Energen : to Invest Additional $100-$150 MM in 2H16 to Rebuild DUC Inventory

For the 3 months ended March 31, 2016, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $(203.1) million, or $(2.34) per diluted share. Excluding mark-to-market derivatives losses, commodity price-driven impairments, loss on held-for-sale assets, and pension settlement expenses, Energen’s adjusted loss in the 1st quarter of 2016 totaled $(55.5) million, or $(0.64) per diluted share. This compares with adjusted income in the 1st quarter of 2015 of $6.8 million, or $0.09 per diluted share. The variance between the periods primarily is due to lower realized commodity prices partially offset by increased production, lower lease operating, marketing and transportation expenses (LOE), lower production and ad valorem taxes, and lower net salaries and general and administrative expenses (SG&A). [See “Non-GAAP Financial Measures” beginning on pp 9 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 9 for more information]

Asset impairments in 1Q16 primarily reflect price-driven write downs of proved properties in the Central Basin Platform. Pension and pension settlement expenses relate to the termination and subsequent distribution of benefits of Energen’s qualified defined pension plan and non-qualified supplemental retirement plans.

Energen’s adjusted 1Q16 loss was substantially better than internal expectations largely due to lower-than-expected LOE and net SG&A as well as better-than-expected production and higher realized oil prices.

LOE, including marketing and transportation, totaled $8.51 per boe and benefited from the timing of workovers and less-than-expected water disposal and electricity costs. Net SG&A (excluding pension settlement expenses) totaled $4.52 per boe in 1Q16 and benefited from small improvements in numerous factors that reflect the company’s continuing efforts to reduce costs. Production in 1Q16, excluding production from held-for-sale assets, totaled 54.2 thousand barrels of oil equivalent per day (mboepd) and exceeded the production guidance midpoint of 53.0 mboepd by 2 percent. Oil production alone was up almost 5 percent.

Energen’s adjusted EBITDAX totaled $44.2 million in the 1st quarter of 2016 and compared with adjusted EBITDAX in the same period last year of $143.9 million. [See “Non-GAAP Financial Measures” beginning on pp 9 for more information and reconciliation.]

2016 Capital Investment Increased to Rebuild DUC Inventory

Energen plans to invest approximately $100-$150 million in the second half of 2016 to build an inventory of drilled but uncompleted wells (DUCs) which will be available for completion in 2017. This additional capital will bring Energen’s total investment for drilling and development activities in 2016 to approximately $350-$400 million. In addition to drilling and development, Energen has invested approximately $20 million in 2016 (through April 30) to acquire some 3,700 net acres in the Midland and Delaware basins.

Energen is required to drill and complete 3 gross (2 net) Wolfcamp wells in Martin County in 2016 in conjunction with a Midland Basin acquisition. In the central Delaware Basin, unassociated with a lease acquisition, an additional well will be drilled and completed to hold acreage. Costs associated with drilling and completing these 4 gross (3 net) wells have been offset by savings realized in the first quarter.

The focus of additional capital to be invested in 2H16 is on drilling but not completing approximately 27-40 net wells in the Midland Basin and some 8-10 net wells in the core, central Delaware Basin. Incremental facilities costs are approximately $15-$30 million.

The dominant factors behind this decision to rebuild its DUC inventory were Energen’s recapitalized balance sheet and the resulting flexibility that has provided the company as it looks to 2017. Energen’s balance sheet has strengthened as a result of the issuance of equity in February, the addition of oil hedges in 2016, and the general improvement in oil futures prices; in addition, the company continues to move closer to culminating its planned sale of non-core assets, which will further strengthen the company’s balance sheet.

The majority of the new drills in 2H16 in the Midland Basin will be 10,000-plus foot lateral-length wells in Martin County targeting the Jo Mill, Middle Spraberry, Lower Spraberry and Wolfcamp A and B. The average working interest of the new drills is estimated to exceed 97 percent.

The core central Delaware Basin new drills will focus on the Wolfcamp A and B in Reeves and Loving counties. Nine potential wells have an average lateral length in excess of 9,500’; one potential well has a 4,500’ lateral. Energen’s average working interest in the new drills in the Delaware Basin is approximately 100 percent.

At year-end, the company estimates that it will have approximately 27-40 gross (27-39 net) horizontal DUCs in the Midland Basin, 1 (gross and net) vertical DUC in the Midland Basin, and 8-10 (gross and net) horizontal DUCs in the Delaware Basin. [See 1Q16 Supplemental Slides at www.energen.com for capital and balance sheet information.]

2016 Capital Summary

Energen Sees Attractive EURs in the Core Central Delaware Basin

Energen’s decision to allocate capital in the core Delaware Basin is largely the result of strong performances from wells drilled by the company and offset operators and from the expectation of continued efficiency gains, all of which have combined to support estimated internal rates of return (IRRs) that are highly competitive with those in the Midland Basin. [See 1Q16 Supplemental Slides at www.energen.com for data on D&C costs for various lateral lengths and estimated IRRs at various fixed oil prices.]

Energen estimates that the expected ultimate recoveries (EURs) from wells drilled in the core of the central Delaware Basin could approach 1.1 mmboe for a 4,500’ lateral, 1.5 mmboe for a 7,500’ lateral, and 2.0 mmboe for a 10,000’ lateral. The product mix is estimated to be 56 percent oil, 21 percent NGL, and 23 percent gas.

All of the Energen wells to be drilled in the Delaware Basin in 2016 are located in the core area for which these EURs are associated.

Midland Basin Development Program Results

Energen completed 33 gross (33 net) net wells in the Midland Basin during 1Q16; 18 wells -- all with 7,500’ laterals targeting the Wolfcamp A and B in Glasscock County and the Lower Spraberry and Wolfcamp A and B in Martin County -- were placed on production during the quarter. Production data indicates that the early response to up-sized fracs in the company’s new completions is tracking above the type curve by more than 30 percent. The majority of the wells tested were in Glasscock County. Energen plans to complete another 14 gross (14 net) wells in the Midland Basin during 2Q16, representing the completion of its 2015 DUC inventory.

1st Quarter 2016 Comparisons to 1st Quarter 2015

Liquidity Update

As of March 31, 2016, Energen had cash of $35.8 million and long-term debt of $551.1 million; the company had nothing drawn on its $1.05 billion line of credit. The borrowing base was lowered in April from $1.4 billion to $1.05 billion primarily due to lower commodity prices. Including the company’s most recent hedges and increased capital plans, and assumed sale of non-core assets, Energen estimates that is total debt-to-2016 adjusted EBITDAX will range from approximately 0.9 to 1.1. [See “Non-GAAP Financial Measures” beginning on pp 9 for more information and reconciliation.]

2Q16 and CY16 Financial and Production Guidance

LOE per boe in CY16 is estimated to range from $6.00-$6.50 in the Midland Basin, $9.00-$9.50 in the Delaware Basin, and $21.20-$21.80 in the Central Basin Platform. Production and ad valorem taxes in CY16, as a percent of revenues excluding hedges, are estimated to be 6.9 percent in the Midland Basin and 8.7 percent in the Delaware Basin and Central Basin Platform.

Net SG&A per boe in CY16 (excluding pension settlement expenses) is estimated to be comprised of cash of $3.30-$3.65 per boe and non-cash, equity-based compensation of $0.70-$0.80 per boe.

Production in 2Q16 is estimated to range from 56.0-56.4 mboepd, while the estimate for 2016 production has been increased 1.3 percent to a new range of 54.1-56.1 mboepd. Given Energen’s increased 4Q16 exit rate of 53.3 mpoed (based on the estimated midpoint), the 4Q15 to 4Q16 exit rate decline has improved from 12 percent to 9 percent. [See 1Q16 Supplemental Slides at www.energen.com for CY16 guidance information.]

Additional Hedges Added in 2016, 2017

Energen continued to increase its 2016 oil hedge position in April by selling swaps for 1.2 million barrels of oil production at an average NYMEX price of $44.41 per barrel. These latest hedges bring the company’s total oil hedge position in calendar year 2016 to 7.5 million barrels, or 58 percent of its oil production guidance midpoint, at an average NYMEX price of $45.18 per barrel.

Energen also has added another 1.4 million barrels of oil hedges in 2017 at an average NYMEX price of $47.36 per barrel. This brings the company’s total oil hedge position in calendar year 2017 to 2.5 million barrels at an average NYMEX price of $46.37 per barrel. The company also hedged 3.6 bcf of basin-specific natural gas in 2017 at an average NYMEX-equivalent price of $2.90 per Mcf. [See 1Q16 Supplemental Slides at www.energen.com for CY16 hedge information.]

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 $2.15 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 are:

• $44.23 per barrel of oil (April-December)
• $0.48 per gallon of NGL (April-December), and
• $2.49 per Mcf of gas (May-December).

Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (May-December) are $(0.35) and $(0.50), respectively. And assumed gas basis assumptions for all open contracts (May-December) are $(0.16) 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 cash flows by approximately $3.9 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 $0.9 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 $0.8 million.

Supplemental Slides and Conference Call

1Q16 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, May 6, 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 and gas exploration and production company with headquarters in Birmingham, Alabama. At year-end 2015, the company had 355 million barrels of oil-equivalent proved reserves and another 2.8 billion barrels of oil-equivalent probable and possible reserves and contingent resources. These all-domestic reserves and resources are located primarily 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. Among other forward-looking statements in this release are statements regarding our intention to engage in certain assets sales and the estimated proceeds thereof. These sales processes are at preliminary stages, and we do not have binding agreements for any transactions; as a result, the estimate of proceeds from these transactions is preliminary and may not be realized. Our ability to consummate any transactions and their timing are subject to market conditions and other factors, and we may not be able to consummate these transactions at all or for the net proceeds we are estimating.

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.

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