Energen Adds 676 Net Lower Spraberry Locations to Drilling Inventory

For the 3 months ended March 31, 2015, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $15.4 million, or $(0.21) per diluted share. After adjusting for mark-to-market losses on derivatives, impairment losses, and income from the sale of the majority of the company’s San Juan Basin assets, Energen’s adjusted income in the 1st quarter of 2015 totaled $3.7 million, or $0.05 per diluted share. This compares with adjusted income from continuing operations in the 1st quarter of 2014 of $24.2 million, or $0.33 per diluted share. The variance between the periods largely is attributable to a 23 percent decline in realized oil and natural gas liquids (NGL) prices partially offset by a 14 percent increase in oil and NGL production. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Energen’s adjusted EBITDAX totaled $145.0 million in the 1st quarter of 2015 and compared with prior-year adjusted EBITDAX from continuing operations of $168.1 million. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

The company’s adjusted 1st quarter earnings per diluted share surpassed internal expectations by $4.4 million ($0.06 per diluted share) largely due to greater production partially offset by lower realized sales prices.

Production in the 1st quarter of 2015 (excluding production from the San Juan Basin divestiture) exceeded the guidance range midpoint by 6 percent (approximately 300,000 BOE) largely due to accelerated completions in the Delaware and Midland basins, less-than-expected negative impact from a 3rd party gas handling issue in the Delaware Basin, and better-than-expected well performance from Wolfcamp and 3rd Bone Spring wells in the Delaware Basin.

“It is great to have 2015 get off to such a good start,” said James McManus, chairman and chief executive officer of Energen Corporation. “As we disclosed a few weeks ago, we made significant progress during the 1st quarter in reducing the number of days to drill our wells, particularly in the Delaware Basin, and our costs to drill and complete all our wells have further declined due to reductions in drilling and completion service costs. We estimate that drilling efficiencies and additional service cost reductions are saving us approximately $100 million in 2015 relative to our original budget. We plan to use the majority of these savings to drill 16 more net wells in the Lower Spraberry and Wolfcamp shales in the 4th quarter. At this time, we do not plan to complete these wells until 2016.

“Not only do we plan to drill 9 more net lower Spraberry wells this year, these will be drilled in conjunction with 9 Wolfcamp A and B wells in Martin County, representing a new, 3-well, pad drilling development program. We are very excited by this prospect given the strength of our first Lower Spraberry well results in Martin County,” McManus added. “These wells are among the best Lower Spraberry wells drilled to date in Martin County. We also are pleased with the solid result from our first Glasscock County lower Spraberry well. We believe we can continue to perfect our landing and improve performance with additional testing and fully expect to move from our current 2-well, pad drilling development program in Glasscock County to a 3-well program in 2016 that incorporates the Lower Spraberry.

“Based on the strength of our Lower Spraberry results, we have identified 676 net, unrisked drilling locations in the play on our Midland Basin acreage position. These additions give us a Midland Basin drilling inventory of 2,803 net, unrisked drilling locations, a total Permian Basin drilling inventory of 5,701 net, unrisked drilling locations, and a company-wide drilling inventory of 6,266 net, unrisked drilling locations – all engineered locations. And we think there could be more to come, as the thick Wolfcamp B and C benches in Glasscock County may well offer the potential for two laterals per zone.

“These are very exciting times for Energen. We have a high-quality asset base that is driving double-digit, year-over-year production growth; we have an extensive drilling inventory that we are prepared to pursue more aggressively when commodity prices rebound; we have a solid hedge position; and we have a clean balance sheet. We also are improving our drilling efficiency and working hard to capture the lower service costs resulting from low oil prices in order to do more with the same dollars in 2015.”

1st Quarter Financial Review

After adjusting for mark-to-market losses on derivatives, impairment losses, and income from the sale of the majority of the company’s San Juan Basin assets, Energen’s adjusted income in the 1st quarter of 2015 totaled $3.7 million, or $0.05 per diluted share. This compares with adjusted income from continuing operations in the 1st quarter of 2014 of $24.2 million, or $0.33 per diluted share. The variance between the periods largely is attributable to a 23 percent decline in realized oil and NGL prices partially offset by a 14 percent increase in oil and NGL production.

1st Quarter Comparisons, 2015 vs 2014 (Excluding San Juan Basin Assets Sold March 31, 2015)

• The strength of Energen’s successful Wolfcamp development program led to a 51 percent increase in Midland Basin production and more than compensated for expected declines in the Delaware Basin and Central Basin Platform to result in total Permian Basin production growth of 13 percent.
• The company’s average realized oil price fell 22 percent, while the realized price of NGL dropped 61 percent. Excluding the impact of commodity and differential hedges, the average realized price of oil would have been $43.93 per barrel.
• LOE per unit declined 7 percent to $11.32 per barrel largely due to fewer workovers and repairs and lower costs for electricity and water hauling. Per-unit production taxes and ad valorem taxes declined 34 percent.
• Per-unit DD&A expense increased 3 percent to $25.63 per BOE largely due to year-over-year increases in development costs and production.
• Per-unit net G&A expense of $6.30 per BOE (excluding pension and pension settlement expenses) declined 16 percent from the same period a year ago largely due to increased production.
• Interest expense increased 49 percent to total $11.8 million largely due to a prior-year reclassification of certain interest expense to discontinued operations as well as increased interest and fees associated with the company’s credit facility.

In its 2-well, pad drilling development program in Glasscock County, Energen tested 22 gross (22 net) wells of 6,700’ and 7,500’ lateral lengths during the 1st quarter of 2015. These wells generated average peak 24-hour IP rates (3-stream) of 825 boepd (88% oil) and peak 30-day average rates (3-stream) of 607 boepd (75% oil).

The 49 gross (48 net) wells tested since the program’s inception in 2014 have generated average peak 24-hour IPs (3-stream) of 906 boepd (81% oil) and peak 30-day average rates (3-stream) of 723 boepd (75% oil). In aggregate, these wells continue to meet or exceed the company’s unrisked type curve that supports EURs of 770 MBOE for 6,700’ lateral lengths and 850 MBOE for 7,500’ lateral lengths.

When the development program is expanded to Martin County later this year, the company plans shift from its 2-well, pad-drilling program to a new 3-well program that incorporates the Lower Spraberry, the Wolfcamp A, and the Wolfcamp B. This development design is also expected to be utilized in Glasscock County in 2016.

All 20 gross (20 net) wells with 4,400’ lateral lengths in Energen’s down-spacing test in Glasscock County have now been drilled and are in various stages of completion and flowback.

Midland and Delaware Basin Appraisal Program Results

Energen tested 11 new appraisal wells in the Permian Basin during the 1st quarter of 2015, including its first three Lower Spraberry wells in the Midland Basin and two new eastern wells in the Delaware Basin. [See locator maps at www.energen.com]

The Campbell #501H and the Wilbanks SN 16-15 #501H, both Lower Spraberry wells in Martin County, generated excellent 3-stream results. The two wells generated 24-hour peak rates of 1,007 boepd and 946 boepd, respectively. In addition, the oil content of the two product streams was high, at 85% and 78%, respectively. The peak 30-day average rates were equally strong at 897 boepd (81% oil) and 831 boepd (78% oil). In Glasscock County, the Lower Spraberry well San Saba NS 37-48 #501H generated solid results and is expected to be an economic zone for future development; in addition, the company plans to continue perfecting its landing target and improving performance with future Lower Spraberry tests.

In the 1st quarter of 2015, Energen drilled 6 gross (6 net) wells in its 2015 Midland Basin appraisal program; 5 gross (5 net) wells – including 4 gross (4 net) wells in the 2014 program -- were completed, tested, and reported above; another 5 gross (5 net) wells drilled were completed and currently are flowing back; and 1 gross (1 net) well is waiting on completion. Among the wells currently flowing back are Lower Spraberry tests in Howard and Midland counties. All 15 gross (15 net) wells in Energen’s 2015 Midland Basin appraisal program are expected to be completed by year-end 2015.

In the Delaware Basin, two Winkler County wells generated solid results in testing the Wolfcamp A. The Tier 2 University 4-21 #1 and the Tier 1 University 35-20 #2H had strong 24-hour and 30-day average peak rates; oil comprised approximately 80 percent of the 3-stream product mix on both wells.

In the 1st quarter of 2015, Energen drilled 7 gross (7 net) wells in its 2015 Delaware Basin appraisal program; 5 gross (5 net) wells – including 4 gross (4 net) wells in the 2014 program – were completed, tested, and reported above; 5 gross (5 net) wells drilled were completed and currently are flowing back; 1 gross (1 net) well is waiting on completion; and 1 gross (1 net) well is drilling. All 8 gross (8 net) wells in Energen’s 2015 Delaware Basin appraisal program are expected to be completed by mid-year 2015.

San Juan Basin Mancos Appraisal Program

Energen plans to drill 8 gross (8 net) wells in the second half of 2015 to test its acreage position in the Mancos oil play in the San Juan Basin. The company also is participating as a 50 percent non-operated participant in 6 gross (3 net) wells drilled by WPX Energy. These non-operated wells have been drilled and are in various stages of completion and flowback.

676 Net Lower Spraberry Locations Added

On the strength of its first three Lower Spraberry wells and known results of other operators, Energen has updated its unrisked potential drilling inventory in the Midland Basin to include the addition of 676 net, engineered Lower Spraberry locations across approximately 67,700 net acres. Together with three benches of the Wolfcamp shale and the Cline shale, the Lower Spraberry additions increase the company’s total unrisked potential drilling inventory of engineered net locations to 2,803. [See Midland Basin location details at www.energen.com]

The company has previously identified a Delaware Basin Wolfcamp drilling inventory of 2,898 net locations in four Wolfcamp intervals and 565 potential locations in one target zone of the Mancos oil formation in the San Juan Basin. Energen’s company-wide drilling inventory now totals of 6,266 engineered, unrisked, net drilling locations.

Capital, Production, and Financial Guidance

Energen’s total capital spending remains essentially unchanged at $1.0 billion. The company estimates that it will realize approximately $100 million in savings (relative to the original capital budget) as a result of drilling efficiency gains and additional service cost reductions. These savings will be used primarily to drill 16 more net Lower Spraberry and Wolfcamp wells in the Midland Basin in the 4th quarter. At present, the company does not plan to complete these well until 2016. Also included in the revised capital budget is $5.5 million for the acquisition of unproved leasehold, primarily in the Delaware Basin.

Energen’s estimate of 2015 production (excluding volumes from the company’s San Juan Basin divestiture) has been revised to reflect 1st quarter results that were approximately 0.3 MMBOE higher than expected largely due to accelerated completions in the Delaware and Midland basins, less-than-expected negative impact from a 3rd party gas handling issue, and better-than-expected well performance from Wolfcamp and 3rd Bone Spring wells in the Delaware Basin.

Production for the year is now estimated to range from 21.7-22.7 MMBOE (59,452–62,192 boepd), with a midpoint of 22.2 MMBOE (60,729 boepd). This reflects an increase of approximately 16 percent from comparable, adjusted 2014 production volumes of 19.1 MMBOE. Production in the 2nd quarter of 2015 is estimated to range from 5.2-5.6 MMBOE (57,143-61,538 boepd), with a midpoint of 5.4 MMBOE (59,165 boepd).

2Q15 and ROY 2015 Hedges

For the remaining 9 months of 2015, approximately 55 percent of the company’s production guidance midpoint of 17.3 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 1.6 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 5.7 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 (May-December) are $0.22 per Mcf (basis actuals in April were approximately $0.22 per Mcf).

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 $2.41 per barrel for the remainder 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 $58.75 per barrel of oil (April-December), $2.70 per Mcf of gas (May-December), and $0.52 per gallon of NGL (April-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (April-December) are $0.73 and $0.32, respectively.

For unhedged production, every $1.00 change in the average NYMEX price of oil from $58.75 per barrel is estimated to have a $4.2 million impact on cash flows, and every 1-cent change in the average price of NGL from $0.52 per gallon is estimated to have a cash flows impact of $960,000.

For the 2nd quarter of 2015, approximately 57 percent of the company’s production guidance midpoint of 5.4 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 78 percent of its oil production in the 2nd quarter of 2015 will be sweet. Gas basis assumptions (May-June) are $0.21 per Mcf (basis actuals in April were $0.22 per Mcf).

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 $2.41 per barrel in the 2nd 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 2nd quarter of 2015.

Energen’s assumptions for the commodity prices of unhedged production in the 2nd quarter of 2015 are $55.50 per barrel of oil (April-June), $2.55 per Mcf of gas (May-June), and $0.52 per gallon of NGL (April-June). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil are $0.67 and $0.26, respectively.

For unhedged production, every $1.00 change in the average NYMEX price of oil from $55.50 per barrel is estimated to have a $1.1 million impact on cash flows, and every 1-cent change in the average price of NGL from $0.52 per gallon is estimated to have a cash flows impact of $300,000.

Conference Call

Energen will hold its quarterly conference call Thursday, May 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.

FORWARD LOOKING STATEMENT: 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 timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, 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. 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 filing. 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.

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