Exhibit 99.1

ENERGEN RAISES 2015 ANNUAL PRODUCTION GUIDANCE BY 500,000 BOE

Strong Results Generated by 9 Appraisal Wells in Delaware, Midland basins

Continued Efficiency Gains Reflected in Declining Days to Drill Development Wells

Highlights

BIRMINGHAM, Alabama – For the 3 months ended June 30, 2015, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $111.6 million, or $(1.52) per diluted share. Excluding mark-to-market derivatives losses, impairment losses and other non-cash items, and a purchase price adjustment from the sale of the majority of the company’s San Juan Basin assets in March 2015, Energen’s adjusted income in the 2^nd quarter of 2015 totaled $7.7 million, or $0.10 per diluted share. This compares with adjusted income from continuing operations in the 2nd quarter of 2014 of $26.0 million, or $0.36 per diluted share. The variance between the periods largely is attributable to a 22 percent decline in realized oil and natural gas liquids (NGL) prices and higher depreciation, depletion, and amortization expense (DD&A) associated with increased drilling activity, partially offset by a 23 percent increase in production. [See “Non-GAAP Financial Measures” beginning on pp 14 for more information and reconciliation.]

Energen’s adjusted EBITDAX totaled $180.3 million in the 2^nd quarter of 2015, up 4 percent from adjusted EBITDAX from continuing operations in the same period last year of $172.9 million. [See “Non-GAAP Financial Measures” beginning on pp 14 for more information and reconciliation.]

The company’s adjusted 2^nd quarter net income approximated internal expectations as increased production, lower lease operating expenses (LOE), and lower production and ad valorem taxes were essentially offset by increased depreciation expense, lower commodity prices, higher net general and administrative expense (G&A), and the timing of geological and geophysical (G&G) exploration expenses.

Production in the 2^nd quarter of 2015 exceeded the guidance range midpoint by 8 percent (approximately 4,635 boepd) largely due to the continued impact of accelerated completions in the first quarter on Delaware Basin production, better-than-expected well performance from Wolfcamp and 3^rd Bone Spring wells in the Delaware Basin, and the timing of horizontal completions in the Midland Basin.

production increased almost 8,400 barrels a day from the same period last year and 11 percent from the 1^st quarter, and we now expect total production in 2015 to show 19 percent growth, year-over-year.

“We have continued to improve our drilling efficiency by driving down the number of days to drill to total depth in our Glasscock County development program. We have continued to refine our completions and are encouraged by the early production response we have seen in our latest Wolfcamp development wells. Production from our Lower Spraberry shale appraisal wells in the northern Midland Basin continues to suggest the potential for outstanding returns. And an excellent set of Wolfcamp results across the Delaware Basin continues to build an encouraging body of data that supports the long-term potential of this play.

“Energen is well capitalized and well positioned to navigate through this period of uncertain commodity prices; but, as we look ahead to 2016, we plan to proceed at a pace of development and investment that will maintain our balance sheet strength and financial flexibility,” McManus added. “We have outstanding assets in the Midland and Delaware Basins that support a rich inventory of opportunities, and we plan to develop those assets in a manner that supports value creation for our shareholders.”

2nd Quarter Financial Review

Excluding mark-to-market derivatives losses, impairment losses and other non-cash items, and a purchase price adjustment from the sale of the majority of the company’s San Juan Basin assets in March 2015, Energen’s adjusted income in the 2^nd quarter of 2015 totaled $7.7 million, or $0.10 per diluted share. This compares with adjusted income from continuing operations in the 2nd quarter of 2014 of $26.0 million, or $0.36 per diluted share. The variance between the periods largely is attributable to a 22 percent decline in realized oil and NGL prices and higher DD&A expense associated with increased drilling activity partially offset by a 23 percent increase in production. [See “Non-GAAP Financial Measures” beginning on pp 14 for more information and reconciliation.]

More than 75 percent of the after-tax asset impairments of $42.9 million is related to a write down of a field in the Central Basin Platform that is in tertiary recovery ($33 million); another $3.0 million covers approximately 775 net acres in Reeves County (Enterprise area).

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

[See “Non-GAAP Financial Measures” beginning on pp 14 for more information]

Note: Per share amounts may not sum due to rounding

Production from Continuing Operations (excludes production associated with San Juan divestiture)

Note: Totals may not sum due to rounding

Production from Continuing Operations (excludes production associated with San Juan divestiture)

Note: Totals may not sum due to rounding

Average Realized Sales Prices from Continuing Operations

* Prior period hedges were left unallocated for current-year San Juan Basin divestiture; as reported last year, the average realized sales price of natural gas in 2Q14 was $4.25 per Mcf.

Average Prices from Continuing Operations Before Effects of Hedges

Expenses from Continuing Operations and Excluding San Juan Basin Assets sold March 31, 2015 (per BOE, except interest expense)

* Production costs + workovers and repairs + marketing and transportation

† Excludes $0.19 per BOE for pension and pension settlement expenses

2nd Quarter Comparisons, 2015 vs 2014 (excluding San Juan Basin assets sold March 31, 2015)

Liquidity Update

On June 22, Energen closed on the sale of 5.7 million shares of common stock for net proceeds of $399 million. Energen initially used net proceeds to repay borrowings outstanding under its revolving credit facility.

As of June 30, 2015, Energen had borrowings of $133.0 million on its revolving credit facility, which has a $1.6 billion borrowing base, and cash/cash equivalents of $1.5 million, for total liquidity available of $1.47 billion. Long-term debt at the end of June totaled $553.6 million.

Midland Basin Development Program Results

In its 2-well, pad-drilling development program in Glasscock County, Energen tested eight Wolfcamp A and B wells during the 2^nd quarter of 2015. These wells generated average peak 24-hour IP rates (3-stream) of 1,076 boepd (83% oil) and peak 30-day average rates (3-stream) of 856 boepd (68% oil). These average rates were substantially higher than the comparable rates for the larger group of 22 gross development wells tested in the 1^st quarter and likely were positively impacted, at least in part, by an adjustment made to the company’s completion design.

The 57 gross (56 net) wells tested since the program’s inception in 2014 have generated average peak 24-hour IPs (3-stream) of 930 boepd (81% oil) and peak 30-day average rates (3-stream) of 742 boepd (74% oil). A supplemental slide posted at www.energen.com shows that the average production from these wells – normalized to a 7,000’ lateral length – are tracking very closely to the company’s unrisked type curve normalized to 7,000’.

Energen continued to achieve efficiency gains in its development drilling program in Glasscock County in the second quarter. For example, the average days to drill to total depth a Wolfcamp A well with a 7,500’ lateral declined by approximately 7 days – from 21 to 14 – and the drill & complete cost of that same Wolfcamp A well is now averaging at the company’s year-end target of $5.9 million. The shortest drill time during the quarter was 11 days from spud to TD.

In a separate down-spacing test in Glasscock County, the company is in the early stages of analyzing initial production results of 20 gross (20 net) Wolfcamp A and B wells with 4,400’ lateral lengths, half of which were drilled on 660’ spacing and half on 440’ spacing. A multi-year analysis is expected in order to understand the long-term implications of the tighter spacing concept. Nine wells were part of the 2014 program; the 11 in the 2015 program are among the wells completed in the 2^nd quarter.

Energen’s total 2015 Midland Basin development program calls for the drilling of 100 gross (94 net) wells in Glasscock and Martin counties, with 37 gross (33 net) wells remaining to be drilled in the second half of the year. The company currently expects 46 gross (42 net) wells in the 2015 program to be completed in 2016.

Midland and Delaware Basin Appraisal Program Results

Energen tested nine new appraisal wells in the Permian Basin during the 2nd quarter of 2015, including its first Lower Spraberry wells in Howard and Midland counties in the Midland Basin. [See locator maps at www.energen.com]

Midland Basin (3-Stream Results)

Note: Totals may not foot due to rounding

The Smith SN 48-37 #501H, a Lower Spraberry well in Howard County, generated an excellent peak 24-hour IP rate of 1,067 boepd (78% oil); the well’s peak 30-day average remained strong at 895 boepd (79% oil). Through 81 days, the Smith well’s oil production is tracking very close to a 1.2 MMBOE EUR type curve. [See cumulative oil performance over time and potential economics of the company’s four northern Midland Basin Lower Spraberry wells at www.energen.com]

Further south in northern Midland County, in the heart of a vertical Spraberry field that dates back to the 1960s, the L.B. Epley NS 39-46 #501H showed the effects of that prior drilling. The well’s peak 24-hour IP rate was 652 (82% oil), and its peak 30-day average was 428 boepd (76% oil). Even though this Lower Spraberry Epley well is not as strong a performer as the company’s other northern Midland Basin Lower Spraberry wells, its cumulative oil production through 52 days is tracking close to a 770 MBOE EUR type curve. Energen estimates that its exposure in the Midland Basin to areas of Spraberry depletion associated with older vertical drilling is limited to a maximum of 5,000 net acres in this area and that the vast majority of its Spraberry potential is in areas with younger or fewer vertical wells.

A Wolfcamp B well drilled at the same location – the L.B. Epley NS 39-46 #201H – generated an excellent 24-hour IP rate of 1,053 (74% oil) and a peak 30-day average rate of 885 boepd (76% oil).

Energen plans to drill a total of 8 gross (8 net) Wolfcamp shale wells in its Midland Basin appraisal program in 2015. In addition to the two 2015 Wolfcamp wells for which results have been disclosed, three wells in Glasscock County with 10,000’ laterals currently are flowing back; a fourth well is awaiting completion, another is drilling, and the final well has not yet been spud.

Energen also plans to drill a total of 12 gross (12 net) Spraberry wells in its Midland Basin appraisal program in 2015; this reflects an additional 5 gross (5 net) wells now planned in the second half of 2015. In addition to three Lower Spraberry wells in the 2015 program for which results have been disclosed, one well currently is flowing back, four more wells are awaiting completion or are in various stages of completion, and the other four wells have not yet been spud. All 20 gross (20 net) wells in Energen’s 2015 Midland Basin appraisal program are expected to be completed by year-end 2015.

Delaware Basin (3-Stream Results)

Note: Totals may not foot due to rounding

In the Delaware Basin, the Helbing 56-5 #1H and 56-6 #1H and the Jaymac 56-7 #1H were drilled into the B-bench of the Wolfcamp shale in western Reeves County and generated strong peak 24-hour IP rates of 1,381 boepd (31% oil), 1,123 boepd (39% oil), and 1,167 boepd (33% oil), respectively. Their peak 30-day average rates were 1,163 boepd (33% oil), 753 boepd (29% oil), and 888 (34% oil), respectively.

In the central part of the Delaware Basin, the Piper State 54-14 #1H – an A-bench well – had an impressive peak 24-hour IP of 1,498 (56% oil) and a peak 30-day average of 973 boepd (55% oil). The Spectre State 54-4 #1H, a B-bench well, also was drilled in the central part of the basin and had a solid peak 24-hour IP of 885 boepd (63% oil) and a peak 30-day average of 733 boepd (63% oil). The Spectre State’s test rates were limited due to water-handling constraints.

On the Eastern side of the Delaware Basin in Ward County, the company drilled the University 24-17 #1H into the Wolfcamp B with a completed lateral length of approximately 7,000 feet. The results were very solid, with a peak 24-hour IP of 1,073 (74% oil) and peak 30-day average of 987 boepd (71% oil). These test rates were limited due to water-handling constraints. The company believes its successful execution of this longer lateral in the Delaware Basin can be applied elsewhere in the basin.

Energen’s 2015 appraisal drilling program in the Delaware Basin totals 8 gross (8 net) Wolfcamp shale wells. Results of 7 of these wells have been disclosed. The remaining well in the 2015 program is targeting the Wolfcamp A in Winkler County and currently is being completed.

San Juan Basin Mancos Appraisal Program

Energen currently is drilling its first Mancos oil formation appraisal well in the San Juan Basin in Rio Arriba County, NM. The company plans to drill 8 gross (8 net) wells in the second half of 2015 to test its 91,000 net acres for Mancos oil potential. The company also is participating as a 50 percent non-operated participant in 6 gross (3 net) wells drilled by WPX Energy. The peak 24-hour and peak 30-day average oil production rates only of these six wells averaged an attractive 923 barrels of oil per day and 479 barrels of oil per day, respectively.

Capital, Production, and Financial Guidance

Energen increased its 2015 capital budget slightly to $1.1 billion. Drilling plans for 2015 now include an additional 14 gross (11 net) Wolfcamp development wells, 3 gross (3 net) additional Spraberry development wells, and 5 gross (5 net) additional Spraberry appraisal wells in the program. In addition, the company plans to complete 6 gross (5 net) development wells previously scheduled for 2016 as well as the 5 new Spraberry appraisal wells. The revised budget also reflects a net addition of approximately $14 million for infrastructure in the Midland Basin needed to support 2016 drilling activity as well as approximately $10 million for additional unproved leasehold in the Midland Basin.

Energen’s revised budget is based on running four horizontal drilling rigs in its Midland Basin development program in the last six months of the year; one horizontal rig in the Midland Basin appraisal program through October; and one horizontal rig in the San Juan Basin Mancos appraisal program in the second half of 2015.

2015 Capital Summary

Note: “Facilities” capital includes artificial lift and central gathering facilities; “Other”

Capital includes payadds and refracs

Energen’s estimate of 2015 production (excluding volumes from the company’s San Juan Basin divestiture) has been revised upward by 500,000 BOE to reflect 2^nd quarter results and an additional 100,000 BOE of production in the 2^nd half of the year, primarily in the Midland Basin development program. Production would be higher still absent high natural gas pipeline pressures that have materialized as a result of increased Delaware Basin production industry-wide. As a result, Energen’s Reeves County production is expected to be negatively impacted by approximately 200,000 BOE in the 2^nd half of 2015.

Production for the year is now estimated to range from 22.2-23.2 MMBOE (60,820–63,560 boepd), with a midpoint of 22.7 MMBOE (62,215 boepd). This reflects an increase of approximately 19 percent from comparable, adjusted 2014 production volumes of 19.1 MMBOE.

The production midpoint in the 3rd quarter of 2015 is estimated to be 5.8 MMBOE (62,815 boepd). This is down slightly from the prior estimate of 5.9 MMBOE (64,239 boepd) largely due to the timing of completions in the Midland Basin and pipeline pressure issues in the Delaware Basin Wolfcamp, partially offset by a continuation of outstanding performance in the Delaware Basin Wolfcamp and 3^rd Bone Spring. The company has added two frac crews in the Midland Basin and plans to run three for most of the third quarter. As a result, production in the 4^th quarter is estimated to increase substantially to a midpoint of 6.2 MMBOE (67,978 boepd).

Production by Play (Excluding San Juan Basin Divestiture)

NOTE: Totals may not sum due to rounding

Production by Product (Excluding San Juan Basin Divestiture)

Production by Basin/Quarter (Excluding San Juan Divestiture)

NOTE: Totals may not sum due to rounding

Production by Commodity/Quarter (Excluding San Juan Basin Divestiture)

NOTE: Totals may not sum due to rounding

3Q15 AND CY15 FINANCIAL GUIDANCE

Energen’s estimated expenses, excluding San Juan Basin divestiture, are as follows:

* Excludes $0.07 per BOE in 3Q15 and $1.63 per BOE in CY15 for pension and pension settlement expenses.

3Q15 and 2H15 Hedges

For the remaining 6 months of 2015, approximately 78 percent of the company’s production guidance midpoint of 12.0 MMBOE is hedged. Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 1.1 million barrels of oil production at an average price of -$4.30 per barrel and the WTI Midland to WTI Cushing (sweet oil) differential for 3.8 million barrels at an average price of -$4.55 per barrel. Energen estimates that approximately 80 percent of its oil production for the remainder of the year will be sweet. Gas basis assumptions for all open contracts (August-December) are -$0.12 per Mcf (basis actuals in July were approximately -$0.10 per Mcf).

The company’s hedge position for the last six months of 2015 is:

Note: Known actuals included

In the table 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 oil transportation charges of $2.26 per barrel for the second half of 2015; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin for the remainder of the year.

Energen’s assumptions for the commodity prices of unhedged production for the remainder of 2015 are $49.60 per barrel of oil (July-December), $2.90 per Mcf of gas (August-December), and $0.43 per gallon of NGL (July-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (July-December) are +$0.42 and +$0.69, respectively.

Every 1-cent change in the average price of NGL from $0.43 per gallon is estimated to have a cash flows impact of $700,000.

Energen estimates that price realizations in the second half of 2015 (pre-hedge) will be approximately:

For the 3rd quarter of 2015, approximately 81 percent of the company’s production guidance midpoint of 5.8 MMBOE is hedged. Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 540,000 barrels of oil production at an average price of -$4.30 per barrel and the WTI Midland to WTI Cushing (sweet oil) differential for 1.9 million barrels at an average price of -$4.55 per barrel. Energen estimates that approximately 79 percent of its oil production in the 3rd quarter of 2015 will be sweet. Gas basis assumptions (August-September) are -$0.09 per Mcf (basis actuals in July were approximately -$0.10 per Mcf).

The company’s hedge position for the 3rd quarter of 2015 is:

Note: Known actuals included

In the table 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 oil transportation charges of $2.31 per barrel in the 3rd quarter of 2015; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin in the 3rd quarter of 2015.

Energen’s assumptions for the commodity prices of unhedged production in the 3rd quarter of 2015 are $49.60 per barrel of oil (July-September), $2.80 per Mcf of gas (August-September), and $0.43 per gallon of NGL (July-September). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (July-September) are +$0.46 and +$1.01, respectively.

Every 1-cent change in the average price of NGL from $0.43 per gallon is estimated to have a cash flows impact of $335,000.

Energen estimates that price realizations in the 3^rd quarter (pre-hedge) will be approximately:

Conference Call

Energen will hold its quarterly conference call Friday, August 7, 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. The company has 1.1 billion barrels of oil-equivalent proved, probable, and possible reserves and another 2.2 billion barrels of oil-equivalent 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.

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