Exhibit 99.1

For Release: 5:00 p.m. EDT		Contacts:  Julie S. Ryland
Tuesday, February 11, 2014		205.326.8421

SIX NEW WOLFCAMP WELLS GENERATE EXCELLENT RATES

2014 PRODUCTION, CAPITAL GUIDANCE ANNOUNCED

ENERGEN REPORTS 4TH QUARTER 2013 OPERATING, FINANCIAL RESULTS

3P RESERVES AND CONTINGENT RESOURCES INCREASE 96%

Highlights

BIRMINGHAM, Alabama – Energen Corporation (NYSE: EGN) has tested six new Wolfcamp wells in the Permian Basin, including two “B” bench wells in western Reeves County and two “B” bench well with 7,000-foot drilled lateral lengths in southern Glasscock County. All produced at very attractive initial rates. [See locator maps at www.energen.com].

The Winchester 57-10 #1H in western Reeves County produced at a peak 24-hour rate (3-stream) of 2,387 boepd, which is the highest initial production (IP) rate for a southern Delaware Wolfcamp well known to have been publicly disclosed to date. Were it not for its shorter completed lateral length, the Tisdale 56-8 #1H – also in western Reeves County – likely would have been comparable to the Winchester.

In the Midland Basin, the company’s first “B’ bench wells and first wells with 7,000-foot lateral lengths, the San Saba NS 37-48 #205H and #204H, tested without artificial lift at peak 24-hour rates (3-stream) of 1,387 boepd and 1,205 boepd, respectively. Oil comprised 79- 80 percent of the product mix in both wells.

“We continue to be very pleased with the Wolfcamp results we are achieving in the “A” and “B” benches in both the Midland and Delaware basins,” said James McManus, Energen’s chairman and chief executive officer. “We have six horizontal rigs currently drilling in the Midland Basin, as we significantly ramp up our activity level there. During 2014 we plan to drill and operate 57 gross Wolfcamp wells and 2 gross Cline wells.

“Our horizontal development plan in the Midland Basin is designed to maximize drilling and completion efficiencies; optimize spacing, work flow, and rig utilization; maximize stimulated reservoir volume for enhanced fracture complexity; and minimize stimulation impacts.”

“In the Delaware Basin, we are concentrating on drilling to hold leases, to further delineate our extensive acreage position there, and to drive down well costs. We plan to have two rigs working the Wolfcamp play in the Delaware Basin throughout 2014 and expect to drill and operate 12 gross Wolfcamp wells there,” he said.

“All-in-all, we expect our drilling and development capital spending in 2014 to approximate $1.05 billion, or about $225 million more than our estimated E&P after-tax cash flows,” McManus added. “In this transition year, we expect production to be relatively flat during the first half of 2014 before picking up steam as our Wolfcamp production accelerates in the second half of the year. Our 2014 exit rate (December average at midpoint) could well be approximately 73 mboe per day, up from some 64 mboe per day at mid-year (June average at midpoint).

“I am really looking forward to 2014 as a year of significant progress for Energen,” McManus said. “I believe the results of our aggressive drilling program in the Midland Basin in 2014 will provide a springboard for even greater acceleration in 2015 and beyond as we pursue 2,475 potential net Wolfcamp and Cline locations on our 81,500 net acres in the Midland Basin and Eastern Shelf.

“And another year of delineation in the Delaware Basin could well lead in 2015 to the start of development of the more than 3,100 potential net Wolfcamp locations we have identified on our 106,000 net acres in Ward, Winkler, Loving and Reeves counties.”

2013 Earnings Summary

For the 12 months ended December 31, 2013, Energen reported consolidated net income of $204.6 million, or $2.82 per diluted share. After adjusting for non-cash and/or non-recurring items and for discontinued operations, Energen’s adjusted income from continuing operations in 2013 totaled $216.9 million, or $2.99 per diluted share. In 2012, the comparable adjusted income from continuing operations totaled $218.0 million, or $3.01 per diluted share.

Non-cash and/or non-recurring items in 2013 included non-cash mark-to-market revenue losses, a gain on the sale of the company’s Black Warrior Basin assets partially offset by the non-cash impairment of properties held for sale in North Louisiana/East Texas, a gain on the sale of the company’s Birmingham utility service center, and income from discontinued operations.

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

[See “Non-GAAP Financial Measures” beginning on pp. 18 for more information]

Note: Per share amounts may not sum due to rounding

In comparing the two years: The impact of a 10 percent increase in 2013 production from continuing operations, including a 20 percent increase in oil and natural gas liquids (NGL), and higher realized oil and natural gas prices were essentially offset by higher depreciation, depletion and amortization (DD&A) expense, greater lease operating expense (LOE) and production taxes, increased net administrative expenses, and increased exploration expense primarily associated with write-offs of miscellaneous parcels of leasehold expiring in first half of 2014.

Relative to the company’s calendar year guidance issued on October 30, 2013, adjusted income from continuing operations fell below the midpoint largely due to the negative impact on production and expenses of two Permian Basin ice storms ($0.10) and a write-off of approximately 5,000 miscellaneous acres of unproved leasehold ($0.06). In addition, lower net general and administrative expense, a change in the effective tax rate, and higher commodity prices were offset by a slight decrease in expected production and greater-than-anticipated LOE.

Production by Commodity (MBOE)

Energen’s adjusted EBITDAX from continuing operations (excluding non-cash and/or non-recurring items) totaled $937 million in 2013 and compared with $818 million in 2012. Energen Resources, the company’s oil and gas exploration and production subsidiary, had adjusted EBITDAX from continuing operations (excluding mark-to-market) of $797 million in 2013 and $681 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 18 for more information and reconciliation.]

4^th Quarter 2013 Earnings Summary

For the 3 months ended December 31, 2013, Energen reported consolidated net income of $84.1 million, or $1.15 per diluted share. After adjusting for non-cash and/or non-recurring items and for discontinued operations, Energen’s adjusted income from continuing operations in the fourth quarter of 2013 totaled $56.4 million, or $0.77 per diluted share. In the fourth quarter of 2012, the comparable adjusted income from continuing operations totaled $44.9 million, or $0.62 per diluted share.

Non-cash and/or non-recurring items in the fourth quarter of 2013 included non-cash mark-to-market revenue gains, a gain on the sale of the company’s Black Warrior Basin assets partially offset by the non-cash impairment of properties held for sale in North Louisiana/East Texas, a gain on the sale of the company’s Birmingham utility service center, and income from discontinued operations.

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

[See “Non-GAAP Financial Measures” beginning on pp. 18 for more information]

Note: Per share amounts may not sum due to rounding

In comparing the two periods: The impact of a 9 percent increase in fourth quarter 2013 production from continuing operations, including an 18 percent increase in oil and natural gas liquids, and higher realized oil, NGL, and natural gas prices were partially offset by modest increases in DD&A expense, LOE and production taxes, net general and administrative expense, and exploration expense primarily associated with write-offs of miscellaneous parcels of expiring leasehold.

Production by Commodity (MBOE)

Energen’s adjusted EBITDAX from continuing operations (excluding non-cash and/or non-recurring items) totaled $249 million in the fourth quarter of 2013 and compared with $204 million in the same period last year.

Energen Resources had adjusted EBITDAX from continuing operations (excluding mark-to-market) of $213 in the fourth quarter of 2013 and $170 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 18 for more information and reconciliation.]

Wolfcamp Shale Exploration Results

(Locator map available at www.energen.com)

MIDLAND BASIN WOLFCAMP EXPLORATORY WELLS – GLASSCOCK COUNTY

* Represents distance from surface to toe

Energen’s first two Wolfcamp “B” wells in southern Glasscock County and its first two wells drilled to a 7,000-foot lateral length have generated excellent results. The San Saba NS 37-48 #205H and #204H tested at attractive peak 24-hour IP rates of 1,387 boepd (80% oil, 10% NGL, and 10% gas) and 1,205 boepd (79% oil, 11% NGL, and 10% gas), respectively. The #205H has the highest peak 24-hour IP drilled by the company in the Midland Basin to-date. The Guadalupe 48 #101H is an “A” bench well with a 5,300-foot drilled lateral length. Its peak 24-hour IP was a solid 1,000 boepd (74% oil, 14% NGL, and 12% gas).

Management said it does not have 30-day rates for these wells yet because the company is fracture-stimulating neighboring wells before these are brought on production; however, management said it is comfortable disclosing just the peak 24-hour IP given the consistency of results being generating by its southern Glasscock County wells.

The last two wells in Energen’s 2013 exploratory drilling program in the Midland Basin are flowing back or awaiting completion.

The company’s 2014 exploratory drilling program in the Midland Basin consists of 17 gross (16 net) Wolfcamp wells and 2 gross (2 net) Cline wells. The first three wells in the 2014 exploratory program currently are awaiting completion or drilling, including the company’s first well in Martin County and its first Cline test well.

Another 40 gross (39 net) Wolfcamp development wells are scheduled to be drilled in 2014 in southern Glasscock County. Our 2014 Wolfcamp development program is focused on drilling stacked laterals in the “A” and “B” benches with lateral lengths of 6,700 feet and 7,500 feet. The company estimates that unrisked ultimate recoveries (EURs) from these development wells will range from 550-750 MBOE for a 6,700-foot lateral and 650-850 MBOE for a 7,500-foot lateral.

DELAWARE BASIN

* Represents distance from surface to toe

Energen’s first two Wolfcamp “B” wells in the Delaware Basin were drilled in far west Reeves County approximately 10 miles apart. Both have generated excellent results. The Winchester 57-10 #1H tested at an outstanding peak 24-hour IP rate of 2,387 boepd (41% oil, 27% NGL, and 32% gas). This not only is the highest rate among Energen’s Wolfcamp wells, the Winchester has the highest known 24-hour peak IP of any southern Delaware Basin Wolfcamp well reported to date. The peak 30-day average rate was 2,186 boepd (38% oil, 28% NGL, and 33% gas).

The Tisdale 56-8 #1H, despite a shorter, completed lateral length, tested at a peak 24-hour IP rate of 2,081 boepd; this 3-stream rate was 32% oil, 33% NGL, and 36% gas. The peak 30-day average rate (3-stream) was 1,804 boepd (30% oil, 34% NGL, 37% gas).

Also in Reeves County, located near the previously disclosed Bodacious C7-19 #1H, Energen drilled the Red Rock 6-6 #1H in the “A” bench of the Wolfcamp shale. The Red Rock was a solid well that tested at a peak 24-hour IP rate of 1,471 boepd. The 3-stream rate was 65% oil, 18% NGL, and 17% gas. The peak 30-day average rate (3-stream) was 1,137 boepd (64% oil, 18% NGL, and 17% gas).

The last two wells in Energen’s 2013 exploratory program are “A” bench wells in Reeves County that are drilling or awaiting completion. The company’s 2014 exploratory drilling program in the Delaware Basin consists of 12 gross (10 net) Wolfcamp wells. The first two wells in the 2014 exploratory program currently are drilling.

2014 Capital and Production Guidance

Energen estimates that it will invest approximately $1.1 billion in 2014, including $1.05 billion for oil and gas drilling and development and $75 million for utility system maintenance, information technology, and construction of new service centers in Birmingham.

In accelerating the drilling of its horizontal Wolfcamp and Cline potential in the Midland Basin, Energen is committing 45 percent of its planned capital spending of $1.05 billion to drill 55 net Wolfcamp shale wells and 2 net Cline shale wells in 2014. The average drill-and-complete cost of a Wolfcamp well in 2014 is estimated to be $8.5 MM; 24 net Wolfcamp wells have a planned drilled lateral length of 6,700 feet, while the other 31 are to be drilled to 7,500 feet. The drill-and-complete cost of the two, planned Cline wells with 7,200-foot drilled lateral lengths is estimated to average $9 million.

Elsewhere in the Midland Basin, the company is scaling back its vertical Wolfberry program in 2014 as it focuses on the higher-return horizontal program. Two vertical drilling rigs are expected to drill an estimated 49 net wells, which is sufficient to meet Energen’s continuous drilling obligations in the Wolfberry play.

With significant Wolfcamp potential in the Delaware Basin, as well, the company will be running two rigs and investing approximately $108 million to drill 10 net wells that will further delineate its 106,000 net acres and secure expiring leases. Still in the exploratory phase, these wells are expected to cost approximately $10 million to drill, complete, and install surface facilities.

Elsewhere in the Delaware Basin, Energen plans to drill 22 net 3^rd Bone Spring wells in the southern Delaware Basin and two net 2nd Bone Spring wells in the northern Delaware Basin in New Mexico for approximately $173 million. Energen’s 3^rd Bone Spring program has been one of the two major drivers of the company’s oil and NGL production growth over the last three years. With only 5 net locations remaining to be drilled after this year, the company anticipates concluding its 3^rd Bone Spring drilling program in early 2015.

Energen’s legacy Permian Basin assets are in the Central Basin Platform, where the company plans to invest $17 million to drill 13 net producers and 8 net injector wells in 2014. And in the San Juan Basin, which is home to approximately 65 percent of the company’s proved natural gas reserves, Energen will be investing only $15 million in 2014; of that amount, 40 percent reflects the company’s 50 percent working interest in two non-operated Niobrara oil shale wells to be drilled by WPX Energy.

2014e Drilling and Development Capital and Production Summary

Note: “Facilities” capital includes salt water disposal wells, artificial lift, and central gathering facilities; “Other” capital includes payadds, refracs, and non-operated activities.

* Includes 10 gross (8 net) injectors

Production from continuing operations in 2014 is estimated to range from 24.4 MMBOE to 25.4 MMBOE, with a midpoint of 24.9 MMBOE. At the midpoint, this reflects a 16 percent increase (YOY) in total Permian Basin production while production in the San Juan Basin, the company’s primary natural gas-producing region, is expected to see production decline 8 percent in 2014.

In the Midland Basin, where the company is transitioning from its vertical Wolfberry focus to a focus on the Wolfcamp and Cline shales, production is estimated to increase 45 percent (YOY). In the Delaware Basin, where growth from the maturing 3^rd Bone Spring program is slowing in 2014, production is estimated to increase approximately 15 percent. Production from Energen’s legacy oil assets in the Central Basin Platform is expected to decline some 16 percent.

Production from Continuing Operations by Area (MMBOE)

Oil and NGL production is estimated to grow 12 percent in 2014, while natural gas production is expected to remain essentially flat as a result of associated gas in the Permian Basin offsetting natural gas declines in the San Juan Basin.

Production from Continuing Operations by Product (MMBOE)

Production from Continuing Operations by Basin and Product (MMBOE)

NOTE: 2014e production reflects the midpoint of guidance

Production is expected to remain relatively flat through the first six months of 2014, then accelerate in the second half as a result of the company’s Wolfcamp drilling in the Midland Basin.

2014e Production from Continuing Operations by Basin per Quarter (MMBOE)

NOTE: 2014e production reflects the midpoint of guidance

Energen’s 2014 guidance range for consolidated after-tax cash flows is an estimated $907 million to $937 million. Energen Resources’ after-tax cash flows are estimated to be $812 million to $842 million, and Alagasco is expected to generate after-tax cash flows of approximately $95 million. [See “Non-GAAP Financial Measures” beginning on pp 18 for more information and reconciliation.]

Consolidated earnings from continuing operations in 2014 are estimated to range from $200 million to $230 million, or $2.74-$3.14 per diluted share, with Alagasco’s utility operations contributing approximately 20 percent.

Energen Resources’ estimated exploration and production expenses from continuing operations per barrels of oil equivalents (BOE) in calendar year 2014 are:

Approximately 74 percent of the company’s total estimated midpoint of 2014 production from continuing operations is hedged. Assumed prices applicable to Energen Resources’ unhedged volumes for the remainder of the year are $90.00 per barrel of oil, $0.89 per gallon of NGL, and $4.00 per Mcf of natural gas.

Energen’s 2014 guidance also includes assumed prices for various basis differentials. These assumptions for oil are $2.58 per barrel (WTS Midland to WTI Cushing, “sour oil”) and $1.75 per barrel (WTI Midland to WTI Cushing). Energen estimates that approximately 70 percent of its oil production in 2014 is sweet. Gas basis assumptions are $0.19 per Mcf in both the San Juan and Permian basins.

The company’s current hedge position for 2014 is as follows:

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 Resources’ assumed San Juan and Permian basis differentials.

Average realized oil and gas prices for Energen Resources’ 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 oil transportation charges of approximately $2.60 per barrel in 2014; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.09 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin. The company also has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price.

As a result of Energen’s 2014 hedge position for oil and gas, changes in commodity prices will have a significantly lessened impact on Energen’s 2014 cash flows. Every $1.00 change in the average NYMEX price of oil from $90 per barrel represents an estimated net impact of $670,000, and every 10-cent change in the average NYMEX price of gas from $4.00 represents an immaterial impact. Because NGL production is unhedged, the net income impact of every 1-cent change in the average price of NGL from $0.89 per gallon is estimated to be approximately $840,000. Price-related events such as substantial basis differential changes could cause these sensitivities to be different from those outlined.

CY2013 Earnings Detail

Excluding non-cash and/or non-recurring items, Energen Resources’ adjusted income from continuing operations totaled $166.0 million in 2013 and $168.5 million in 2012.

Production from Continuing Operations by Area (MBOE)

Average Realized Sales Prices from Continuing Operations

Per-unit LOE from continuing operations in 2013 increased approximately 15 percent YOY to $15.10 per BOE. Base LOE and marketing and transportation expenses increased approximately 15 percent to $12.20 per BOE largely due to increased workovers and repairs, equipment rental, gathering costs, and environmental compliance. Commodity price-driven production taxes increased approximately 15 percent on a per-unit basis to $2.90 per BOE.

Per-unit DD&A expense from continuing operations in 2013 totaled $19.32 per BOE, increasing approximately 21 percent from the same period last year largely due to year-over-year increases in development costs and production and to the impact of reduced year-end 2012 natural gas reserves resulting from lower commodity prices.

Per-unit net G&A expense in the 2013 year-to-date period increased approximately 35 percent from the same period last year to $4.61 per BOE. This largely was due to increased stock-based compensation.

Alagasco generated 2013 net income of $57.4 million, including an after-tax gain of $6.8 million on the sale of its Birmingham service center. Utility net income in 2012 totaled $49.4 million in 2012.

Fourth Quarter Earnings Detail

Excluding non-cash and/or non-recurring items, Energen Resources’ adjusted income from continuing operations totaled $43.5 million in the fourth quarter of 2013 and $32.6 million in the same period a year ago.

Production from Continuing Operations by Area (MBOE)

Average Realized Sales Prices from Continuing Operations

Per-unit LOE from continuing operations in the fourth quarter of 2013 increased approximately 6 percent from the same period a year ago to $15.18 per BOE. Base LOE and marketing and transportation expenses increased approximately 3 percent to $12.21 per BOE largely due to increased workovers and repairs, labor,

non-operated activities, environmental compliance, and increased ad valorem taxes partially offset by decreased water disposal costs and equipment rental. Commodity price-driven production taxes increased approximately 19 percent on a per-unit basis to $2.97 per BOE.

Per-unit DD&A expense from continuing operations in the 4th quarter of 2013 totaled $19.96 per BOE, increasing approximately 14 percent from the same period last year largely due to year-over-year increases in development costs and production.

Per-unit net G&A expense increased approximately 50 percent in the fourth quarter of 2013 to $4.28 per BOE primarily due to increased stock-based compensation.

Alagasco’s net income in the fourth quarter of 2013 totaled $19.8 million, including an after-tax gain of $6.8 million on the sale of its Birmingham service center. Net income totaled $12.2 million in the same period a year ago.

Contingent Resources Increase 172%

The strength of Energen’s extensive inventory of unrisked Wolfcamp and Cline drilling locations is reflected in the 172 percent increase in the company’s year-end 2013 contingent resources.

Contingent resources are defined by the Petroleum Resource Management System as “those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.”

After consultation with its third party reserve engineers, Energen determined that much of its Wolfcamp and Cline potential in the Midland and Delaware basins does not have sufficient well control data to support a 3P reserve classification. The driver of that conclusion was the limited number of wells drilled and completed in the two basins. As Energen’s continuing exploration and development drilling increases the body of geologic and engineering data for these plays, the company expects its contingent resources to begin moving into 3P reserve categories.

Energen’s proved reserves at year-end 2013 totaled a record 348 MMBOE and were essentially unchanged from the prior year as record production and divestures essentially offset the addition of previously classified unproved reserves and contingent resources and upward price-related revisions.

Oil and NGL reserves at year end represented more than 65 percent of total proved reserves and are expected to increase as Energen continues to focus on the exploration and development of the liquids-rich Permian Basin.

Commodity prices used for calculating reserves at year-end 2013 were $96.94 per barrel of oil (up from $94.71 in 2012), $3.67 per thousand cubic feet (Mcf) for natural gas (up from $2.76 in 2012); and an average of $0.76 per gallon of NGL before transportation and fractionation (down from $0.88 per gallon in 2012).

Proved Reserves by Basin (MMBOE)

Proved Reserves by Commodity (MMBOE)

YE2013 3P Reserves & Contingent Resources (MMBOE)

Contingent Resources, 2013 vs 2012 (MMBOE)

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 best estimate of current costs to drill wells in each basin/area and bring associated production to market.

CONFERENCE CALL

Energen will hold its quarterly conference call Wednesday, February 12, at 11:00 a.m. EDT. Members of the investment community may participate by calling 1-866-939-3921. 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. Through Energen Resources Corporation, the company has approximately 775 million barrels of oil-equivalent proved, probable, and possible reserves and another 2.5 billion barrels of 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.