First Midland Basin Wells with Gen 3 Completions Show Substantial, Early Production Uplift

For the 3 months ended December 31, 2016, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $(54.5) million, or $(0.56) per diluted share. Excluding mark-to-market derivatives losses and a loss associated with prior-period property sales, Energen’s adjusted loss in 4Q16 totaled $(26.6) million, or $(0.27) per diluted share. This compares with adjusted income in 4Q15 of $28.4 million, or $0.36 per diluted share. [See “Non-GAAP Financial Measures” beginning on pp 12 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 12 for more information]

Note: Per share amounts may not sum due to rounding

Energen’s adjusted 4Q16 per-share loss approximated internal expectations despite a couple of unbudgeted, non-cash items that were largely offset by lower lease operating, marketing and transportation expenses (LOE), lower ad valorem and production taxes, and lower net salaries and general and administrative expenses (net SG&A). The unbudgeted items were a state deferred tax valuation allowance of $(3.6) million, or $(0.04) per diluted share and a depreciation, depletion and amortization (DD&A) look-back adjustment of $(2.6) million, or $(0.03) per diluted share.

Per-unit LOE was approximately 16 percent better-than-expected and benefited largely from lower expenses for workovers, non-operated activities, and water disposal; net SG&A expenses were lower by approximately 10 percent on a per-unit basis due to a variety of cost reductions, including professional services and non-cash compensation.

Production in 4Q16 totaled 53.5 thousand barrels of oil equivalents per day (mboepd) and exceeded the production guidance midpoint of 52.2 mboepd by 2.5 percent. Oil production was less than expected for a combination of reasons including lower Central Basin Platform oil production resulting, in part, from weather-related compressor downtime; the timing of non-operated production in the Delaware Basin; and the timing of pump failures in the northern Midland Basin.

Energen’s adjusted EBITDAX totaled $82.1 million in the 4th quarter of 2016 and exceeded internal expectations by approximately 10 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $201.2 million. [See “Non-GAAP Financial Measures” beginning on pp 12 for more information and reconciliation.]

Comments from the Chairman

“The year 2016 likely will be remembered by our industry as the year that the oil commodity price cycle bottomed out in the mid-$20s in February,” said James McManus, Energen’s chairman and chief executive officer. “I will remember it more for the determination and resiliency of our company. We were tested and challenged and came out stronger than ever.

“Today, with almost $400 million of cash and nothing drawn on our line of credit, our balance sheet is one of the very best among Permian drillers. We have gained a lot of efficiencies in our drilling and completion activities, and our per-unit operating costs continue to decline. As a result and in combination with high-quality rock, our outstanding assets in the Permian Basin generate excellent rates of return even at a $45 flat oil price.

“Beginning in 2017, we will move at an active pace to bring to production a sizeable inventory of uncompleted wells and, more importantly, resume a more typical drilling-and-completion cadence. At the same time, we will pursue improved well performance from more intensive frac designs and continue our work toward identifying the best spacing and completion designs needed for optimal well performance from multiple formations.

“Even as we anticipate attractive, 20 percent production growth in 2017, early results from stand-alone wells in the Midland and Delaware basins that were completed with our Generation 3 frac designs suggest the potential for even better growth in 2017 and beyond.”

2017 Capital and Operating Overview

Energen’s Board of Directors has approved a 2017 capital budget (excluding lease renewals and acquisitions) of $790 million. Approximately 84 percent of the capital is for drilling and completion activities, with approximately 14 percent for saltwater disposal wells and other facilities and 2 percent for non-operated and other activities.

The company’s capital budget supports completion of 124 gross/113 net wells, including 120 gross/110 net horizontal wells. All horizontal wells are scheduled to be completed with a Generation 3 frac design; this includes 61 gross/60 net wells drilled but not completed (DUC) at year-end 2016. In addition, 59 gross/50 net horizontal wells are scheduled to be drilled and completed in 2017 with the company’s 6- to 7-rig drilling program. Another 30 gross/27 net horizontal wells are set to be drilled and awaiting completion at year end. Energen also plans to drill 7 gross/6 net vertical wells in the Midland Basin and complete 4 gross/3 net of them. (Energen counts as completed those wells that have begun flow back).

Energen’s budget reflects a 15 percent increase in pressure pumping costs. Energen plans to use 6-7 frac crews through the first 9 months of 2017 and 2-5 in the 4th quarter.

Horizontal well targets include the Jo Mill, Middle Spraberry, Lower Spraberry and Wolfcamp A and B zones in the northern Midland Basin (Martin and Midland counties), Wolfcamp A and B in the central Midland Basin (Glasscock County) and Wolfcamp A and B in the core Delaware Basin (Reeves and Loving counties).

Taking into account Generation 3 frac designs and increased pressure pumping costs, the company’s estimated costs to drill, complete and equip 10,000’ lateral Wolfcamp A/B wells in the Delaware Basin and 10,000’ laterals in the Midland Basin in 2017 are approximately $7.9 million and $7.2 million, respectively.

Note: In addition to the above, Energen plans to drill 7 gross/6 net vertical wells in the Midland Basin and complete 4 gross/3 net of them.

Acquisitions/Unproved Leasehold

In the first quarter of 2017, Energen acquired 1,400 net acres, primarily in the Delaware Basin, for $32 million; the company also purchased 640 net mineral acres in the Delaware Basin for approximately $18 million. The company does not budget for acquisitions. As Energen continues to pursue bolt-on acreage in its Permian footprint, investment in acquisitions is expected to increase.

2017 Production

Annual estimated 2017 production of 65.7 mboepd reflects a 20 percent year-over-year increase based on older generation frac designs. All 2017 completions will use Generation 3 frac designs (affecting approximately 8.9 mmboe, or 24.4 mboepd); if production response to Generation 3 frac designs is positive ̶ as early results from stand-alone wells in the northern Midland Basin and Delaware Basin suggest ̶ production growth could be higher.

In the Delaware Basin, where Energen’s activity level is significantly higher than in prior years, production is expected to more than double to 21.1 mboepd. In the Midland Basin, where activity is focused on density pattern drilling and completions, 2017 growth from horizontal wells is estimated to be 11 percent. Production growth in 2017 from all horizontal plays in the Permian Basin is estimated to be 37 percent.

Oil is expected to comprise 65 percent of the company’s total production mix in 2017, with natural gas liquids (NGL) and natural gas production estimated to make up 17 percent and 18 percent, respectively.

† Excludes asset sales
NOTE: Totals may not sum due to rounding

† Excludes asset sales
NOTE: Totals may not sum due to rounding

2017 Expenses

Energen expects most of its per-unit expenses to generally decline in 2017 as production increases. Per unit lease operating expenses (including marketing and transportation) are expected to be essentially flat, however, largely due to increased water handling as activity levels increase significantly in the Delaware Basin and as additional zones are completed in the northern Midland Basin. Also in the Midland Basin, the company plans to expand its use of electric submersible pumps, thereby increasing its electric power costs.

† Excludes asset sales
1 Excludes $0.44 per boe for RIF settlement and pension and pension settlement expenses

LOE per boe in CY17 is estimated to range from $6.15-$6.45 in the Midland Basin, $5.90-$6.20 in the Delaware Basin, and $19.70-$20.00 in the Central Basin Platform. Production and ad valorem taxes in CY17, as a percent of revenues excluding hedges, are estimated to be 6.6 percent in the Midland Basin, 7.3 percent in the Central Basin Platform, and 6.2 percent in the Delaware Basin.

Net SG&A per boe in CY17 is estimated to be comprised of cash of $2.70-$2.90 per boe and non-cash, equity-based compensation of $0.80-$1.00 per boe.

Positive Response to First Generation 3 Completions in Midland Basin

Based on cumulative production through 90 days, Energen’s first two Midland Basin wells utilizing a Generation 3 frac design are responding very well. The average cumulative production of the two Wolfcamp B, stand-alone wells in Martin County is exceeding a 1 mmboe type curve for a 7,500- lateral by 30 percent.

The Tiger Unit SN 245-252 201H was drilled to a completed lateral length of 7,518’ and had a peak 24-hour IP rate of 1,791 boepd (91 percent oil) and a 30-day average peak rate of 1,439 (88 percent oil). The Tiger Unit SN 245-252 205H was drilled to a completed lateral length of 7,559’ and had a peak 24-hour IP rate of 1,436 boepd (88 percent oil) and a 30-day average peak rate of 1,167 (85 percent oil). These two wells were drilled on bolt-on acreage acquired in the second quarter of 2016.

Checkers Well Continues to Show Positive Response to Generation 3 Frac Design

Cumulative production from the Checkers St. 54-12-21 701H well in the Delaware Basin continues to outperform the 2.0 mmboe EUR type curve for a 10,000’ lateral length through 90 days. The Checkers St. well, disclosed last quarter, is producing from the Wolfcamp B interval in Reeves County and has a completed lateral length of 9,389’. Its previously disclosed peak 24-hour IP was 2,384 boepd (61% oil); its peak 30-day average rate was 2,072 boepd (58% oil).

The Checkers St. well was one of four wells drilled and completed in 2016 to hold core Delaware Basin acreage and is representative of the product mix the company expects to see across the bulk of its core acreage in Reeves, Loving, and western Ward counties.

YE16 Proved Reserves Total 316 MMBOE

Energen’s proved reserves at YE16 totaled 316.3 mmboe, down 11 percent from YE15 as reserve additions were more than offset by asset sales, lower commodity prices, and certain reserve reclassifications.

Horizontal drilling in the Midland and Delaware basins was the dominant driver of total proved reserve additions of 64.1 mmboe; these additions replaced 2016 production (excluding production from 2016 asset sales) by 320 percent. The company sold approximately 55 mmboe of proved reserves during 2016, primarily in the Delaware and San Juan basins. Negative revisions of 26 mmboe largely were due to lower SEC commodity prices and to reclassifying as “probable” certain wells that will no longer be developed in the five-year time horizon prescribed by the SEC (e.g., wells with short lateral lengths and others for which development has been delayed by a focus on other assets with higher returns).

Proved oil reserves represent approximately 63 percent of total proved reserves. Approximately 51 percent of Energen’s total proved reserves are proved developed.

Commodity prices used for calculating reserves at year-end 2016 were lower than those at year-end 2015. WTI oil prices declined 15 percent to $42.75 per barrel, while NGL prices (before transportation and fractionation) declined 5 percent to 39 cents per gallon and Henry Hub natural gas prices dropped 4 percent to $2.48 per thousand cubic feet (Mcf).

Proved Reserves by Basin (MMBOE)

NOTE: Totals may not sum due to rounding

Proved Reserves by Commodity (MMBOE)

NOTE: Totals may not sum due to rounding

YE16 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 p. 11].

Potential Drilling Inventory Totals 3,545 Net Horizontal Locations at YE16

Energen’s updated, unrisked potential drilling inventory of horizontal locations in the Wolfcamp, Cline, and Spraberry trends in the Permian Basin at year-end 2016 totaled 3,545. Of that amount, 2,594 net locations are in the Midland Basin, and 951 net locations are in the Delaware Basin. The company estimates that the associated net undeveloped resource potential is more than 2 billion BOE.

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.

4th Quarter 2016 Results

Production (excludes asset sales) (mboepd)

Note: Totals in production tables above may not sum due to rounding.

Average Realized Sales Prices (excludes asset sales)

Average Prices Before Effects of Hedges (excludes asset sales)

Expenses (excludes asset sales)

† Excludes $5.02 per BOE in 4Q15 for pension and pension settlement expenses.

2016 Capital Summary

1 Includes approximately $28 mm for facilities in the Midland Basin, $19 mm for facilities in the Delaware Basin and $6 mm for non-operated activities and miscellaneous items
* Includes 6 gross (6 net) vertical wells to hold acreage and 3 gross (2 net) horizontal wells to hold new leasehold, 1 gross (1 net) well to complete a pad, 2 gross (2 net) wells to hold acreage, and 40 gross (39 net) new DUC drills in 2H16
** Includes 4 gross (4 net) horizontal wells to hold acreage and 17 gross and net new DUC drills in 2H16
† Includes 6 gross (6 net) vertical wells, 3 gross (2 net) horizontal wells to hold new leasehold, 47 gross(47 net) development program completions in 1H16

In addition to drilling and development, Energen acquired approximately 9,000 net acres in its focus areas in the Delaware and Midland basins in 2016 for approximately $120 million; this includes approximately 1,100 net acres acquired in 4Q16. During 2016, Energen also invested approximately $11 million to acquire mineral acreage and approximately $17 million for lease renewals and miscellaneous items.

Liquidity Update

As of December 31, 2016, Energen had cash of $386.1 million and debt of $551.4 million; the company had nothing drawn on its $1.05 billion line of credit. Energen’s total net debt-to-2016 adjusted EBITDAX was 0.6x.

CY17 Quarterly Guidance

Production

Operating Expenses

* Production costs, marketing & transportation
** % of revenues, excluding hedges
† Does not include estimate of 4Q17 DD&A look-back adjustment

Hedge Position for 2017

Energen has increased its 2017 hedge positions for oil, NGL, and natural gas and has initiated hedging for 2018. Hedges are in place for 70 percent of the company’s 2017 estimated oil production, 47 percent of its estimated NGL production, and 60 percent of its natural gas production. Energen also has hedged the Midland to Cushing differential on 9.1 million barrels (approximately 69 percent) of its sweet oil production in 2017 at an average price of $(0.63).

Energen’s total oil hedge position for 2017 is as follows:

1 When the NYMEX price is above the call price, Energen receives the call price; when the NYMEX price is between the call price and the put price, Energen receives the NYMEX price; when the NYMEX price is between the put price and the short put price, Energen receives the put price; and when the NYMEX price is below the short put price, Energen receives the NYMEX price plus the difference between the put price and the short put price.

Energen’s total natural gas and NGL hedge positions for 2017 are as follows:

1Q17 Hedge Position

In the first quarter of 2017, hedges are in place for 79 percent of the company’s estimated oil production, 51 percent of its estimated NGL production, and 63 percent of its natural gas production. Energen also has hedged the Midland to Cushing differential on 1.5 million barrels (approximately 70 percent) of its estimated 1Q17 sweet oil production at an average price of (0.58).

Energen’s total oil hedge position for 1Q17 is as follows:

Energen’s total natural gas and NGL hedge positions for 1Q17 as follows:

Basis Differentials and Sensitivities

The company’s average realized prices will reflect commodity and basis hedges; oil transportation charges of approximately $2.13 per barrel in CY17 ($2.29 per barrel in 1Q17), NGL transportation and fractionation fees of approximately $0.12 per gallon in CY17 ($0.13 per gallon in 1Q17), and gas and oil basis differentials applicable to unhedged production. In addition, natural gas and NGL production is subject to a percent of proceeds contract of approximately 85%.

The assumed gas basis for all open contracts in 2017 is $(0.34) per Mcf, and assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil are $(0.88) and $(1.44), respectively. Energen’s assumed commodity prices for unhedged production for 2017 are: $55.00 per barrel of oil, $0.64 per gallon of NGL, and $3.19 per Mcf of gas (February-December).

Estimated Price Realizations (pre-hedge):

2018 Hedging Initiated

In recent weeks, Energen has begun layering in oil and NGL hedges for 2018. Hedges currently are in place for 5.6 mmbo of 2018 oil production and 30.2 mm gallons of 2018 NGL production at an average price of $0.60 per gallon.

Energen’s total oil hedge position for 2018 is as follows:

Supplemental Slides and Conference Call

4Q16 supplemental slides associated with Energen’s quarterly release and conference call are available at www.energen.com. Energen will hold its quarterly conference call Friday, February 10, at 11:00 a.m. EDT. Investment community members 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 via www.energen.com.

Energen Corporation is an oil-focused exploration and production company with operations in the Permian Basin in west Texas and New Mexico. For more information, go to 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. 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.