’s recovery of its gas distribution property. During 2008, working capital needs were primarily affected by increased gas costs and accrued taxes. Other working capital items, which primarily are the result of changes in throughput and the timing of payments, combined to create the remaining increases in all years.

The Company made net investments of $842.7 million during 2010. Energen Resources invested $410.3 million in property acquisitions including approximately $201.9 million of unproved leaseholds, $301.2 million for development costs (excludes approximately $26.6 million of accrued development cost) including approximately $258.2 million to drill 251 net development and service wells and $36.5 million for exploration. In September 2010, Energen Resources completed a purchase of oil properties located in the Permian Basin for a cash price of approximately $189 million adding approximately 18 MMBOE in proved reserves. Energen Resources completed, in December 2010, a purchase of oil properties located in the Permian Basin for a cash price of approximately $74 million. The acquisition added approximately 7.6 MMBOE in proved reserves. Energen Resources also completed in December 2010, the purchase of oil properties with only unproved reserves in the Permian Basin for a cash price of $110 million. Energen Resources had cash proceeds in 2010 of $3.2 million primarily from the sale of certain Permian and Black Warrior basin properties. Utility expenditures in 2010 totaled $92.1 million (excludes approximately $0.5 million of accrued capital cost) and primarily represented expansion and replacement of its distribution system and replacement of its support facilities. During 2009, the Company made net investments of $519.1 million. Energen Resources invested $189.8 million in property acquisitions including approximately $5.1 million of unproved leaseholds, $237.9 million for development costs (includes approximately $23.8 million of accrued development cost) including approximately $138.8 million to drill 163 net development and service wells and $16.2 million for exploration. In June 2009, Energen Resources completed its purchase of oil properties located in the Permian Basin for a cash price of approximately $181 million. The acquisition added approximately 15.2 MMBOE in proved reserves. Energen Resources had cash proceeds in 2009 of $7.9 million primarily from the sale of certain Permian Basin oil properties. Utility expenditures in 2009 totaled $77 million (includes approximately $0.5 million of accrued capital cost) and primarily represented expansion and replacement of its distribution system and support facilities, including the implementation of the Customer Care and Service (CCS) software system. 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 (excludes approximately $26.2 million of accrued development cost) including approximately $262 million 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.

During 2010, the Company added approximately 155 Bcfe of reserves primarily from the Permian Basin oil property acquisitions. Also during 2010, Energen Resources added 110 Bcfe of reserves from discoveries and other additions, primarily the result of development drilling that increased the number of proved undeveloped locations in both the San Juan and Permian basins as well as continued downspacing in the Permian Basin. Energen Resources added approximately 204 Bcfe and 126 Bcfe of reserves in 2009 and 2008, respectively.

The Company provided $118.5 million from net financing activities in 2010 largely from an increase in short-term debt borrowings used largely to fund acquisitions partially offset by the payment of current maturities for long-term debt of $150.7 million. The Company used $97.7 million and $100.2 million for net financing activities in 2009 and 2008, respectively, primarily for the repayment of short-term debt borrowings. In addition, long-term debt was reduced by $1 million and $10.9 million for current maturities in 2009 and 2008, respectively. For each of the years, net cash used in financing activities also reflected dividends paid to common shareholders.

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Capital Expenditures

Oil and Gas Operations: Energen Resources spent a total of $1.7 billion for capital projects during the years ended December 31, 2010, 2009 and 2008. Property acquisition expenditures totaled $619.4 million, development activities totaled $970.3 million, and exploratory expenditures totaled $72.2 million.

Years ended December 31, (in thousands)	2010		2009		2008
Capital and exploration expenditures for:
Property acquisitions	$	409,042	$	191,363	$  18,996
Development		331,850		225,482	412,928
Exploration		36,455		16,230	19,504
Other		4,103		4,198	5,763
Total		781,450		437,273	457,191
Less exploration expenditures charged to income		63,668		9,874	7,620
Net capital expenditures	$	717,782	$	427,399	$449,571

Natural Gas Distribution: During the years ended December 31, 2010, 2009 and 2008, Alagasco invested $234.7 million for capital projects: $164.6 million for expansion, replacements and support of its distribution system and $70 million for support facilities, including the development and implementation of information systems.

Years ended December 31, (in thousands)	2010		2009		2008
Capital expenditures for:
Renewals, replacements, system expansion and other	$	68,774	$	52,585	$43,284
Support facilities		24,792		25,224	20,036
Total	$	93,566	$	77,809	$63,320

FUTURE CAPITAL RESOURCES AND LIQUIDITY

Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2011, the Company expects its oil and gas capital spending to total approximately $667 million, including $639 million for existing properties and $25 million for exploration. Included in this $639 million is approximately $320 million for the development of previously identified proved undeveloped reserves.

Capital expenditures by area during 2011 are planned as follows:

Year ended December 31, (in thousands)	2011
San Juan Basin	$  83,000
Permian Basin	532,000
Black Warrior Basin	14,000
North Louisiana/East Texas	10,000
Exploration	25,000
Other	3,000
Total	$667,000

Energen anticipates having the following drilling rigs and net wells by area during 2011. The drilling rigs presented below are operated while the net wells include operated and non-operated wells.

	Drilling Rigs	Net Wells
San Juan Basin	2 - 5	45
Permian Basin	14 - 15	355
Black Warrior Basin	1	41
North Louisiana/East Texas	1	3
Total	18 - 22	444

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria.

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Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company primarily expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity.

Alabama Shales

During 2010, Energen Resources incurred write-offs of unproved capitalized leasehold costs associated with its Alabama shale acreage. The non-cash charges totaled $39.7 million pre-tax and were charged to exploration expense, which is included in O&M expense, after the Company determined that the shale acreage was not economically viable. Energen Resources also recorded $15.5 million pre-tax in write-offs of well costs related to Alabama shale leasehold.

During 2009, Energen Resources was unsuccessful in the completion of a Chattanooga shale well. The costs related to this well of approximately $5.6 million pre-tax were expensed during the fourth quarter of 2009. Also expensed during the fourth quarter was approximately $1.2 million pre-tax of costs associated with a well originally drilled by Chesapeake in an area of the Chattanooga shale. In addition, the Company recognized unproved leasehold impairments of approximately $2.1 million pre-tax during 2009 related to the Alabama shales.

Natural Gas Distribution

Alagasco’s use of commodity price hedges for a portion of its gas supply needs is reflected in the utility’s current rates. Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider which permits the pass-through to customers for changes in the cost of gas supply. The GSA rider is designed to capture the Company’s cost of natural gas and provides for a pass-through of gas cost fluctuations to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management gains and losses.

Alagasco is a mature utility operating in a slow-growth service area. Over the last five years, Alagasco’s customer count has declined at a rate of approximately 1 percent annually despite above-average levels of penetration along existing distribution lines. To increase its customer base, the utility is capitalizing on opportunities to expand its distribution lines to areas with economic growth potential and pursuing the acquisition of mutually beneficial municipally owned gas systems in Alabama. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices and the underlying current and future economic conditions facing the utility’s customer base.

Another aspect of growth is usage per customer. Throughout the country, customer use of natural gas has declined over the years in large part due to energy-efficiencies in home construction and appliances and conservation. Alagasco’s marketing emphasis in this area is directed toward retention and increasing end-use applications by existing customers.

Alagasco maintains an investment in storage gas that is expected to average approximately $40 million in 2011 but will vary depending upon the price of natural gas. During 2011, Alagasco plans to invest approximately $75 million in utility capital expenditures for normal distribution and support systems. The utility anticipates funding these capital requirements through internally generated cash flow and the utilization of its credit facilities.

Stock Repurchases

Energen periodically considers stock repurchases as a capital investment. Energen may buy shares on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. The Company did not repurchase shares of common stock for this program during 2010, 2009 or 2008. The Company expects any future stock repurchases to be funded through internally generated cash flows or through the utilization of credit facilities. During 2010, the Company had noncash purchases of approximately $2.9 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation plans. The Company utilized internally generated cash flows in payment of the related tax withholdings.

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Credit Facilities

Access to capital is an integral part of the Company’s business plan. While the Company expects to have ongoing access to its credit facilities and the longer-term markets, continued access could be adversely affected by current and future economic and business conditions and credit rating downgrades. On October 29, 2010, Energen and Alagasco entered into an $850 million and a $150 million, respectively, three-year syndicated unsecured credit facility (syndicated credit facilities) with domestic and foreign lenders. Energen’s obligations under the $850 million syndicated credit facility are unconditionally guaranteed by Energen Resources. These syndicated credit facilities replace the majority of the Company’s short-term credit facilities which were available to Energen and Alagasco. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of 65 percent for each of the Company and Alagasco. Both the Company and Alagasco were in compliance with the terms of the syndicated credit facilities at December 31, 2010. The Company currently has available credit facilities as follows:

(in thousands)	Current Term		Energen		Alagasco		Total
Syndicated Credit Facility		10/29/2013	$	850,000	$	150,000	$1,000,000
Bryant Bank		11/1/2011		-		9,000	9,000
BancorpSouth Bank		5/23/2011		-		10,000	10,000
Total			$	850,000	$	169,000	$1,019,000

Energen and Alagasco rely upon excess cash flow supplemented by the syndicated credit facilities and the short-term credit facilities to fund working capital needs. The Company may also issue long-term debt and equity periodically to replace obligations under the credit facilities, enhance liquidity and provide for permanent financing.

Credit Ratings

Energen and Alagasco’s current debt ratings by Moody’s Investors Service and Standard & Poor’s are considered investment grade and each have a stable outlook.

Dividends

Energen expects to pay annual cash dividends of $0.54 per share on the Company’s common stock in 2011. 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.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes the Company’s significant contractual cash obligations, other than hedging contracts, as of December 31, 2010:

	Payments Due before December 31,
(in thousands)	Total		2011		2012-2013		2014-2015		2016 and   Thereafter
Short-term debt	$	305,000	$	305,000	$	-	$	-	$               -
Long-term debt (1)		410,793		5,000		51,000		80,000	274,793
Interest payments on debt		335,808		25,981		49,461		45,855	214,511
Purchase obligations (2)		151,912		50,946		85,775		11,261	3,930
Capital lease obligations		-		-		-		-	-
Operating leases		38,236		5,436		9,243		6,643	16,914
Asset retirement obligations (3)		593,966		14,798		3,983		4,680	570,505
Nonqualified supplemental retirement plans		34,122		2,304		4,833		3,223	23,762
Total contractual cash obligations	$	1,869,837	$	409,465	$	204,295	$	151,662	$ 1,104,415

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(1) Long-term cash obligations include $0.5 million of unamortized debt discounts as of December 31, 2010.

(2) Certain of the Company’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of $152 million through September 2024. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 249 Bcf through August 2020.

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

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

The Company has two defined non-contributory pension plans and provides certain postretirement healthcare and life insurance benefits. The Company anticipates required contributions of approximately $7.2 million during 2011 to the pension plans. The Company expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. It is not anticipated that the funded status of the pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2011. The Company expects to make discretionary payments of approximately $4.8 million to postretirement benefit program assets during 2011. The contractual obligations reported above exclude any payments the Company expects to make to postretirement benefit program assets.

The contractual obligations reported above exclude the Company’s liability of $24.6 million related to the Company’s provision for uncertain tax positions. The Company cannot make a reasonably reliable estimate of the amount and period of related future payments for such liability.

Energen and its subsidiaries’ 2007 and 2008 federal consolidated income tax returns have been under Internal Revenue Service (IRS) examination. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company has filed a petition in United States Tax Court challenging the IRS assessment. Although the timing of the resolution is highly uncertain, a maximum exposure of an unfavorable outcome would result in income tax cash payments of approximately $31 million.

During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit of federal oil and gas leases located in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from U.S. federal leases. The Department proposes a change in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases. Such proposal, if determined appropriate, will result in increases of royalties due under the audit periods.

The Department’s preliminary findings are contrary to those allowed under previous audits and are inconsistent with the Company’s understanding of industry practice. The Company intends to vigorously contest the proposal under the preliminary findings and has requested additional information from the Department to determine the basis of its conclusion. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this finding and no amount has been accrued as of December 31, 2010.

OUTLOOK

Oil and Gas Operations: Energen Resources plans to continue to implement its growth strategy with capital spending in 2011. Production in 2011 is estimated to be 124 Bcfe, including approximately 118 Bcfe of estimated

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production from proved reserves owned at December 31, 2010. Production estimates do not include amounts for potential future acquisitions. In the event Energen Resources is unable to fully invest in its capital investment opportunities, future operating revenues, production and proved reserves could be negatively affected.

Production volumes by area are expected to be as follows:

Years ended December 31, (Bcfe)	2011
San Juan Basin	57
Permian Basin	48
Black Warrior Basin	13
North Louisiana/East Texas	6
Total	124

During 2011, Energen Resources expects an annualized decline rate of approximately 7.2 percent for its proved developed producing properties owned at December 31, 2010. During the same period, total production from proved properties is expected to increase approximately 4.6 percent and total production is expected to increase approximately 9.5 percent. The above proved developed producing properties decline rates are not necessarily indicative of the Company’s expectations for its terminal decline rate on a long-term basis.

Various factors influence decline rates. For example, certain properties may have production curves that decline at faster rates in the early years of production and at slower rates in later years. Other properties, such as certain coalbed methane wells or waterflood projects, may experience inclining production during the early years followed by declining production. Further, production curves can be positively impacted by various enhanced recovery techniques. Accordingly, the decline rate for a single year is influenced by numerous factors, including but not limited to, the mix of types of wells, the mix of newer versus older wells, and the effect of enhanced recovery activities, but it is not necessarily indicative of future decline rates. Excluding the positive effects of more recent activities as discussed above, the longer term decline rates of properties typically flatten but continue to decline until a property reaches its economic limit and is then plugged and abandoned. Energen Resources expects a compound annual decline rate for proved producing properties owned at December 31, 2010 of approximately 9 percent for the 10 year period 2010 to 2020.

Energen Resources’ major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, national supply and demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, worldwide political developments and actions of the Organization of Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas. Additionally, downward commodity price trends may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties.

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.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment and commercial banks and energy-trading firms. At December 31, 2010, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net loss position with eight of

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its active counterparties and a net gain with the remaining three at December 31, 2010. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen Resources does not hedge more than 80 percent of its estimated annual production. Production may be hedged for a longer period immediately following an acquisition in order to protect targeted returns.

Alagasco also enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

Energen Resources entered into the following transactions for 2011 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	13.6 Bcf	$6.58 Mcf	NYMEX Swaps
	31.3 Bcf	$5.98 Mcf	Basin Specific Swaps
	*0.7 Bcf	$4.74 Mcf	NYMEX Swaps
	*6.8 Bcf	$4.35 Mcf	Basin Specific Swaps
2012	7.2 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
	*3.8 Bcf	$5.08 Mcf	NYMEX Swaps
2013	7.2 Bcf	$5.31 Mcf	NYMEX Swaps
	12.0 Bcf	$4.90 Mcf	Basin Specific Swaps
	*1.6 Bcf	$5.28 Mcf	NYMEX Swaps
	*7.2 Bcf	$4.91 Mcf	Basin Specific Swaps
Oil
2011	4,421 MBbl	$78.83 Bbl	NYMEX Swaps
2012	3,744 MBbl	$82.52 Bbl	NYMEX Swaps
2013	3,199 MBbl	$85.32 Bbl	NYMEX Swaps
2014	2,742 MBbl	$87.44 Bbl	NYMEX Swaps
Oil Basis Differential
2011	2,076 MBbl	**	Basis Swaps
2012	672 MBbl	**	Basis Swaps
Natural Gas Liquids
2011	42.8 MMGal	$0.90 Gal	Liquids Swaps
2012	36.4 MMGal	$0.85 Gal	Liquids Swaps
2012	*3.5 MMGal	$0.96 Gal	Liquids Swaps
*       Contracts entered into subsequent to December 31, 2010 **     Average contract prices not meaningful due to the varying nature of each contract

Alagasco entered into the following natural gas transactions for 2011 and subsequent years:

Production Period	Total Hedged Volumes	Description
2011	15.2 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

Energen Resources has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil, natural gas and natural gas liquids may have on the fair value of its derivative instruments. This analysis measured the impact on the commodity derivative instruments and, thereby, did not consider the underlying exposure related to the commodity. At December 31, 2010, Energen Resources was in a net loss position of $70.5 million for derivative contracts and estimates that a 10 percent increase or decrease in the commodities prices would have resulted in an approximate $176 million change in the fair value of open derivative

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contracts; however, gains and losses on derivative contracts are expected to be similarly offset by sales at the spot market price. The hypothetical change in fair value was calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes and did not include the impact of related taxes on actual cash prices.

All derivatives are recognized at fair value under the fair value hierarchy as discussed in Note 1, Summary of Significant Accounting Policies, in the Notes to Financial Statements. Over-the-counter derivatives are valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to New York Mercantile Exchange (NYMEX) natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and liquids swaps. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen or Alagasco. As of the balance sheet date, the Company believes that these prices represent the best estimate of the exit price for these instruments and are representative of the prices for which the contract will ultimately settle or realize.

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

	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Noncurrent assets		-			-			-
Current liabilities		(76,527	)		(1,997	)		(78,524	)
Noncurrent liabilities		(107,452	)		(5,484	)		(112,936	)
Net derivative asset (liability)	$	(173,663	)	$	42,755		$	(130,908	)

	December 31, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	57,235		$	62,208		$	119,443
Noncurrent assets		(1,600	)		9,424			7,824
Current liabilities		(25,518	)		(6,584	)		(32,102	)
Noncurrent liabilities		(59,914	)		(531	)		(60,445	)
Net derivative asset (liability)	$	(29,797	)	$	64,517		$	34,720

* Amounts classified in accordance with accounting guidance which permits offsetting fair value of amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of December 31, 2010, Alagasco has $27.9 million and $32.5 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. As of December 31, 2009, Alagasco has $25.8 million and $19 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco has no derivative instruments classified as Level 3 fair values as of December 31, 2010 and 2009.

Level 3 assets as of December 31, 2010 represent approximately 1 percent of total assets and an immaterial amount of total liabilities, respectively. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $39 million

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change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations for Level 3 derivatives would be immaterial due to the derivative instruments qualifying as cash flow hedges. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the Securities and Exchange Commission to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The Dodd-Frank Act may require the Company and Alagasco to comply with margin requirements and certain clearing and trade execution requirements. Certain counterparties may also be required to spin off some of their derivatives activities to separate and potentially less creditworthy entities. Further, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets. These rules and regulations if implemented could materially impact the Company and Alagasco’s use of derivative instruments and could significantly increase the cost of derivative instruments, limit the availability of derivatives instruments used to protect against risks, increase exposure to credit risk and reduce available liquidity. The Company and Alagasco are currently unable to estimate the impact of the Dodd-Frank Act, however, these rules and regulations could have a material adverse effect on the Company and Alagasco’s financial position, results of operations and cash flows.

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Oil and Gas Operations

Accounting for Natural Gas and Oil Producing Activities and Related Reserves: The Company utilizes the successful efforts method of accounting for its natural gas and oil producing activities. Acquisition and development costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of total proved and proved developed reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have audited the estimates of proved reserves of natural gas, crude oil and natural gas liquids attributed to the Company’s net interests in oil and gas properties as of December 31, 2010. The independent reservoir engineers

36

have issued reports covering approximately 96 percent of the Company’s ending proved reserves and in their judgment these estimates were reasonable in the aggregate. The Company’s production of proved undeveloped reserves requires the drilling of development wells and the installation or completion of related infrastructure facilities.

Changes in oil and gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property’s book value if an impairment is warranted. The table below reflects an estimated increase in 2011 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and gas reserve amounts at December 31, 2010:

	Percentage Change in Oil & Gas Reserves From Reported Reserves as of December 31, 2010
(dollars in thousands)	-5%	-10%
Estimated increase in DD&A expense for the year ended December 31, 2011, net of tax	$ 6,645	$ 13,974

Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred.

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

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

Energen Resources also may recognize any impairment of capitalized costs for unproved properties. The greatest portion of these costs generally relates to the acquisition of leasehold costs and exploratory drilling costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by exploration activities, changes in economic factors and potential shifts in business strategy employed by management. The Company considers a combination of geologic and engineering factors to evaluate the need for impairment of these costs.

Derivatives: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. Energen Resources recognizes all derivates on the balance sheet and measures all derivatives at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources may also enter into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. Gains and losses from the change in fair value of

37

derivative instruments that do not qualify for hedge accounting are reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.

Natural Gas Distribution

Regulated Operations: Alagasco capitalizes costs as regulatory assets that otherwise would be charged to expense if it is probable that the cost is recoverable in the future through regulated rates. Likewise, if current recovery is provided for a cost that will be incurred in the future, the cost would be recognized as a regulatory liability. Alagasco’s rate setting methodology, Rate Stabilization and Equalization, has been in effect since 1983.

Consolidated

Employee Benefit Plans: An employer is required to recognize the net funded status of defined benefit pensions and other postretirement benefit plans (benefit plans) as an asset or liability in its statement of financial position and to recognize changes in the funded status through comprehensive income in the year in which the changes occur. The pension benefit obligation is the projected benefit obligation (PBO), a measurement of earned benefit obligations at expected retirement salary levels; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation (APBO), a measurement of earned postretirement benefit obligations expected to be paid to employees upon retirement. Alagasco established a regulatory asset for the portion of the total benefit obligation to be recovered through rates in future periods.

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

In selecting the discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments; the weighted average discount rate used to determine net periodic costs was 5.49 percent for the plans for the year ended December 31, 2010. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions; the return on assets used to determine net periodic expense was 7.25 percent for each of the applicable plans for the year ended December 31, 2010. The estimated weighted average rate of increase in the compensation level for pay related plans was 3.95 percent for the year ended December 31, 2010.

The selection and use of actuarial assumptions affects the amount of benefit expense recorded in the Company’s financial statements. The table below reflects a hypothetical 25 basis point change in assumed actuarial assumptions to pre-tax benefit expense for the year ended December 31, 2010:

	Pension	Postretirement
(in thousands)	Expense	Expense
Discount rate change	$  1,100	$  50
Return on assets	$     450	$150
Compensation increase	$     650	$     -

The weighted average discount rate, return on plan assets and estimated rate of compensation increase used in the 2011 actuarial assumptions is 4.89 percent, 7.25 percent, and 3.75 percent, respectively.

Asset Retirement Obligation: The Company records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the

38

related assets. Upon settlement of the liability, the Company will settle the obligation for its recorded amount and recognize the resulting gain or loss. Energen Resources has an obligation to remove tangible equipment and restore land at the end of oil and gas production operations. Alagasco has certain removal cost obligations related to its gas distribution assets and a conditional asset retirement obligation to purge and cap its distribution and transmission lines upon abandonment. The estimate of future restoration and removal costs includes numerous assumptions and uncertainties, including but not limited to, inflation factors, discount rates, timing of settlement, and changes in contractual, regulatory, political, environmental, safety and public relations considerations.

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

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

39

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ENERGEN CORPORATION

ALABAMA GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULES

		Page
1.	Financial Statements
	Energen Corporation
	Report of Independent Registered Public Accounting Firm		41
	Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008		43
	Consolidated Balance Sheets as of December 31, 2010 and 2009		44
	Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2010, 2009 and 2008		46
	Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		47
	Notes to Financial Statements		53
	Alabama Gas Corporation
	Report of Independent Registered Public Accounting Firm		42
	Statements of Income for the years ended December 31, 2010, 2009 and 2008		48
	Balance Sheets as of December 31, 2010 and 2009		49
	Statements of Shareholder’s Equity for the years ended December 31, 2010, 2009 and 2008		51
	Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		52
	Notes to Financial Statements		53
2.	Financial Statement Schedules
	Energen Corporation
	Schedule II - Valuation and Qualifying Accounts		93
	Alabama Gas Corporation
	Schedule II - Valuation and Qualifying Accounts		93

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

40

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energen Corporation:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Energen Corporation and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report On Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 25, 2011

41

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

In our opinion, the financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Alabama Gas Corporation at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report On Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 25, 2011

42

CONSOLIDATED STATEMENTS OF INCOME

Energen Corporation

Years ended December 31, (in thousands, except share data)	2010			2009			2008
Operating Revenues
Oil and gas operations	$	958,762		$	822,546		$	914,132
Natural gas distribution		619,772			617,874			654,778
Total operating revenues		1,578,534			1,440,420			1,568,910
Operating Expenses
Cost of gas		316,988			306,054			351,774
Operations and maintenance		429,165			380,625			354,760
Depreciation, depletion and amortization		247,865			235,084			188,413
Taxes, other than income taxes		84,961			78,329			107,605
Accretion expense		6,178			4,935			4,290
Total operating expenses		1,085,157			1,005,027			1,006,842
Operating Income		493,377			435,393			562,068
Other Income (Expense)
Interest expense		(39,222	)		(39,379	)		(41,981	)
Other income		4,285			4,972			1,885
Other expense		(643	)		(690	)		(7,014	)
Total other expense		(35,580	)		(35,097	)		(47,110	)
Income Before Income Taxes		457,797			400,296			514,958
Income tax expense		166,990			143,971			193,043
Net Income	$	290,807		$	256,325		$	321,915
Diluted Earnings Per Average Common Share	$	4.04		$	3.57		$	4.47
Basic Earnings Per Average Common Share	$	4.05		$	3.58		$	4.50
Diluted Average Common Shares Outstanding		72,050,997			71,885,422			72,030,210
Basic Average Common Shares Outstanding		71,845,463			71,667,304			71,600,925

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

43

CONSOLIDATED BALANCE SHEETS

Energen Corporation

(in thousands)	December 31, 2010		December 31, 2009
ASSETS
Current Assets
Cash and cash equivalents	$	22,659	$           75,844
Accounts receivable, net of allowance for doubtful accounts of $15,048 and $17,251 at December 31, 2010 and 2009, respectively		286,849	327,163
Inventories
Storage gas inventory		36,706	42,475
Materials and supplies		19,045	17,440
Liquified natural gas in storage		3,551	3,409
Regulatory asset		28,286	33,196
Income tax receivable		44,489	4,552
Deferred income taxes		32,732	-
Prepayments and other		11,966	11,527
Total current assets		486,283	515,606
Property, Plant and Equipment
Oil and gas properties, successful efforts method		4,080,779	3,379,128
Less accumulated depreciation, depletion and amortization		1,161,635	972,676
Oil and gas properties, net		2,919,144	2,406,452
Utility plant		1,292,611	1,211,624
Less accumulated depreciation		509,989	489,924
Utility plant, net		782,622	721,700
Other property, net		17,461	16,317
Total property, plant and equipment, net		3,719,227	3,144,469
Other Assets
Regulatory asset		105,365	102,133
Pension and other postretirement assets		13,907	-
Long-term derivative instruments		-	7,824
Deferred charges and other		38,778	33,086
Total other assets		158,050	143,043
TOTAL ASSETS	$	4,363,560	$      3,803,118

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

44

CONSOLIDATED BALANCE SHEETS
Energen Corporation
(in thousands, except share data)	December 31, 2010			December 31, 2009
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	5,000		$	150,000
Notes payable to banks		305,000			-
Accounts payable		268,214			164,327
Accrued taxes		52,845			49,884
Customers’ deposits		20,459			20,836
Amounts due customers		20,161			24,106
Accrued wages and benefits		25,203			27,347
Regulatory liability		75,703			29,719
Royalty payable		19,221			19,034
Deferred income taxes		-			10,015
Other		26,805			25,493
Total current liabilities		818,611			520,761
Long-term debt		405,254			410,786
Deferred Credits and Other Liabilities
Asset retirement obligation		97,415			88,298
Pension and other postretirement liabilities		36,551			55,899
Regulatory liability		110,447			155,088
Deferred income taxes		615,084			505,460
Long-term derivative instruments		112,936			60,446
Other		13,219			18,137
Total deferred credits and other liabilities		985,652			883,328
Commitments and Contingencies
Shareholders’ Equity		-			-
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized
Common shareholders’ equity		748			746
Common stock, $0.01 par value; 150,000,000 shares authorized, 74,786,376 shares issued at December 31, 2010 and 74,593,431 shares issued at December 31, 2009
Premium on capital stock		468,934			461,661
Capital surplus		2,802			2,802
Retained earnings		1,880,183			1,626,753
Accumulated other comprehensive income (loss), net of tax
Unrealized gain (loss) on hedges, net		(43,667	)		49,405
Pension and postretirement plans		(30,730	)		(31,790	)
Deferred compensation plan		3,288			3,121
Treasury stock, at cost; 3,024,847 shares and 2,991,373 shares at December 31, 2010 and 2009, respectively		(127,515	)		(124,455	)
Total shareholders’ equity		2,154,043			1,988,243
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	4,363,560		$	3,803,118

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

45

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

Energen Corporation

	Common Stock				Premium on Capital Stock			Capital Surplus		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Deferred Compensation Plan			Treasury Stock			Total Shareholders’ Equity
	Number of Shares		Par Value
BALANCE DECEMBER 31, 2007		74,190,786	$	742	$	434,999		$	2,802	$	1,119,816		$	(86,224	)	$	16,121		$	(109,598	)	$	1,378,658
Net income											321,915												321,915
Other comprehensive income (loss):
Change in fair value of derivative instruments, net of tax of $120,742														197,000									197,000
Reclassification adjustment, net of tax of $42,243														68,924									68,924
Pension and postretirement plans, net of tax of ($5,324)														(9,883	)								(9,883	)
Comprehensive income																							577,956
Purchase of treasury shares, net																				(27,345	)		(27.345	)
Shares issued for employee benefit plans		331,171		3		8,548																	8,551
Deferred compensation obligation																	(13,173	)		13,173			-
Stock based compensation						(5,862	)																(5,862	)
Tax benefit from employee stock plans						17,093																	17,093
Change in measurement date for defined benefit and postretirement plans, net of tax of ($614)											(1,141	)											(1,141	)
Cash dividends - $0.48 per share											(34,620	)											(34,620	)
BALANCE DECEMBER 31, 2008		74,521,957		745		454,778			2,802		1,405,970			169,817			2,948			(123,770	)		1,913,290
Net income											256,325												256,325
Other comprehensive income (loss):
Change in fair value of derivative instruments, net of tax of ($2,032)														(3,316	)								(3,316	)
Reclassification adjustment, net of tax of ($90,799)														(148,146	)								(148,146	)
Pension and postretirement plans, net of tax of ($397)														(740	)								(740	)
Comprehensive income																							104,123
Purchase of treasury shares, net																				(512	)		(512	)
Shares issued for employee benefit plans		71,474		1		994																	995
Deferred compensation obligation																	173			(173	)		-
Stock based compensation						5,283																	5,283
Tax benefit from employee stock plans						606																	606
Cash dividends - $0.50 per share											(35,542	)											(35,542	)
BALANCE DECEMBER 31, 2009		74,593,431		746		461,661			2,802		1,626,753			17,615			3,121			(124,455	)		1,988,243
Net income											290,807												290,807
Other comprehensive income (loss):
Change in fair value of derivative instruments, net of tax of $19,491														31,801									31,801
Reclassification adjustment, net of tax of ($76,535)														(124,873	)								(124,873	)
Pension and postretirement plans, net of tax of $570														1,060									1,060
Comprehensive income																							198,795
Purchase of treasury shares, net																				(2,893	)		(2,893	)
Shares issued for employee benefit plans		192,945		2		6,449																	6,451
Deferred compensation obligation																	167			(167	)		-
Stock based compensation						(83	)																(83	)
Tax benefit from employee stock plans						907																	907
Cash dividends - $0.52 per share											(37,377	)											(37,377	)
BALANCE DECEMBER 31, 2010		74,786,376	$	748	$	468,934		$	2,802	$	1,880,183		$	(74,397	)	$	3,288		$	(127,515	)	$	2,154,043

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

46

CONSOLIDATED STATEMENTS OF CASH FLOWS

Energen Corporation

Years ended December 31, (in thousands)	2010			2009			2008
Operating Activities
Net income	$	290,807		$	256,325		$	321,915
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		247,865			235,084			188,413
Accretion expense		6,178			4,935			4,290
Deferred income taxes		133,840			84,616			188,414
Bad debt expense		1,565			10,688			6,471
Change in derivative fair value		(819	)		(104	)		(2,580	)
Gain on sale of assets		(2,521	)		(5,617	)		(10,752	)
Other, net		(568	)		23,843			8,834
Exploratory expense		63,668			9,874			7,620
Net change in:
Accounts receivable		(31,939	)		(31,914	)		94
Inventories		4,022			30,679			1,274
Accounts payable		18,889			5,539			(36,149	)
Amounts due customers including gas supply pass-through		20,751			16,967			(16,873	)
Income tax receivable		(39,937	)		45,924			(50,476	)
Pension and other postretirement benefit contributions		(42,233	)		(24,137	)		(30,261	)
Other current assets and liabilities		1,454			16,755			(11,001	)
Net cash provided by operating activities		671,022			679,457			569,233
Investing Activities
Additions to property, plant and equipment		(434,121	)		(340,107	)		(460,237	)
Acquisitions, net of cash acquired		(410,348	)		(185,131	)		(17,914	)
Proceeds from sale of assets		3,155			7,923			16,224
Purchase of short-term investments		(154,880	)		-			-
Sale of short-term investments		154,965			-			-
Other, net		(1,464	)		(1,808	)		(2,656	)
Net cash used in investing activities		(842,693	)		(519,123	)		(464,583	)
Financing Activities
Payment of dividends on common stock		(37,377	)		(35,542	)		(34,620	)
Issuance of common stock		685			621			277
Reduction of long-term debt		(150,729	)		(1,035	)		(10,910	)
Net change in short-term debt		305,000			(62,000	)		(72,000	)
Tax benefit on stock compensation		907			606			17,093
Other		-			(317	)		-
Net cash provided by (used in) financing activities		118,486			(97,667	)		(100,160	)
Net change in cash and cash equivalents		(53,185	)		62,667			4,490
Cash and cash equivalents at beginning of period		75,844			13,177			8,687
Cash and cash equivalents at end of period	$	22,659		$	75,844		$	13,177

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

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STATEMENTS OF INCOME

Alabama Gas Corporation

Years ended December 31, (in thousands)	2010			2009			2008
Operating Revenues	$	619,772		$	617,874		$	654,778
Operating Expenses
Cost of gas		316,988			306,054			351,774
Operations and maintenance		128,830			134,847			127,877
Depreciation and amortization		44,042			50,995			48,874
Income taxes
Current		1,014			11,096			(26,075	)
Deferred		28,861			16,257			50,904
Taxes, other than income taxes		41,529			41,994			44,297
Total operating expenses		561,264			561,243			597,651
Operating Income		58,508			56,631			57,127
Other Income (Expense)
Allowance for funds used during construction		808			1,106			700
Other income		1,923			2,014			704
Other expense		(462	)		(622	)		(3,563	)
Total other income (expense)		2,269			2,498			(2,159	)
Interest Charges
Interest on long-term debt		11,907			11,906			11,961
Other interest charges		1,987			1,808			2,846
Total interest charges		13,894			13,714			14,807
Net Income	$	46,883		$	45,415		$	40,161

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

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BALANCE SHEETS

Alabama Gas Corporation

(in thousands)	December 31, 2010			December 31, 2009
ASSETS
Property, Plant and Equipment
Utility plant	$	1,292,611		$	1,211,624
Less accumulated depreciation		509,989			489,924
Utility plant, net		782,622			721,700
Other property, net		43			146
Current Assets
Cash		16,910			9,460
Accounts receivable
Gas		136,800			137,891
Other		10,229			8,617
Affiliated companies		698			-
Allowance for doubtful accounts		(14,200	)		(16,400	)
Inventories
Storage gas inventory		36,706			42,475
Materials and supplies		4,147			4,374
Liquified natural gas in storage		3,551			3,409
Regulatory asset		28,286			33,196
Income tax receivable		10,315			3,469
Deferred income taxes		27,302			25,896
Prepayments and other		4,223			3,303
Total current assets		264,967			255,690
Other Assets
Regulatory asset		105,365			102,133
Pension and other postretirement assets		9,201			-
Deferred charges and other		5,399			4,997
Total other assets		119,965			107,130
TOTAL ASSETS	$	1,167,597		$	1,084,666

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

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BALANCE SHEETS

Alabama Gas Corporation

(in thousands, except share data)	December 31, 2010		December 31, 2009
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative, $0.01 par value, 120,000 shares authorized	$	-	$                    -
Common shareholder’s equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at December 31, 2010 and 2009, respectively		20	20
Premium on capital stock		31,682	31,682
Capital surplus		2,802	2,802
Retained earnings		292,815	283,299
Total common shareholder’s equity		327,319	317,803
Long-term debt		200,793	206,522
Total capitalization		528,112	524,325
Current Liabilities
Long-term debt due within one year		5,000	-
Notes payable to banks		70,000	-
Accounts payable		83,515	78,154
Affiliated companies		-	24,962
Accrued taxes		48,476	35,314
Customers’ deposits		20,459	20,836
Amounts due customers		20,161	24,106
Accrued wages and benefits		11,851	11,472
Regulatory liability		75,703	29,719
Other		11,822	9,830
Total current liabilities		346,987	234,393
Deferred Credits and Other Liabilities
Deferred income taxes		141,780	121,826
Pension and other postretirement liabilities		4,733	19,054
Regulatory liability		110,447	155,088
Long-term derivative instruments		32,461	18,965
Other		3,077	11,015
Total deferred credits and other liabilities		292,498	325,948
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,167,597	$      1,084,666

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

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STATEMENTS OF SHAREHOLDER’S EQUITY

Alabama Gas Corporation

(in thousands, except share data)
	Common Stock											Total
	Number of Shares		Par Value		Premium on Capital Stock		Capital Surplus		Retained Earnings			Shareholder’s Equity
Balance December 31, 2007		1,972,052	$	20	$	31,682	$	2,802	$	261,979		$	296,483
Net income										40,161			40,161
Cash dividends										(28,397	)		(28,397	)
Balance December 31, 2008		1,972,052		20		31,682		2,802		273,743			308,247
Net income										45,415			45,415
Cash dividends										(35,859	)		(35,859	)
Balance December 31, 2009		1,972,052		20		31,682		2,802		283,299			317,803
Net income										46,883			46,883
Cash dividends										(37,367	)		(37,367	)
Balance December 31, 2010		1,972,052	$	20	$	31,682	$	2,802	$	292,815		$	327,319

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

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STATEMENTS OF CASH FLOWS

Alabama Gas Corporation

Years ended December 31, (in thousands)	2010			2009			2008
Operating Activities
Net income	$	46,883		$	45,415		$	40,161
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		44,042			50,995			48,874
Deferred income taxes		28,861			16,257			50,904
Bad debt expense		1,561			10,605			6,391
Other, net		(10,958	)		9,092			9,234
Net change in:
Accounts receivable		(26,567	)		7,001			(16,125	)
Inventories		5,854			34,585			589
Accounts payable		2,663			(30,320	)		3,608
Amounts due customers including gas supply pass-through		20,751			16,967			(16,873	)
Income tax receivable		(6,846	)		27,185			(28,209	)
Pension and other postretirement benefit contributions		(26,083	)		(14,731	)		(17,807	)
Other current assets and liabilities		14,273			585			774
Net cash provided by operating activities		94,434			173,636			81,521
Investing Activities
Additions to property, plant and equipment		(92,099	)		(77,070	)		(62,637	)
Other, net		(1,827	)		(1,320	)		(3,832	)
Net cash used in investing activities		(93,926	)		(78,390	)		(66,469	)
Financing Activities
Payment of dividends on common stock		(37,367	)		(35,859	)		(28,397	)
Reduction of long-term debt		(729	)		(1,035	)		(910	)
Net advances (to) from parent company		(24,962	)		3,380			16,648
Net change in short-term debt		70,000			(62,000	)		-
Net cash provided by (used in) financing activities		6,942			(95,514	)		(12,659	)
Net change in cash and cash equivalents		7,450			(268	)		2,393
Cash and cash equivalents at beginning of period		9,460			9,728			7,335
Cash and cash equivalents at end of period	$	16,910		$	9,460		$	9,728

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

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NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

During the first quarter of 2010, Alabama Gas Corporation (Alagasco) identified an error in calculating the estimate of the allowance for doubtful accounts as of December 31, 2009. This error resulted in a $3 million overstatement to the allowance for doubtful accounts and a corresponding overstatement of net income by approximately $0.6 million (approximately $0.01 per diluted share) after reflecting the regulatory limits on Alagasco’s allowed rate of return for rate year ending September 30, 2010 in the application of Rate Stabilization and Equalization. The Company considered the net impact of this adjustment on the current and prior quarterly results, the prior year-end results, and the results of Alagasco and Energen for the year ended December 31, 2010 and determined that the amount was not material to these periods. As a result, the Company corrected this error in the first quarter of 2010.

A. Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation, after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years’ financial statements to the current-year presentation. The Company has evaluated subsequent events until the time the consolidated financial statements were issued.

B. Oil and Gas Operations

Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.

Operating Revenue: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no material production imbalances at December 31, 2010 and 2009.

Derivative Commodity Instruments: Energen Resources recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated statements of cash flows.

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Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment and commercial banks and energy-trading firms. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of December 31, 2010, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Additionally, the Company may also enter into derivatives that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness in hedging the exposure to the hedged transaction’s variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge.

Long-Lived Assets and Discontinued Operations: The Company reports gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for certain held-for-sale properties are reclassified and reported as discontinued operations for prior periods. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.

Acquisitions: Energen Resources recognizes all acquisitions at fair value. Energen Resources estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen Resources obtained control of the properties for all acquisitions that qualify as business combinations. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. Energen Resources uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs. Acquisition related costs are expensed as incurred in operations and maintenance expense on the consolidated income statements.

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C. Natural Gas Distribution

Regulatory Accounting: Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) with respect to rates, accounting and various other matters. In general, Alagasco capitalizes or defers certain costs or revenues, based on the approvals received from the APSC, to be recovered from or refunded to customers in future periods. These costs or revenues are recorded as regulatory assets or liabilities.

Utility Plant and Depreciation: Property, plant and equipment are stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets are charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the APSC. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July, 2010 and $2.7 million through lower tariff rates in December, 2010, and will return to eligible customers an additional estimated $112.8 million, which includes approximately $22.3 million between January 1, 2011 and December 31, 2011. The remainder will be refunded to eligible customers on a declining basis through lower tariff rates over an eight year period originally beginning December 1, 2011. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. On November 1, 2010, the APSC specifically approved adjustments to the total amount refundable to include items originally approved in the APSC’s 1998 order establishing the ESR, environmental response costs and self insurance costs that exceed $1 million per occurrence. The refunds as of December, 2010 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the past five years. Approved depreciation rates averaged approximately 3.6 percent in the year ended December 31, 2010, and approximately 4.4 percent in the years ended December 31, 2009 and 2008. The revised depreciation rates decreased depreciation expense by approximately $9.2 million for the year ended December 31, 2010 from that using the prior depreciation rate.

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

Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2010 and 2009.

Derivative Commodity Instruments: Alagasco may enter into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet at fair value. Any gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Alagasco.

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

Years ended December 31, (in thousands)	2010		2009		2008
Taxes on revenues	$	30,704	$	31,704	$	32,970

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

D. Fair Value Measurements

The carrying values of cash and cash equivalents, accounts payable and receivable, derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The fair value hierarchy that prioritizes the inputs used to measure fair value is defined as follows:

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

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

Pension and postretirement plan assets include mutual and comingled funds and a limited partnership. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds. Level 3 fair values used unobservable market prices primarily associated with certain alternative investments and a limited partnership.

E. Income Taxes

The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.

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F. Accounts Receivable and Allowance for Doubtful Accounts

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

G. Cash Equivalents

All highly liquid financial instruments with an original maturity of three months or less at the time of purchase are considered to be cash or cash equivalents.

H. Short-term investments

All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short term investments. As of December 31, 2010, Energen had no short term investments. Short-term investments are classified as Level 2 fair value.

I. Earnings Per Share (EPS)

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

J. Stock-Based Compensation

The Company measures all share-based compensation awards at fair value at the date of grant and expenses the awards over the requisite vesting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates.

The Company previously recognized all stock-based employee compensation expense over the stated vesting periods for each award. For awards granted prior to January 1, 2006, the Company recorded any unrecognized expense on the date of an employee’s retirement. For new awards granted to retirement eligible employees effective January 1, 2006, the Company began recognizing the entire compensation expense in the period of grant. If this method of expense recognition for retirement eligible employees had been applied to all awards, there would have been no impact to compensation expense during 2010 and 2009, and an increase of approximately $1.2 million in 2008. The Company utilized the long-form method of calculating the available pool of windfall tax benefit. For 2010 and 2009, the Company recognized an excess tax benefit of $0.9 million and $0.6 million related to its stock-based compensation.

K. Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that regulatory accounting will continue as the applicable accounting standard for the Company’s regulated operations, the Company’s obligations under its employee pension plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves, asset retirement obligations, self insurance reserves and regulatory assets and liabilities. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

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L. Employee Benefit Plans

Energen has two defined benefit non-contributory qualified pension plans. These plans cover substantially all employees. Pension benefits for the majority of the Company’s employees are based on years of service and final earnings; one plan is based on years of service and flat dollar amounts. The Company also has nonqualified supplemental pension plans covering certain officers of the Company. In addition to providing pension benefits, the Company provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. The Company continues to provide these benefits to certain non-salaried employees. Substantially all of the Company’s employees may become eligible for certain benefits if they reach normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.

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

Measurement: The Company calculates periodic expense for defined benefit pension plans and other post retirement benefit plans on an actuarial basis and the net funded status of benefit plans is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligation to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be provided through rates in the future. As of December 31, 2008, the Company measured the funded status of its employee benefit plans as of the date of its year-end statement of financial position. Previously, the Company used a September 30 valuation date for its benefit plans. During the fourth quarter of 2008, the Company changed the measurement date to December 31 using the alternative method. The Company recognized a one-time reduction to retained earnings of $1.8 million pre-tax and an increase to the current and noncurrent regulatory assets of Alagasco totaling approximately $0.1 million and $1.4 million pre-tax, respectively. The increase to regulatory assets which totaled $1.5 million will be recovered in rates over the average remaining service lives of each plan.

Discount Rate: In selecting each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate for each plan was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments; the weighted average discount rates used to determine net periodic costs were 5.49 percent for the pension plans and 5.9 percent for the other postretirement benefit plans for the year ended December 31, 2010.

Long-Term Rate of Return: The assumed rate of return on assets is the weighted average of expected long-term asset assumptions; the return on assets used to determine net periodic expense was 7.25 percent for each of the applicable plans for the year ended December 31, 2010. The Company based its expected return on long-term investment expectations. The Company considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets.

Other Significant Assumptions: The estimated weighted average rate of increase in the compensation level for pay related plans was 3.95 percent for determining the net periodic costs for the year ended December 31, 2010.

M. Environmental Costs

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

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2. REGULATORY MATTERS

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

Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, whether Alagasco’s return on average equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the year ended December 31, 2010, Alagasco had reduction in revenues of $17.4 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. As of September 30, 2009, Alagasco had a $1.5 million pre-tax reduction in revenues to bring the return on average equity to midpoint within allowed range of return. Alagasco did not have a reduction in rates related to the return on average equity for the rate year ended 2008. Under the provisions of RSE, a $1.3 million annual decrease, $10.2 million annual increase and $24.7 million annual increase in revenues became effective December 1, 2010, 2009, and 2008, respectively.

RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. In the rate year ended September 30, 2010, $2.5 million of extraordinary bad debt expense was excluded from the CCM calculation. In the rate year ended September 30, 2008, the increase in O&M expense was below the Index Range; as a result the utility benefited by $2.9 million pre-tax with the related impact to rates effective December 1, 2008. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2010 and 2009.

Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed 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.

In 1988, the APSC approved an Enhanced Stability Reserve, with a maximum funding level of $4 million, to which Alagasco could charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses caused Alagasco’s year-end return on average equity (RCE) to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent. Prior to June 28, 2010, the APSC provided for accretions to the ESR of no more than $40,000 monthly until the maximum funding level was achieved, following

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a year in which a charge against the ESR was made. The APSC’s June 28, 2010 order approved Alagasco’s lower depreciation rates and approved standing authority for Alagasco to charge items to the ESR in excess of its funded balance and to allocate each year from the refundable negative salvage costs that are being refunded to customers over the nine year period the amount necessary to clear the debit balance in the ESR each September 30, subject to APSC-approved guidelines. The APSC also approved the amortization of the ESR charges into rates over a five year period in cases where the ESR is unfunded or underfunded, subject to APSC-approved guidelines. As a result of these changes in the funding mechanism for the ESR, the APSC suspended the $40,000 per month accruals to the ESR during the nine year period when the refundable negative salvage costs are being refunded to customers.

Following a vote on September 7, 2010, the APSC, by order dated November 1, 2010, approved expansion of the ESR to include extraordinary O&M charges related to environmental response costs and to self insurance costs that exceed $1 million per occurrence. In addition, the APSC raised the thresholds on items that may be charged to the ESR as follows: (1) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single event that results in more than $275,000 of increased O&M; (2) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a combination of extraordinary O&M events that result in more than $412,500 of increased O&M; and (3) individual large commercial and industrial customer revenue variances that exceed $350,000. Charges to the ESR relating to extraordinary O&M expenses can only be made when the Company’s year-end return on average common equity for RSE, not including the ESR charge, is below the midpoint of the APSC-approved return on equity range and only to the extent necessary to bring the RCE to the midpoint of the range. Charges to the ESR relating to individual large commercial and industrial customer revenue losses can only be made if such losses cause the RCE to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent, and then only to the extent necessary to bring the RCE up to the midpoint of the range. In the event that Alagasco’s RCE at September 30 of the related year is above the midpoint, any debit balance in the ESR shall remain in the ESR for recovery in subsequent years subject to the established guidelines. Additionally, the APSC, while confirming the five year amortization period established in the June 28, 2010 order for charges to the ESR in cases where the ESR is unfunded or underfunded, limited the amortization expense to $660,000 annually, with any excess amortization expense over $660,000 in any rate year being carried over and amortized in future rate years until full amortization of the ESR debit balance is complete. The APSC also raised the $40,000 per month accruals to $55,000 per month, but suspended the accruals pending further order of the APSC. Finally, the APSC established guidelines for the documentation, reporting and approval of rate recovery of items charged to the ESR.

In connection with the above, Alagasco expects to recover certain manufactured gas plant site remediation costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory account of $3.8 million and $2.7 million as of December 31, 2010 and 2009, respectively, as more fully described in Note 7, Commitments and Contingencies.

The excess of total acquisition costs over book value of net assets of acquired municipal gas distribution systems is included in utility plant and is being amortized through Alagasco’s rate-setting mechanism on a straight-line basis with a weighted average remaining life of approximately 7 years. At December 31, 2010 and 2009, the net acquisition adjustments were $5.1 million and $5.9 million, respectively.

3. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

(in thousands)	December 31, 2010		December 31, 2009
Energen Corporation:
Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 30, 2012, to February 15, 2028		$    155,000	$    305,000
5% Notes, due October 1, 2013		50,000	50,000
Alabama Gas Corporation:
Medium-term Notes, Series A, interest of 7.57%, due September 20, 2011		5,000	5,000
5.20% Notes, due January 15, 2020		40,000	40,000
5.70% Notes, due January 15, 2035		35,793	36,522
5.368% Notes, due December 1, 2015		80,000	80,000
5.90% Notes, due January 15, 2037		45,000	45,000
Total		410,793	561,522
Less amounts due within one year		5,000	150,000
Less unamortized debt discount		539	736
Total		$    405,254	$    410,786

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

Years ending December 31, (in thousands)
2011	2012	2013	2014	2015
$  5,000	$  1,000	$  50,000	-	$  80,000

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

Years ending December 31, (in thousands)
2011	2012	2013	2014	2015
$  5,000	-	-	-	$  80,000

The long-term debt and short-term debt agreements of Energen and Alagasco contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. None of the agreements have covenants or events of default based on credit ratings. All of the Company’s debt is unsecured.

Under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee, a cross default provision provides that any debt default of more than $10 million by Energen, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s Indenture dated November 1, 1993 with The Bank of New York as Trustee, a cross default provision provides that any debt default by Alagasco of more than $10 million will constitute an event of default by Alagasco. Neither Indenture includes a restriction on the payment of dividends.

On October 29, 2010, Energen and Alagasco entered into an $850 million and a $150 million, respectively, three-year syndicated unsecured credit facility (syndicated credit facilities) with domestic and foreign lenders. These syndicated credit facilities replace the majority of the Company’s short-term credit facilities which were available to Energen and Alagasco. Alagasco has been authorized by the APSC to borrow up to $200 million at any one time under short-term lines of credit.

Energen’s obligations under its credit facility are unconditionally guaranteed by Energen Resources. The financial covenants of the Energen credit facility require Energen to maintain a maximum consolidated debt to capitalization ratio of 65 percent as of the end of any fiscal quarter. Energen may not pay dividends during an event of default or if the payment would result in an event of default.

Similarly, the financial covenants of the Alagasco credit facility require Alagasco to maintain a maximum consolidated debt to capitalization ratio of 65 percent as of the end of any fiscal quarter. Alagasco may not pay dividends during an event of default or if the payment would result in an event of default.

Under the Energen credit facility, a cross default provision provides that any debt default of more than $50 million by Energen, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s credit facility, a cross default provision provides that any debt default by Alagasco of more than $50 million will constitute an event of default by Alagasco.

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Upon an uncured event of default under either of the credit facilities, all amounts owing under the defaulted credit facility, if any, depending on the nature of the event of default will automatically, or may upon notice by the administrative agent or the requisite lenders thereunder, become immediately due and payable and the lenders may terminate their commitments under the defaulted facility. Energen and Alagasco were in compliance with the terms of their respective credit facilities as of December 31, 2010.

The following is a summary of information relating to the credit facilities:

(in thousands)	Current Term		Energen		Alagasco		Total
Syndicated Credit Facility		10/29/2013	$	850,000	$	150,000	$1,000,000
Bryant Bank		11/1/2011		-		9,000	9,000
BancorpSouth Bank		5/23/2011		-		10,000	10,000
Total			$	850,000	$	169,000	$1,019,000

(in thousands)	December 31, 2010			December 31, 2009
Energen outstanding	$	235,000		$              -
Alagasco outstanding		70,000		-
Notes payable to banks		305,000		-
Available for borrowings		714,000		525,000
Total	$	1,019,000		$  525,000
Energen maximum amount outstanding at any month-end	$	305,000		$    95,000
Energen average daily amount outstanding	$	19,732		$    33,630
Energen weighted average interest rates based on:
Average daily amount outstanding		2.07	%	1.06%
Amount outstanding at year-end		2.03	%	-
Alagasco maximum amount outstanding at any month-end	$	70,000		$    59,000
Alagasco average daily amount outstanding	$	6,436		$    16,123
Alagasco weighted average interest rates based on:
Average daily amount outstanding		1.56	%	1.02%
Amount outstanding at year-end		1.90	%	-

Energen’s total interest expense was $39,222,000, $39,379,000 and $41,981,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Total interest expense for Alagasco was $13,894,000, $13,714,000 and $14,807,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

4. INCOME TAXES

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

Years ended December 31, (in thousands)	2010		2009		2008
Taxes estimated to be payable currently:
Federal	$	31,920	$	56,821	$    1,090
State		1,230		2,534	3,539
Total current		33,150		59,355	4,629
Taxes deferred:
Federal		121,804		75,644	172,137
State		12,036		8,972	16,277
Total deferred		133,840		84,616	188,414
Total income tax expense	$	166,990	$	143,971	$193,043

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

Years ended December 31, (in thousands)	2010		2009		2008
Taxes estimated to be payable currently:
Federal	$	859	$	11,035	$	(24,972	)
State		155		61		(1,103	)
Total current		1,014		11,096		(26,075	)
Taxes deferred:
Federal		25,582		13,631		46,869
State		3,279		2,626		4,035
Total deferred		28,861		16,257		50,904
Total income tax expense	$	29,875	$	27,353	$	24,829

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

(in thousands)	December 31, 2010						December 31, 2009
	Current			Noncurrent			Current			Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	14,495		$	-		$	11,221		$	-
Allowance for doubtful accounts		5,626			-			6,459			-
Insurance accruals		2,350			-			2,788			-
Compensation accruals		9,822			-			7,594			-
Inventories		896			-			1,050			-
Other comprehensive income		-			46,244			-			29,078
Gas supply adjustment related accruals		1,407			-			2,111			-
State net operating losses and other carryforwards		811			2,866			702			2,729
Other		2,270			501			2,165			73
Total deferred tax assets		37,677			49,611			34,090			31,880
Valuation allowance		(311	)		(2,555	)		(331	)		(2,398	)
Total deferred tax assets		37,366			47,056			33,759			29,482
Deferred tax liabilities:
Depreciation and basis differences		-			632,032			-			513,302
Pension and other costs		-			29,437			-			19,556
Other comprehensive income		2,934			-			42,241			-
Other		1,700			671			1,533			2,084
Total deferred tax liabilities		4,634			662,140			43,774			534,942
Net deferred tax assets (liabilities)	$	32,732		$	(615,084	)	$	(10,015	)	$	(505,460	)

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

(in thousands)	December 31, 2010					December 31, 2009
	Current		Noncurrent			Current		Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	14,495	$	-		$	11,221	$	-
Allowance for doubtful accounts		5,369		-			6,201		-
Insurance accruals		2,143		-			2,635		-
Compensation accruals		2,672		-			2,365		-
Inventories		896		-			1,050		-
Gas supply adjustment related accruals		1,407		-			2,111		-
State net operating losses and other carryforwards		811		-			702		-
Other		753		55			703		50
Total deferred tax assets		28,546		55			26,988		50
Deferred tax liabilities:
Depreciation and basis differences Pension and other costs		- -		114,193 27,642			- -		100,570 21,306
Other		1,244		-			1,092		-
Total deferred tax liabilities		1,244		141,835			1,092		121,876
Net deferred tax assets (liabilities)	$	27,302	$	(141,780	)	$	25,896	$	(121,826	)

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The Company files a consolidated federal income tax return with all of its subsidiaries. The Company has a current deferred tax asset of $811,000 relating to Alagasco’s $18.8 million state net operating loss carryforward which will expire beginning in 2023. Alagasco anticipates generating adequate future taxable income to fully realize this benefit. The Company has a full valuation allowance recorded against a noncurrent deferred tax asset of $2,866,000 arising from certain state net operating loss and charitable contribution carryforwards. The Company intends to fully reserve this asset until it is determined that it is more likely than not that the asset can be realized through future taxable income in the respective state taxing jurisdictions. No other valuation allowance with respect to deferred taxes is deemed necessary as both the Company and Alagasco anticipate generating adequate future taxable income to realize the benefits of all remaining deferred tax assets on the consolidated balance sheets.

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

Years ended December 31, (in thousands)	2010			2009			2008
Income tax expense at statutory federal income tax rate	$	160,229		$	140,104		$	180,235
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit		8,398			7,384			12,524
Qualified Section 199 production activities deduction		(1,745	)		(2,715	)		(455	)
401(k) stock dividend deduction		(565	)		(567	)		(574	)
Other, net		673			(235	)		1,313
Total income tax expense	$	166,990		$	143,971		$	193,043
Effective income tax rate (%)		36.48			35.97			37.49

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

Years ended December 31, (in thousands)	2010		2009			2008
Income tax expense at statutory federal income tax rate	$	26,865	$	25,469		$	22,747
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit		2,157		2,045			1,826
Other, net		853		(161	)		256
Total income tax expense	$	29,875	$	27,353		$	24,829
Effective income tax rate (%)		38.92		37.59			38.20

A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)
Balance as of December 31, 2007	$	8,517
Additions based on tax positions related to the current year		2,732
Additions for tax positions of prior years		7,199
Reductions for tax positions of prior years (lapse of statute of limitations)		(1,643	)
Balance as of December 31, 2008		16,805
Additions based on tax positions related to the current year		2,530
Additions for tax positions of prior years		841
Reductions for tax positions of prior years (lapse of statute of limitations)		(2,379	)
Balance as of December 31, 2009		17,797
Additions based on tax positions related to the current year		1,436
Additions for tax positions of prior years		11,703
Reductions for tax positions of prior years		(3,624	)
Lapse of statute of limitations		(1,313	)
Settlements		(1,409	)
Balance as of December 31, 2010	$	24,590

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The increase in the additions for tax position of prior years in 2010 and 2008 is primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property that was approved by the Internal Revenue Service (IRS) and subsequently in dispute under an IRS examination. During 2010, the Company had a gross reduction of $3.6 million and recognized in its effective income tax rate a $2.4 million net benefit associated with the release of an unrecognized income tax benefit liability. The Company reassessed its measurement due to recent developments related to the issue and now believes that the full amount of the tax benefit has a greater than 50% chance of being fully realized. The amount of unrecognized tax benefits at December 31, 2010 that would favorably impact the Company’s effective tax rate, if recognized, is $1.5 million. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2010, 2009, and 2008, the Company recognized approximately $801,000, $91,000 and $164,000 of expense for interest (net of tax benefit) and penalties, respectively. The Company had approximately $1,573,000 and $772,000 for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2010 and 2009, respectively.

A reconciliation of Alagasco’s beginning and ending amount of unrecognized tax benefits is as follows:

(in thousands)
Balance as of December 31, 2007	$	955
Additions based on tax positions related to the current year		515
Additions for tax positions of prior years		5,804
Reductions for tax positions of prior years (lapse of statute of limitations)		(384	)
Balance as of December 31, 2008		6,890
Additions based on tax positions related to the current year		821
Additions for tax positions of prior years		197
Reductions for tax positions of prior years (lapse of statute of limitations)		(287	)
Balance as of December 31, 2009		7,621
Additions based on tax positions related to the current year		9
Additions for tax positions of prior years		11,645
Reductions for tax positions of prior years (lapse of statute of limitations)		(90	)
Settlements		(244	)
Balance as of December 31, 2010	$	18,941

The increase in the additions for tax positions of prior years in 2010 and 2008 is primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property discussed above. The amount of unrecognized tax benefits at December 31, 2010 that would favorably impact Alagasco’s effective tax rate, if recognized, is $210,000. Alagasco recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2010, 2009, and 2008, Alagasco recognized approximately $1,037,000, $146,000 and $131,000 of expense for interest (net of tax benefit) and penalties, respectively. Alagasco had approximately $1,400,000 and $364,000 for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2010 and 2009, respectively.

The Company and Alagasco’s tax returns for years 2007-2009, including the tax accounting method change noted above, remain open to examination by the IRS and major state taxing jurisdictions. The Company has been under IRS examination of its federal consolidated income tax returns for 2007-2008. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change from the recovery of its gas distribution property. The Company has filed a petition in United States Tax Court challenging the IRS assessment. Although the timing of the resolution is highly uncertain, an unfavorable outcome in this matter would result in income tax cash payments of approximately $31 million with no material impact to the Company and Alagasco’s effective income tax rate.

The Company and Alagasco have on-going income tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of the completion of various audits and the expiration of statute of limitations. Although the timing and outcome of these tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

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5. EMPLOYEE BENEFIT PLANS

Benefit Obligations: The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in the Company’s consolidated financial statements:

As of December 31, (in thousands)	2010			2009			2010			2009
	Pension						Postretirement Benefits
Accumulated benefit obligation	$	196,421		$	177,711
Projected benefit obligation:
Balance at beginning of period	$	213,920		$	190,431		$	84,085		$	76,626
Service cost		8,574			7,340			2,064			1,813
Interest cost		11,365			12,064			4,833			4,849
Actuarial (gain) loss		12,961			21,524			(3,062	)		4,523
Termination benefit charge		-			145			-			-
Benefits paid		(13,048	)		(17,584	)		(4,172	)		(3,726	)
Balance at end of period	$	233,772		$	213,920		$	83,748		$	84,085
Plan assets:
Fair value of plan assets at beginning of period	$	167,653		$	139,274		$	72,227		$	56,421
Actual return on plan assets		20,443			27,091			7,580			14,605
Employer contributions		37,406			18,872			4,483			5,006
Benefits paid		(13,048	)		(17,584	)		(4,172	)		(3,805	)
Fair value of plan assets at end of period	$	212,454		$	167,653		$	80,118		$	72,227
Funded status of plan	$	(21,318	)	$	(46,267	)	$	(3,630	)	$	(11,858	)
Noncurrent assets	$	12,804		$	-		$	1,103		$	-
Current liabilities		(2,304	)		(2,223	)		-			-
Noncurrent liabilities		(31,818	)		(44,044	)		(4,733	)		(11,858	)
Net liability recognized	$	(21,318	)	$	(46,267	)	$	(3,630	)	$	(11,858	)
Amounts recognized to accumulated other comprehensive income:
Prior service costs, net of taxes	$	945		$	1,139		$	-		$	-
Net actuarial (gain) loss, net of taxes		30,112			29,435			(915	)		454
Transition obligation, net of taxes		-			-			580			762
Total accumulated other comprehensive income (loss)	$	31,057		$	30,574		$	(335	)	$	1,216

Alagasco recognized a regulatory asset of $54.2 million and $55.8 million as of December 31, 2010 and 2009, respectively, for the portion of the pension plan obligation to be recovered through rates in future periods. Alagasco recognized a regulatory asset of $5 million and $9.5 million as of December 31, 2010 and 2009, respectively, for the portion of the postretirement health care and life insurance benefit obligation to be recovered through rates in future periods. Alagasco also recognized a regulatory liability of $0.8 million as of December 31, 2010 for the portion of the postretirement health care and life insurance benefit obligation to be refunded through rates in future periods.

Other investment assets designated for payment of the nonqualified supplemental retirement plans were as follows:

	December 31, 2010
(in thousands)	Level 1		Level 2		Level 3		Total
Insurance contracts	$	-	$	6,700	$	5,069	$	11,769
United States equities		4,738		-		-		4,738
Global equities		1,955		-		-		1,955
Fixed income		-		9,372		-		9,372
Total	$	6,693	$	16,072	$	5,069	$	27,834

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	December 31, 2009
(in thousands)	Level 1		Level 2		Level 3		Total
Insurance contracts	$	-	$	5,984	$	4,824	$	10,808
United States equities		4,403		-		-		4,403
Global equities		1,734		-		-		1,734
Fixed income		-		2,502		-		2,502
Cash and cash equivalents		-		6,300		-		6,300
Total	$	6,137	$	14,786	$	4,824	$	25,747

While intended for payment of the nonqualified supplemental retirement plan benefits, these assets remain subject to the claims of the Company’s creditors and are not recognized in the funded status of the plan. These assets are recorded at fair value and included in Deferred Charges and Other in the Consolidated Balance Sheets.

The following is a reconciliation of insurance contracts in Level 3 of the fair value hierarchy:

Years ended December 31, (in thousands)	2010		2009
Balance at beginning of period	$	4,824	$	-
Realized losses		-		(538	)
Unrealized gains relating to instruments held at the reporting date		245		33
Purchases during period		-		5,329
Balance at end of period	$	5,069	$	4,824

The components of net periodic benefit cost were:

Years ended December 31, (in thousands)	2010			2009			2008
Pension Plans
Components of net periodic benefit cost:
Service cost	$	8,574		$	7,340		$	7,160
Interest cost		11,365			12,064			11,802
Expected long-term return on assets		(12,915	)		(14,002	)		(13,156	)
Prior service cost amortization		496			579			918
Actuarial loss		5,773			3,987			4,283
Termination benefit charge		-			145			-
Settlement loss		-			-			677
Net periodic expense	$	13,293		$	10,113		$	11,684
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	2,064		$	1,813		$	1,637
Interest cost		4,833			4,849			4,914
Expected long-term return on assets		(3,986	)		(3,542	)		(5,534	)
Actuarial (gain) loss		-			228			(781	)
Transition amortization		1,917			1,917			1,917
Net periodic expense	$	4,828		$	5,265		$	2,153

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

Years ended December 31, (in thousands)	2010			2009			2008
Pension Plans
Net actuarial loss experienced during the year	$	4,332		$	5,683		$	14,061
Net actuarial loss recognized as expense		(3,290	)		(2,559	)		(3,472	)
Prior service cost established during the year		-			-			(131	)
Prior service cost recognized as expense		(298	)		(298	)		(403	)
Total recognized in other comprehensive income	$	744		$	2,826		$	10,055
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	(2,094	)	$	(1,363	)	$	5,333
Amortization of net actuarial gain (loss)		-			(46	)		157
Amortization of transition asset		(280	)		(280	)		(341	)
Total recognized in other comprehensive income (loss)	$	(2,374	)	$	(1,689	)	$	5,149

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Net retirement expense for Alagasco was $6,291,000, $4,231,000 and $5,595,000 for the years ended December 31, 2010, 2009 and 2008, respectively. In the second quarter of 2009, the Company recognized a termination benefit charge of $145,000 to provide for early retirement of certain non-highly compensated employees. The Company recognized a settlement charge of $0.7 million in the fourth quarter of 2008 for the payment of lump sums from a defined benefit pension plan. This charge represented an acceleration of the unamortized actuarial losses. Net periodic postretirement benefit expense for Alagasco was $3,594,000, $4,051,000 and $1,457,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

Estimated amounts to be amortized from accumulated other comprehensive income into pension cost during 2011 are as follows:

(in thousands)
Amortization of prior service cost	$   297
Amortization of net actuarial loss	$3,636

Estimated amounts to be amortized from accumulated other comprehensive income into benefit cost during 2011 are as follows:

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

The Company has a long-term disability plan covering most employees. The Company had expense for the years ended December 31, 2010, 2009 and 2008 of $379,000, $458,000 and $346,000, respectively.

Assumptions:

The weighted average rate assumptions to determine net periodic benefit costs were as follows:

Years ended December 31,	2010			2009			2008
Pension Plans
Discount rate		5.49	%		6.50	%		6.18	%
Expected long-term return on plan assets		7.25	%		8.25	%		8.25	%
Rate of compensation increase for pay-related plans		3.95	%		3.90	%		4.07	%
Postretirement Benefit Plans
Discount rate		5.90	%		6.50	%		6.40	%
Expected long-term return on plan assets		7.25	%		8.25	%		8.25	%
Rate of compensation increase		3.69	%		3.55	%		3.65	%

The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:

Years ended December 31,	2010			2009
Pension Plans
Discount rate		4.89	%		5.49	%
Rate of compensation increase for pay-related plans		3.75	%		3.95	%
Postretirement Benefit Plans
Discount rate		5.45	%		5.90	%
Rate of compensation increase for pay-related plans		3.61	%		3.69	%

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The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:

As of December 31,	2010			2009
Health care cost trend rate assumed for next year		8.50	%		8.50	%
Rate to which the cost trend rate is assumed to decline		5.50	%		5.50	%
Year that rate reaches ultimate rate		2017			2016

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

(in thousands)
	1-Percentage Point Decrease			1-Percentage Point Increase
Effect on total of service and interest cost	$	(542	)	$         663
Effect on net postretirement benefit obligation	$	(4,593	)	$      5,479

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

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

The Company seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

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

	Pension									Postretirement Benefits
As of December 31,	Target			2010			2009			Target			2010			2009
Asset category:
Equity securities		49	%		43	%		44	%		60	%		60	%		70	%
Debt securities		29	%		33	%		28	%		40	%		40	%		30	%
Other		22	%		24	%		28	%		-			-			-	%
Total		100	%		100	%		100	%		100	%		100	%		100	%

Equity securities for pension and postretirement benefits do not include the Company’s common stock.

Plan assets included in the funded status of the pension plans were as follows:

	December 31, 2010
(in thousands)	Level 1		Level 2		Level 3		Total
United States equities	$	44,566	$	10,360	$	-	$  54,926
Global equities		24,785		5,560		5,087	35,432
Fixed income		-		69,878		-	69,878
Alternative investments		-		26,688		21,754	48,442
Cash and cash equivalents		-		3,776		-	3,776
Total	$	69,351	$	116,262	$	26,841	$212,454

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	December 31, 2009
(in thousands)	Level 1		Level 2		Level 3		Total
United States equities	$	35,020	$	7,860	$	-	$  42,880
Global equities		22,044		4,176		4,674	30,894
Fixed income		-		46,716		-	46,716
Alternative investments		-		16,124		17,134	33,258
Cash and cash equivalents		1,624		12,281		-	13,905
Total	$	58,688	$	87,157	$	21,808	$167,653

United States equities consist of mutual and commingled funds with varying strategies. Such strategies include stock investments across market capitalizations and investment styles. Global equities consist of mutual funds and a limited partnership that invest in United States and non-United States securities broadly diversified across mostly developed markets but with some tactical exposure to emerging markets. Fixed income securities consist of mutual funds and separate accounts. Fixed income securities are well diversified with allocations to investment grade and non-investment grade issues and issues that provide both intermediate and longer duration exposure. Alternative asset investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative assets are meant to serve as a risk reducer at the total portfolio level as they provide asset class exposures not found elsewhere in the portfolio.

The following is a reconciliation of plan assets in Level 3 of the fair value hierarchy:

Years ended December 31, (in thousands)	2010		2009
Balance at beginning of period	$	21,808	$	19,523
Purchases		3,791		-
Unrealized gains relating to instruments held at the reporting date		1,242		2,285
Balance at end of period	$	26,841	$	21,808

Plan assets included in the funded status of the postretirement benefit plans were as follows:

	December 31, 2010
(in thousands)	Level 1		Level 2		Total
United States equities	$	34,387	$	-	$	34,387
Global equities		13,603		-		13,603
Fixed income		-		32,128		32,128
Total	$	47,990	$	32,128	$	80,118

	December 31, 2009
(in thousands)	Level 1		Level 2		Total
United States equities	$	36,150	$	-	$	36,150
Global equities		14,410		-		14,410
Fixed income		-		21,283		21,283
Cash and cash equivalents		384		-		384
Total	$	50,944	$	21,283	$	72,227

The Company had no Level 3 postretirement benefit plan assets. United States equities consisted of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches. Global equities are mutual funds that invest in non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles. Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors.

Cash Flows: The Company anticipates required contributions of approximately $7.2 million during 2011 to the pension plans. The Company expects sufficient funding credits, as established under Internal Revenue Code

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Section 430(f), exist to meet the required funding. It is not anticipated that the funded status of the pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2011. The Company expects to make benefit payments of approximately $2.3 million during 2011 to retirees with respect to the nonqualified supplemental retirement plans. The Company expects to make discretionary contributions of $4.8 million to the postretirement health care and life insurance benefit plan during 2011.

The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:

(in thousands)	Pension Benefits		Postretirement Benefits		Postretirement Benefits – Prescription Drug  Subsidy
2011		$      19,117		$      4,820		$       (321	)
2012		$      20,596		$      5,186		$       (334	)
2013		$      14,670		$      5,454		$       (344	)
2014		$      16,572		$      5,625		$       (351	)
2015		$      17,940		$      5,815		$       (360	)
2016-2020		$    128,383		$    32,287		$    (1,844	)

In March 2010, The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively, Health Care Reform) was signed into law. The impact of the legislation has been estimated and is reflected in the December 31, 2010 measurement of the post retirement benefit obligation. Energen has applied and been approved for the Early Retiree Reinsurance Program (ERRP). Due to the uncertain nature of this program, the impact has not been reflected in the post retirement benefit obligation.

6. COMMON STOCK PLANS

Energen Employee Savings Plan (ESP): A majority of Company employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. The Company may match a percentage of the contributions and make these contributions in Company common stock or in funds for the purchase of Company common stock. Employees may diversify 100 percent of their ESP Company stock account into other ESP investment options. The ESP also contains employee stock ownership plan provisions. At December 31, 2010, total shares reserved for issuance equaled 1,080,108. Expense associated with Company contributions to the ESP was $6,228,000, $5,806,000 and $5,559,000 for the years ended December 31, 2010, 2009 and 2008, respectively.

1997 Stock Incentive Plan: The 1997 Stock Incentive Plan provided for the grant of incentive stock options and non-qualified stock options to officers and key employees. The 1997 Stock Incentive Plan also provided for the grant of performance share awards and restricted stock. The Company has typically funded options, restricted stock obligations and performance share obligations through original issue shares. Under the 1997 Stock Incentive Plan, 5,600,000 shares of Company common stock were reserved for issuance with 1,089,604 remaining for issuance as of December 31, 2010.

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

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No performance share awards were granted in 2010, 2009 or 2008. A summary of performance share award activity as of December 31, 2010, and transactions during the years ended December 31, 2010, 2009 and 2008 are presented below:

	1997 Stock Incentive Plan
	Shares			Weighted Average Price
Nonvested at December 31, 2007		362,903			$    49.87
Vested and paid		(134,220	)		54.25
Nonvested at December 31, 2008		228,683			30.80
Expired without payout		(117,540	)		18.50
Nonvested at December 31, 2009		111,143			43.81
Vested and paid		(111,143	)		43.81
Nonvested at December 31, 2010		-			$            -

During the year ended December 31, 2010, the Company recorded no expense for performance share awards. The Company recorded expense of $502,000 for the year ended December 31, 2009 for performance share awards with a related deferred income tax benefit of $190,000. The Company recorded income of $2,308,000 for the year ended December 31, 2008 for performance share awards with a related deferred income tax expense of $873,000.

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

A summary of stock option activity as of December 31, 2010, and transactions during the years ended December 31, 2010, 2009 and 2008 are presented below:

	1997 Stock Incentive Plan
	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2007		466,339			$    30.79
Granted		186,700			60.56
Exercised		(28,068	)		11.88
Forfeited		(4,454	)		10.17
Outstanding at December 31, 2008		620,517			40.75
Granted		543,242			29.91
Exercised		(55,950	)		13.10
Outstanding at December 31, 2009		1,107,809			36.83
Granted		281,110			46.69
Exercised		(111,676	)		23.83
Forfeited		(1,200	)		13.72
Outstanding at December 31, 2010		1,276,043			$    40.16
Exercisable at December 31, 2008		276,530			$    24.05
Exercisable at December 31, 2009		360,229			$    36.87
Exercisable at December 31, 2010		574,992			$    41.16
Remaining reserved for issuance at December 31, 2010		1,089,604			-

The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values:

Grant date		1/27/10			8/24/2009			1/28/09			1/23/2008
Awards granted		281,110			4,750			538,492			186,700
Fair market value of stock at grant	$	16.47		$	15.00		$	8.83		$	17.83
Expected life of award		5.7 years			5.7 years			5.7 years			5.7 years
Risk-free interest rate		2.76	%		2.80	%		1.89	%		2.87	%
Annualized volatility rate		37.3	%		36.9	%		34.8	%		24.3	%
Dividend yield		1.1	%		1.2	%		1.7	%		0.0	%

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The Company recorded stock option expense of $4,604,000, $4,352,000 and $3,080,000 during the years ended December 31, 2010, 2009 and 2008, respectively, with a related deferred tax benefit of $1,741,000, $1,645,000 and $1,165,000 respectively.

The total intrinsic value of stock options exercised during the year ended December 31, 2010, was $2,209,000. During the year ended December 31, 2010, the total intrinsic value of stock appreciation rights exercised was $271,000. During the year ended December 31, 2010, the Company received cash of $830,000 from the exercise of stock options and paid $91,000 in settlement of stock appreciation rights. Total intrinsic value for outstanding options as of December 31, 2010, was $12,681,000 and $5,667,000 for exercisable options. The fair value of options vested for the year ended December 31, 2010 was $4,124,000. As of December 31, 2010, there was $1,768,000 of unrecognized compensation cost related to outstanding nonvested stock options.

The following table summarizes options outstanding as of December 31, 2010:

1997 Stock Incentive Plan
Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
$11.32	28,180	0.83 years
$14.86	48,210	2.08 years
$21.38	16,500	3.08 years
$46.45	232,285	6.00 years
$55.08	7,260	6.50 years
$60.56	186,700	7.00 years
$29.79	471,048	8.00 years
$43.30	4,750	8.67 years
$46.69	281,110	9.00 years
$11.32-$60.56	1,276,043	7.26 years

The weighted average remaining contractual life of currently exercisable stock options is 6.55 years as of December 31, 2010.

Restricted Stock: In addition, the 1997 Stock Incentive Plan provided for the grant of restricted stock which have been valued based on the quoted market price of the Company’s common stock at the date of grant. Restricted stock awards have a three to six year vesting period. A summary of restricted stock activity as of December 31, 2010, and transactions during the years ended December 31, 2010, 2009 and 2008 is presented below:

	1997 Stock Incentive Plan
	Shares			Weighted Average Price
Nonvested at December 31, 2007		137,595			$    29.94
Vested		(26,240	)		23.36
Nonvested at December 31, 2008		111,355			31.49
Granted		6,150			43.30
Vested		(64,500	)		31.65
Nonvested at December 31, 2009		53,005			32.66
Vested		(28,855	)		30.30
Nonvested at December 31, 2010		24,150			$    35.49

The Company recorded expense of $185,000, $379,000 and $596,000 for the years ended December 31, 2010, 2009 and 2008, respectively, related to restricted stock, with a related deferred income tax benefit of $70,000, $143,000 and $225,000, respectively. As of December 31, 2010, there was $198,000 of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a remaining requisite service period of 1.26 years.

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2004 Stock Appreciation Rights Plan: The Energen 2004 Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. These awards have a three year requisite service period.

The Company issued the following awards with stock appreciation rights. The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2010:

Grant date	1/27/2010		2/13-16/2009		1/28/09		2/04/2008
Awards granted	171,749		3,292		305,257		67,093
Fair market value of stock	$      17.20		$      22.02		$      22.87		$      8.81
Expected life of award	5.6 years		4.6 years		4.6 years		3.6 years
Risk-free interest rate	2.31	%	1.83	%	1.83	%	1.32	%
Annualized volatility rate	37.9	%	37.9	%	37.9	%	37.9	%
Dividend yield	1.1	%	1.1	%	1.1	%	1.1	%

Expense associated with stock appreciation rights of $3,360,000 and $4,608,000 was recorded for the years ended December 31, 2010 and 2009, respectively. Income associated with stock appreciation rights of $2,413,000 was recorded for the year ended December 31, 2008.

Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provided for the grant of stock equivalent units which may include market conditions. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. The fair value of the stock equivalent units with a market condition was calculated using a Monte Carlo approach. Stock equivalent units with service conditions were valued based on the Company’s stock price at the end of the period adjusted to remove the present value of future dividends.

During 2010, Energen Resources awarded 2,442 stock equivalent units with a three year vesting period. In the first quarter of 2009, Energen Resources awarded 900 stock equivalent units with a two year vesting period and 2,911 stock equivalent units with a three year vesting period. During the third quarter of 2009, Energen Resources awarded 938 stock equivalent units with a three year vesting period. Energen Resources awarded 1,805 stock equivalent units with a two year vesting period and 1,014 stock equivalent units with a three year vesting period in 2008. None of the awards issued included a market condition. Energen Resources recognized expense of $224,000 and $1,028,000 during 2010 and 2009, respectively, related to these units. Energen Resources recognized income of $2,042,000 during 2008 related to these units.

1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Company’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of the Company’s creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the consolidated statements of shareholders’ equity. As of December 31, 2010 there were 709,000 shares reserved for issuance from the 1997 Deferred Compensation Plan.

1992 Energen Corporation Directors Stock Plan: In 1992 the Company adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Company

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common stock. Under the Plan, 15,400 shares, 12,000 shares and 11,218 shares were awarded during the years ended December 31, 2010, 2009 and 2008, respectively, leaving 175,324 shares reserved for issuance as of December 31, 2010.

Stock Repurchase Program: By resolution adopted May 25, 1994, and supplemented by a resolution adopted April 26, 2000 and June 24, 2006, the Board authorized the Company to repurchase up to 12,564,400 shares of the Company’s common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2010, 2009 and 2008. As of December 31, 2010, a total of 8,992,700 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company’s stock compensation plans. For the years ended December 31, 2010, 2009 and 2008, the Company acquired 62,794 shares, 23,942 shares and 446,045 shares, respectively, in connection with its stock compensation plans.

7. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $152 million through September 2024. During the years ended December 31, 2010, 2009 and 2008, Alagasco recognized approximately $52 million, $49 million and $51 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 249 Bcf through August 2020.

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

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

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

In June 2009, Alagasco received a General Notice Letter from the United States Environmental Protection Agency (EPA) identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949 with such sale being approved by the APSC. While Alagasco no longer owns the Huntsville site, the Company and the current site owner have entered into a Consent Order and agreed 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 of approximately $4.3 million. During the years ended December 31, 2010 and 2009, the Company incurred costs of $0.7 million and $0.2 million, respectively, associated with the site. As of December 31, 2010, the Company has accrued a contingent liability of $3.4 million in addition to the costs previously incurred. The estimate assumes an action plan for excavation of affected soil and sediment only. 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 future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

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

Legacy Litigation

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

Other

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

New Mexico Audits: During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit of federal oil and gas leases located in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from U.S. federal leases. The Department proposes a change in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases. Such proposal, if determined appropriate, will result in increases of royalties due under the audit periods.

The Department’s preliminary findings are contrary to those allowed under previous audits and are inconsistent with the Company’s understanding of industry practice. The Company intends to vigorously contest the proposal under the preliminary findings and has requested additional information from the Department to determine the basis of its conclusion. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this finding and no amount has been accrued as of December 31, 2010.

Lease Obligations: Alagasco leases the Company’s headquarters building over a 25-year term ending January 31, 2024 and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Energen’s total lease payments related to leases included as operating lease expense were $18,570,000, $21,529,000 and $21,403,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Minimum future rental payments required after 2010 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2011	2012	2013	2014	2015	2016 and thereafter
$    5,436	$    5,163	$    4,080	$    3,442	$    3,201	$    16,914

Alagasco’s total payments related to leases included as operating expense, net of approximately $1,025,000 of lease expense paid by Energen each year, were $2,127,000, $2,150,000 and $2,114,000 for the years ended December 31, 2010, 2009 and 2008, respectively. Minimum future rental payments required after 2010 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)
2011	2012	2013	2014	2015	2016 and thereafter
$    3,215	$    3,195	$    3,158	$    3,179	$    3,201	$    16,914

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Included in the table above are approximately $13.4 million of payments associated with leasing of the Company’s headquarters, which are expected to be reimbursed to Alagasco by Energen through the remaining term of the related lease. Such amounts are subject to intercompany allocations but are not subject to contractual agreements.

8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial Instruments: The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, approximates $434.4 million and has a carrying value of $410.8 million at December 31, 2010. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, approximates $208.1 million and has a carrying value of $205.8 million at December 31, 2010. The fair values were based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At December 31, 2010, the fixed price purchases under these guarantees had a maximum term outstanding through December 2011 with an aggregate purchase price of $4 million and a market value of $3.7 million.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At December 31, 2010, Alagasco’s finance receivable totaled approximately $8.8 million. These finance receivables currently have an average balance of approximately $1,500 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. At December 31, 2010, Alagasco had an allowance for credit losses related to its finance receivables of approximately $447,000. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency.

Risk Management: At December 31, 2010, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. The company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net loss position with eight of its active counterparties and in a net gain with the remaining three at December 31, 2010. The four largest counterparty positions at December 31, 2010, Citibank, N.A., Shell Energy North American (US), L.P., Morgan Stanley Capital Group, Inc and Barclays Bank PLC, constituted a $34.6 million loss, $24.5 million loss, $22.4 million loss and a $13.1 million gain, respectively, of Energen Resources’ net loss on its fair value of derivatives.

The following table details the fair values of commodity contracts by business segment on the balance sheets:

(in thousands)	December 31, 2010
	Oil and Gas Operations			Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	85,867		$	-		$	85,867
Long-term derivative instruments		3,156	*		-			3,156
Total derivative assets		89,023			-			89,023
Accounts receivable		(25,315	)*		-			(25,315	)
Accounts payable		(50,508	)		-			(50,508	)
Long-term liability derivative instruments		(83,631	)		-			(83,631	)
Total derivative liabilities		(159,454	)		-			(159,454	)
Total derivatives designated		(70,431	)		-			(70,431	)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable		(110	)		(27,906	)		(28,016	)
Long-term liability derivative instruments		-			(32,461	)		(32,461	)
Total derivative liabilities		(110	)		(60,367	)		(60,477	)
Total derivatives not designated		(110	)		(60,367	)		(60,477	)
Total derivatives	$	(70,541	)	$	(60,367	)	$	(130,908	)

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(in thousands)	December 31, 2009
	Oil and Gas Operations			Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	148,937		$	-		$	148,937
Long-term derivative instruments		16,164			-			16,164
Total derivative assets		165,101			-			165,101
Accounts receivable		(29,484	)*		-			(29,484	)
Accounts payable		(6,352	)		-			(6,352	)
Long-term asset derivative instruments		(8,340	)*		-			(8,340	)
Long-term liability derivative instruments		(41,374	)		-			(41,374	)
Total derivative liabilities		(85,550	)		-			(85,550	)
Total derivatives designated		79,551			-			79,551
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable		(10	)*		-			(10	)
Accounts payable		-			(25,750	)		(25,750	)
Long-term liability derivative instruments		(106	)		(18,965	)		(19,071	)
Total derivative liabilities		(116	)		(44,715	)		(44,831	)
Total derivatives not designated		(116	)		(44,715	)		(44,831	)
Total derivatives	$	79,435		$	(44,715	)	$	34,720

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $26.8 million deferred tax asset and a net $30.3 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in other comprehensive income as of December 31, 2010 and 2009, respectively.

The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:

Years ended December 31, (in thousands)	Location on Income Statement	2010		2009
Net gain (loss) recognized in OCI on derivative (effective portion), net of tax of $19.5 million and ($2) million	_		$    31,801		$     (3,316	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues		$  200,324		$  238,965
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues		$      1,082		$          (20	)

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The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:

Years ended December 31, (in thousands)	Location on Income Statement	2010			2009
Gain (loss) recognized in income on derivative	Operating revenues		$	(3)		$            310

As of December 31, 2010, $6.1 million of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, net of tax, are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of December 31, 2010, the Company had 12 thousand barrels (MBbl) of oil hedges which expire during 2011 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. During 2009, the Company reclassified gains of $66,000 after-tax from other comprehensive income into operating revenues associated with these hedges.

As of December 31, 2010, Energen Resources entered into the following transactions for 2011 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	13.6 Bcf	$6.58 Mcf	NYMEX Swaps
	31.3 Bcf	$5.98 Mcf	Basin Specific Swaps
2012	7.2 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
2013	7.2 Bcf	$5.31 Mcf	NYMEX Swaps
	12.0 Bcf	$4.90 Mcf	Basin Specific Swaps
Oil
2011	4,421 MBbl	$78.83 Bbl	NYMEX Swaps
2012	3,744 MBbl	$82.52 Bbl	NYMEX Swaps
2013	3,199 MBbl	$85.32 Bbl	NYMEX Swaps
2014	2,742 MBbl	$87.44 Bbl	NYMEX Swaps
Oil Basis Differential
2011	2,076 MBbl	*	Basis Swaps
2012	672 MBbl	*	Basis Swaps
Natural Gas Liquids
2011	42.8 MMGal	$0.90 Gal	Liquids Swaps
2012	36.4 MMGal	$0.85 Gal	Liquids Swaps
*  Average contract prices not meaningful due to the varying nature of each contract

Alagasco entered into the following natural gas transactions for 2011 and subsequent years:

Production Period	Total Hedged Volumes	Description
2011	15.2 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

As of December 31, 2010, the maximum term over which Energen Resources and Alagasco has hedged exposures to the variability of cash flows is through December 31, 2014 and March 31, 2013, respectively.

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

	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Noncurrent assets		-			-			-
Current liabilities		(76,527	)		(1,997	)		(78,524	)
Noncurrent liabilities		(107,452	)		(5,484	)		(112,936	)
Net derivative asset (liability)	$	(173,663)		$	42,755		$	(130,908	)

	December 31, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	57,235		$	62,208		$	119,443
Noncurrent assets		(1,600	)		9,424			7,824
Current liabilities		(25,518	)		(6,584	)		(32,102	)
Noncurrent liabilities		(59,914	)		(531	)		(60,445	)
Net derivative asset (liability)	$	(29,797)		$	64,517		$	34,720

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of December 31, 2010, Alagasco had $27.9 million and $32.5 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. As of December 31, 2009, Alagasco had $25.8 million and $19 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2010 and 2009.

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

Years ended December 31, (in thousands)	2010			2009			2008
Balance at beginning of period	$	64,517		$	154,094		$	(9,998)
Realized (gains) losses		241			(13	)		5,921
Unrealized gains relating to instruments held at the reporting date		90,098			65,041			165,637
Purchases and settlements during period		(112,101	)		(154,605	)		(7,466	)
Balance at end of period	$	42,755		$	64,517		$	154,094

Concentration of Credit Risk: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality for its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The four largest oil and gas purchasers accounted for approximately 18 percent, 14 percent, 13 percent and 11 percent of Energen Resources’ accounts receivable for commodity sales as of December 31, 2010. Energen Resources’ other purchasers each accounted for less than 9 percent of this accounts receivable as of December 31, 2010. During the year ended December 31, 2010, the three largest oil and gas purchasers accounted for approximately 13 percent, 12 percent and 11 percent of Energen Resources’ total operating revenues.

Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 437,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.

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9. RECONCILIATION OF EARNINGS PER SHARE

Years ended December 31,
(in thousands, except per share amounts)			2010				2009						2008
	Net Income		Shares		Per Share Amount		Net Income		Shares		Per Share Amount		Net Income		Shares		Per Share Amount
Basic EPS	$	290,807		71,845	$	4.05	$	256,325		71,667	$	3.58	$	321,915		71,601	$	4.50
Effect of dilutive securities
Performance share awards				-						108						106
Stock options				190						78						225
Non-vested restricted stock				16						32						98
Diluted EPS	$	290,807		72,051	$	4.04	$	256,325		71,885	$	4.47	$	321,915		72,030	$	4.47

For the year ended December 31, 2010, the Company had 479,820 options and no shares of non-vested restricted stock that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the year ended December 31, 2009, the Company had 969,487 options and 6,150 shares of non-vested restricted stock that were excluded from the computation of diluted EPS. The Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS for the year ended December 31, 2008.

10. ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the period incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company. Revisions in estimates to the ARO result from revisions to the estimated timing or amount of the underlying cash flows. In 2010, 2009 and 2008, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2007	$	60,571
Liabilities incurred		3,736
Liabilities settled		(2,446	)
Accretion expense		4,290
Balance of ARO as of December 31, 2008		66,151
Liabilities incurred		8,226
Liabilities settled		(672	)
Revision in estimated cash flows		9,658
Accretion expense		4,935
Balance of ARO as of December 31, 2009		88,298
Liabilities incurred		4,033
Liabilities settled		(1,094	)
Accretion expense		6,178
Balance of ARO as of December 31, 2010	$	97,415

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exist. Included in the liabilities incurred for the year ended December 31, 2009, is $6,590,000 related to the acquisition of certain oil properties in the Permian Basin from Range Resources Corporation (Range Resources). Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $11.4 million and $17.4 million to purge and cap its gas pipelines upon abandonment as a

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regulatory liability as of December 31, 2010 and 2009, respectively. The conditional asset retirement obligation as of December 31, 2010 reflects the re-estimation of removal costs associated with Alagasco’s revised depreciation rate as discussed in Note 1, Summary of Significant Accounting Policies. The costs associated with asset retirement obligations are currently either being recovered in rates or are probable of recovery in future rates.

Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Regulatory liabilities for accumulated asset removal costs of $6.9 million and $136.8 million for December 31, 2010 and 2009, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets. As of December 31, 2010, the Company recognized $22.3 million and $90.5 million of refundable negative salvage as regulatory liabilities in current liabilities and deferred credit and other liabilities, respectively, on the balance sheet in response to the June 28, 2010 APSC order as discussed in Note 1, Summary of Significant Accounting Policies.

11. SUPPLEMENTAL CASH FLOW INFORMATION

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

Years ended December 31, (in thousands)	2010		2009		2008
Interest paid, net of amount capitalized	$	37,071	$	37,032	$	39,814
Income taxes paid	$	83,894	$	48,061	$	38,235
Noncash investing activities:
Accrued development and exploration costs	$	75,167	$	46,107	$	70,319
Capitalized depreciation	$	116	$	94	$	98
Capitalized asset retirement obligations costs	$	4,194	$	18,113	$	3,940
Allowance for funds used during construction	$	808	$	1,106	$	700
Noncash financing activities:
Issuance of common stock for employee benefit plans	$	5,765	$	641	$	8,275
Treasury stock acquired in connection with tax withholdings	$	2,894	$	778	$	27,345

The Company recorded a non-cash adjustment for accretion expense of $6.2 million, $4.9 million and $4.3 million during 2010, 2009 and 2008, respectively. In 2009, the Company issued treasury shares for $0.3 million.

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

Years ended December 31, (in thousands)	2010		2009		2008
Interest paid, net of amount capitalized	$	11,653	$	11,731	$	12,611
Income taxes paid	$	13,063	$	7,908	$	3,012
Interest on affiliated company debt, net	$	274	$	221	$	57
Noncash investing activities:
Accrued property, plant and equipment costs	$	2,592	$	2,049	$	2,510
Capitalized depreciation	$	116	$	94	$	98
Capitalized asset retirement obligations costs	$	161	$	229	$	204
Allowance for funds used during construction	$	808	$	1,106	$	700

12. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

On December 15, 2010, Energen completed the purchase of certain oil properties in the Permian Basin for a cash purchase price of $74 million (subject to closing adjustments). This purchase had an effective date of December 1, 2010. Energen acquired proved reserves of approximately 7.6 million barrels of oil equivalents (MMBOE). Of the proved reserves acquired, an estimated 92 percent are undeveloped. Approximately 62 percent of the acquisition’s estimated proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

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The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 15, 2010. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,060
Unproved leasehold properties		32,500
Accounts receivable		149
Asset retirement obligation		(79	)
Total identifiable net assets	$	73,630

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2010.

On December 9, 2010, Energen completed the asset purchase of certain oil properties in the Permian Basin from SandRidge Energy, Inc. for a cash purchase price of $110 million (subject to closing adjustments). This purchase had an effective date of December 9, 2010. Energen acquired no proved reserves related to this acquisition. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

During 2010, Energen Resources incurred write-offs of unproved capitalized leasehold costs associated with its Alabama shale acreage. The non-cash costs totaled $39.7 million pre-tax and were charged to exploration expense, which is included in O&M expense, after the Company determined that the shale acreage was not economically viable. During the year ended December 31, 2010, Energen Resources also recorded $15.5 million pre-tax in write-offs of well costs related to Alabama shale leasehold. During 2009, Energen Resources was unsuccessful in the completion of a Chattanooga shale well. The costs related to this well of approximately $5.6 million pre-tax were expensed during the fourth quarter of 2009. Also expensed during the fourth quarter, was approximately $1.2 million pre-tax of costs associated with a well originally drilled by Chesapeake in an area of the Chattanooga shale. In addition, the Company recognized unproved leasehold impairments of approximately $2.1 million pre-tax during 2009 related to the Alabama shales.

On September 30, 2010, Energen completed the purchase of certain oil properties in the Permian Basin for a cash price of $189 million (subject to closing adjustments). This purchase had an effective date of September 1, 2010.

Energen acquired proved reserves of approximately 18 MMBOE. Of the proved reserves acquired, an estimated 89 percent are undeveloped. Approximately 65 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 13 percent. Energen Resources used its internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of September 30, 2010. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

(in thousands)
Consideration given
Cash (net)	$	188,531
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	152,050
Unproved leasehold properties		35,360
Accounts receivable		1,375
Asset retirement obligation		(142	)
Accounts payable		(112	)
Total identifiable net assets	$	188,531

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Included in the Company’s consolidated results of operations for the year ended December 31, 2010, is $5 million of operating revenues and $2.1 million in operating income resulting from the operation of the properties acquired above.

In September 2009, Energen Resources recorded a $4.9 million pre-tax gain in other operating revenues from the sale of certain oil properties in the Permian Basin. The Company received approximately $6.5 million pre-tax in cash from the sale of this property.

On June 30, 2009, Energen completed the purchase of certain oil properties in the Permian Basin from Range Resources for a cash price of $181 million. This purchase had an effective date of May 1, 2009. Energen acquired proved reserves of approximately 15.2 MMBOE. Of the proved reserves acquired, an estimated 24 percent are undeveloped. Approximately 76 percent of the proved reserves are oil, 16 percent are natural gas liquids and natural gas comprises the remaining 8 percent. Energen Resources used its short-term credit facilities and internally generated cash flows to finance the acquisition.

The following table summarizes the consideration paid to Range Resources and the amounts of the assets acquired and liabilities assumed recognized as of June 30, 2009 (including the effects of closing adjustments).

(in thousands)
Consideration given to Range Resources
Cash (net)	$	181,249
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	182,668
Unproved leasehold properties		3,800
Accounts receivable		4,987
Inventory and other		455
Asset retirement obligation		(6,590	)
Environmental liabilities		(3,124	)
Accounts payable		(947	)
Total identifiable net assets	$	181,249

Included in the Company’s consolidated results of operations for the year ended December 31, 2009, is $22.3 million of operating revenues and $8.9 million in operating income resulting from operation of the properties acquired from Range Resources.

Summarized below are the consolidated results of operations for the years ended December 30, 2009 and 2008, on an unaudited pro forma basis as if the acquisition had occurred at the beginning of each of the periods presented. The pro forma information is based on the Company’s consolidated results of operations for the years ended December 31, 2009 and 2008, and on the data provided by the seller. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor are they indicative of results of the future operations of the combined enterprises.

Years ended December 31, (in thousands)	2009		2008
Operating revenues	$	1,458,995	$	1,659,814
Operating income	$	439,624	$	617,293

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

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13. REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	December 31, 2010				December 31, 2009
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	132	$	60,284	$	132	$	66,552
Accretion and depreciation for asset retirement obligation		-		8,681		-		13,566
Gas supply adjustment		-		-		7,059		-
Risk management activities		27,906		32,461		25,750		18,965
RSE adjustment		25		-		25		-
Enhanced stability reserve		-		3,794		-		2,706
Other		223		145		230		344
Total regulatory assets	$	28,286	$	105,365	$	33,196	$	102,133
Regulatory liabilities:
RSE adjustment Unbilled service margin Postretirement liabilities Gas supply adjustment Asset removal costs, net Refundable negative salvage* Asset retirement obligation	$	4,147 34,197 - 14,990 - 22,336 -	$	- - 754 - 6,913 90,504 11,439	$	1,508 28,178 - - - - -	$	- - - - 136,799 - 17,419
Other		33		837		33		870
Total regulatory liabilities	$	75,703	$	110,447	$	29,719	$	155,088

* As of December 31, 2010, the Company reclassified $22.3 million and $90.5 million of accumulated asset removal costs to refundable negative salvage as regulatory liabilities in current liabilities and deferred credit and other liabilities, respectively, on the balance sheet in response to the June 28, 2010 APSC order as discussed in Note 1, Summary of Significant Accounting Policies.

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

14. TRANSACTIONS WITH RELATED PARTIES

The Company allocates certain corporate costs to Energen Resources and Alagasco based on the nature of the expense to be allocated using various factors including, but not limited to, total assets, earnings, or number of employees. The Company’s cash management program seeks to minimize borrowing from outside sources through inter-company lending. Under this program, Alagasco may borrow from but does not lend to affiliates. Alagasco had net trade receivables from affiliates of $698,000 and net payables of $24,962,000 at December 31, 2010 and 2009, respectively. Interest income and expense between affiliates is calculated monthly based on the market weighted average interest rate. Alagasco had $0.3 million, $0.2 million and $0.1 million in affiliated company interest expense during the years ended December 31, 2010, 2009 and 2008, respectively. The weighted average interest rate during 2010 and 2009 was 1.56 percent and 1.02 percent, respectively.

15. RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2010, the FASB issued ASU No. 2010-29, Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations. These disclosures are effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. This standard is not expected to have a material impact on the consolidated financial statements of the Company.

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In July 2010, the FASB issued ASU No. 2010-20, Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses. These disclosures as of the end of a reporting period are effective for the interim and annual reporting periods ending on or after December 15, 2010. The disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. This standard did not have a material impact on the consolidated financial statements of the Company.

On January 1, 2010, the Company adopted an accounting standard update to improve financial reporting by companies involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. This standard did not have an impact on the consolidated financial statements of the Company.

On January 1, 2010, the Company adopted Accounting Standard Update (ASU) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures About Fair Value Measurements. These disclosures are effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. This standard did not have a material impact on the consolidated financial statements of the Company.

On January 1, 2010, the Company adopted ASU No. 2010-07, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements, which eliminates the requirements for SEC filers to disclose the date through which it has evaluated subsequent events. This standard did not have a material impact on the consolidated financial statements of the Company.

16. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

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

	Year ended December 31, 2010
(in thousands, except per share amounts)	First		Second			Third			Fourth
Operating revenues	$	574,914	$	333,725		$	295,804		$	374,091
Operating income	$	192,198	$	98,293		$	67,320		$	135,566
Net income	$	116,710	$	55,543		$	38,304		$	80,250
Diluted earnings per average common share	$	1.62	$	0.77		$	0.53		$	1.11
Basic earnings per average common share	$	1.63	$	0.77		$	0.53		$	1.12
	Year ended December 31, 2009
(in thousands, except per share amounts)	First		Second			Third			Fourth
Operating revenues	$	484,106	$	306,220		$	287,289		$	362,805
Operating income	$	161,476	$	94,145		$	81,849		$	97,923
Net income	$	95,582	$	55,001		$	47,121		$	58,621
Diluted earnings per average common share	$	1.33	$	0.76		$	0.65		$	0.81
Basic earnings per average common share	$	1.33	$	0.77		$	0.66		$	0.82
Alagasco’s business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco’s quarterly operating results.
	Year ended December 31, 2010
(in thousands)	First		Second			Third			Fourth
Operating revenues	$	337,300	$	99,139		$	61,693		$	121,640
Operating income (loss)	$	75,255	$	3,138		$	(9,015	)	$	19,005
Net income (loss)	$	44,246	$	(340	)	$	(7,120	)	$	10,097
	Year ended December 31, 2009
(in thousands)	First		Second			Third			Fourth
Operating revenues	$	294,986	$	107,683		$	68,788		$	146,417
Operating income (loss)	$	80,839	$	3,242		$	(15,237	)	$	15,140
Net income (loss)	$	47,476	$	902		$	(10,746	)	$	7,783

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17. OIL AND GAS OPERATIONS (Unaudited)

Capitalized Costs: The following table sets forth capitalized costs:

(in thousands)	December 31, 2010		December 31, 2009
Proved		$    3,868,945		$    3,316,939
Unproved		211,834		62,189
Total capitalized costs		4,080,779		3,379,128
Accumulated depreciation, depletion and amortization		1,161,635		972,676
Capitalized costs, net		$2,919,144		$2,406,452

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

Years ended December 31, (in thousands)	2010		2009		2008
Property acquisition:
Proved	$	207,161	$	186,263	$	864
Unproved		201,881		5,100		18,132
Exploration		37,371		16,590		21,180
Development		332,541		226,841		415,682
Total costs incurred	$	778,954	$	434,794	$	455,858

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

Years ended December 31, (in thousands)	2010		2009		2008
Gross revenues	$	957,371	$	815,465	$	906,006
Production (lifting costs)		224,901		217,429		236,679
Exploration expense		64,584		10,234		9,296
Depreciation, depletion and amortization		200,179		180,752		136,404
Accretion expense		6,178		4,935		4,290
Income tax expense		166,750		143,691		194,953
Results of operations from producing activities	$	294,779	$	258,424	$	324,384

Oil and Gas Operations: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that proved categories of reserves be disclosed. Reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2010 and 2009 and year-end prices and current costs for the year ended December 31, 2008. Changes to prices and costs could have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of reserves disclosed. The proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman), independent oil and gas reservoir engineers, have audited the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2010. Ryder Scott audited the reserve estimates for coalbed methane in the Black Warrior and San Juan basins and substantially all of

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the Permian Basin reserves. T. Scott Hickman audited the reserves for the North Louisiana and East Texas regions and the conventional reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 96 percent of the Company’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

Year ended December 31, 2010	Gas MMcf			Oil MBbl			NGL MBbl			Total Bcfe
Proved reserves at beginning of period		897,546			77,963			30,257			1,546.9
Revisions of previous estimates		66,679			(2,243	)		2,434			67.8
Purchases		21,700			16,443			5,730			154.8
Extensions and discoveries		39,570			16,234			4,058			161.3
Production		(70,924	)		(5,131	)		(1,880	)		(113.0	)
Sales		(184	)		(4	)		2			(0.2	)
Proved reserves at end of period		954,387			103,262			40,601			1,817.6
Proved developed reserves at end of period		786,292			72,030			28,809			1,391.3
Proved undeveloped reserves at end of period		168,095			31,232			11,792			426.2
Year ended December 31, 2009	Gas MMcf			Oil MBbl			NGL MBbl			Total Bcfe
Proved reserves at beginning of period		1,038,453			62,034			28,953			1,584.4
Revisions of previous estimates		(122,862	)		1,175			(1,411	)		(124.3	)
Purchases		9,646			12,064			2,537			97.2
Extensions and discoveries		45,791			8,144			1,969			106.5
Production		(72,337	)		(4,690	)		(1,791	)		(111.2	)
Sales		(1,145	)		(764	)		-			(5.7	)
Proved reserves at end of period		897,546			77,963			30,257			1,546.9
Proved developed reserves at end of period		743,859			66,078			24,985			1,290.2
Proved undeveloped reserves at end of period		153,687			11,885			5,272			256.6
Year ended December 31, 2008		Gas MMcf			Oil MBbl			NGL MBbl			Total Bcfe
Proved reserves at beginning of period		1,115,918			74,625			31,664			1,753.7
Revisions of previous estimates		(73,105	)		(15,813	)		(3,359	)		(188.1	)
Purchases		1,211			6			-			1.2
Extensions and discoveries		62,232			7,937			2,407			124.3
Production		(67,573	)		(4,114	)		(1,683	)		(102.4	)
Sales		(230	)		(607	)		(76	)		(4.3	)
Proved reserves at end of period		1,038,453			62,034			28,953			1,584.4
Proved developed reserves at end of period		868,873			51,929			24,869			1,329.7
Proved undeveloped reserves at end of period		169,580			10,105			4,084			254.7

2010 Activities: Energen Resources had upward reserve revisions during 2010 which totaled 67.8 Bcfe. The Black Warrior Basin had upward reserve revisions totaling 3.3 Bcfe of which approximately 7.7 Bcfe related to changes in year-end pricing partially offset by downward reserve revisions of 4.4 Bcfe. The San Juan Basin upward reserve revisions of 66 Bcfe included 45.8 Bcfe related to changes in year-end pricing and 49 Bcfe associated with well performance partially offset by 32 Bcfe of downward reserve revisions resulting from the SEC’s five-year development rule. Downward reserve revisions of 7.8 Bcfe in the Permian Basin were due to lower than anticipated injection response in certain waterflood units offset by 17.8 Bcfe of estimated positive price related revisions.

Energen Resources purchased 154.8 Bcfe of reserves during 2010 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2010, Energen Resources had extensions and discoveries of 161.3 Bcfe of which 77 percent were proved undeveloped reserves and 23 percent were proved developed reserves. Extension drilling resulted in 159.5 Bcfe of discoveries with exploratory drilling providing 1.8 Bcfe of discoveries. The San Juan Basin added 38.2 Bcfe of reserves through the drilling or identification of 36 well locations; additionally, 1 sidetrack well added 6.5 Bcfe of reserves. The Permian Basin added 132.7 Bcfe of reserves primarily through the drilling or identification of 271 well locations.

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2009 Activities: Energen Resources had downward reserve revisions during 2009 which totaled 124.3 Bcfe. The Black Warrior Basin had downward reserve revisions totaling 45.6 Bcfe of which approximately 20.5 Bcfe related to changes in year-end pricing and approximately 12.9 Bcfe was caused by accelerated coal mining plans. In the San Juan Basin, downward reserve revisions of 73.9 Bcfe were largely due to 70.5 Bcfe of estimated price revisions and higher fuel usage. Upward reserve revisions of 6.4 Bcfe in the Permian Basin were due to 25.2 Bcfe of estimated positive price related revisions partially offset by lower than anticipated injection response in certain waterflood units.

Energen Resources purchased 97.2 Bcfe of reserves during 2009 primarily related to the acquisition of oil properties in the Permian Basin.

During 2009, Energen Resources had extensions and discoveries of 106.5 Bcfe of which 81 percent were proved undeveloped reserves and 19 percent were proved developed reserves. Extension drilling resulted in 105.9 Bcfe of discoveries with exploratory drilling providing 0.6 Bcfe of discoveries. The San Juan Basin added 38.2 Bcfe of reserves through the drilling or identification of 46 well locations; additionally, 10 sidetrack wells added 6.5 Bcfe of reserves. The Permian Basin added 56.8 Bcfe of reserves primarily through the drilling or identification of 130 well locations.

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

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

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

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of the Company’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. At December 31, 2010, 2009 and 2008, the Company had a deferred hedging loss of $70.4 million, a deferred hedging gain of $79.7 million and a deferred hedging gain of $324 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.

Years ended December 31, (in thousands)	2010		2009		2008
Future gross revenues	$	13,210,211	$	8,208,613	$	8,212,212
Future production costs		4,959,403		3,915,736		3,692,060
Future development costs		1,026,903		533,674		485,806
Future income tax expense		2,201,742		944,875		1,070,005
Future net cash flows		5,022,163		2,814,328		2,964,341
Discount at 10% per annum		2,555,027		1,251,138		1,337,724
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	$	2,467,136	$	1,563,190	$	1,626,617
Discounted future net cash flows before income taxes	$	3,155,746	$	1,765,632	$	1,902,594

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The following are the principal sources of changes in the standardized measure of discounted future net cash flows:

Years ended December 31, (in thousands)	2010			2009			2008
Balance at beginning of year	$	1,563,190		$	1,626,617		$	3,264,713
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs		945,179			(248,236	)		(2,571,311	)
Net changes due to revisions in quantity estimates		36,349			(117,990	)		(250,491	)
Development costs incurred, previously estimated		195,269			140,169			177,343
Accretion of discount		156,319			162,662			326,471
Changes in timing and other		15,815			97,142			461,876
Total revisions		1,348,931			33,747			(1,856,112	)
New field discoveries and extensions, net of future production and development costs		319,223			81,954			36,266
Sales of oil and gas produced, net of production costs		(576,755	)		(389,125	)		(843,202	)
Purchases		278,384			116,435			1,085
Sales		87			(7,571	)		(26,861	)
Net change in income taxes		(465,924	)		101,133			1,050,728
Net change in standardized measure of discounted future net cash flows		903,946			(63,427	)		(1,638,096	)
Balance at end of year	$	2,467,136		$	1,563,190		$	1,626,617

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18. INDUSTRY SEGMENT INFORMATION

The Company is principally engaged in two business segments: the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution). The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies.

Years ended December 31,(in thousands)	2010			2009			2008
Operating revenues
Oil and gas operations	$	958,762		$	822,546		$	914,132
Natural gas distribution		619,772			617,874			654,778
Total	$	1,578,534		$	1,440,420		$	1,568,910
Operating income (loss)
Oil and gas operations	$	406,729		$	353,645		$	482,588
Natural gas distribution		88,383			83,984			81,956
Eliminations and corporate expenses		(1,735	)		(2,236	)		(2,476	)
Total	$	493,377		$	435,393		$	562,068
Depreciation, depletion and amortization expense
Oil and gas operations	$	203,821		$	184,089		$	139,539
Natural gas distribution		44,042			50,995			48,874
Other		2			-			-
Total	$	247,865		$	235,084		$	188,413
Interest expense
Oil and gas operations	$	25,753		$	25,775		$	27,587
Natural gas distribution		13,894			13,714			14,807
Eliminations and other		(425	)		(110	)		(413	)
Total	$	39,222		$	39,379		$	41,981
Income tax expense (benefit)
Oil and gas operations	$	138,775		$	117,969		$	169,862
Natural gas distribution		29,875			27,353			24,829
Other		(1,660	)		(1,351	)		(1,648	)
Total	$	166,990		$	143,971		$	193,043
Capital expenditures
Oil and gas operations	$	717,782		$	427,399		$	449,571
Natural gas distribution		93,566			77,809			63,320
Total	$	811,348		$	505,208		$	512,891
Identifiable assets
Oil and gas operations	$	3,160,601		$	2,654,068		$	2,650,136
Natural gas distribution		1,166,899			1,084,666			1,126,587
Eliminations and other		36,060			64,384			(1,319	)
Total	$	4,363,560		$	3,803,118		$	3,775,404
Property, plant and equipment, net
Oil and gas operations	$	2,936,284		$	2,422,623		$	2,181,131
Natural gas distribution		782,665			721,846			686,517
Other		278			-			-
Total	$	3,719,227		$	3,144,469		$	2,867,648

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SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

Energen Corporation

Years ended December 31, (in thousands)	2010			2009			2008
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	17,251		$	12,868		$	12,244
Additions:
Charged to income		2,665			11,200			6,716
Recoveries and adjustments		(1,100	)		(512	)		(245	)
Net additions		1,565			10,688			6,471
Less uncollectible accounts written off		(3,768	)		(6,305	)		(5,847	)
Balance at end of year	$	15,048		$	17,251		$	12,868
Alabama Gas Corporation
Years ended December 31, (in thousands)	2010			2009			2008
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year	$	16,400		$	12,100		$	11,500
Additions:
Charged to income		2,655			11,122			6,590
Recoveries and adjustments		(1,094	)		(517	)		(199	)
Net additions		1,561			10,605			6,391
Less uncollectible accounts written off		(3,761	)		(6,305	)		(5,791	)
Balance at end of year	$	14,200		$	16,400		$	12,100

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

None

ITEM 9A. CONTROLS AND PROCEDURES

Energen Corporation

a. Disclosure Controls and Procedures

Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

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

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

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

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

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

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

Management assessed the effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2010. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Energen Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management determined that, as of December 31, 2010, Energen Corporation maintained effective internal control over financial reporting. The effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 25, 2011

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c. Changes in Internal Control Over Financial Reporting

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

Alabama Gas Corporation

a. Disclosure Controls and Procedures

Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

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

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

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

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

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

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

Management assessed the effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of December 31, 2010. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Alabama Gas Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management determined that, as of December 31, 2010, Alabama Gas Corporation maintained effective internal control over financial reporting. The effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 25, 2011

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c. Changes in Internal Control Over Financial Reporting

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

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2011. The definitive proxy statement will be filed on or about March 18, 2011.

ITEM 11. EXECUTIVE COMPENSATION

The information regarding executive compensation is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2011.

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

a. Security Ownership of Certain Beneficial Owners

The information regarding the security ownership of the beneficial owners of more than five percent of Energen’s common stock is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2011.

b. Security Ownership of Management

The information regarding the security ownership of management is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2011.

c. Securities Authorized for Issuance Under Equity Compensation Plans

The information regarding securities authorized for issuance under equity compensation plans is included in Part 2 under Item 4.

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

The information regarding certain relationships and related transactions, and director independence is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2011.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2011.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a. Documents Filed as Part of This Report

(1) Financial Statements

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

(2) Financial Statement Schedules

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

(3) Exhibits

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

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Energen Corporation

Alabama Gas Corporation

INDEX TO EXHIBITS

Item 14(a)(3)

Exhibit Number	Description
*3(a)	Restated Certificate of Incorporation of Energen Corporation (composite, as amended April 29, 2005) which was filed as Exhibit 3(a) to Energen’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005
*3(b)	Articles of Amendment to Restated Certificate of Incorporation of Energen, designating Series 1998 Junior Participating Preferred Stock (July 27, 1998) which was filed as Exhibit 4(b) to Energen’s Post Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 333-00395)
*3(c)	Bylaws of Energen Corporation (as amended through July 23, 2008) which was filed as Exhibit 99.1 to Energen’s Current Report on Form 8-K, dated July 25, 2008
*3(d)	Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for the year ended September 30, 1995
*3(e)	Bylaws of Alabama Gas Corporation (as amended through October 24, 2007) which was filed as Exhibit 3 to Energen’s Quarterly Report on Form 10-Q for the period ended October 31, 2007
*4(a)	Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which was dated as of September 1, 1996 (the “Energen 1996 Indenture”), and which was filed as Exhibit 4(i) to the Registrant’s Registration Statement on Form S-3 (Registration No. 333-11239)
*4(a)(i)	Officers’ Certificate, dated September 13, 1996, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Series A Notes which was filed as Exhibit 4(d)(i) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001
*4(a)(ii)	Officers’ Certificate, dated July 8, 1997, pursuant to Section 301 of the Energen 1996 Indenture amending the terms of the Series A Notes which was filed as Exhibit 4(d)(ii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001
*4(a)(iii)	Amended and Restated Officers’ Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes which was filed as Exhibit 4(d)(iii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001
*4(a)(iv)	Officers’ Certificate, dated October 3, 2003, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 5 percent Notes due October 1, 2013, which was filed as Exhibit 4 to Energen’s Current Report on Form 8-K, dated October 3, 2003
*4(b)	Indenture dated as of November 1, 1993, between Alabama Gas Corporation and NationsBank of Georgia, National Association, Trustee, (“Alagasco 1993 Indenture”), which was filed as Exhibit 4(k) to Alabama Gas Corporations’ Registration Statement on Form S-3 (Registration No. 33-70466)
*4(b)(i)	Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.70 percent Notes due January 15, 2035, which was filed as Exhibit 4.3 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005

98

*4(b)(ii)	Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.20 percent Notes due January 15, 2020, which was filed as Exhibit 4.4 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005
*4(b)(iii)	Officers’ Certificate, dated November 17, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.368 percent Notes due December 1, 2015, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed November 17, 2005
*4(b)(iv)	Officers’ Certificate, dated January 16, 2007, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.90 percent Notes due January 15, 2037, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 16, 2007
*10(a)	Service Agreement Under Rate Schedule CSS (No. SSNG1), between Southern Natural Gas Company and Alabama Gas Corporation, dated as of September 1, 2005, which was filed as Exhibit 10(a) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(b)	Firm Transportation Service Agreement Under Rate Schedule FT and/or FT-NN (No. FSNG1), between Southern Natural Gas Company and Alabama Gas Corporation dated as of September 1, 2005, which was filed as Exhibit 10(b) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(c)	Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alabama Gas Corporation, which was filed as Exhibit 10(b) to Energen’s Annual Report on Form 10-K for the year ended September 30, 1993
*10(c)(i)	Amended Exhibits A and B, effective June 1, 2009, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(c)(i) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2009
*10(c)(ii)	Amended Exhibits A and B, effective September 1, 2010, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(c)(ii) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2009
*10(d)	Service Agreement between Transcontinental Gas Pipeline Corporation and Transco Energy Marketing Company as Agent for Alabama Gas Corporation, dated August 1, 1991 which was filed as Exhibit 3(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2003
*10(e)	Amendment to Service Agreement between Transcontinental Gas Pipeline Corporation and Alabama Gas Corporation, dated December 2, 2005, which was filed as Exhibit 10(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(f)	Occluded Gas Lease, dated January 1, 1986 and First through Seventh Amendments, which was filed as Exhibit 10(f) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(f)(i)	Eighth Amendment to Occluded Gas Lease, dated January 1, 2009, while was filed as Exhibit 10(f)(i) to Energen’s Annual Report on Form 10-k for the year ended December 31, 2008
*10(g)	Form of Executive Retirement Supplement Agreement between Energen Corporation and its executive officers (as revised October 2000) which was filed as Exhibit 10(c) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2000

99

*10(h)	Form of Severance Compensation Agreement between Energen Corporation and its executive officers which was filed as Exhibit 10(h) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2009
*10(i)	Energen Corporation 1997 Stock Incentive Plan (as amended effective January 1, 2010) which was filed as Exhibit 10(i) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2009
*10(j)	Form of Stock Option Agreement under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(a) to Energen’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004
*10(k)	Form of Restricted Stock Agreement under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(b) to Energen’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004
*10(l)	Form of Performance Share Award under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(c) to Energen’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004
*10(m)	Energen Corporation 1997 Deferred Compensation Plan (amended and restated effective January 1, 2008)
*10(n)	Energen Corporation Directors Stock Plan (as amended April 28, 2010) which was filed as an attachment to Energen’s definitive Proxy Statement on Schedule 14A
*10(o)	Energen Corporation Annual Incentive Compensation Plan, as amended effective January 1, 2010 which was filed as an attachment to Energen’s definitive Proxy Statement on Schedule 14A, filed March 19, 2010
*10(p)	Credit Agreement dated October 29, 2010, by and among Energen Corporation, Energen Resources Corporation, Bank of America, N.A., as Administrative Agent, Wells Fargo Bank, N.A. and Regions Bank, and Co-Syndication Agents, BBVA, as Documentation Agent, Banc of America Securities LLC, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank and BBVA as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed November 1, 2010
*10(q)	Credit Agreement dated October 29, 2010, by and among Alabama Gas Corporation, Bank of America, N.A., as Administrative Agent, Wells Fargo Bank, N.A. and Regions Bank, and Co- Syndication Agents, BBVA, as Documentation Agent, Banc of America Securities LLC, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank and BBVA as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.2 to Energen’s Current Report on Form 8-K filed November 1, 2010
21	Subsidiaries of Energen Corporation and Alabama Gas Corporation
23(a)	Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP)
23(b)	Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company, L.P.)
23(c)	Consent of Independent Oil and Gas Reservoir Engineers (T. Scott Hickman and Associates, Inc.)
24	Power of Attorney

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31(a)	Energen Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)
31(b)	Energen Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)
31(c)	Alabama Gas Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)
31(d)	Alabama Gas Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)
32(a)	Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)	Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350
99(a)	Reserve Audit – Ryder Scott & Company, L.P.
99(b)	Reserve Audit – T. Scott Hickman and Associates, Inc.
101	The following financial statements from Energen Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Shareholders Equity, (iv) Consolidated Statements of Cash Flows, (v) the Notes to Unaudited Financial Statements, tagged as blocks of text.

*Incorporated by reference

101

SIGNATURE

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

ENERGEN CORPORATION

(Registrant)

ALABAMA GAS CORPORATION

(Registrant)

February 25, 2011	By	/s/ J.T. McManus, II
	J.T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation

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SIGNATURES

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

February 25, 2011	By    /s/ J.T. McManus, II
	J.T. McManus, II
	Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation
February 25, 2011	By    /s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr.
	Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
February 25, 2011	By    /s/ Russell E. Lynch, Jr.
	Russell E. Lynch, Jr.
	Vice President and Controller of Energen Corporation
February 25, 2011	By    /s/ William D. Marshall
	William D. Marshall
	Vice President and Controller of Alabama Gas
	Corporation
February 25, 2011	*
	Julian W. Banton
	Director
February 25, 2011	*
	Kenneth W. Dewey
	Director
February 25, 2011	*
	James S. M. French
	Director
February 25, 2011	*
	Judy M. Merritt
	Director
February 25, 2011	*
	David W. Wilson
	Director
	*By    /s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr.,
	Attorney-in-Fact

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