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First Midland Basin Wells with Gen 3 Completions Show Substantial, Early Production Uplift
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Delaware Basin Production Expected to More than Double in 2017

Energen’s $790 MM Capital Program Includes Drilling 96 Gross Wells

FINANCIAL AND OPERATING HIGHLIGHTS

CY16

  • 4Q16 per-unit LOE and net SG&A outperformed midpoint of respective guidance ranges by approximately 16% and 10%
  • 4Q16 production of 53.5 mboepd exceeds guidance midpoint by 2.5%
  • Energen acquired ≈9,000 net acres in CY16 in Permian Basin focus areas for some $120 million, including 1,100 net acres in 4Q16
  • Proved reserve additions replaced production (excluding 2016 asset sales) by more than 300%
  • Updated inventory for YE16 reflects 3,545 net locations with > 2 billion boe of net resource potential

CY17 PLANS

  • Drilling and development capital estimated at $790 mm; includes Generation 3 fracs and 15% increase in pressure pumping costs
  • Annual production estimated to increase 20% to 65.7 mboepd; does not reflect potential uplift from Generation 3 fracs
  • Permian Basin horizontal production in 2017 estimated to increase 37 percent y/y
  • 4Q17 vs 4Q16 exit rate estimated to increase approximately 47%
  • Company plans to drill 96 gross wells, complete 124 gross wells (including 61 gross DUCs), and exit the year with 33 gross DUCs
  • Hedge position strengthened with additional 3-way oil collars and swaps, natural gas basin-specific contracts, and NGL swaps

WELL RESULTS

  • Energen’s first two Generation 3 completions in the Midland Basin show the average cumulative production substantially exceeding a 1 mmboe EUR type curve for a 7,500’ lateral well through 90 days
  • Cumulative production from the Checkers well, completed in the Delaware Basin in 3Q16 with a Generation 3 frac design and disclosed in 3Q16, continues to exceed the company’s 2 MMBOE EUR type curve for a 10,000’ lateral well through 90 days

NOTE: 4Q16 supplemental slides available at www.energen.com

BIRMINGHAM, Ala.--(BUSINESS WIRE)--Feb. 9, 2017-- 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]

                 
        4Q16       4Q15
        $M     $/dil. sh.       $M     $/dil. sh.
Net Income/(Loss) All Operations (GAAP)       $ (54,470 )     $ (0.56 )     $ (590,806 )     $ (7.50 )
Less: Non-cash mark-to-market gains/(losses)         (22,792 )       (0.23 )       (66,984 )       (0.85 )
Less: Asset impairments         (25 )     nm         (413,300 )       (5.25 )
Less: Pension and other expenses         --         --         (16,884 )       (0.21 )
Less: Income/(loss) associated with asset sales         (5,014 )       (0.05 )       (122,074 )       (1.55 )
Adj. Income Continuing Operations (Non-GAAP)       $ (26,639 )     $ (0.27 )     $ 28,436       $ 0.36  

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.

                         
2017 Horizontal Program       Gross/Net Wells       Avg. Lateral Length       Average WI
Midland Basin                        
YE16 DUC Completions       44/43       9,600’       98%
New Drills       56/48       8,200’       85%
New Drill Completions       34/28                
YE17 DUCs       22/20                
                         
Delaware Basin                        
YE16 DUCS       17/17       8,765’       98%
New Drills       33/29       8,400’       89%
New Drill Completions       25/22                
YE17 DUCs       8/7                

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.

     
         
Capital Summary by Basin       2017e Capital ($MM)
Midland Basin       $ 440
Delaware Basin       $ 345
Central Basin and ARO       $ 5
Drilling & Development Capital       $ 790
Acquisitions/Unproved Leasehold       $ 50
Total Capital Expenditures       $ 840
 
 

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.

 
Area       2017 Guidance     2016 Actual†     % Change
Midland Basin       36.5     35.3     3.4
Horizontal       29.4     26.5     10.9
Vertical       7.1     8.8     (19.3)
Delaware Basin       21.1     10.3     104.9
Central Basin Platform/Other       8.1     9.0     (10)
Total       65.7     54.6     20.3

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

                     
Commodity       2017 Guidance     2016 Actual†     % Change
Oil       42.8     34.5     24.1
NGL       11.1     9.4     18.1
Gas       11.8     10.7     10.3
Total Production       65.7     54.6     20.3

† 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.

               
Per BOE, except where noted       2017e     CY16 Actual†
LOE (production costs, marketing & transportation)       $7.60-$8.10     $7.86
Production & ad valorem taxes (% of revenues, excluding hedges)       6.6%     6.6%
DD&A expense       $17.60-$18.10     $21.45
Salaries and general & administrative expense, net       $3.50-$3.90    

$4.321

Exploration expense (seismic, delay rentals, etc.)       $0.20-$0.40     $0.27
Interest expense ($MM)       $30.0-$40.0     $36.9
FF&E depreciation ($MM)       $4.4-$4.8     $4.8
Accretion of discount on ARO ($MM)       $5.6-$6.0     $6.2
Effective tax rate (%)       35%-37%     32%

† 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)

                                       
Basin       YE15    

2016
Production

   

2016
Acquisitions/
(Divestitures)

   

2016
Additions

   

2016
Price/Other
Revisions

    YE16
Midland Basin       225.1     (12.9)     (1.0)     53.3     (28.1)     236.4
Delaware Basin       69.7     (4.3)     (38.1)     10.8     0.9     39.0
Central Basin Platform/Other       43.0     (3.3)     --     --     1.2     40.9
San Juan Basin       16.9     (1.1)     (15.8)     --     --     --
TOTAL       354.7     (21.6)     (54.9)     64.1     (26.0)     316.3

NOTE: Totals may not sum due to rounding

Proved Reserves by Commodity (MMBOE)

 
Commodity       2016     2015
Oil       200     211
Natural gas liquids       58     72
Natural gas       58     72
TOTAL       316     355

NOTE: Totals may not sum due to rounding

YE16 3P Reserves & Contingent Resources (MMBOE)

 
Basin       Proved     Probable     Possible     Contingent

Resources

    Total
Midland Basin       236     142     150     881     1,410
Delaware Basin       39     9     21     764     833
Central Basin Platform/Other       41     --     --     2     42
TOTAL       316     151     171     1,647     2,285

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)

                                       
Commodity     4Q16     4Q16 Guidance Mdpt     4Q15 3Q16     2Q16     1Q16
Oil     32.0     33.4     36.2 35.8     36.5     33.6
NGL     9.7     9.1     9.6 10.4     9.4     8.3
Natural Gas     11.8     9.7     11.0 10.3     10.2     10.4
Total     53.5     52.2     56.8 56.6     56.0     52.3
                   
                                         
Area       4Q16     4Q16 Guidance Mdpt     4Q15 3Q16     2Q16     1Q16
Midland Basin       33.2     32.9     35.9 38.2     37.1     33.0
Horizontal       25.0     24.8     25.5 29.2     28.5     23.3
Vertical       8.2     8.1     10.4 9.0     8.6     9.7
Delaware Basin       11.3     10.4     11.6 9.6     9.8     10.3
Central Basin/Other       9.0     8.9     9.3 8.7     9.1     9.0
Total       53.5     52.2     56.8 56.6     56.0     52.3

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

Average Realized Sales Prices (excludes asset sales)

                     
Commodity       4Q16     4Q15     % Change
Oil (per barrel)       $ 41.36     $ 74.09     (44)
NGL (per gallon)       $ 0.38     $ 0.28     36
Natural Gas (per Mcf)       $ 2.16     $ 4.08     (47)
             

Average Prices Before Effects of Hedges (excludes asset sales)

                     
Commodity       4Q16     4Q15     % Change
Oil (per barrel)       $ 45.57     $ 39.40     16
NGL (per gallon)       $ 0.38     $ 0.28     36
Natural Gas (per Mcf)       $ 2.27     $ 1.84     23
             

Expenses (excludes asset sales)

               
Per BOE, except where noted       4Q16     4Q15
LOE (including marketing and transportation)       $ 7.85     $ 8.52
Production & ad valorem taxes       $ 1.89     $ 1.90
DD&A       $ 20.79     $ 27.46
Net SG&A       $ 4.25     $ 5.11
Interest ($MM)       $ 9.0     $ 10.0

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

2016 Capital Summary

                     
        2016 Capital

($MM)

    Wells Drilled     Wells Completed
          Operated Gross (Net)     Operated Gross (Net)
Midland Basin       $ 307       52 (50) *     56 (55) †
Delaware Basin       $ 118       21 (21) **    

4 (4)

Central Basin/Other/ARO       $ 8              
                     
Drilling & Development Capital      

$

433

1

    73 (71)    

60 (59)

Acquisitions/Unproved Leasehold       $ 148              
Total Capital Expenditures       $ 581              

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

                           
Guidance by Basin (mboepd)       1Q17     2Q17     3Q17     4Q17
Midland Basin       30.6     34.2     38.6     42.3
Delaware Basin       11.3     19.8     24.6     28.4
Central Basin Platform/Other       8.3     8.2     8.1     7.9
Total       50.2     62.2     71.3     78.6
                           
Guidance by Commodity (mboepd)       1Q17     2Q17     3Q17     4Q17
Oil       31.4     40.6     46.6     52.1
NGL       9.1     10.5     11.9     12.8
Gas       9.7     11.1     12.8     13.7
Total       50.2     62.2     71.3     78.6
                 

Operating Expenses

                           
Per BOE, except where noted       1Q17     2Q17     3Q17     4Q17
LOE*       $9.10-$9.40     $8.10-$8.40     $7.35-$7.65     $6.90-$7.20
Production & ad valorem taxes**       7.5%     6.6%     6.3%     6.3%
DD&A expense       $20.75-$21.15     $18.50-$18.90     $17.20-$17.60     $15.50-$15.9†
SG&A, net       $4.95-$5.25     $3.85-$4.15     $3.05-$3.35     $2.75-$3.05
Exploration exp. (seismic, delay rentals, etc.)       $0.30-$0.40     $0.20-$0.30     $0.30-$0.40     $0.25-$0.35
Effective tax rate (%)       33%-35%     37%-39%     36%-38%     34%-36%

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

                             
Gross Horizontal Wells         1Q17     2Q17     3Q17     4Q17
Midland Basin
Wells Drilled         17     13     12     14
First Production         10     26     18     24
Delaware Basin
Wells Drilled         13     4     8     8
First Production         3     14     11     8
                   
 

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:

                 
Oil       2017 Hedge Volumes       Avg. NYMEX Price
Swaps       6.1 mmbo       $ 49.77 per barrel

Three way Collars1

      4.8 mmbo        
Call Price               $ 62.18 per barrel
Put Price               $ 45.00 per barrel
Short Put Price               $ 35.00 per barrel

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:

                               
Commodity       Hedge Volumes       Production Guidance     % Hedged       Avg. NYMEXe Price
NGL       80.0 mm gallons       170 mm gallons     47%       $ 0.57 per gallon
Natural gas       15.6 bcf       26 bcf     60%       $ 3.21 per Mcf
                     

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:

                 
Oil       1Q17 Hedge Volumes       Avg. NYMEX Price
Swaps       1.0 mmbo       $ 47.97 per barrel
Three way Collars       1.2 mmbo        
Call Price               $ 62.37 per barrel
Put Price               $ 45.00 per barrel
Short Put Price               $ 35.00 per barrel
           

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

                           
Commodity       Hedge Volumes     Production Guidance     Hedge %     NYMEXe Price
NGL       17.6 mm gallons     34.4 mm gallons     51%     $ 0.56 per gallon
Natural Gas       3.3 bcf     5.2 bcf     63%     $ 3.22 per mcf
                 

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):

                     
            1Q17       CY17
Crude oil (% of NYMEX/WTI)           94%       94%
NGL (after T&F) (% of NYMEX/WTI)           35%       34%
Natural gas (% of NYMEX/Henry Hub)           80%       80%
               

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:

                 
Oil       2018 Hedge Volumes       Avg. NYMEX Price
Three way Collars       5.6 mmbo        
Call Price               $ 65.18 per barrel
Put Price               $ 50.00 per barrel
Short Put Price               $ 40.00 per barrel
           

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.

 
 
 
 
 

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, certain pension and pension settlement expenses and income and losses associated with divestitures. 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 12/31/2016
Energen Net Income ($ in millions except per share data)     Net Income    

Per Diluted

Share

Net Income (Loss) All Operations (GAAP) (54.5 )   (0.56 )
Non-cash mark-to-market losses (net of $12.5 tax) 22.8 0.23
Asset impairment, other (net of $0.0 tax) * nm nm
Loss associated with property sales (net of $1.3 tax)     5.0     0.05  
Adjusted Income from Continuing Operations (Non-GAAP)     (26.6 )   (0.27 )
* Approximately $25,000 (net of tax)
     
Three Months Ended 12/31/2015
Energen Net Income ($ in millions except per share data)     Net Income    

Per Diluted

Share

Net Income (Loss) All Operations (GAAP) (590.8 ) (7.50 )
Non-cash mark-to-market losses (net of $37.1 tax) 67.0 0.85
Asset impairment, other (net of $233.3 tax) 413.3 5.25
Pension and pension settlement expenses (net of $9.4 tax) 16.9 0.21
Loss associated with property sales (net of $71.1 tax)     122.1     1.55  
Adjusted Income from Continuing Operations (Non-GAAP)     28.4     0.36  
 
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 certain pension and pension settlement expenses, income and losses associated with  divestitures, 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 12/31
($ in millions)     2016   2015
 
Energen Net Income (Loss) (GAAP) (54.5 ) (590.8 )
Loss associated with property sales, net of tax     5.0     122.1  
Net Income (Loss) Excluding Property Sales (Non-GAAP)     (49.5 )   (468.7 )
Interest expense 9.0 10.0
Income tax expense (benefit) * (21.5 ) (263.6 )
Depreciation, depletion and amortization * 103.4 144.8
Accretion expense * 1.6 1.5
Exploration expense * 3.6 0.3
Adjustment for asset impairment * 0.0 646.6
Adjustment for mark-to-market losses 35.3 104.1
Adjustment for pension and pension settlement expenses     0.0     26.2  
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)     82.1     201.2  
 
 
Note: Amounts may not sum due to rounding
 
* Amount adjusted to exclude property sales in either current or prior period. See reconciliation to GAAP Information for the Three Months Ended 12/31/2016 and 12/31/2015.
 
 
 
 
 

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 divestitures 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 Property Sales          
Reconciliation to GAAP Information Year Ended
December 31, 2016
(in thousands except per share and production data)                  
GAAP   $/BOE   Property Sales   Non-GAAP   $/BOE
Revenues  
Oil, natural gas liquids and natural gas sales $ 621,366 $ 29,808 $ 591,558
Gain (loss) on derivative instruments       (88,477 )         -       (88,477 )    
Total Revenues       532,889           29,808       503,081      
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 171,714 $ 7.94 14,784 156,930 $ 7.85
Production and ad valorem taxes 42,938 $ 1.98 3,589 39,349 $ 1.97
O&G Depreciation, depletion and amortization 443,007 $ 20.47 14,366 428,641 $ 21.45
FF&E Depreciation, depletion and amortization 4,954 $ 0.23 153 4,801 $ 0.24
Asset impairment 220,652 31,407 189,245
Exploration 5,415 $ 0.25 117 5,298 $ 0.27
General and administrative † 95,689 $ 4.42 523 95,166 $ 4.76
Accretion of discount on asset retirement obligations 6,672 501 6,171
(Gain) loss on sale of assets and other       (246,922 )         (246,283 )     (639 )    
Total costs and expenses       744,119           (180,843 )     924,962      
Operating Income (Loss)       (211,230 )         210,651       (421,881 )    
Other Income/(Expense)
Interest expense (36,899 ) - (36,899 )
Other income       978           58       920      
Total other expense       (35,921 )         58       (35,979 )    
 
Loss Before Income Taxes (247,151 ) 210,709 (457,860 )
Income tax expense (benefit)       (79,638 )         76,102       (155,740 )    
Net Income (Loss)     $ (167,513 )       $ 134,607     $ (302,120 )    
                       
Diluted Earnings Per Average Common Share     $ (1.77 )       $ 1.43     $ (3.20 )    
                       
Basic earning Per Average Common Share     $ (1.77 )       $ 1.43     $ (3.20 )    
 
Oil 13,213 597 12,616
NGL 3,892 432 3,460
Natural Gas       4,534           629       3,905      
Total Production (mboe)       21,639           1,658       19,981      
Total Production (boepd)       59,123           4,530       54,593      
 
Note: Amounts may not sum due to rounding
 
† General and administrative includes $8,824 or $0.44 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 divestitures 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 Property Sales          
Reconciliation to GAAP Information Three Months Ended
December 31, 2016
(in thousands except per share and production data)  
GAAP   $/BOE   Property Sales   Non-GAAP   $/BOE
Revenues  
Oil, natural gas liquids and natural gas sales $ 162,992 $ 42 $ 162,950
Gain (loss) on derivative instruments       (48,472 )         -       (48,472 )    
Total Revenues       114,520           42       114,478      
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 38,867 $ 7.90 258 38,609 $ 7.85
Production and ad valorem taxes 9,516 $ 1.93 209 9,307 $ 1.89
O&G Depreciation, depletion and amortization 102,230 $ 20.78 - 102,230 $ 20.79
FF&E Depreciation, depletion and amortization 1,167 $ 0.24 - 1,167 $ 0.24
Asset impairment 40 - 40
Exploration 3,635 $ 0.74 - 3,635 $ 0.74
General and administrative 20,906 $ 4.25 1 20,905 $ 4.25
Accretion of discount on asset retirement obligations 1,580 - 1,580
(Gain) loss on sale of assets and other       5,175           5,889       (714 )    
Total costs and expenses       183,116           6,357       176,759      
Operating Income (Loss)       (68,596 )         (6,315 )     (62,281 )    
Other Income/(Expense)
Interest expense (9,041 ) - (9,041 )
Other income       398           8       390      
Total other expense       (8,643 )         8       (8,651 )    
 
Loss Before Income Taxes (77,239 ) (6,307 ) (70,932 )
Income tax expense (benefit)       (22,769 )         (1,293 )     (21,476 )    
Net Income (Loss)     $ (54,470 )       $ (5,014 )   $ (49,456 )    
                       
Diluted Earnings Per Average Common Share     $ (0.56 )       $ (0.05 )   $ (0.51 )    
                       
Basic earning Per Average Common Share     $ (0.56 )       $ (0.05 )   $ (0.51 )    
 
Oil 2,944 1 2,943
NGL 892 1 891
Natural Gas       1,084           -       1,084      
Total Production (mboe)       4,920           2       4,918      
Total Production (boepd)       53,478           22       53,457      
 
Note: Amounts may not sum due to rounding
 
 
 
 
 
 
 

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 divestitures 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 Property Sales
Reconciliation to GAAP Information       Three Months Ended
December 31, 2015
(in thousands except per share and production data)  
GAAP   $/BOE   Property Sales   Non-GAAP   $/BOE
Revenues        
Oil, natural gas liquids and natural gas sales $ 167,751 $ 15,150 $ 152,601
Gain (loss) on derivative instruments         25,048           -       25,048      
Total Revenues         192,799           15,150       177,649      
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 52,447 $ 8.79 7,938 44,509 $ 8.52
Production and ad valorem taxes 11,597 $ 1.94 1,668 9,929 $ 1.90
O&G Depreciation, depletion and amortization 158,371 $ 26.54 14,889 143,482 $ 27.46
FF&E Depreciation, depletion and amortization 1,413 $ 0.24 100 1,313 $ 0.25
Asset impairment 825,918 179,319 646,599
Exploration 2,604 $ 0.44 2,271 333 $ 0.06
General and administrative † 54,794 $ 9.18 1,818 52,976 $ 10.14
Accretion of discount on asset retirement obligations 1,729 246 1,483
(Gain) loss on sale of assets and other         (524 )         79       (603 )    
Total costs and expenses         1,108,349           208,328       900,021      
Operating Income (Loss)         (915,550 )         (193,178 )     (722,372 )    
Other Income/(Expense)
Interest expense (10,022 ) - (10,022 )
Other income         80           46       34      
Total other expense         (9,942 )         46       (9,988 )    
 
Loss Before Income Taxes (925,492 ) (193,132 ) (732,360 )
Income tax expense (benefit)         (334,686 )         (71,058 )     (263,628 )    
Net Income (Loss)       $ (590,806 )       $ (122,074 )   $ (468,732 )    
                         
Diluted Earnings Per Average Common Share       $ (7.50 )       $ (1.55 )   $ (5.95 )    
                         
Basic earning Per Average Common Share       $ (7.50 )       $ (1.55 )   $ (5.95 )    
 
Oil 3,584 254 3,330
NGL 1,078 191 887
Natural Gas         1,305           296       1,009      
Total Production (mboe)         5,967           741       5,226      
Total Production (boepd)         64,859           8,054       56,804      
 
Note: Amounts may not sum due to rounding
 
† General and administrative includes $26,246 or $5.02 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 divestitures 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 Property Sales        
Reconciliation to GAAP Information Quarter Ended
September 30, 2016
         
GAAP   Property Sales   Non-GAAP
 
Oil 3,325 30 3,295
NGL 980 22 958
Natural Gas     993   43   950
Total Production (mboe)     5,298   95   5,203
Total Production (boepd)     57,587   1,033   56,554
 
 
Energen Production Excluding Property Sales
Reconciliation to GAAP Information Quarter Ended
June 30, 2016
         
GAAP   Property Sales   Non-GAAP
 
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
 
               
Energen Production Excluding Property Sales
Reconciliation to GAAP Information Quarter Ended
March 31, 2016
         
GAAP   Property Sales   Non-GAAP
 
Oil 3,386 327 3,059
NGL 953 197 756
Natural Gas     1,241   295   946
Total Production (mboe)     5,580   819   4,761
Total Production (boepd)     61,319   9,000   52,319
 
Note: Amounts may not sum due to rounding
 
 
 
 
 
 
 

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 3 months ending December 31, 2016 and 2015

 
      4th Quarter    
   
(in thousands, except per share data)       2016     2015     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 162,992 $ 167,751 $ (4,759 )
Gain (loss) on derivative instruments, net         (48,472 )       25,048         (73,520 )
 
Total revenues         114,520         192,799         (78,279 )
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 38,867 52,447 (13,580 )
Production and ad valorem taxes 9,516 11,597 (2,081 )
Depreciation, depletion and amortization 103,397 159,784 (56,387 )
Asset impairment 40 825,918 (825,878 )
Exploration 3,635 2,604 1,031

General and administrative (including non-cash stock based compensation of $5,148 and $870 for the three months ended Dec. 31, 2016, and 2015, respectively)

20,906

54,794

(33,888

)

Accretion of discount on asset retirement obligations 1,580 1,729 (149 )
(Gain) loss on sale of assets and other         5,175         (524 )       5,699  
 
Total operating costs and expenses         183,116         1,108,349         (925,233 )
 
Operating Loss         (68,596 )       (915,550 )       846,954  
 
Other Income (Expense)
Interest expense (9,041 ) (10,022 ) 981
Other income         398         80         318  
 
Total other expense         (8,643 )       (9,942 )       1,299  
 
Loss Before Income Taxes (77,239 ) (925,492 ) 848,253
Income tax benefit         (22,769 )       (334,686 )       311,917  
 
Net Loss       $ (54,470 )     $ (590,806 )     $ 536,336  
                           
Diluted Earnings Per Average Common Share       $ (0.56 )     $ (7.50 )     $ 6.94  
Basic Earnings Per Average Common Share       $ (0.56 )     $ (7.50 )     $ 6.94  
Diluted Average Common Shares Outstanding         97,074         78,783         18,291  
Basic Average Common Shares Outstanding         97,074         78,783         18,291  
Dividends Per Common Share       $       $ 0.02       $ (0.02 )
 
 
 
 
 
 
 

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 12 months ending December 31, 2016 and 2015

 
      Year-to-date    
   
(in thousands, except per share data)       2016     2015     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $

621,366

$ 763,261 $ (141,895 )
Gain (loss) on derivative instruments, net         (88,477 )       115,293         (203,770 )
 
Total revenues         532,889         878,554         (345,665 )
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production

171,714

228,380 (56,666 )
Production and ad valorem taxes 42,938 57,380 (14,442 )
Depreciation, depletion and amortization 447,961 593,789 (145,828 )
Asset impairment 220,652 1,292,308 (1,071,656 )
Exploration 5,415 14,878 (9,463 )

General and administrative (including non-cash stock based compensation of $19,641 and $12,910 for the years ended December 31, 2016, and 2015, respectively)

95,689

149,132

(53,443

)

Accretion of discount on asset retirement obligations 6,672 7,108 (436 )
Gain on sale of assets and other         (246,922 )       (26,570 )       (220,352 )
 
Total operating costs and expenses         744,119         2,316,405         (1,572,286 )
 
Operating Loss         (211,230 )       (1,437,851 )       1,226,621  
 
Other Income (Expense)
Interest expense (36,899 ) (43,108 ) 6,209
Other income         978         223         755  
 
Total other expense         (35,921 )       (42,885 )       6,964  
 
Loss Before Income Taxes (247,151 ) (1,480,736 ) 1,233,585
Income tax benefit         (79,638 )       (535,005 )       455,367  
 
Net Loss       $ (167,513 )     $ (945,731 )     $ 778,218  
                           
Diluted Earnings Per Average Common Share       $ (1.77 )     $ (12.43 )     $ 10.66  
Basic Earnings Per Average Common Share       $ (1.77 )     $ (12.43 )     $ 10.66  
Diluted Average Common Shares Outstanding         94,476         76,078         18,398  
Basic Average Common Shares Outstanding         94,476         76,078         18,398  
Dividends Per Common Share       $       $ 0.08       $ (0.08 )
 
 
 
 
 
 
 

CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of December 31, 2016 and December 31, 2015

 
(in thousands)       December 31, 2016     December 31, 2015
         
 
ASSETS
Current Assets
Cash and cash equivalents $ 386,093 $ 1,272
Accounts receivable, net 73,322 63,097
Inventories 14,222 11,255
Assets held for sale 93,739
Derivative instruments 50 56,963
Income tax receivable 27,153 8,376
Prepayments and other         5,071       11,638
 
 
Total current assets         505,911       246,340
 
 
Property, Plant and Equipment
Oil and natural gas properties, net 4,016,683 4,302,332
Other property and equipment, net         44,869       48,358
 
 
Total property, plant and equipment, net         4,061,552       4,350,690
 
 
Other postretirement assets 3,619 3,881
Other assets 8,741 10,245
 
 
TOTAL ASSETS       $ 4,579,823     $ 4,611,156
 

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities
Long-term debt due within one year 24,000
Accounts payable 65,031 64,742
Accrued taxes 7,252 5,801
Accrued wages and benefits 25,089 28,563
Accrued capital costs 79,988 79,206
Revenue and royalty payable 51,217 60,493
Liabilities related to assets held for sale 12,789
Pension liabilities 15,685
Derivative instruments 65,467 459
Other         20,160       19,783
 
 
Total current liabilities         338,204       287,521
 
 
Long-term debt 527,443 773,550
Asset retirement obligations 81,544 89,990
Noncurrent derivative instruments 3,006
Deferred income taxes 495,888 552,369
Other         13,136       11,866
 
 
Total liabilities         1,459,221       1,715,296
 
 
Total Shareholders’ Equity         3,120,602       2,895,860
 
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY       $ 4,579,823     $ 4,611,156
 
 
 
 
 
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending December 31, 2016 and 2015

 
      4th 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 $ 134,112 $ 140,505 $ (6,393 )
Natural gas liquids 14,068 12,240 1,828
Natural gas         14,812         15,006         (194 )
Total       $ 162,992       $ 167,751       $ (4,759 )
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ (23,704 ) $ (92,484 ) $ 68,780
Natural gas liquids (5,914 ) (5,914 )
Natural gas         (5,712 )       (11,586 )       5,874  
Total       $ (35,330 )     $ (104,070 )     $ 68,740  
 
Closed gains (losses) on derivative instruments
Oil $ (12,380 ) $ 115,519 $ (127,899 )
Natural gas         (762 )       13,599         (14,361 )
Total       $ (13,142 )     $ 129,118       $ (142,260 )
Total revenues       $ 114,520       $ 192,799       $ (78,279 )
 
Production volumes
Oil (MBbl) 2,944 3,584 (640 )
Natural gas liquids (MMgal) 37.5 45.3 (7.8 )
Natural gas (MMcf)         6,504         7,830         (1,326 )
Total production volumes (MBOE) 4,920         5,967         (1,047 )
 

Average daily production volumes Oil (MBbl/d)

32.0

 

39.0

(7.0

)

Natural gas liquids (MMgal/d) 0.4 0.5 (0.1 )
Natural gas (MMcf/d)         70.7         85.1         (14.4 )
Total average daily production volumes (MBOE/d)         53.5         64.9         (11.4 )
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 41.35 $ 71.44 $ (30.09 )
Natural gas liquids (per gallon) $ 0.38 $ 0.27 $ 0.11
Natural gas (per Mcf) $ 2.16 $ 3.65 $ (1.49 )
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 45.55 $ 39.20 $ 6.35
Natural gas liquids (per gallon) $ 0.38 $ 0.27 $ 0.11
Natural gas (per Mcf) $ 2.28 $ 1.92 $ 0.36
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

7.90

$

8.79

$

(0.89

)

Production and ad valorem taxes $ 1.93 $ 1.94 $ (0.01 )
Depreciation, depletion and amortization $ 21.02 $ 26.78 $ (5.76 )
Exploration expense $ 0.74 $ 0.44 $ 0.30
General and administrative $ 4.25 $ 9.18 $ (4.93 )
Capital expenditures       $ 154,455       $ 196,010       $ (41,555 )
 
 
 
 
 
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 12 months ending December 31, 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 $ 521,017 $ 631,663 $ (110,646 )
Natural gas liquids 48,652 48,856 (204 )
Natural gas         51,697         82,742         (31,045 )
Total       $ 621,366       $ 763,261       $ (141,895 )
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ (57,148 ) $ (242,227 ) $ 185,079
Natural gas liquids (6,868 ) (6,868 )
Natural gas         (7,174 )       (39,525 )       32,351  
Total       $ (71,190 )     $ (281,752 )     $ 210,562  
 
Closed gains (losses) on derivative instruments
Oil $ (17,701 ) $ 346,404 $ (364,105 )
Natural gas         414         50,641         (50,227 )
Total       $ (17,287 )     $ 397,045       $ (414,332 )
Total revenues       $ 532,889       $ 878,554       $ (345,665 )
 
Production volumes
Oil (MBbl) 13,213 14,023 (810 )
Natural gas liquids (MMgal) 163.5 170.7 (7.2 )
Natural gas (MMcf)         27,204         35,604         (8,400 )
Total production volumes (MBOE) 21,639         24,022         (2,383 )
 

Average daily production volumes Oil (MBbl/d)

36.1

38.4

(2.3

)

Natural gas liquids (MMgal/d) 0.4 0.5 (0.1 )
Natural gas (MMcf/d)         74.3         97.5         (23.2 )
Total average daily production volumes (MBOE/d)         59.1         65.8         (6.7 )
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 38.09 $ 69.75 $ (31.66 )
Natural gas liquids (per gallon) $ 0.30 $ 0.29 $ 0.01
Natural gas (per Mcf) $ 1.92 $ 3.75 $ (1.83 )
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 39.43 $ 45.04 $ (5.61 )
Natural gas liquids (per gallon) $ 0.30 $ 0.29 $ 0.01
Natural gas (per Mcf) $ 1.90 $ 2.32 $ (0.42 )
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

7.93

$

9.51

$

(1.58

)

Production and ad valorem taxes $ 1.98 $ 2.39 $ (0.41 )
Depreciation, depletion and amortization $ 20.70 $ 24.72 $ (4.02 )
Exploration expense $ 0.25 $ 0.62 $ (0.37 )
General and administrative $ 4.42 $ 6.21 $ (1.79 )
Capital expenditures       $ 582,898       $ 1,114,808       $ (531,910 )
 
 
 
 

Source: Energen Corporation

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



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