Energen : Estimates Annual Production to Grow 20% a Year, 2017-2019

For the 3 months ended September 30, 2016, Energen Corporation (NYSE: EGN) reported GAAP net income from all operations of $53.3 million, or $0.55 per diluted share. Excluding mark-to-market derivatives losses, income from the sale of properties, and pension expenses, Energen’s adjusted loss in 3Q16 totaled $(21.4) million, or $(0.22) per diluted share. This compares with adjusted income in 3Q15 of $32.4 million, or $0.41 per diluted share. [See “Non-GAAP Financial Measures” beginning on pp 9 for more information and reconciliation.]

Energen’s adjusted 3Q16 per-share loss was 24 percent better than internal expectations largely due to lower-than-expected operating expenses and better-than-expected production. Per-unit lease operating expense (LOE) was 10 percent better-than-expected and benefited largely from lower workover expense and lower water disposal and other costs; net salaries and general and administrative expense (SG&A) also was 10 percent better-than-expected per-unit due to a wide variety of cost reductions partially offset by higher non-cash compensation. Exploration expense was below budget primarily due to the timing of geological and geophysical costs.

Production in 3Q16 totaled 56.6 thousand barrels of oil equivalents per day (mboepd) and exceeded the production guidance midpoint of 55.4 mboepd by 2.0 percent; production in the Midland and Delaware basins exceeded budget by 3 percent, while Central Basin Platform production fell short of expectations by 3 percent. Actual and guidance production numbers exclude all 2016 property sales.

Energen’s adjusted EBITDAX totaled $84.8 million in the 3rd quarter of 2016 and exceeded internal expectations by 11 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $196.4 million. [See “Non-GAAP Financial Measures” beginning on pp 9 for more information and reconciliation.]

2016 Capital Plan

Drilling is under way in the Midland and Delaware basins on some 56-59 net wells with long lateral lengths and high working interests that currently are scheduled to be completed in 1H17 using Generation 3 frac designs. In the Midland Basin, the new drills also will test varying spacing concepts as the company works to identify the optimal number of wells that can be drilled and completed in a density-pattern development program.

The pace of drilling in the Midland Basin is ahead of schedule, and the company may opt to accelerate its completion schedule there by moving ahead with 8 completions before year-end 2016. Energen estimates that capital investment associated with drilling and development activity in 2016 could range from $440-$485 million depending on the number of new drills and completions.

The majority of new drills in 2H16 in the Midland Basin are 10,000-plus foot lateral-length wells in Martin County targeting the Jo Mill, Middle Spraberry, Lower Spraberry and Wolfcamp A and B zones. The average working interest of the new drills is estimated to exceed 98 percent.

In the core central Delaware Basin, new drills focus on the Wolfcamp A and B in Reeves and Loving counties and have an average lateral length greater than 9,500’. Energen’s working interest in the new drills in the Delaware Basin is approximately 100 percent. At year-end 2016, the company estimates that it will have 33-41 gross and net horizontal DUCs in the Midland Basin and 19-20 gross and net horizontal DUCs in the Delaware Basin.

In addition to drilling and development, Energen continues to acquire leasehold in the Delaware and Midland basins. Through October 2016, Energen has invested approximately $115 million to add some 7,900 net acres in its focus areas in the Delaware and Midland basins at an average cost of less than $14,600 per acre. Approximately $20 million has been invested for lease renewals, mineral interests, and miscellaneous related items.

2017 Guidance

Energen estimates that it will invest $700-$800 million in 2017 to complete its YE2016 DUC inventory, run 5-7 horizontal rigs in the Midland and Delaware basins, and generate 20 percent, year-over-year production growth. The capital estimate assumes recent strip prices, the company’s updated hedge position (see pp 7), and additional capital for Generation 3 fracs. Estimated production could be higher, as it currently does not assume production uplift from Generation 3 fracs. The company also estimates that 2017 production will grow sequentially from the first quarter through the fourth quarter, with the 4Q17 exit rate up more than 40 percent from 4Q16.

3-Year Outlook

Looking further into the future, Energen management believes the quality of its deep inventory in the Midland and Delaware basins supports a compound annual production growth rate of more than 20 percent. This growth comes as Energen further de-levers its outstanding balance sheet at the same time it increases capital investment to bring forward the value of its inventory.

Energen expects production to approach 100 mboepd by year-end 2019, almost doubling its current 2016 estimated production midpoint of 54.3 mboepd. Production growth estimates do not assume production uplift from Generation 3 fracs.

At recent strip prices, Energen estimates that its capital plans for 2017-2019 support increasing annual capital investment up to a range of $900 million to $1 billion in 2019; the company further estimates that it will be near cash-flow neutral at recent strip prices beginning in 2018. Energen’s EBITDAX at year-end 2019 is estimated to be close to $1 billion, representing a 3-year CAGR in excess of 50 percent a year. (Oil prices used in 3-year outlook reflect recent strip of $52.75 per barrel in 2017, $54.50 in 2018, and $55.25 in 2019).

Early Positive Response to Generation 3 Completions in Delaware Basin

Energen’s first Wolfcamp A and Wolfcamp B wells in the Delaware Basin to use Generation 3 fracs are performing extremely well in early days. Through the first 30 days and 20 days of cumulative production, respectively, each well is tracking more than 30 percent above the 2.0 mmboe EUR type curve for a 10,000’ lateral length well.

Energen drilled and completed four wells in 2016 to hold core Delaware Basin acreage. The Checkers St. 54-12-21 701H, targeting the Wolfcamp B interval, was drilled in Reeves County to a completed lateral length of 9,389’. Its peak 24-hour IP was 2,384 boepd (3-stream), with oil comprising 61 percent of the product mix. Its peak 30-day average rate was 2,072 boepd (3-stream), with oil comprising 58 percent of the product mix.

The Razorback NW 33-77 604H is a Wolfcamp A well drilled in Loving County to a completed lateral length of 8,962’. Its peak 24-hour IP was 3,111 boepd (3-stream), with oil comprising 27 percent of the product mix. Its peak 20-day average rate was 2,549 boepd (3-stream), with oil comprising 26 percent of the product mix.

Based on preliminary flowback data, the other two wells (targeting the Wolfcamp B zone in Loving County) are expected to have a similar product mix to the neighboring Razorback 604H. These three wells are located in a confined area of approximately 2,500 net acres that has a higher gas-to-oil ratio than the bulk of the company’s core Delaware Basin footprint.

Midland Basin Well Results Continue to Outperform

With 90 days of production history (normalized to 7,500’), the average cumulative production of 12 Lower Spraberry wells completed in Martin County in 1H16 with a Generation 2 frac design continues to track the 900 mboe EUR type curve. And the average cumulative production of 9 Glasscock County Wolfcamp A/B wells completed in 1H16 with a Generation 2 frac design exceeds the 890 mboe type curve by more than 20 percent after 120 days.

The company is very encouraged by the performance of these Midland Basin wells, which are helping the company understand the optimal spacing and completion design for wells drilled in density patterns across multiple producing zones.

3rd Quarter 2016 Results

Liquidity Update

As of September 30, 2016, Energen had cash of $447.9 million and long-term debt of $551.3 million; the company had nothing drawn on its recently renewed $1.05 billion line of credit. Energen estimates that its total net debt-to-2016 adjusted EBITDAX will be approximately 0.8x.

4Q16 and CY16 Financial and Production Guidance

LOE per boe in CY16 is estimated to range from $5.95-$6.30 in the Midland Basin, $7.45-$7.80 in the Delaware Basin, and $17.00-$17.30 in the Central Basin Platform. Production and ad valorem taxes in CY16, as a percent of revenues excluding hedges, are estimated to be 6.7 percent in the Midland Basin, 7.0 percent in the Central Basin Platform, and 7.8 percent in the Delaware Basin.

Net SG&A per boe in CY16 (excluding pension settlement and RIF settlement expenses) is estimated to be comprised of cash of $3.30-$3.50 per boe and non-cash, equity-based compensation of $1.00-$1.10 per boe.

Production is estimated to range from 52.0-52.4 mboepd in 4Q16. The production guidance midpoint for the year is essentially unchanged and is estimated to fall within a range of 53.9-54.7 mboepd. For all applicable periods, production excludes all 2016 asset sales.

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

Average realized prices will reflect commodity and basis hedges; oil transportation charges of approximately $2.45 per barrel; NGL transportation and fractionation fees of approximately $0.12 per gallon; 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%.

Energen’s assumed commodity prices for unhedged production for the remainder of the year (November-December) are: $50.00 per barrel of oil, $0.58 per gallon of NGL, and $3.35 per Mcf of gas. Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil are $(0.30) and $(1.13), respectively. And the assumed gas basis assumption for all open contracts is $(0.26) per Mcf.

Relative to the company’s price assumptions: every $1.00 per barrel change in the price of oil for the remainder of the year is estimated to impact the company’s EBITDAX by approximately $0.7 million; every $0.01 per gallon change in the average price of NGL for the remainder of the year is estimated to have an impact of approximately $0.3 million; and every $0.10 per Mcf change in the price of natural gas for the remainder of the year is estimated to have an impact of approximately $0.2 million.

2017 Hedge Position Strengthened

Energen has continued to increase its 2017 oil and gas hedge positions by adding 3-way oil collars and gas swaps. The company also has started layering in hedges for some of its NGL production.

Energen also has hedged the Midland to Cushing differential on approximately 5.8 million barrels of its sweet oil production in 2017 at an average price of (0.59).

Supplemental Slides and Conference Call

3Q16 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, November 4, 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 via www.energen.com.

Energen Corporation is an oil-focused exploration and production company with operations in the Permian Basin in west Texas. 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.