News Release

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08/08/16

Energen’s 2Q16 Production Exceeds Guidance Midpoint by 4%

Broad-based Efficiency Gains Continue as Expenses Reduced

5-Well Average Production History Underscores Core Delaware Basin Potential

Highlights

  • Positive response to upsized (MB Generation 2) completions continued in Midland Basin
  • Total 2Q16 production increased 7% from 1Q16; sequential growth in oil production of 8.5%
  • 2Q16 production from Midland Basin horizontal wells increased 22% from 1Q16
  • CY16 production guidance midpoint raised approximately 2%, or 900 boepd
  • 2Q per-unit LOE and SG&A declined 20% and 39% YoY, respectively
  • 2016 per-unit LOE guidance midpoint lowered 11%
  • Capital efficiency improvements realized in Delaware and Midland basins as days to drill and D&C costs decline
  • Energen added approximately 850 net acres in July to its core Delaware Basin footprint through bolt-on acquisitions
  • 2017 oil hedge position strengthened with additional 3-way collars
  • Drilling of 54-58 net DUCs in Delaware and Midland basins under way
  • Company sees double-digit production growth potential in 2017 while maintaining strong balance sheet

“Armed with an outstanding balance sheet and solid, 2017 hedge position, we are very excited to be focused on bringing forward the value of our high-quality assets in the Permian Basin,” said James McManus, chairman and chief executive officer of Energen Corporation. “Work is under way to build a 54- to 58-well inventory of drilled but uncompleted wells, or DUCs, at year end.

“We are particularly pleased to be drilling 17-19 wells in our core Delaware Basin, where we believe internal rates of return on the longer lateral-length wells will be even better than we originally estimated,” McManus said. “And in the Midland Basin, we are drilling primarily 10,000’ lateral length wells in Martin County that we plan to complete in 2017 with a new generation frac design; we also are adding the Jo Mill and Middle Spraberry zones to our stacked, density-pattern development program.

“While our plans for 2017 are still evolving, we believe that completing our DUC inventory in the first half of 2017 combined with additional drilling and development supports year-over-year, double-digit production growth in 2017.”

BIRMINGHAM, Ala.--(BUSINESS WIRE)--Aug. 8, 2016-- For the 3 months ended June 30, 2016, Energen Corporation (NYSE: EGN) reported GAAP net income from all operations of 36.8 million, or $0.38 per diluted share. Excluding mark-to-market derivatives losses, income from the sale of properties, and pension and reduction in force (RIF) settlement expenses, Energen’s adjusted loss in 2Q16 totaled $27.1 million, or $(0.28) per diluted share. This compares with adjusted income in 2Q15 of $11.9 million, or $0.16 per diluted share.

The variance between the periods primarily is due to lower realized commodity prices partially offset by less depreciation, depletion and amortization expense (DD&A), lower net salaries and general and administrative expenses (SG&A), and lower lease operating, marketing and transportation expenses (LOE). [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]

        2Q16     2Q15
        $M     $/dil. sh.     $M     $/dil. sh.
Net Income/(Loss) All Operations (GAAP)       $ 36,759       $ 0.38       $ (111,601 )     $ (1.52 )
Less: Non-cash mark-to-market gains/(losses)         (39,109 )       (0.40 )       (75,133 )       (1.02 )
Less: Asset impairments         --         --         (37,644 )       (0.51 )
Less: Pension settlement and RIF settlement expenses         (559 )       (0.01 )       (701 )       (0.01 )
Less: Income/(loss) associated 2016 asset sales         103,540         1.06         (10,005 )       0.14  
Adj. Income Continuing Operations (Non-GAAP)       $ (27,113 )     $ (0.28 )     $ 11,882       $ 0.16  

Note: Per share amounts may not sum due to rounding

Energen’s adjusted 2Q16 loss was substantially better than internal expectations largely due to significantly lower-than-expected LOE and better-than-expected production. LOE, including marketing and transportation, totaled $7.29 per boe and benefited largely from lower costs for water disposal, gathering, and electrical power, and from fewer workovers.

Production in 2Q16 totaled 56.0 thousand barrels of oil equivalents per day (mboepd) and exceeded the production guidance midpoint of 53.9 mboepd by 3.9 percent. Oil production was up almost 5 percent relative to the guidance midpoint. Actual and guidance production numbers exclude all 2016 property sales (closed and pending). The production increase was driven primarily by the outperformance of the company’s Midland Basin horizontal plays, which are responding favorably to the Generation 2 frac design used to complete Energen’s drilled but uncompleted (DUC) well inventory in the first half of 2016.

Energen’s adjusted EBITDAX totaled $82.3 million in the 2nd quarter of 2016 and exceeded internal expectations by 30 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $169.8 million. [See “Non-GAAP Financial Measures” beginning on pp 9 for more information and reconciliation.]

2H16 Drilling Program Under Way in Permian Basin

Drilling is under way in the Midland and Delaware basins as Energen looks to end 2016 with 54-58 net DUCs that will be available for completion in 2017. Energen estimates that capital investment associated with drilling and development activity in 2016 will be approximately $450 million. In addition to drilling and development, Energen has invested approximately $37 million in 2016 (through July 31) to acquire acreage and renew leases, including adding more than 4,500 net acres in the core Delaware and Midland basins through bolt-on acquisitions. In July alone, Energen added 851 net acres in its core Delaware Basin footprint.

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 in the new drills is estimated to exceed 97 percent. Energen anticipates completing these new Midland Basin DUCs in the first half of 2017 using a new generation frac design with more sand per linear foot and tighter frac stages (MB Generation 3). [See 2Q16 Supplemental Slides at www.energen.com for the company’s evolution in frac design.]

In the core central Delaware Basin, new drills will focus on the Wolfcamp A and B in Reeves and Loving counties, and all but two potential DUCs will have an average lateral length in excess of 9,500’. Energen’s average working interest in the new drills in the Delaware Basin is approximately 100 percent. The new DUCs to be completed in 2017 likely will utilize a new generation frac design (DB Generation 3) and optimized surface facilities. [See 2Q16 Supplemental Slides at www.energen.com for the company’s evolution in frac design.]

At year-end, the company estimates that it will have approximately 38-40 gross (37-39 net) horizontal DUCs in the Midland Basin, 1 (gross and net) vertical DUC in the Midland Basin, and 17-19 (gross and net) horizontal DUCs in the Delaware Basin.

2016 Capital Summary

      2016e Capital

($MM)

    Wells to be Drilled     Wells Completions
          Operated Gross (Net)     Operated Gross (Net)
Midland Basin     $ 300       48 (46) – 50 (48) *     55 (54) †
Delaware Basin     $ 130       21 (21) – 23 (23) **     4 (4)
Net Carry/ARO/Other     $ 20              
                       

Drilling & Development Capital

   

$

450

¹

   

69 (67) – 73 (71)

   

59 (58)

¹ Includes approximately $35 mm for facilities in the Midland Basin, $25 mm for facilities in the Delaware Basin and $10 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, and 38-40 gross (37-39) net DUC drills in 2H16
** Includes 4 gross (4 net) horizontal wells to hold acreage and 17-19 gross and net DUC drills in 2H16
Includes 5 gross (5 net) vertical wells, 3 gross (2 net) horizontal wells to hold new leasehold, 47 gross (47 net) development program completions, virtually all of which comprised the company’s YE15 DUC inventory

Energen Sees Attractive EURs in the Core Central Delaware Basin

Energen’s decision to allocate increasing amounts of capital in its core Delaware Basin is the result of strong performances by 5 wells it drilled in the core and from approximately 20 wells drilled by offset operators as well as from the expectation of continued efficiency gains. All of these factors have combined to support outstanding internal rates of return (IRRs) in the Wolfcamp A and Wolfcamp B in the core Delaware Basin, with expected ultimate recoveries (EURs) estimated to 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 377-day average cumulative production of the 5 Energen Wolfcamp wells, normalized to 7,500’, is closely tracking the 1.5 mmboe EUR type curve. These Reeves County wells have been producing for approximately 12-24 months, and include Wolfcamp A, B, and C targets. The majority of them were completed with the DB Generation 1 frac design. [See 2Q16 Supplemental Slides at www.energen.com for graph of average cumulative production of the 5 wells and for details on the company’s evolution in frac design.]

Energen has increased its estimated IRRs for 7,500’ and 10,000’ lateral-length Wolfcamp A and Wolfcamp B wells in its core Delaware Basin as the result of increasing flow rates primarily by optimizing surface facilities. The return for a 10,000’ lateral-length well drilled and completed for $8 million at a $45 oil price is now estimated to be 86 percent. [See 2Q16 Supplemental Slides at www.energen.com for estimated Delaware Basin Wolfcamp A and Wolfcamp B IRRs at varying oil prices.]

Energen currently is drilling its fourth well to hold acreage in the core Delaware Basin footprint; three of these wells will be completed in 3Q16 and the fourth well is scheduled to be completed in 4Q16. These four wells utilize optimized surface facilities and will be completed with the DB Generation 3 frac design.

Underscoring the strides it continues to make in drilling efficiency in the Delaware Basin, Energen drilled one of these wells -- a 9,000’ lateral well targeting the Wolfcamp A -- in just 22.4 days from spud to TD and estimates the drill and complete cost will be $7.2 million.

Midland Basin Development Program Outperforms

Energen completed its remaining DUC inventory of 14 gross (14 net) net wells in the Midland Basin during the second quarter. Together with 15 wells completed in the first quarter but not yet on production, Energen placed on production in the second quarter a total of 24 DUCs: 22 in Martin County targeting the Lower Spraberry, Wolfcamp A, and Wolfcamp B zones and 2 in Glasscock County targeting the Wolfcamp A and Wolfcamp B. The lateral length of the Martin County wells placed on production averaged approximately 6,700 feet, and the Glasscock County wells had an average lateral length of approximately 7,600 feet.

Based on early production results, these wells are outperforming internal expectations due, in large part, to the company’s MB Generation 2 completions. In Martin County, for example, 6 Lower Spraberry DUCs with more than 60 days of productive history are averaging a 900 mboe EUR estimate. In their first 90 days of production, the 9 Glasscock County DUCs completed in 1H16 have outperformed the type curve.

As strong as production has been, the full extent of the Martin County DUCs’ performance was hampered in June when the salt water disposal facility servicing that area was damaged by lightning. This caused a temporary interruption in production. Intermittent storm-related power outages also were experienced in Martin and Glasscock counties in July. The direct impact of weather on annual production is estimated to be less than 500 boepd.

Efficiency gains continue to be realized in the Midland Basin, where Energen drilled a 7,500’ Wolfcamp A DUC in Glasscock County in 13.1 days, spud to TD; the well was completed in 1H16 with MB Generation 3 frac design for $5.2 mm.

2nd Quarter 2016 Results

Production (excluding 2016 asset sales) (mboepd)

Commodity             2Q16     2Q15         1Q16
Oil             36.5     36.5         33.6
NGL             9.4     9.5         8.3
Natural Gas             10.2     9.5         10.4
Total             56.0     55.4         52.3
                       
Area       2Q16     2Q15         1Q16
Midland Basin       37.1     32.5         33.0
Horizontal       28.5     19.6         23.3
Vertical       8.6     12.9         9.7
Delaware Basin       9.8     12.9         10.3
Central Basin/Other       9.1     10.0         9.0
Total       56.0     55.4         52.3

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

Average Realized Sales Prices (excluding 2016 asset sales)

Commodity         2Q16     2Q15     % Change
Oil (per barrel)         $ 39.52     $ 69.39     (43 )
NGL (per gallon)         $ 0.32     $ 0.34     (6 )
Natural Gas (per Mcf)         $ 1.68     $ 4.22     (60 )
               
 

Average Prices Before Effects of Hedges (excluding 2016 asset sales)

Commodity       2Q16     2Q15     % Change
Oil (per barrel)       $ 41.42     $ 52.75     (22 )
NGL (per gallon)       $ 0.32     $ 0.34     (6 )
Natural Gas (per Mcf)       $ 1.49     $ 2.17     (31 )
             
 

Expenses (excluding 2016 asset sales)

Per BOE, except where noted       2Q16     2Q15     % Change
LOE (including marketing and transportation)       $ 7.29     $ 9.09     (20 )
Production & ad valorem taxes       $ 1.97     $ 2.31     (15 )
DD&A       $ 21.46     $ 26.92     (20 )
Net SG&A       $ 4.45     $ 7.34     (39 )
Interest ($MM)       $ 9.0     $ 11.2     (20 )

† Excludes $0.17 per boe in 2Q16 for RIF settlement expenses and $0.22 per BOE in 2Q15 for pension and pension settlement expenses.

Liquidity Update

As of June 30, 2016, Energen had cash of $309.9 million and long-term debt of $551.2 million; the company had nothing drawn on its $1.05 billion line of credit. Energen estimates that is total net debt-to-2016 adjusted EBITDAX will be approximately 0.5x.

3Q16 and CY16 Financial and Production Guidance

Energen’s Estimated Expenses (excluding 2016 asset sales):

Per BOE, except where noted         3Q16       CY16
LOE (production costs, marketing & transportation)         $8.60-$9.00       $8.25- $8.65
Production & ad valorem taxes (% of revenues, excluding hedges)         7.1%       7.3%
DD&A expense         $20.50-$21.00       $21.30-$21.70
Salaries and general & administrative expense, net         $4.35-$4.70       $4.35-$4.70†
Exploration expense (seismic, delay rentals, etc.)         $0.42-$0.47       $0.30-$0.35
Interest expense ($MM)         $8.8-$9.2       $36.5-$37.5
FF&E depreciation ($MM)         $1.2-$1.4       $5.0-$5.2
Accretion of discount on ARO ($MM)         $1.5-$1.7       $6.1-$6.3
Effective tax rate (%)         33%-35%       33%-35%

Excludes $0.45 per boe in CY16 for pension settlement and RIF settlement expenses

LOE per boe in CY16 is estimated to range from $5.95-$6.35 in the Midland Basin, $8.25-$8.65 in the Delaware Basin, and $17.20-$17.60 in the Central Basin Platform. Production and ad valorem taxes in CY16, as a percent of revenues excluding hedges, are estimated to be 7.0 percent in the Midland Basin and Central Basin Platform and 8.4 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 $3.50-$3.70 per boe and non-cash, equity-based compensation of $0.85-$1.00 per boe.

Production is estimated to range from 55.2-55.6 mboepd in 3Q16 and from 52.0-52.4 mboepd in 4Q16. The company’s 4Q15 to 4Q16 exit rate decline continues to shrink and now is estimated (at midpoint) to be 8 percent. The production guidance midpoint for the year has been increased approximately 2%, or some 900 boepd, within a range of 53.6-54.4 mboepd. For all applicable periods, production excludes 2016 asset sales.

Production by Basin (excluding 2016 asset sales) (mboepd)

Area      

3Q16e Guidance

Midpoint

   

4Q16e Guidance

Midpoint

   

2016e Guidance

Midpoint

Midland Basin       36.9     32.9     34.9
Horizontal       28.4     24.8     26.2
Vertical       8.5     8.1     8.7
Delaware Basin       9.5     10.4     10.0
Central Basin Platform/Other       9.0     8.9     9.1
Total       55.4     52.2     54.0

NOTE: Totals may not sum due to rounding

 
 

Production by Commodity (excluding 2016 asset sales) (mboepd)

Commodity      

3Q16e Guidance

Midpoint

   

4Q16e Guidance

Midpoint

   

2016e Guidance

Midpoint

Oil       35.9     33.4     34.9
NGL       9.4     9.1     9.0
Gas       10.1     9.7     10.1
Total Production       55.4     52.2     54.0

NOTE: Totals may not sum due to rounding

 
 

3Q16 Hedge Position

Commodity       Hedge Volumes     Production @ Midpoint     Hedge %     NYMEXe Price
Oil       2.5 mmbo     3.3 mmbo     76     $ 44.73 per barrel
Natural Gas       1.8 bcf     5.6 bcf     32     $ 2.51 per mcf

NOTE: Includes known actuals

 
 
Differential       Hedge Volumes     Avg. Price (per barrel)
WTS Midland to WTI Cushing (sour)       0.5 mmbo     $ (1.64)
WTI Midland to WTI Cushing (sweet)       1.9 mmbo     $ (1.92)

NOTE: Approximately 79% of 3Q16 oil production is “sweet”

 
 

July-December 2016 Hedge Position

Commodity       Hedge Volumes     Production @ Midpoint     Hedge %     NYMEXe Price
Oil       4.4 mmbo     6.4 mmbo     69     $ 44.72 per barrel
Natural Gas       3.6 bcf    

10.9 bcf

    33     $ 2.47 per mcf

NOTE: Includes known actuals

 
 
Differential       Hedge Volumes     Avg. Price (per barrel)
WTS Midland to WTI Cushing (sour)       1.0 mmbo     $ (1.64)
WTI Midland to WTI Cushing (sweet)       3.8 mmbo     $ (1.92)

NOTE: Approximately 79% of July-December 2016 oil production is “sweet”

 

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.

Estimated Price Realizations (pre-hedge):

        3Q16     CY16
Crude oil (% of NYMEX/WTI)       93%     90%
NGL (after T&F) (% of NYMEX/WTI)       28%     29%
Natural gas (% of NYMEX/Henry Hub)       79%     78%
 

Average realized prices will reflect commodity and basis hedges; oil transportation charges of approximately $2.19 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 are: $45.00 per barrel of oil (July-December); $0.49 per gallon of NGL (July-December), and $2.80 per Mcf of gas (August-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (August-December) are $(0.45) and $(0.90), respectively. And assumed gas basis assumptions for all open contracts (August-December) are $(0.13) 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 $1.7 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 $0.6 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 $0.4 million.

2017 Hedge Position Strengthened

Energen continued to increase its 2017 oil hedge position in the second quarter by adding 3-way collars for 1.1 million barrels of oil production at an average call price of $65.67 per barrel, an average put price of $45 per barrel, and an average short put price of $35 per barrel. This brings the company’s total oil volumes hedged in 2017 to 8.2 million barrels.

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

Oil       2017 Hedge Volumes¹     Avg. NYMEX Price
Swaps       4.1 mmbo     $ 47.97 per barrel
Three way Collars²       4.1 mmbo      
Call Price             $ 62.25 per barrel
Put Price             $ 45.00 per barrel
Short Put Price             $ 35.00 per barrel

¹ Hedges are distributed equally throughout the year by month
² 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 also added 2.4 Bcf of Permian Basin-specific contracts to its 2017 natural gas hedge position at an average contract price of $3.00 per Mcf. This brings Energen’s total natural gas hedge position in 2017 to 13.2 Bcf of basin-specific gas at an average contract price of $2.85 per Mcf. Assuming a $0.15 per Mcf differential, the company’s NYMEX-equivalent price for its 2017 natural gas hedges is $3.00 per Mcf.

Supplemental Slides and Conference Call

2Q16 Supplemental Slides associated with Energen’s quarterly release and conference call are available at www.energen.com. Energen will hold its quarterly conference call Tuesday, August 9, 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. 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.

 
 
 
 
 

Non-GAAP Financial Measures

 

Adjusted Net Income is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles) which excludes the effects of certain non-cash mark-to-market derivative financial instruments. Adjusted  income from continuing operations further excludes impairment losses, expenses related to the 2016 reductions in force, certain pension and pension settlement expenses and income and losses associated with 2016 property sales (closed and pending). Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.

     
Three Months Ended 6/30/2016
Energen Net Income ($ in millions except per share data)     Net Income  

Per Diluted

Share

Net Income All Operations (GAAP) 36.8   0.38
Non-cash mark-to-market losses (net of $21.5 tax) 39.1 0.40
Reduction in force expenses (net of $0.3 tax) 0.6 0.01
Income associated with 2016 property sales (net of $58.2 tax)     (103.5 )   (1.06 )
Adjusted Income from Continuing Operations (Non-GAAP)     (27.1 )   (0.28 )
 
 
Three Months Ended 6/30/2015
Energen Net Income ($ in millions except per share data)     Net Income  

Per Diluted

Share

Net Income (Loss) All Operations (GAAP) (111.6 ) (1.52 )
Non-cash mark-to-market losses (net of $41.7 tax) 75.1 1.02
Asset impairment, other (net of $21.1 tax) 37.6 0.51
Pension and pension settlement expenses (net of $0.4 tax) 0.7 0.01

Loss associated with 2016 property sales (net of $5.8 tax)

    10.0     0.14  
Adjusted Income from Continuing Operations (Non-GAAP)     11.9     0.16  
 
Note: Amounts may not sum due to rounding
 
 
 
 
 
 
 

Non-GAAP Financial Measures

 

Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles).  Adjusted EBITDAX from continuing operations further excludes expenses related to the 2016 reductions in force, certain pension and pension settlement expenses, income and losses associated with  2016 property sales (closed and pending), impairment losses and certain non-cash mark-to-market derivative financial  instruments. Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies.

     
Reconciliation To GAAP Information Three Months Ended 6/30
($ in millions)     2016   2015
 
Energen Net Income (Loss) (GAAP) 36.8 (111.6 )
(Income) Loss associated with 2016 property sales, net of tax     (103.5 )   10.0  
Net Income (Loss) Excluding 2016 Property Sales (Non-GAAP)     (66.8 )   (101.6 )
Interest expense 9.0 11.2
Income tax expense (benefit) * (35.1 ) (55.5 )
Depreciation, depletion and amortization * 110.6 137.2
Accretion expense * 1.5 1.4
Exploration expense * 1.5 0.3
Adjustment for asset impairment * 0.0 58.7
Adjustment for mark-to-market losses 60.6 116.9
Adjustment for reduction in force and pension and pension settlement expenses     0.9     1.1  
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)     82.3     169.8  
 
Note: Amounts may not sum due to rounding
 
* Amount adjusted to exclude held for sale assets in either current or prior period. See reconciliation to GAAP Information for the Three Months Ended 6/30/2016 and 6/30/2015.
 
 
 
 
 
 
 

Non-GAAP Financial Measures

 

The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles).  Energen believes excluding information associated with 2016 property sales (closed and pending) provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations.  Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

 

Energen Net Income (Loss) Excluding 2016 Property Sales (Closed and Pending)

   
Reconciliation to GAAP Information Three Months Ended
June 30, 2016
(in thousands except per share and production data)                      
GAAP   $/BOE  

2016 Property

Sales

  Non-GAAP   $/BOE
Revenues        
Oil, natural gas liquids and natural gas sales $ 171,637 $ 14,426 $ 157,211
Gain (loss) on derivative instruments       (65,872 )      

 

-       (65,872 )    
Total Revenues       105,765           14,426       91,339      
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 42,840 $ 7.33 5,660 37,180 $ 7.29
Production and ad valorem taxes 11,265 $ 1.93 1,236 10,029 $ 1.97
O&G Depreciation, depletion and amortization 115,768 $ 19.82 6,368 109,400 $ 21.46
FF&E Depreciation, depletion and amortization 1,267 $ 0.22 71 1,196 $ 0.23
Asset impairment - - -
Exploration 1,520 32 1,488
General and administrative † 23,548 $ 4.03 10 23,538 $ 4.62
Accretion of discount on asset retirement obligations 1,779 248 1,531
(Gain) loss on sale of assets and other       (161,097 )         (160,944 )     (153 )    
Total costs and expenses       36,890           (147,319 )     184,209      
Operating Income (Loss)       68,875           161,745       (92,870 )    
Other Income/(Expense)
Interest expense (9,038 ) - (9,038 )
Other income       63           (1 )     64      
Total other expense       (8,975 )         (1 )     (8,974 )    
 
Loss Before Income Taxes 59,900 161,744 (101,844 )
Income tax expense (benefit)       23,141           58,204       (35,063 )    
Net Income (Loss)     $ 36,759         $ 103,540     $ (66,781 )    
                       
Diluted Earnings Per Average Common Share     $ 0.38         $ 1.06     $ (0.69 )    
                       
Basic earning Per Average Common Share     $ 0.38         $ 1.06     $ (0.69 )    
 
Oil 3,558 238 3,320
NGL 1,067 212 855
Natural Gas       1,216           292       924      
Total Production (mboe)       5,841           742       5,099      
Total Production (boepd)       64,187           8,154       56,033      
 
Note: Amounts may not sum due to rounding
 
† General and administrative includes $866 or $0.17 per BOE of expense related to the reductions in force
 
 
 
 
 
 
 

Non-GAAP Financial Measures

 

The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles).  Energen believes excluding information associated with 2016 property sales (closed and pending) provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations.  Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

 
Energen Net Income (Loss) Excluding 2016 Property Sales (Closed and Pending)        
Reconciliation to GAAP Information Three Months Ended
June 30, 2015
(in thousands except per share and production data)                      
GAAP   $/BOE  

2016 Property

Sales

  Non-GAAP   $/BOE
Revenues    
Oil, natural gas liquids and natural gas sales $ 219,290 $ 20,557 $ 198,733
Gain (loss) on derivative instruments       (50,964 )      

 

-       (50,964 )    
Total Revenues       168,326           20,557       147,769      
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 53,581 $ 9.15 7,706 45,875 $ 9.09
Production and ad valorem taxes 13,352 $ 2.28 1,692 11,660 $ 2.31
O&G Depreciation, depletion and amortization 148,374 $ 25.35 12,547 135,827 $ 26.92
FF&E Depreciation, depletion and amortization 1,469 $ 0.25 106 1,363 $ 0.27
Asset impairment 60,413 1,725 58,688
Exploration 11,018 10,666 352
General and administrative † 38,652 $ 6.60 525 38,127 $ 7.56
Accretion of discount on asset retirement obligations 1,669 237 1,432
(Gain) loss on sale of assets and other       1,476           1,148       328      
Total costs and expenses       330,004           36,352       293,652      
Operating Income (Loss)       (161,678 )         (15,795 )     (145,883 )    
Other Income/(Expense)
Interest expense (11,244 ) - (11,244 )
Other income       41           -       41      
Total other expense       (11,203 )         -       (11,203 )    
 
Loss Before Income Taxes (172,881 ) (15,795 ) (157,086 )
Income tax expense (benefit)       (61,280 )         (5,790 )     (55,490 )    
Net Income (Loss)     $ (111,601 )       $ (10,005 )   $ (101,596 )    
                       
Diluted Earnings Per Average Common Share     $ (1.52 )       $ (0.14 )   $ (1.38 )    
                       
Basic earning Per Average Common Share     $ (1.52 )       $ (0.14 )   $ (1.38 )    
 
Oil 3,594 269 3,325
NGL 1,070 209 861
Natural Gas       1,189           330       859      
Total Production (mboe)       5,853           808       5,045      
Total Production (boepd)       64,319           8,879       55,440      
 
Note: Amounts may not sum due to rounding
 
† General and administrative includes $1,090 or $0.22 per BOE of pension and pension settlement expense
 
 
 
 
 
 
 

Non-GAAP Financial Measures

 

Excluding production associated with certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles).  Energen believes excluding data associated with the 2016 property sales (closed and pending) provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations.  Further, this measure is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

 
Energen Production Excluding 2016 Property Sales (Closed and Pending)      
Reconciliation to GAAP Information Quarter Ended
March 31, 2016
         
GAAP  

2016 Property

Sales

  Non-GAAP
 
Oil 3,386 325 3,061
NGL 953 199 754
Natural Gas     1,241   296   945
Total Production (mboe)     5,580   820   4,760
Total Production (boepd)     61,319   9,011   52,308
 
Note: Amounts may not sum due to rounding
 
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 3 months ending June 30, 2016 and 2015
 
      2nd Quarter    
   
(in thousands, except per share data)       2016     2015     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 171,637 $ 219,290 $ (47,653 )
Loss on derivative instruments, net         (65,872 )       (50,964 )       (14,908 )
 
Total revenues         105,765         168,326         (62,561 )
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 42,840 53,581 (10,741 )
Production and ad valorem taxes 11,265 13,352 (2,087 )
Depreciation, depletion and amortization 117,035 149,843 (32,808 )
Asset impairment 60,413 (60,413 )
Exploration 1,520 11,018 (9,498 )
General and administrative (including non-cash stock based compensation of $5,504 and $6,027 for the three months ended June 30, 2016, and 2015, respectively)

 

 

23,548

 

 

38,652

 

 

(15,104

 

 

)

Accretion of discount on asset retirement obligations 1,779 1,669 110
(Gain) loss on sale of assets and other         (161,097 )       1,476         (162,573 )
 
Total operating costs and expenses         36,890         330,004         (293,114 )
 
Operating Income (Loss)         68,875         (161,678 )       230,553  
 
Other Income (Expense)
Interest expense (9,038 ) (11,244 ) 2,206
Other income         63         41         22  
 
Total other expense         (8,975 )       (11,203 )       2,228  
 
Income (Loss) Before Income Taxes 59,900 (172,881 ) 232,781
Income tax expense (benefit)         23,141         (61,280 )       84,421  
 
Net Income (Loss)       $ 36,759       $ (111,601 )     $ 148,360  
                           
Diluted Earnings Per Average Common Share       $ 0.38       $ (1.52 )     $ 1.90  
Basic Earnings Per Average Common Share       $ 0.38       $ (1.52 )     $ 1.90  
Diluted Average Common Shares Outstanding         97,389         73,452         23,937  
Basic Average Common Shares Outstanding         97,067         73,452         23,615  
Dividends Per Common Share       $       $ 0.02       $ (0.02 )
 
 
 
 
 
 
 
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 6 months ending June 30, 2016 and 2015
 
      Year-to-date    
   
(in thousands, except per share data)       2016     2015     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 294,401 $ 407,112 $ (112,711 )
Loss on derivative instruments, net         (60,417 )       (16,928 )       (43,489 )
 
Total revenues         233,984         390,184         (156,200 )
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 90,567 121,335 (30,768 )
Production and ad valorem taxes 22,435 32,417 (9,982 )
Depreciation, depletion and amortization 236,397 284,224 (47,827 )
Asset impairment 220,025 66,996 153,029
Exploration 1,762 11,781 (10,019 )

General and administrative (including non-cash stock based compensation of $7,975 and $11,107 for the six months ended June 30, 2016, and 2015, respectively)

 

 

53,073

 

 

70,707

 

 

(17,634

 

 

)

Accretion of discount on asset retirement obligations 3,536 3,679 (143 )
Gain (loss) on sale of assets and other         (160,875 )       (26,868 )       (134,007 )
 
Total operating costs and expenses         466,920         564,271         (97,351 )
 
Operating Loss         (232,936 )       (174,087 )       (58,849 )
 
Other Income (Expense)
Interest expense (18,871 ) (23,002 ) 4,131
Other income         159         87         72  
 
Total other expense         (18,712 )       (22,915 )       4,203  
 
Loss Before Income Taxes (251,648 ) (197,002 ) (54,646 )
Income tax benefit         (85,291 )       (69,981 )       (15,310 )
 
Net Loss       $ (166,357 )     $ (127,021 )     $ (39,336 )
                           
Diluted Earnings Per Average Common Share       $ (1.81 )     $ (1.74 )     $ (0.07 )
Basic Earnings Per Average Common Share       $ (1.81 )     $ (1.74 )     $ (0.07 )
Diluted Average Common Shares Outstanding         91,850         73,143         18,707  
Basic Average Common Shares Outstanding         91,850         73,143         18,707  
Dividends Per Common Share       $       $ 0.04       $ (0.04 )
 
 
 
 
 
 
 
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of June 30, 2016 and December 31, 2015
 

 

         
(in thousands)       June 30, 2016     December 31, 2015
 
 
ASSETS
Current Assets
Cash and cash equivalents $ 309,889 $ 1,272
Accounts receivable, net 76,119 63,097
Inventories 12,596 11,255
Assets held for sale 176,914 93,739
Derivative instruments 3,235 56,963
Prepayments and other         7,087       20,014
 
Total current assets         585,840       246,340
 
Property, Plant and Equipment
Oil and natural gas properties, net 3,858,918 4,302,332
Other property and equipment, net         45,755       48,358
 
Total property, plant and equipment, net         3,904,673       4,350,690
 
Other postretirement assets 4,358 3,881
Other assets         9,866       10,245
 
TOTAL ASSETS       $ 4,504,737     $ 4,611,156
 

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities
Accounts payable 53,108 64,742
Accrued taxes 16,684 5,801
Accrued wages and benefits 13,386 28,563
Accrued capital costs 40,347 79,206
Revenue and royalty payable 57,979 60,493
Liabilities related to assets held for sale 13,279 12,789
Pension liabilities 15,685
Derivative instruments 46,452 459
Other         19,344     19,783
 
Total current liabilities         260,579     287,521
 
Long-term debt 551,245 773,550
Asset retirement obligations 91,473 89,990
Deferred income taxes 460,424 552,369
Noncurrent derivative instruments 12,875
Other long-term liabilities         11,910     11,866
 
Total liabilities         1,388,506     1,715,296
 
Total Shareholders’ Equity         3,116,231     2,895,860
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY       $ 4,504,737    

$4,611,156

 
 
 
 
 
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending June 30, 2016 and 2015

 
      2nd Quarter    
   
(in thousands, except sales price and per unit data)       2016     2015     Change
 
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil $ 146,360 $ 188,599 $ (42,239 )
Natural gas liquids 13,928 14,781 (853 )
Natural gas         11,349         15,910         (4,561 )
Total       $ 171,637       $ 219,290       $ (47,653 )

 

 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ (54,729 ) $ (103,734 ) $ 49,005
Natural gas         (5,896 )       (13,133 )       7,237  
Total       $ (60,625 )     $ (116,867 )     $ 56,242  
 
Closed gains (losses) on derivative instruments
Oil $ (6,297 ) $ 55,330 $ (61,627 )
Natural gas         1,050         10,573         (9,523 )
Total       $ (5,247 )     $ 65,903       $ (71,150 )
Total revenues       $ 105,765       $ 168,326       $ (62,561 )
 
Production volumes
Oil (MBbl) 3,558 3,594 (36 )
Natural gas liquids (MMgal) 44.8 44.9 (0.1 )
Natural gas (MMcf)         7,296         7,134         162  
Total production volumes (MBOE) 5,841         5,853         (12 )
 
Average daily production volumes
Oil (MBbl/d) 39.1 39.5 (0.4 )
Natural gas liquids (MMgal/d) 0.5 0.5
Natural gas (MMcf/d)         80.2         78.4         1.8  
Total average daily production volumes (MBOE/d)         64.2         64.3         (0.1 )
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 39.37 $ 67.87 $ (28.50 )
Natural gas liquids (per gallon) $ 0.31 $ 0.33 $ (0.02 )
Natural gas (per Mcf) $ 1.70 $ 3.71 $ (2.01 )
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 41.14 $ 52.48 $ (11.34 )
Natural gas liquids (per gallon) $ 0.31 $ 0.33 $ (0.02 )
Natural gas (per Mcf) $ 1.56 $ 2.23 $ (0.67 )
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

7.34

$

9.15

$

(1.81

)

Production and ad valorem taxes $ 1.93 $ 2.28 $ (0.35 )
Depreciation, depletion and amortization $ 20.04 $ 25.60 $ (5.56 )
Exploration expense $ 0.26 $ 1.88 $ (1.62 )
General and administrative $ 4.03 $ 6.60 $ (2.57 )
Capital expenditures       $ 92,962       $ 300,178       $ (207,216 )
 
 
 
 
 
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 6 months ending June 30, 2016 and 2015

 
      Year-to-Date    
   
(in thousands, except sales price and per unit data)       2016     2015     Change
 
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil $ 248,517 $ 330,627 $ (82,110 )
Natural gas liquids 22,517 25,615 (3,098 )
Natural gas         23,367         50,870         (27,503 )
Total       $ 294,401       $ 407,112       $ (112,711 )
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ (56,428 ) $ (155,503 ) $ 99,075
Natural gas         (4,454 )       (21,015 )       16,561  
Total       $ (60,882 )     $ (176,518 )     $ 115,636  
 
Closed gains (losses) on derivative instruments
Oil $ (1,203 ) $ 132,813 $ (134,016 )
Natural gas         1,668         26,777         (25,109 )
Total       $ 465       $ 159,590       $ (159,125 )
Total revenues       $ 233,984       $ 390,184       $ (156,200 )
 
Production volumes
Oil (MBbl) 6,944 6,829 115
Natural gas liquids (MMgal) 84.8 81.1 3.7
Natural gas (MMcf)         14,742         20,412         (5,670 )
Total production volumes (MBOE) 11,421         12,162         (741 )
 
Average daily production volumes
Oil (MBbl/d) 38.2 37.7 0.5
Natural gas liquids (MMgal/d) 0.5 0.5
Natural gas (MMcf/d)         81.0         112.8         (31.8 )
Total average daily production volumes (MBOE/d)         62.8         67.2         (4.4 )
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 35.62 $ 67.86 $ (32.24 )
Natural gas liquids (per gallon) $ 0.27 $ 0.32 $ (0.05 )
Natural gas (per Mcf) $ 1.70 $ 3.80 $ (2.10 )
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 35.79 $ 48.42 $ (12.63 )
Natural gas liquids (per gallon) $ 0.27 $ 0.32 $ (0.05 )
Natural gas (per Mcf) $ 1.59 $ 2.49 $ (0.90 )
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

7.93

$

9.98

$

(2.05

)

Production and ad valorem taxes $ 1.96 $ 2.67 $ (0.71 )
Depreciation, depletion and amortization $ 20.70 $ 23.37 $ (2.67 )
Exploration expense $ 0.15 $ 0.97 $ (0.82 )
General and administrative $ 4.65 $ 5.81 $ (1.16 )
Capital expenditures       $ 217,050       $ 678,282       $ (461,232 )
 
 
 
 
 

Source: Energen Corporation

Energen Corporation
Julie S. Ryland, 205-326-8421