Exhibit 99.1

ENERGEN’S FIRST JO MILL WELLS TRACKING 1,200 MBOE EUR TYPE CURVE

Company Plans to Exit San Juan Basin and Sell Other Non-Core Assets in Delaware Basin

Focus on Capital Discipline, Expense Reductions in 2016

Highlights

BIRMINGHAM, Alabama – For the 3 months ended December 31, 2015, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $(590.8) million, or $(7.50) per diluted share. Excluding mark-to-market derivatives losses, commodity price-driven impairments, and pension settlement charges, Energen’s adjusted income in the 4th quarter of 2015 totaled $21.3 million, or $0.27 per diluted share. This compares with adjusted income from continuing operations in the 4th quarter of 2014 of $38.2 million, or $0.52 per diluted share. The variance between the periods largely is attributable to lower realized commodity prices and higher depreciation, depletion, and amortization expense (DD&A) associated with increased drilling activity and the impact of lower year-end commodity prices, partially offset by increased production, lower lease operating, marketing and transportation expenses (LOE), and lower production and ad valorem taxes. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Energen’s adjusted EBITDAX totaled $205.0 million in the 4th quarter of 2015 and compared with adjusted EBITDAX from continuing operations in the same period last year of $208.6 million. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Relative to internal expectations, Energen’s adjusted 4Q15 earnings were negatively affected by a 4^th quarter DD&A adjustment that totaled $0.17 per share and was driven by the impact on reserves of low commodity prices at year end. Otherwise, Energen’s adjusted 4Q15 earnings would have been $0.44 per diluted share. In addition, the impact of slightly below-budget production was more than offset by decreased LOE and ad valorem, production and other taxes, greater-than-expected realized oil prices, lower exploration expense, and less net salaries and general and administrative expense (G&A).

Production in 4Q15 fell just short of the company’s guidance midpoint for a number of reasons, including the underperformance of primarily Wolfcamp B wells in a select area near the Glasscock/Reagan county line where higher gas rates and lower oil rates were encountered, weather-related impacts, and the timing of flow back of 4^th quarter development wells; these factors were partially offset by continued strong production from 3rd Bone Spring and Wolfcamp wells in the Delaware Basin.

2016 Capital and Production Summary

Energen plans to invest approximately $250-$350 million of drilling and development capital in 2016. At recent strip oil prices for the year approximating $36 per barrel, the low end of the range reflects capital investment to hold the company’s acreage in the Delaware and Midland basins and to complete 47 gross (47 net) horizontal wells in the Midland Basin, including 46 gross (46 net) wells that were drilled but uncompleted (DUC) at YE15.

If oil prices increase later in the year, Energen likely would invest capital at the higher end of the range in order to resume drilling in the Midland Basin.

The company anticipates funding the estimated gap between capital investment and after-tax cash flows of approximately $225-$325 million with proceeds from the sale of non-core assets in the San Juan and Delaware basins in 2016. After-tax cash flows will include a working capital adjustment of $(79.0) million related to accrued capital at YE15.

Being largely unhedged, the company’s debt-to-EBITDAX ratio is highly sensitive to changes in oil prices. At average 2016 oil prices of $40 per barrel, and assuming the sale of non-core assets for cash proceeds of approximately $400 million, Energen’s capital investment of $250 million would result in an estimated total debt-to-EBITDAX multiple at YE16 of approximately 2.5.

2016 Capital Summary

Energen’s capital plan includes approximately $168 million for completion of 46 gross (46 net) DUCs in the Midland Basin and another $6.6 million to drill and complete a Lower Spraberry well needed to finish a pad. Approximately $48 million will be invested to drill 6 gross (6 net) vertical Wolfberry wells in the Midland Basin and 4 gross (4 net) Wolfcamp shale wells in the Delaware Basin to hold leases. Another $17 million will be invested in other drilling- and development-related activities such as facilities and non-operated drilling, including $10 million in the Midland Basin and $5 million in the Delaware Basin.

2016 Production Guidance

Production in 2016 is estimated to be essentially flat relative to 2015, as 25 percent production growth from horizontal drilling and development activities in the Midland Basin is offset by natural declines in the vertical Wolfberry, the 3^rd Bone Spring sands in the Delaware Basin, and the Central Basin Platform.

Excluding production from the planned sales of non-core assets in the San Juan and Delaware basins, the company estimates that production in 2016 will range from 19.5-20.3 MMBOE, or 53,280-55,465 boepd. The guidance midpoint is 19.9 MMBOE, or 54,437 boepd. With DUC completions scheduled to occur in the first half of the year, 2016 production is expected to peak in 3Q16. Energen’s 4Q16 exit rate is estimated to be 51,370 boepd, or 12 percent less than the comparable 4Q15 exit rate of 58,457 boepd.

Production by Product, Pro Forma to Exclude Planned Sales of Non-Core Assets

NOTE: Totals may not sum due to rounding

Production by Play, Pro Forma to Exclude Planned Sales of Non-Core Assets

NOTE: Totals may not sum due to rounding

Plans to Monetize Non-Core Assets Announced

Energen plans to sell the remainder of its San Juan Basin assets in 2016 along with other non-core assets in the Delaware Basin. The company estimates that proceeds from these asset sales could total $400 million.

Approximately 70 percent of the company’s assets in the San Juan Basin were sold in March 2015. The remaining assets are primarily natural gas production with upside potential in the Mancos oil play. Energen decided to exit the San Juan Basin after assessing the early performance of exploratory wells it drilled in 2015 to test the oil play’s potential on portions of its acreage. The company concluded that these assets do not compete with its high-quality assets in the Midland and Delaware basins.

In addition to exiting the San Juan Basin, Energen is marketing select, non-core assets in the eastern Delaware Basin in Texas. Sales processes are under way.

As a pure Permian Basin operator, Energen will focus on its high-quality assets in the Midland and Delaware basins.

Cost-cutting Measures Implemented as Oil Prices Drop

Energen has implemented a variety of cost-cutting measures, including a workforce reduction, in response to the dramatic drop in oil prices. Additional savings will occur with the disposition of the company’s remaining San Juan Basin assets.

G&A expenses (excluding pension settlement charges and severance payments) are estimated to decrease 25 percent year-over-year in 2016 to approximately $89 million.

Other measures taken to enhance capital discipline include the recent decision to discontinue paying the company’s cash dividend.

Updated Permian Basin Inventory Identifies Net Potential of >2 Billion BOE

Energen’s updated, unrisked potential drilling inventory of horizontal locations in the Permian Basin at year-end 2015 totals 4,440. Of that amount, 2,504 net locations are in the Midland Basin, and 1,936 net locations are in the Delaware Basin. The company estimates that the associated net undeveloped resource potential is more than 1 billion BOE in each basin. [See inventory and spacing slides at www.energen.com]

Adjustments to Energen’s inventory included the addition of 340 net Jo Mill and Middle Spraberry locations in the Midland Basin along with the identification of 477 net locations with 10,000’ lateral lengths in the Midland Basin and 143 net locations in the Delaware Basin with an average lateral length of 9,700’. The inventory also was adjusted for locations drilled in 2015.

Potential drilling locations are engineered based on the company’s existing acreage and spacing plans and may change over time as the company and offset operators drill wells in each target zone. The updated potential inventory excludes eastern Delaware Basin assets that are targeted for sale in 2016.

Energen’s proved reserves at year-end 2015 totaled 355 MMBOE. This reflected only a 5 percent decrease from 2014 even though the company lost 58 MMBOE primarily due to substantially lower commodity prices and another 68 MMBOE due to the sale of proved reserves in the San Juan Basin in March 2015. Adjusting 2014 year-end proved reserves just for the 1Q15 San Juan Basin divestiture, proved reserves at year-end 2015 would have increased 16 percent.

Wolfcamp and Spraberry drilling in the Midland and Delaware basins was the dominant driver of total proved reserve additions of approximately 132 MMBOE, which replaced 2015 production by 550 percent. Proved oil reserves increased 17 percent in 2015 and represent 59 percent of total proved reserves. Approximately 52 percent of Energen’s total proved reserves are proved developed.

Commodity prices used for calculating reserves at year-end 2015 were substantially lower than those at year-end 2014. WTI oil prices declined 47 percent to $50.28 per barrel, while NGL prices (before transportation and fractionation) declined 45 percent to 41 cents per gallon and Henry Hub natural gas prices dropped 40 percent to $2.59 per thousand cubic feet (Mcf).

Proved Reserves by Basin (MMBOE)

NOTE: Totals may not sum due to rounding

Proved Reserves by Commodity (MMBOE)

YE2015 3P Reserves & Contingent Resources (MMBOE)

NOTE: Totals may not sum due to rounding

The definitions of probable and possible reserves imply different probabilities of potential recovery in each classification; the quantities reported here are unrisked and based on the Company’s estimate of current costs to drill wells in each basin/area and bring associated production to market. [See Cautionary Statements on page 12].

Energen’s First Jo Mill Wells Highlight 4Q15 Appraisal Program Results

Energen’s latest appraisal wells in the Midland Basin were highlighted by the company’s first two Jo Mill tests –impressive wells that are tracking at or above a 1.2 million BOE type curve. Drilled in Martin County, these wells had an average peak 24-hour IP of 1,062 boepd and an average peak 30-day average rate of 943 boepd, and were approximately 75 percent oil.

Another highlight was the company’s test of the Lower Spraberry in Glasscock County north of its first Lower Spraberry well. With a 10,000’ lateral length, the Daniel SN 7-6 04 #504H generated a 24-hour IP of 1,460 boepd (74% oil) and a peak, 30-day average rate of 1,213 boepd (70% oil). The company also drilled wells east and west of its first Lower Spraberry well; while results were not as strong as the Daniel well, these are solid wells that will be good additions to the Glasscock County development program in a higher commodity price environment.

In northern Midland County, the company drilled a Wolfcamp A test well that confirmed the positive results of the B-bench well drilled at that location earlier in 2015. [See locator maps and graphs of the cumulative oil production of Jo Mill, Middle Spraberry, and Lower Spraberry wells over time at www.energen.com].

Midland Basin (3-Stream Results)

Midland Basin Development Program Results

In its 2-well, pad-drilling development program in Glasscock County, Energen tested 15 Wolfcamp A and B wells with lateral lengths of 7,500 feet during 4Q15. These wells generated average peak 24-hour IP rates (3-stream) of 1,242 boepd (83% oil) and peak 30-day average rates (3-stream) of 875 boepd (71% oil).

Since the development program’s inception in 2014, Energen has tested 90 gross (87 net) wells that generated average peak 24-hour IPs (3-stream) of 1,002 boepd (80% oil) and peak 30-day average rates (3-stream) of 754 boepd (71% oil).

[See updated Glasscock County Wolfcamp A/B type curve, normalized to 7,500’, at www.energen.com].

4th Quarter Financial Review

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations

[See “Non-GAAP Financial Measures” beginning on pp 13 for more information]

Note: Per share amounts may not sum due to rounding

Asset impairments in 4Q15 reflect price-driven write downs of proved properties, primarily in the San Juan and Delaware basins, and a write down to fair value of unproved leasehold in the San Juan Basin (which has been designated as “held for sale” at year-end 2015). Pension and pension settlement expenses relate to the termination and subsequent distribution of benefits of Energen’s qualified defined pension plan and non-qualified supplemental retirement plans. The bulk of these expenses occurred in 4Q15.

Production from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Note: Totals may not sum due to rounding

Production from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Note: Totals may not sum due to rounding

Average Realized Sales Prices from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Average Prices from Continuing Operations Before Effects of Hedges

(excludes production associated with 1Q15 San Juan divestiture)

Expenses from Continuing Operations and Excluding San Juan Basin Assets sold 1Q15

(per BOE, except interest expense)

4th Quarter Comparisons, 2015 vs 2014 (excluding San Juan Basin assets sold March 31, 2015)

2015 Financial Review

For the 12 months ended December 31, 2015, Energen reported a GAAP net loss from all operations of $(945.7) million, or $(12.43) per diluted share. Excluding mark-to-market derivatives losses, commodity price-related impairments, and pension settlement charges, Energen’s adjusted income in 2015 totaled $64.5 million, or $0.85 per diluted share. This compares with adjusted income from continuing operations in 2014 of $135.8 million, or $1.85 per diluted share.

The variance between the periods largely is attributable to lower realized commodity prices and higher DD&A associated with increased drilling activity and the impact of lower prices at year-end, partially offset by increased production, lower LOE, lower production and ad valorem taxes, and decreased exploration expense. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Energen’s adjusted 2015 EBITDAX totaled $739.8 million as compared with adjusted EBITDAX from continuing operations in 2014 of $762.9 million. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations

[See “Non-GAAP Financial Measures” beginning on pp 13 for more information]

Note: Per share amounts may not sum due to rounding

Production from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Note: Totals may not sum due to rounding

Production from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Note: Totals may not sum due to rounding

Average Realized Sales Prices from Continuing Operations

(excludes production associated with 1Q15 San Juan divestiture)

Average Prices from Continuing Operations Before Effects of Hedges

(excludes production associated with 1Q15 San Juan divestiture)

Expenses from Continuing Operations and Excluding San Juan Basin Assets sold 1Q15

(per BOE, except interest expense)

Liquidity Update

As of December 31, 2015, Energen had borrowings (net of cash) of $221.2 million on its line of credit, for total liquidity available on its $1.4 billion borrowing base of $1.18 billion. Long-term debt at the end of December totaled $553.6 million. Total debt-to-2015 adjusted EBITDAX was approximately 1.0 at YE15. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Capital

Drilling and development capital in 2015 totaled $1.0 billion, with total capital investment of $1.1 billion, including approximately $0.1 billion for the acquisition of proved and unproved leasehold, primarily in the Permian Basin.

1Q16 and CY16 Financial Guidance

Energen’s estimated expenses, pro forma for planned sales of non-core assets:

Production by Commodity/Quarter, Pro Forma to Exclude Planned Sales of Non-Core Assets

NOTE: Totals may not sum due to rounding

1Q16 Hedge Position

CY16 Hedge Position

In the tables above, basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen’s assumed basis differentials.

Average realized oil and gas prices for Energen’s production associated with NYMEX contracts as well as for unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect estimated 1Q16 and CY16 oil transportation charges of $2.60 per barrel and $2.55 per barrel, respectively; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.12 per gallon in 1Q16 and CY16.

The company also has hedges in place to limit its exposure to the Midland to Cushing differential. For 1Q16 and CY16, Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 0.5 million barrels and 2.1 million barrels of oil production, respectively, at an average price of $(1.63) per barrel; WTI Midland to WTI Cushing (sweet oil) differential hedges in 1Q16 and CY16 are for 1.9 million barrels and 7.5 million barrels, respectively, at an average price of $(1.92) per barrel.

Approximately 75 percent and 77 percent of Energen’s estimated oil production in 1Q16 and CY16, respectively, will be sweet oil. Gas basis assumptions for all open contracts (February-December) are $(0.17) per Mcf.

Estimated Price Realizations (pre-hedge):

Energen’s assumed commodity prices for unhedged production in 2016 are $36.33 per barrel of oil (February-December), $0.38 per gallon of NGL (February-December), and $2.39 per Mcf of gas (March-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (March-December) are $(0.30) and $(0.41), respectively.

Given Energen’s modest hedge position in 2016, its cash flows and earnings are highly sensitive to changes in commodity prices. Relative to the company’s price assumptions: every $1.00 per barrel change in the price of oil is estimated to impact the company’s cash flows by approximately $11.3 million; every $0.01 per gallon change in the average price of NGL is estimated to have an impact of approximately $1.2 million; and every $0.10 per Mcf change in the price of natural gas is estimated to have an impact of approximately $950,000.

Conference Call

Energen will hold its quarterly conference call Friday, February 12, at 11:00 a.m. EDT. Members of the investment community may participate by calling 1-877-407-8289 (reference Energen earnings call). A live audio Webcast of the program as well as a replay may be accessed through Web site, www.energen.com.

Energen Corporation is an oil and gas exploration and production company with headquarters in Birmingham, Alabama. At year-end 2015, the company had 355 million barrels of oil-equivalent proved reserves and another 2.8 billion barrels of oil-equivalent probable and possible reserves and contingent resources. These all-domestic reserves and resources are located primarily in the Permian Basin in west Texas. For more information, go to http://www.energen.com.

FORWARD LOOKING STATEMENTS: All statements, other than statements of historical fact, appearing in this release constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to the timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, the nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, the timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. Among other forward-looking statements in this release are statements regarding our intention to engage in certain assets sales and the estimated proceeds thereof. These sales processes are at preliminary stages, and we do not have binding agreements for any transactions; as a result, the estimate of proceeds from these transactions is preliminary and may not be realized. Our ability to consummate any transactions and their timing are subject to market conditions and other factors, and we may not be able to consummate these transactions at all or for the net proceeds we are estimating.

Forward-looking statements may include words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”, “foresee”, “intend”, “may”, “plan”, “potential”, “predict”, “project”, “seek”, “will” or other words or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this news release. 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. We base our forward-looking statements on information currently available to us, and we undertake no obligation to correct or update these statements whether as a result of new information, future events or otherwise. Additional information regarding our forward-looking statements and related risks and uncertainties that could affect future results of Energen, can be found in the Company’s periodic reports filed with the Securities and Exchange Commission and available on the Company’s website - www.energen.com.

CAUTIONARY STATEMENTS: The SEC permits oil and gas companies to disclose in SEC filings only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. Outside of SEC filings, we use the terms “estimated ultimate recovery” or “EUR,” reserve or resource “potential,” “contingent resources” and other descriptions of volumes of non-proved reserves or resources potentially recoverable through additional drilling or recovery techniques. These estimates are inherently more speculative than estimates of proved reserves and are subject to substantially greater risk of actually being realized. We have not risked EUR estimates, potential drilling locations, and resource potential estimates. Actual locations drilled and quantities that may be ultimately recovered may differ substantially from estimates. We make no commitment to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of our on-going drilling program, which will be directly affected by the availability of capital, drilling, and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approvals, and geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per-well EURs, and resource potential may change significantly as development of our oil and gas assets provides additional data. Additionally, initial production rates contained in this news release are subject to decline over time and should not be regarded as reflective of sustained production levels.

Financial, operating, and support data pertaining to all reporting periods included in this release are

unaudited and subject to revision.