October 3, 2013

VIA EDGAR FILING

H. Roger Schwall

Assistant Director

Division of Corporate Finance

U.S. Securities and Exchange Commission

Washington, D.C. 20549

RE: Energen Corporation/Alabama Gas Corporation

Form 10-K for Fiscal Year Ended December 31, 2012

Filed February 28, 2013

File Nos. 001-07810 / 002-38960

Comment Letter Dated August 27, 2013

Dear Mr. Schwall:

Energen Corporation has received your letter dated August 27, 2013, to our Chief Executive Officer, James McManus. We have reviewed your comments and submit the following responses for your consideration:

Form 10-K for the Fiscal Year Ended December 31, 2012

Financial Statements and Supplementary Data, page 39

Note 1 – Summary of Significant Accounting Policies, page 53

B. Oil and Gas Operations – Property and Related Depletion, page 53

1. We note your disclosure: “Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed.” Please tell us what consideration you gave to the additional exploratory well cost disclosure requirements of FASB ASC Topic 932-235-50-1A and 1B, or tell us why you believe such disclosures are not applicable.

We considered the requirements of FASB ASC Topic 932-235-50-1A and 1B and determined the amounts of capitalized exploratory well costs to be insignificant. At December 31, 2011 and 2012, the amounts of capitalized exploratory well costs that were pending the determination of proved reserves were $70.4 million and $79.8 million, respectively. For year ends 2011 and 2012, this represented approximately 2 percent of Oil and Gas Properties, net

and approximately 1 percent of Total Assets. We also considered the likelihood of year end exploratory well costs that might be charged to expense and, given the locations of the exploratory wells, we estimated that the amount of such potential charges to be insignificant for disclosure purposes. Since year end 2012, we have reclassified approximately $77.7 million of the $79.8 million capitalized exploratory well costs to proved reserves. The remaining $2.1 million represents two non-operated wells that are pending determination of proved reserves. In addition, we did not recognize any year end capitalized exploratory well costs to expense during 2010, 2011 and 2012.

The nature of the majority of our exploratory expenditures are associated with resource activities in which the success rate is very high, as indicated by the data above. Therefore, we would anticipate a substantial portion of our exploratory expenditures to be reclassified to proved properties. In future filings, we will include for all periods in which an income statement is presented, all exploratory wells costs that are pending the determination of proved reserves.

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense during the year:

Years ended December 31, (in thousands)	2012			2011			2010
Capitalized exploratory well costs at beginning of period	$	70,437		$	21,438		$	6,569
Additions pending determination of proved reserves		406,226			178,005			21,510
Reclassifications due to determination of proved reserves		(396,872	)		(129,006	)		(6,641	)
Exploratory well costs charged to expense		—			—			—
Capitalized exploratory well costs at end of period	$	79,791		$	70,437		$	21,438

The following table sets forth capitalized exploratory wells costs at year end and includes amounts capitalized for a period greater than one year:

Years ended December 31, (in thousands)	2012		2011		2010
Exploratory wells in progress	$	77,693	$	70,437	$	21,438
Capitalized exploratory well costs for a period greater than one year		2,098		—		—
Total capitalized exploratory well costs	$	79,791	$	70,437	$	21,438

Note 8 – Financial Instruments and Risk Management, page 80

Concentration of Credit Risk, page 85

2. We note your disclosure pertaining to significant customer concentrations, in which you state: “During the year ended December 31, 2012, the two largest oil and gas purchasers accounted for approximately 27 percent and 12 percent of Energen Resources’ total operating revenues.” Based on this information, it appears the largest purchaser you reference would correspondingly have been responsible for approximately 19.5 percent of your 2012 total operating revenues. Accordingly, please tell us what consideration you gave to the disclosure requirements of Item 101(C)(1)(vii) of Regulation S-K in your “Item 1. Business” disclosures.

As noted on page 85 of our Form 10-K in the discussion of “Concentration of Credit Risk,” our revenues are generated primarily from the sale of produced natural gas and oil for which payment is typically due the month following delivery. With the potential exposure limited to the loss of approximately two months of revenue from any single purchaser, we did not consider the potential loss of even a large customer to have a material adverse effect on the registrant and its subsidiaries taken as a whole, as is required by Item 101(C)(1)(vii) of Regulation S-K. With respect to future revenues, we believe an interruption in sales would be temporary in nature as there are alternative purchasers in our producing regions.

In future filings, we will disclose the names of any customers representing greater than 10 percent of our consolidated total operating revenues. Plains Marketing, LP was the only such customer for calendar year 2012.

Note 17 – Oil and Gas Operations, page 93

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, page 96

3. We note your disclosure of “Discounted future net cash flows before income taxes” or what is more commonly known as “PV10.” Please be advised that this disclosure is considered a non-GAAP measure. As such, please remove such disclosure from the footnotes.

In future filings, we will not include the “Discounted future net cash flows before income taxes” in the notes to the financial statements.

Engineering Comments

Properties, page 12

Net Undeveloped Acreage, page 14

4. Item 1208(b) of Regulation S-K requires the disclosure of the remaining terms of material expiring leasehold acreage. Please amend your document to comply with Regulation S-K.

As of December 31, 2012, the Company had development plans and expected to extend lease terms through continuous development. Accordingly, we did not have material acreage positions expected to expire during 2013.

For 2012, the table below sets forth future expiration amounts of our gross and net undeveloped acreage at December 31, 2012. We expect expirations to be significantly less if we establish production or undertake continuous development beyond the primary term of the lease. Our current capital plan contemplates such production or continuous development for a significant portion of the acreage. In future filings, we will provide a table in the below format including gross and net undeveloped acreage at year end.

The following table sets forth expiration dates for gross and net undeveloped acreage at year end as of December 31, 2012:

	Years ended December 31,
	2013				2014				2015				Thereafter
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
San Juan		440		54		480		183		1,359		685		37,115		19,549
Permian		43,513		37,116		42,599		14,625		33,733		22,212		32,840		23,258
Total *		43,953		37,170		43,079		14,808		35,092		22,897		69,955		42,807

* Our capital plan contemplates avoiding a significant portion of these lease expirations.

5. In addition, tell us the figures for any proved undeveloped reserves you attributed to the expiring acreage that is scheduled to be drilled after the expiration date(s). If such PUD reserves are material, explain to us how/if you will avoid the loss of these reserves.

We have 5.1 million barrels of oil equivalents (MMBOE) of proved undeveloped reserves on leased acreage which is scheduled to be drilled after the expiration dates. The amount represents approximately 6 percent of the 85.9 MMBOE total proved undeveloped reserves and approximately 1 percent of the 346.4 MMBOE total proved reserved at year end 2012. We believe both of which to be immaterial.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 22

Financial Position and Liquidity, page 27

6. We note your statement on page 28, “During 2012, the Company added approximately 12 MMBOE of reserves primarily from the Permian Basin oil property acquisitions. Also during 2012, Energen Resources added 57 MMBOE of reserves from discoveries and other additions, primarily the result of development and exploratory drilling that increased the number of proved undeveloped locations in the Permian Basin.” As you disclose only proved reserves, we assume that you are referring to proved reserves. Please confirm and revise your disclosure accordingly. If you are referring to proved and unproved reserves, then revise to provide the information required by Item 1202(a)(2) of Regulation S-K for those unproved categories.

The noted statement on page 28 was intended to reference only proved reserves. In future filings we will use the word “proved” when discussing reserves.

7. Item 1202(a)(6) of Regulation S-K requires a registrant that is disclosing material additions to its reserves estimates to provide a general discussion of the technologies used to establish the appropriate level of certainty for reserves estimates from material properties included in the total reserves disclosed. Please amend your document to comply with Regulation S-K.

On page 36 of our Form 10-K in the discussion of Critical Accounting Policies and Statements, we provided the following summary of the estimation of our proved 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, 2012.

The proved developed reserve additions were based on well performance. The proved undeveloped reserves additions were one offset location away from producing wells where our geologic interpretation and experience indicate the reservoirs were continuous across those locations. The technology associated with these additions to proved reserve estimates reflects long-standing and customary industry practices including analysis of geophysical data, wireline and core data. We did not believe that these technologies required further disclosure. In future filings, we will provide more specific references to these practices.

Exhibit 99(b)

8. We note the statement on page four of the third party engineering report, “It is our opinion ERC’s estimate of net Proved reserve quantities in the “Subject Areas” were prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forth in the 2007 Petroleum Resources Management System sponsored by the SPE, WPC, AAPG and SPEE.” While we understand that there are fundamentals of physics, mathematics and economics that are applied in the estimation of reserves, we are not aware of an official industry compilation of such “generally accepted petroleum engineering and evaluation principles.” Please explain to us the basis for concluding that such principles have been sufficiently established so as to judge that the reserve information has been prepared in conformity with such principles or revise the report accordingly.

Our proved reserve calculations were prepared pursuant to the rules prescribed by the Securities and Exchange Commission and the guidelines established in the 2007 Petroleum Resource Management System, such as performance based decline curve analysis, analogy and volumetrics. We agree that the petroleum industry does not have an official industry compilation of “generally accepted petroleum engineering and evaluation principles.” Based on our conversations with our expert, we believe that their intent was to refer to techniques that are widely used by and referred to by professionals in the industry. We further believe that our expert was more colloquially referencing “generally accepted petroleum engineering and evaluation principles” as a general reference to these widely used techniques and practices versus referencing published “standard principles” of valuation. We have requested that our expert no longer use this term in future reports.

In accordance with your instructions, the Company acknowledges that the Company is responsible for the adequacy and accuracy of the disclosure in the filing; staff comments or changes to disclosures in response to comments do not foreclose the Commission from taking any action with respect to the filing; and the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please call me if you need additional information or clarification.

Sincerely,

/s/ J. David Woodruff

J. David Woodruff, Jr.

General Counsel and Secretary