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08/06/15

Energen Raises 2015 Annual Production Guidance by 500,000 BOE

Download PDF2Q15 Supplemental Slides

Strong Results Generated by 9 Appraisal Wells in Delaware, Midland basins

Continued Efficiency Gains Reflected in Declining Days to Drill Development Wells

Highlights

  • Record production in 2015 estimated to increase 19% from 2014, with oil estimated to be up 21%
  • Average length of time to drill to total depth 7,500’ Wolfcamp A development wells in Glasscock Co. in 2Q15 dropped by 7 days to 14, as efficiency gains continued; the shortest drill time was 11 days from spud to TD
  • East to west across the southern Delaware Basin, 6 new Wolfcamp appraisal wells generate encouraging results
  • Oil production from Lower Spraberry wells in Martin, Howard, Midland counties suggests attractive return potential
  • 2Q15 production totaled 63,800 boepd, exceeding guidance midpoint by 8%
  • 2Q15 oil production grew 27% from same period last year
  • 4Q15 production rate estimated to average almost 68,000 boepd
  • Capital budget increased 10% for additional drilling, completions, and facilities in Midland Basin in 2nd half of 2015
  • Energen to drill additional 22 gross (19 net) wells in Midland Basin in Second Half of 2015
  • Drilling under way in Rio Arriba Co., NM, as Energen begins to assess Mancos oil potential on its San Juan Basin acreage
  • 2Q15 Glasscock Co. development program wells generated peak 30-day average rates of more than 850 boepd

BIRMINGHAM, Ala.--(BUSINESS WIRE)--Aug. 6, 2015-- For the 3 months ended June 30, 2015, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $111.6 million, or $(1.52) per diluted share. Excluding mark-to-market derivatives losses, impairment losses and other non-cash items, and a purchase price adjustment from the sale of the majority of the company’s San Juan Basin assets in March 2015, Energen’s adjusted income in the 2nd quarter of 2015 totaled $7.7 million, or $0.10 per diluted share. This compares with adjusted income from continuing operations in the 2nd quarter of 2014 of $26.0 million, or $0.36 per diluted share. The variance between the periods largely is attributable to a 22 percent decline in realized oil and natural gas liquids (NGL) prices and higher depreciation, depletion, and amortization expense (DD&A) associated with increased drilling activity, partially offset by a 23 percent increase in production. [See “Non-GAAP Financial Measures” beginning on pp 14 for more information and reconciliation.]

Energen’s adjusted EBITDAX totaled $180.3 million in the 2nd quarter of 2015, up 4 percent from adjusted EBITDAX from continuing operations in the same period last year of $172.9 million. [See “Non-GAAP Financial Measures” beginning on pp 14 for more information and reconciliation.]

The company’s adjusted 2nd quarter net income approximated internal expectations as increased production, lower lease operating expenses (LOE), and lower production and ad valorem taxes were essentially offset by increased depreciation expense, lower commodity prices, higher net general and administrative expense (G&A), and the timing of geological and geophysical (G&G) exploration expenses.

Production in the 2nd quarter of 2015 exceeded the guidance range midpoint by 8 percent (approximately 4,635 boepd) largely due to the continued impact of accelerated completions in the first quarter on Delaware Basin production, better-than-expected well performance from Wolfcamp and 3rd Bone Spring wells in the Delaware Basin, and the timing of horizontal completions in the Midland Basin.

“Energen’s strong performance as a leading operator in the Permian Basin continued in the second quarter,” said James McManus, Energen’s chairman and chief executive officer. “Our oil production increased almost 8,400 barrels a day from the same period last year and 11 percent from the 1st quarter, and we now expect total production in 2015 to show 19 percent growth, year-over-year.

“We have continued to improve our drilling efficiency by driving down the number of days to drill to total depth in our Glasscock County development program. We have continued to refine our completions and are encouraged by the early production response we have seen in our latest Wolfcamp development wells. Production from our Lower Spraberry shale appraisal wells in the northern Midland Basin continues to suggest the potential for outstanding returns. And an excellent set of Wolfcamp results across the Delaware Basin continues to build an encouraging body of data that supports the long-term potential of this play.

“Energen is well capitalized and well positioned to navigate through this period of uncertain commodity prices; but, as we look ahead to 2016, we plan to proceed at a pace of development and investment that will maintain our balance sheet strength and financial flexibility,” McManus added. “We have outstanding assets in the Midland and Delaware Basins that support a rich inventory of opportunities, and we plan to develop those assets in a manner that supports value creation for our shareholders.”

2nd Quarter Financial Review

Excluding mark-to-market derivatives losses, impairment losses and other non-cash items, and a purchase price adjustment from the sale of the majority of the company’s San Juan Basin assets in March 2015, Energen’s adjusted income in the 2nd quarter of 2015 totaled $7.7 million, or $0.10 per diluted share. This compares with adjusted income from continuing operations in the 2nd quarter of 2014 of $26.0 million, or $0.36 per diluted share. The variance between the periods largely is attributable to a 22 percent decline in realized oil and NGL prices and higher DD&A expense associated with increased drilling activity partially offset by a 23 percent increase in production. [See “Non-GAAP Financial Measures” beginning on pp 14 for more information and reconciliation.]

More than 75 percent of the after-tax asset impairments of $42.9 million is related to a write down of a field in the Central Basin Platform that is in tertiary recovery ($33 million); another $3.0 million covers approximately 775 net acres in Reeves County (Enterprise area).

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations
[See “Non-GAAP Financial Measures” beginning on pp 14 for more information]

             
      2Q15     2Q14
    $M     $/dil. sh.     $M     $/dil. sh.
Net Income/(Loss) All Operations (GAAP) $ (111,601 )     $ (1.52 )     $ (7,953 )     $ (0.11 )
Less: Non-cash Mark-to-Market gain/(loss) (75,133 ) (1.02 ) (38,131 ) (0.52 )
Less: Asset Impairment, other (42,878 ) (0.58 ) (1,630 ) (0.02 )
Less: Income Associated w/ San Juan Basin Divestment (1,249 ) (0.02 ) 10,615 0.15
Less: Discontinued Operations       --         --         (4,799 )       (0.07 )
Adj. Income Continuing Operations (Non-GAAP)     $ 7,659       $ 0.10       $ 25,992       $ 0.36  

Note: Per share amounts may not sum due to rounding

 

Production from Continuing Operations (excludes production associated with San Juan divestiture)

                                           
Commodity       2Q15 2Q14     Change

(MBOE)

1Q15     Change

(MBOE)

      MBOE     boepd MBOE     boepd       MBOE     boepd      
Oil 3,595     39,505 2,830     31,099     27 % 3,233     35,922     11 %
NGL 1,060 11,648 898 9,868 18 % 732 8,133 45 %
Natural Gas       1,151     12,648 986     10,835     17 % 904     10,044     27 %
Total       5,806     63,802 4,714     51,802     23 % 4,869     54,100     19 %

Note: Totals may not sum due to rounding

 

Production from Continuing Operations (excludes production associated with San Juan divestiture)

                                         
Area       2Q15 2Q14     Change

(MBOE)

1Q15     Change

(MBOE)

      MBOE     boepd MBOE     boepd       MBOE     boepd      
Midland Basin 2,957     32,495 1,755     19,286     68 % 2,320     25,778     27 %
Wolfcamp/Cline/Spraberry 1,751 19,242 384 4,220 1,293 14,367 35 %
Wolfberry 1,206 13,253 1,371 15,066

 

1,027 11,411 17 %
Delaware Basin 1,450 15,934 1,488 16,352 (3)% 1,225 13,611 18 %
3rd Bone Spring/Other 963 10,582 1,174 12,901 875 9,722 10 %
Wolfcamp 487 5,352 314 3,451 350 3,889 39 %
Central Basin Platform       918     10,088 1,060     11,648     (13)% 909     10,100     1 %
Total Permian Basin 5,324 58,505 4,303 47,286 24 % 4,454 49,489 20 %
San Juan Basin/Other       482     5,297 411     4,516     17 % 415     4,611     16 %
Total       5,806     63,802 4,714     51,802     23 % 4,869     54,100     19 %

Note: Totals may not sum due to rounding

 

Average Realized Sales Prices from Continuing Operations

                       
Commodity           2Q15         2Q14         Change
Oil (per barrel) $ 67.86 $ 83.65 (19) %
NGL (per gallon) $ 0.33 $ 0.72 (54) %
Natural Gas (per Mcf)           $ 3.77        

$

2.92

*

      29 %

* Prior period hedges were left unallocated for current-year San Juan Basin divestiture; as reported last year, the average realized sales price of natural gas in 2Q14 was $4.25 per Mcf.

Average Prices from Continuing Operations Before Effects of Hedges

                         
Commodity           2Q15         2Q14         Change
Oil (per barrel) $ 52.47 $ 92.75 (43) %
NGL (per gallon) $ 0.33 $ 0.72 (54) %
Natural Gas (per Mcf)           $ 2.24         $ 3.92         (43) %
 

Expenses from Continuing Operations and Excluding San Juan Basin Assets sold March 31, 2015
(per BOE, except interest expense)

                       
Expenses           2Q15         2Q14         Change
LOE* $ 8.90 $ 10.54 (16) %
Production & ad valorem taxes $ 2.33 $ 5.15 (55) %
DD&A $ 25.56 $ 25.63 (0.3) %
Net G&A

$ 6.47

$ 7.25 (11) %
Interest ($MM)           $ 11.2         $ 8.0         40 %
 

* Production costs + workovers and repairs + marketing and transportation
† Excludes $0.19 per BOE for pension and pension settlement expenses

2nd Quarter Comparisons, 2015 vs 2014 (excluding San Juan Basin assets sold March 31, 2015)

  • The success of Energen’s Wolfcamp development program led to a 68 percent increase in Midland Basin production; combined with expected declines in the 3rd Bone Spring play in the Delaware Basin and the company’s legacy assets in the Central Basin Platform, Energen’s total Permian Basin production increased 24 percent.
  • The company’s average realized oil price fell 19 percent, while the realized price of NGL dropped 54 percent. Excluding the impact of commodity and differential hedges, the average realized price of oil would have been $52.47 per barrel.
  • LOE per unit declined 16 percent to $8.90 per barrel largely due to the timing of workover expense, lower power costs, and increased production, partially offset by higher rental equipment and water disposal costs. Per-unit production and ad valorem taxes declined 55 percent.
  • Per-unit DD&A expense was essentially unchanged.
  • Per-unit net G&A expense of $6.47 per BOE (excluding pension and pension settlement expenses) declined 11 percent from the same period a year ago largely due to increased production.
  • Interest expense increased 40 percent largely due to a prior-year reclassification of certain interest expense to discontinued operations.

Liquidity Update

On June 22, Energen closed on the sale of 5.7 million shares of common stock for net proceeds of $399 million. Energen initially used net proceeds to repay borrowings outstanding under its revolving credit facility.

As of June 30, 2015, Energen had borrowings of $133.0 million on its revolving credit facility, which has a $1.6 billion borrowing base, and cash/cash equivalents of $1.5 million, for total liquidity available of $1.47 billion. Long-term debt at the end of June totaled $553.6 million.

Midland Basin Development Program Results

             
Development program wells drilled in 2Q15 (gross/net)           29/27
Development program wells completed in 2Q15 (gross/net) 19/19
Development program wells awaiting completion at end of 2Q15 (gross/net) (gross/net) 44/42
Development program wells awaiting completion at YE15e (gross/net)           46/42
 

In its 2-well, pad-drilling development program in Glasscock County, Energen tested eight Wolfcamp A and B wells during the 2nd quarter of 2015. These wells generated average peak 24-hour IP rates (3-stream) of 1,076 boepd (83% oil) and peak 30-day average rates (3-stream) of 856 boepd (68% oil). These average rates were substantially higher than the comparable rates for the larger group of 22 gross development wells tested in the 1st quarter and likely were positively impacted, at least in part, by an adjustment made to the company’s completion design.

The 57 gross (56 net) wells tested since the program’s inception in 2014 have generated average peak 24-hour IPs (3-stream) of 930 boepd (81% oil) and peak 30-day average rates (3-stream) of 742 boepd (74% oil). A supplemental slide posted at www.energen.com shows that the average production from these wells -- normalized to a 7,000’ lateral length – are tracking very closely to the company’s unrisked type curve normalized to 7,000’.

Energen continued to achieve efficiency gains in its development drilling program in Glasscock County in the second quarter. For example, the average days to drill to total depth a Wolfcamp A well with a 7,500’ lateral declined by approximately 7 days -- from 21 to 14 -- and the drill & complete cost of that same Wolfcamp A well is now averaging at the company’s year-end target of $5.9 million. The shortest drill time during the quarter was 11 days from spud to TD.

In a separate down-spacing test in Glasscock County, the company is in the early stages of analyzing initial production results of 20 gross (20 net) Wolfcamp A and B wells with 4,400’ lateral lengths, half of which were drilled on 660’ spacing and half on 440’ spacing. A multi-year analysis is expected in order to understand the long-term implications of the tighter spacing concept. Nine wells were part of the 2014 program; the 11 in the 2015 program are among the wells completed in the 2nd quarter.

Energen’s total 2015 Midland Basin development program calls for the drilling of 100 gross (94 net) wells in Glasscock and Martin counties, with 37 gross (33 net) wells remaining to be drilled in the second half of the year. The company currently expects 46 gross (42 net) wells in the 2015 program to be completed in 2016.

Midland and Delaware Basin Appraisal Program Results

Energen tested nine new appraisal wells in the Permian Basin during the 2nd quarter of 2015, including its first Lower Spraberry wells in Howard and Midland counties in the Midland Basin. [See locator maps at www.energen.com]

Midland Basin (3-Stream Results)

                               
Well Name     Zone/

County

    Lateral length (ft)    

Frac
Stages

    Peak 24-Hour IP     Peak 30-day Avg.
        Drilled*     Completed         Boepd     %Oil     %NGL     %Gas     Boepd     %Oil     %NGL     %Gas
Smith SN 48-37 #501H     LSB/Howard     7,472     6,848     32     1,067     78     14     7     895     79     14     7
L.B. Epley NS 39-46 #501H     LSB/Midland     6,799     6,077     29     652     82     10     8     428     76     14     11
L.B. Epley NS 39-46 #201H     WCB/Midland     6,848     6,293     30     1,053     74     14     12     885     76     13     11

* Represents distance from vertical departure to toe
Note: Totals may not foot due to rounding

 

The Smith SN 48-37 #501H, a Lower Spraberry well in Howard County, generated an excellent peak 24-hour IP rate of 1,067 boepd (78% oil); the well’s peak 30-day average remained strong at 895 boepd (79% oil). Through 81 days, the Smith well’s oil production is tracking very close to a 1.2 MMBOE EUR type curve. [See cumulative oil performance over time and potential economics of the company’s four northern Midland Basin Lower Spraberry wells at www.energen.com]

Further south in northern Midland County, in the heart of a vertical Spraberry field that dates back to the 1960s, the L.B. Epley NS 39-46 #501H showed the effects of that prior drilling. The well’s peak 24-hour IP rate was 652 (82% oil), and its peak 30-day average was 428 boepd (76% oil). Even though this Lower Spraberry Epley well is not as strong a performer as the company’s other northern Midland Basin Lower Spraberry wells, its cumulative oil production through 52 days is tracking close to a 770 MBOE EUR type curve. Energen estimates that its exposure in the Midland Basin to areas of Spraberry depletion associated with older vertical drilling is limited to a maximum of 5,000 net acres in this area and that the vast majority of its Spraberry potential is in areas with younger or fewer vertical wells.

A Wolfcamp B well drilled at the same location – the L.B. Epley NS 39-46 #201H ̶ generated an excellent 24-hour IP rate of 1,053 (74% oil) and a peak 30-day average rate of 885 boepd (76% oil).

Energen plans to drill a total of 8 gross (8 net) Wolfcamp shale wells in its Midland Basin appraisal program in 2015. In addition to the two 2015 Wolfcamp wells for which results have been disclosed, three wells in Glasscock County with 10,000’ laterals currently are flowing back; a fourth well is awaiting completion, another is drilling, and the final well has not yet been spud.

Energen also plans to drill a total of 12 gross (12 net) Spraberry wells in its Midland Basin appraisal program in 2015; this reflects an additional 5 gross (5 net) wells now planned in the second half of 2015. In addition to three Lower Spraberry wells in the 2015 program for which results have been disclosed, one well currently is flowing back, four more wells are awaiting completion or are in various stages of completion, and the other four wells have not yet been spud. All 20 gross (20 net) wells in Energen’s 2015 Midland Basin appraisal program are expected to be completed by year-end 2015.

Delaware Basin (3-Stream Results)

Well Name     Zone/

County

    Lateral length (ft)    

Frac
Stages

    Peak 24-Hour IP     Peak 30-day Avg.
        Drilled*     Completed         Boepd     %Oil     %NGL     %Gas     Boepd     %Oil     %NGL     %Gas
Helbing 56-5 #1H     WCB/Reeves     5,299     4,828     18     1,381     31     31     38     1,163     33     30     37
Helbing 56-6 #1H     WCB/Reeves     5,307     4,423     17     1,123     39     27     34     753     29     32     39
Jaymac 56-7 #1H     WCB/Reeves     4,781     4,163     16     1,167     33     30     37     888     34     30     37
Spectre State 54-4 #1H     WCB/Reeves     4,907     4,372     16     885     63     15     22     733     63     15     22
Piper State 54-14 #1H     WCA/Reeves     4,835     4,223     17     1,498     56     18     26     973     55     19     26
University 24-17 #1H     WCB/Ward     7,463     6,987     32     1,073     74     12     14     987     71     13     16

* Represents distance from vertical departure to toe
Note: Totals may not foot due to rounding

 

In the Delaware Basin, the Helbing 56-5 #1H and 56-6 #1H and the Jaymac 56-7 #1H were drilled into the B-bench of the Wolfcamp shale in western Reeves County and generated strong peak 24-hour IP rates of 1,381 boepd (31% oil), 1,123 boepd (39% oil), and 1,167 boepd (33% oil), respectively. Their peak 30-day average rates were 1,163 boepd (33% oil), 753 boepd (29% oil), and 888 (34% oil), respectively.

In the central part of the Delaware Basin, the Piper State 54-14 #1H ̶ an A-bench well – had an impressive peak 24-hour IP of 1,498 (56% oil) and a peak 30-day average of 973 boepd (55% oil). The Spectre State 54-4 #1H, a B-bench well, also was drilled in the central part of the basin and had a solid peak 24-hour IP of 885 boepd (63% oil) and a peak 30-day average of 733 boepd (63% oil). The Spectre State’s test rates were limited due to water-handling constraints.

On the Eastern side of the Delaware Basin in Ward County, the company drilled the University 24-17 #1H into the Wolfcamp B with a completed lateral length of approximately 7,000 feet. The results were very solid, with a peak 24-hour IP of 1,073 (74% oil) and peak 30-day average of 987 boepd (71% oil). These test rates were limited due to water-handling constraints. The company believes its successful execution of this longer lateral in the Delaware Basin can be applied elsewhere in the basin.

Energen’s 2015 appraisal drilling program in the Delaware Basin totals 8 gross (8 net) Wolfcamp shale wells. Results of 7 of these wells have been disclosed. The remaining well in the 2015 program is targeting the Wolfcamp A in Winkler County and currently is being completed.

San Juan Basin Mancos Appraisal Program

Energen currently is drilling its first Mancos oil formation appraisal well in the San Juan Basin in Rio Arriba County, NM. The company plans to drill 8 gross (8 net) wells in the second half of 2015 to test its 91,000 net acres for Mancos oil potential. The company also is participating as a 50 percent non-operated participant in 6 gross (3 net) wells drilled by WPX Energy. The peak 24-hour and peak 30-day average oil production rates only of these six wells averaged an attractive 923 barrels of oil per day and 479 barrels of oil per day, respectively.

Capital, Production, and Financial Guidance

Energen increased its 2015 capital budget slightly to $1.1 billion. Drilling plans for 2015 now include an additional 14 gross (11 net) Wolfcamp development wells, 3 gross (3 net) additional Spraberry development wells, and 5 gross (5 net) additional Spraberry appraisal wells in the program. In addition, the company plans to complete 6 gross (5 net) development wells previously scheduled for 2016 as well as the 5 new Spraberry appraisal wells. The revised budget also reflects a net addition of approximately $14 million for infrastructure in the Midland Basin needed to support 2016 drilling activity as well as approximately $10 million for additional unproved leasehold in the Midland Basin.

Energen’s revised budget is based on running four horizontal drilling rigs in its Midland Basin development program in the last six months of the year; one horizontal rig in the Midland Basin appraisal program through October; and one horizontal rig in the San Juan Basin Mancos appraisal program in the second half of 2015.

2015 Capital Summary

          2015e Capital ($MM)        

Operated Wells
to Be Drilled
Gross (Net)

Midland Basin

        $ 810        

129

 

(122)

Wolfcamp
Development 485

88

(82)

Appraisal 60

8

(8)

Spraberry
Development 70

12

(12)

Appraisal 80

12

(12)

Wolfberry 20

9

(8)

SWD/Facilities 82
Non-operated/Other 13
 
Delaware Basin $ 143

14

(13)

Bone Spring 18

3

(2)

Wolfcamp 73

8

(8)

Wolfbone 15

3

(3)

SWD/Facilities 32
Non-operated/Other 5

 

Other Permian $ 11

0

(0)

Waterflood injectors 0
Facilities/C02 6
Non-operated/Other 5
 
San Juan Basin/Other $ 63

8

(8)

Mancos 29

8

(8)

Facilities 14
Non-operated/Other 20
 

Net Carry-in/Carry Out/Miscellaneous

        $ 18              
Drilling & Development $ 1,045

151

(143)

Acquisitions/Lease Extensions/UPL         $ 55              
Total Capital $ 1,100

Note: “Facilities” capital includes artificial lift and central gathering facilities; “Other”
Capital includes payadds and refracs

 

Energen’s estimate of 2015 production (excluding volumes from the company’s San Juan Basin divestiture) has been revised upward by 500,000 BOE to reflect 2nd quarter results and an additional 100,000 BOE of production in the 2nd half of the year, primarily in the Midland Basin development program. Production would be higher still absent high natural gas pipeline pressures that have materialized as a result of increased Delaware Basin production industry-wide. As a result, Energen’s Reeves County production is expected to be negatively impacted by approximately 200,000 BOE in the 2nd half of 2015.

Production for the year is now estimated to range from 22.2-23.2 MMBOE (60,820–63,560 boepd), with a midpoint of 22.7 MMBOE (62,215 boepd). This reflects an increase of approximately 19 percent from comparable, adjusted 2014 production volumes of 19.1 MMBOE.

The production midpoint in the 3rd quarter of 2015 is estimated to be 5.8 MMBOE (62,815 boepd). This is down slightly from the prior estimate of 5.9 MMBOE (64,239 boepd) largely due to the timing of completions in the Midland Basin and pipeline pressure issues in the Delaware Basin Wolfcamp, partially offset by a continuation of outstanding performance in the Delaware Basin Wolfcamp and 3rd Bone Spring. The company has added two frac crews in the Midland Basin and plans to run three for most of the third quarter. As a result, production in the 4th quarter is estimated to increase substantially to a midpoint of 6.2 MMBOE (67,978 boepd).

Production by Play (Excluding San Juan Basin Divestiture)

Area       2015e Midpoint       2014       Change
      MMBOE       MMBOE        
Midland Basin 11.8       7.4       59 %
Wolfcamp/Spraberry/Cline 7.7 2.1

 

Wolfberry 4.1 5.3
Delaware Basin 5.3 5.8 (9) %
3rd Bone Spring/Other 3.7 4.6
Wolfcamp 1.6 1.2
Central Basin Platform       3.6       4.1       (12) %
Total Permian Basin 20.8 17.3 20 %
San Juan Basin/Other       1.9       1.8       6 %
Total       22.7       19.1       19 %

NOTE: Totals may not sum due to rounding

 

Production by Product (Excluding San Juan Basin Divestiture)

Commodity      

2015e Midpoint

     

2014

      % change
     

MMBOE

     

boepd

     

MMBOE

     

boepd

      (boepd)
Oil 14.3       39,222 11.8       32,323 21 %
NGL 4.0 10,854 3.4 9,337 16 %
Natural Gas       4.4       12,139       3.9       10,660       14 %
Total Continuing Operations       22.7       62,215       19.1       52,320       19 %
 

Production by Basin/Quarter (Excluding San Juan Divestiture)

                       
Basin 1Q15a 2Q15a 3Q15e Midpoint 4Q15e Midpoint
MMBOE       boepd MMBOE       boepd MMBOE       boepd MMBOE       boepd
Midland Basin 2.3      

25,778

3.0       32,495 3.0       32,250 3.6       38,804
Delaware Basin 1.2

13,611

1.5 15,934 1.4 15,283 1.2 13,543
Central Basin Platform/Other 0.9

10,100

0.9 10,088 0.9 9,891 0.9 9,663
San Juan Basin/Other       0.4       4,611       0.5       5,297       0.5       5,391       0.5       5,967
Total Production       4.9       54,100       5.8       63,802       5.8       62,815       6.2       67,978

NOTE: Totals may not sum due to rounding

 

Production by Commodity/Quarter (Excluding San Juan Basin Divestiture)

Commodity       1Q15a       2Q15a       3Q15e Midpoint       4Q15e Midpoint
MMBOE       boepd MMBOE       boepd MMBOE       boepd MMBOE       boepd
Oil 3.2       35,922 3.6       39,505 3.6       39,022 3.9       42,370
NGL 0.7 8,133 1.1 11,648 1.0 11,293 1.1 12,283
Gas       0.9       10,044       1.2       12,648       1.2       12,500       1.2       13,326
Total Production       4.9       54,100       5.8       63,802       5.8       62,815       6.2       67,978

NOTE: Totals may not sum due to rounding

 

3Q15 AND CY15 FINANCIAL GUIDANCE

Energen’s estimated expenses, excluding San Juan Basin divestiture, are as follows:

Per BOE, except where noted         3Q15         CY15
LOE (production costs, marketing & transportation)         $10.00- $10.65         $9.25-$10.85
Production & ad valorem taxes (% of revenues, excluding hedges) 7.8%
DD&A expense $24.50-$25.50 $24.30-$25.80
General & administrative expense, net* $5.25-$5.40 $5.50-$5.85
Exploration expense (seismic, delay rentals, etc.) $0.35-$0.45 $0.40-$0.50
Interest expense ($MM)         $10.0-$10.5         $40.0-$47.0

* Excludes $0.07 per BOE in 3Q15 and $1.63 per BOE in CY15 for pension and pension settlement expenses.

 

3Q15 and 2H15 Hedges

For the remaining 6 months of 2015, approximately 78 percent of the company’s production guidance midpoint of 12.0 MMBOE is hedged. Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 1.1 million barrels of oil production at an average price of -$4.30 per barrel and the WTI Midland to WTI Cushing (sweet oil) differential for 3.8 million barrels at an average price of -$4.55 per barrel. Energen estimates that approximately 80 percent of its oil production for the remainder of the year will be sweet. Gas basis assumptions for all open contracts (August-December) are -$0.12 per Mcf (basis actuals in July were approximately -$0.10 per Mcf).

The company’s hedge position for the last six months of 2015 is:

Commodity

         

Hedge Volumes

     

2H15e Production

@ Midpoint

      Hedge %      

NYMEXe Price

Oil

         

7.0 MMBO

     

7.5 MMBO

     

93 %

     

$ 78.24 per barrel

Natural Gas

         

13.8 Bcf

     

14.3 Bcf

     

97 %

     

$ 4.27 per Mcf

Note: Known actuals included

 

In the table above, basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen’s assumed basis differentials. Average realized oil and gas prices for Energen’s production associated with NYMEX contracts as well as for unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect estimated oil transportation charges of $2.26 per barrel for the second half of 2015; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin for the remainder of the year.

Energen’s assumptions for the commodity prices of unhedged production for the remainder of 2015 are $49.60 per barrel of oil (July-December), $2.90 per Mcf of gas (August-December), and $0.43 per gallon of NGL (July-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (July-December) are +$0.42 and +$0.69, respectively.

Every 1-cent change in the average price of NGL from $0.43 per gallon is estimated to have a cash flows impact of $700,000.

Energen estimates that price realizations in the second half of 2015 (pre-hedge) will be approximately:

Crude oil (% of NYMEX/WTI)         94%
Natural gas (% of NYMEX/Henry Hub) 88%
NGL (after T&F) (% of NYMEX/WTI) 23%
 

For the 3rd quarter of 2015, approximately 81 percent of the company’s production guidance midpoint of 5.8 MMBOE is hedged. Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential. Energen has hedged the WTS Midland to WTI Cushing (sour oil) differential for 540,000 barrels of oil production at an average price of -$4.30 per barrel and the WTI Midland to WTI Cushing (sweet oil) differential for 1.9 million barrels at an average price of -$4.55 per barrel. Energen estimates that approximately 79 percent of its oil production in the 3rd quarter of 2015 will be sweet. Gas basis assumptions (August-September) are -$0.09 per Mcf (basis actuals in July were approximately -$0.10 per Mcf).

The company’s hedge position for the 3rd quarter of 2015 is:

Commodity

     

Hedge Volumes

     

CY15e Production

Midpoint

      Hedge %      

NYMEXe Price

Oil

     

3.5 MMBO

     

3.6 MMBO

     

97 %

     

$ 78.21 per barrel

Natural Gas

     

6.8 Bcf

     

6.9 Bcf

     

99 %

     

$ 4.25 per Mcf

Note: Known actuals included

                       

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

Average realized oil and gas prices for Energen’s production associated with NYMEX contracts as well as for unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect estimated oil transportation charges of $2.31 per barrel in the 3rd quarter of 2015; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin in the 3rd quarter of 2015.

Energen’s assumptions for the commodity prices of unhedged production in the 3rd quarter of 2015 are $49.60 per barrel of oil (July-September), $2.80 per Mcf of gas (August-September), and $0.43 per gallon of NGL (July-September). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (July-September) are +$0.46 and +$1.01, respectively.

Every 1-cent change in the average price of NGL from $0.43 per gallon is estimated to have a cash flows impact of $335,000.

Energen estimates that price realizations in the 3rd quarter (pre-hedge) will be approximately:

Crude oil (% of NYMEX/WTI)         95%
Natural gas (% of NYMEX/Henry Hub) 89%
NGL (after T&F) (% of NYMEX/WTI) 22%
 

Conference Call

Energen will hold its quarterly conference call Friday, August 7, 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 through Web site, www.energen.com.

Energen Corporation is an oil and gas exploration and production company with headquarters in Birmingham, Alabama. The company has 1.1 billion barrels of oil-equivalent proved, probable, and possible reserves and another 2.2 billion barrels of oil-equivalent contingent resources. These all-domestic reserves and resources are located primarily in the Permian Basin in west Texas. For more information, go to http://www.energen.com.

FORWARD LOOKING STATEMENT: 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 timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, 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 filing. 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.

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 certain non-cash mark-to-market derivative financial instruments. Adjusted  income from continuing operations further excludes impairment losses, income associated with certain divestments, gains and losses on disposal of discontinued operations and income and losses from discontinued operations. 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.

 
       
Quarter 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 $24.0 tax) 42.9 0.58
Loss associated w/ San Juan Basin divestment (net of $0.9 tax)       1.2       0.02  
Adjusted Income from Continuing Operations (Non-GAAP)       7.7       0.10  
 
       
Quarter Ended 6/30/2014
Energen Net Income ($ in millions except per share data)       Net Income    

Per Diluted
Share

Net Income (Loss) All Operations (GAAP) (8.0 ) (0.11 )
Non-cash mark-to-market losses (net of $21.5 tax) 38.1 0.52
Asset impairment, other (net of $0.9 tax) 1.6 0.02
Income associated w/ San Juan Basin divestment (net of $5.9 tax)       (10.6 )     (0.15 )
Adjusted Net Income from All Operations (Non-GAAP)       21.2       0.29  
Loss from discontinued operations (net of $3.0 tax)       4.8       0.07  
Adjusted Income from Continuing Operations (Non-GAAP)       26.0       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 income associated with certain divestments, impairment losses, certain non-cash mark-to-market derivative financial  instruments,  income and losses from discontinued operations and gains and  losses on disposal of discontinued operations. 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 Quarter Ended 6/30
($ in millions)     2015     2014
 
Energen Net Income (Loss) (GAAP) (111.6 ) (8.0 )
(Income) Loss associated w/ San Juan Basin divestment, net of tax     1.2       (10.6 )
Adjusted Net Income from Continuing Operations (Non-GAAP)     (110.4 )     (18.6 )
Interest expense * 11.2 8.0
Income tax expense (benefit) * (60.4 ) (6.9 )
Depreciation, depletion and amortization * 149.8 121.9
Accretion expense * 1.7 1.5
Exploration expense * 4.5 0.0
Dry hole expense * 6.5 1.2
Adjustment for asset impairment * 60.4 1.3
Adjustment for mark-to-market losses 116.9 59.6
Adjustment for income from discontinued operations, net of tax     0.0       4.8  
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)     180.3       172.9  
 
Note: Amounts may not sum due to rounding
 
* Amount adjusted to exclude San Juan Basin divestment. See reconciliation to GAAP Information for the Quarter Ended 6/30/2015 and 6/30/2014.
                       

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 the divestment of assets held in the San Juan Basin 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 San Juan Divestment
Reconciliation to GAAP Information Quarter Ended
June 30, 2015
(in thousands except per share and production data)                                
GAAP     $/BOE San Juan Basin     $/BOE Non-GAAP     $/BOE
Revenues
Oil, natural gas liquids and natural gas sales $ 219,290 $ 592 $ 218,698
Gain (loss) on derivative instruments       (50,964 )             -               (50,964 )      
Total Revenues       168,326               592               167,734        
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production 53,581 $9.15 1,886 $40.13 51,695 $8.90
Production and ad valorem taxes 13,352 $2.28 (174 ) ($3.70 ) 13,526 $2.33
O&G Depreciation, depletion and amortization 148,374 $25.35 - $0.00 148,374 $25.56
FF&E Depreciation, depletion and amortization 1,469 $0.25 - $0.00 1,469 $0.25
Asset impairment 60,413 - 60,413
Exploration 11,018 - 11,018
General and administrative 38,652 $6.60 (1 ) ($0.02 ) 38,653 $6.66
Accretion of discount on asset retirement obligations 1,669 - 1,669
(Gain) loss on sale of assets and other       1,476               994               482        
Total costs and expenses       330,004               2,705               327,299        
Operating Income (Loss)       (161,678 )             (2,113 )             (159,565 )      
Other Income/(Expense)
Interest Expense (11,244 ) - (11,244 )
Other income       41               -               41        
Total other expense       (11,203 )             -               (11,203 )      
 
Income (Loss) from Continuing Operations Before Income Taxes (172,881 ) (2,113 ) (170,768 )
Income tax expense (benefit)       (61,280 )             (864 )             (60,416 )      
Income (Loss) From Continuing Operations       (111,601 )             (1,249 )             (110,352 )      
Discontinued Operations, net of tax
Income from discontinued operations - - -
Loss on Disposal of discontinued ops       -               -               -        
Income from discontinued ops       -               -               -        
Net Income (Loss)     $ (111,601 )           $ (1,249 )           $ (110,352 )      
 
Diluted Earnings Per Average Common Share
Continuing Operations $ (1.52 ) $ (0.02 ) $ (1.50 )
Discontinued Operations     $ -             $ -             $ -        
Net Income (Loss)     $ (1.52 )           $ (0.02 )           $ (1.50 )      
 
Basic earning Per Average Common Share
Continuing Operations $ (1.52 ) $ (0.02 ) $ (1.50 )
Discontinued Operations     $ -             $ -             $ -        
Net Income (Loss)     $ (1.52 )           $ (0.02 )           $ (1.50 )      
 
Oil 3,594 (1 ) 3,595
NGL 1,070 10 1,060
Gas       1,189               38               1,151        
Total Production (mboe)       5,853               47               5,806        
Total Production (boepd)       64,319               516               63,802        
 
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 the divestment of assets held in the San Juan Basin 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 San Juan Divestment
Reconciliation to GAAP Information Quarter Ended
June 30, 2014
(in thousands except per share and production data)                                      
GAAP     $/BOE San Juan Basin     $/BOE Non-GAAP     $/BOE
Revenues
Oil, natural gas liquids and natural gas sales $ 355,852 $ 43,086 $ 312,766
Gain (loss) on derivative instruments         (84,846 )             6,278               (91,124 )      
Total Revenues         271,006               49,364               221,642        
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production 64,697 $10.20 15,017 $9.21 49,680 $10.54
Production and ad valorem taxes 28,049 $4.42 3,750 $2.30 24,299 $5.15
O&G Depreciation, depletion and amortization 135,164 $21.31 14,288 $8.77 120,876 $25.63
FF&E Depreciation, depletion and amortization 1,080 $0.17 62 $0.04 1,018 $0.22
Asset impairment 1,342 - 1,342
Exploration 1,233 3 1,230
General and administrative 33,542 $5.29 (612 ) ($0.38 ) 34,154 $7.25
Accretion of discount on asset retirement obligations 1,883 388 1,495
(Gain) loss on sale of assets and other         909               -               909        
Total costs and expenses         267,899               32,896               235,003        
Operating Income (Loss)         3,107               16,468               (13,361 )      
Other Income/(Expense)
Interest Expense (7,964 ) - (7,964 )
Other income         687               -               687        
Total other expense         (7,277 )             -               (7,277 )      
 
Income (Loss) from Continuing Operations Before Income Taxes (4,170 ) 16,468 (20,638 )
Income tax expense (benefit)         (1,016 )             5,853               (6,869 )      
Income (Loss) From Continuing Operations         (3,154 )             10,615               (13,769 )      
Discontinued Operations, net of tax
Income (Loss) from discontinued operations (4,799 ) - (4,799 )
Loss on Disposal of discontinued ops         -               -               -        
Income from discontinued ops         (4,799 )             -               (4,799 )      
Net Income (Loss)       $ (7,953 )           $ 10,615             $ (18,568 )      
 
Diluted Earnings Per Average Common Share
Continuing Operations $ (0.04 ) $ 0.15 $ (0.19 )
Discontinued Operations       $ (0.07 )           $ -             $ (0.07 )      
Net Income (Loss)       $ (0.11 )           $ 0.15             $ (0.26 )      
 
Basic earning Per Average Common Share
Continuing Operations $ (0.04 ) $ 0.15 $ (0.19 )
Discontinued Operations       $ (0.07 )           $ -             $ (0.07 )      
Net Income (Loss)       $ (0.11 )           $ 0.15             $ (0.26 )      
 
Oil 2,833 3 2,830
NGL 1,065 167 898
Gas         2,446               1,460               986        
Total Production (mboe)         6,344               1,630               4,714        
Total Production (boepd)         69,714               17,912               51,802        
 
Note: Amounts may not sum due to rounding
 
               

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 divestment of assets held in the San Juan Basin 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 San Juan Divestment
Reconciliation to GAAP Information Quarter Ended
March 31, 2015
                 
GAAP       San Juan Basin       Non-GAAP
 
Oil 3,235 2 3,233
NGL 861 129 732
Gas     2,213       1,309       904
Total Production (mboe)     6,309       1,440       4,869
Total Production (boepd)     70,100       16,000       54,100
 
                       
Energen Production Excluding San Juan Divestment
Reconciliation to GAAP Information Year-to-Date Ended
December 31, 2014
                 
GAAP       San Juan Basin       Non-GAAP
 
Oil 11,814 16 11,798
NGL 4,103 695 3,408
Gas     9,767       5,876       3,891
Total Production (mboe)     25,684       6,587       19,097
Total Production (boepd)     70,367       18,047       52,320
 
Note: Amounts may not sum due to rounding
 
       

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 3 months ending June 30, 2015 and 2014

 
2nd Quarter
   
(in thousands, except per share data)     2015     2014     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 219,290 $ 355,852 $ (136,562 )
Loss on derivative instruments, net       (50,964 )       (84,846 )       33,882  
 
Total revenues       168,326         271,006         (102,680 )
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 53,581 64,697 (11,116 )
Production and ad valorem taxes 13,352 28,049 (14,697 )
Depreciation, depletion and amortization 149,843 136,244 13,599
Asset impairment 60,413 1,342 59,071
Exploration 11,018 1,233 9,785
General and administrative 38,652 33,542 5,110
Accretion of discount on asset retirement obligations 1,669 1,883 (214 )
(Gain) loss on sale of assets and other       1,476         909         567  
 
Total costs and expenses       330,004         267,899         62,105  
 
Operating Income (Loss)       (161,678 )       3,107         (164,785 )
 
Other Income (Expense)
Interest expense (11,244 ) (7,964 ) (3,280 )
Other income       41         687         (646 )
 
Total other expense       (11,203 )       (7,277 )       (3,926 )
 

Loss From Continuing Operations Before Income Taxes

(172,881

)

(4,170

)

(168,711

)

Income tax expense (benefit)       (61,280 )       (1,016 )       (60,264 )
 
Loss From Continuing Operations       (111,601 )       (3,154 )       (108,447 )
 
Discontinued Operations, net of tax
Loss from discontinued operations               (4,799 )       4,799  
 
Loss From Discontinued Operations               (4,799 )       4,799  
 
Net Income (Loss)     $ (111,601 )     $ (7,953 )     $ (103,648 )
 
Diluted Earnings Per Average Common Share
Continuing operations $ (1.52 ) $ (0.04 ) $ (1.48 )
Discontinued operations               (0.07 )       0.07  
 
Net Income (Loss)     $ (1.52 )     $ (0.11 )     $ (1.41 )
 
Basic Earnings Per Average Common Share
Continuing operations $ (1.52 ) $ (0.04 ) $ (1.48 )
Discontinued operations               (0.07 )       0.07  
 
Net Income (Loss)     $ (1.52 )     $ (0.11 )     $ (1.41 )
 
Diluted Avg. Common Shares Outstanding       73,452         72,851         601  
 
Basic Avg. Common Shares Outstanding       73,452         72,851         601  
 
Dividends Per Common Share     $ 0.02       $ 0.15       $ (0.13 )
       

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 6 months ending June 30, 2015 and 2014

 
Year-to-date
   
(in thousands, except per share data)     2015     2014     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 407,112 $ 706,674 $ (299,562 )
Loss on derivative instruments, net       (16,928 )       (138,237 )       121,309  
 
Total revenues       390,184         568,437         (178,253 )
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 121,335 132,141 (10,806 )
Production and ad valorem taxes 32,417 55,373 (22,956 )
Depreciation, depletion and amortization 284,224 260,464 23,760
Asset impairment 66,996 2,588 64,408
Exploration 11,781 12,801 (1,020 )
General and administrative 70,707 65,715 4,992
Accretion of discount on asset retirement obligations 3,679 3,726 (47 )
(Gain) loss on sale of assets and other       (26,868 )       1,062         (27,930 )
 
Total costs and expenses       564,271         533,870         30,401  
 
Operating Income (Loss)       (174,087 )       34,567         (208,654 )
 
Other Income (Expense)
Interest expense (23,002 ) (15,852 ) (7,150 )
Other income       87         1,010         (923 )
 
Total other expense       (22,915 )       (14,842 )       (8,073 )
 

Income (Loss) From Continuing Operations Before Income Taxes

(197,002

)

19,725

(216,727

)

Income tax expense (benefit)       (69,981 )       7,232         (77,213 )
 
Income (Loss) From Continuing Operations       (127,021 )       12,493         (139,514 )
 
Discontinued Operations, net of tax
Income from discontinued operations 33,920 (33,920 )
Loss on disposal of discontinued operations               (1,050 )       1,050  
 
Income From Discontinued Operations               32,870         (32,870 )
 
Net Income (Loss)     $ (127,021 )     $ 45,363       $ (172,384 )
 
Diluted Earnings Per Average Common Share
Continuing operations $ (1.74 ) $ 0.17 $ (1.91 )
Discontinued operations               0.45         (0.45 )
 
Net Income (Loss)     $ (1.74 )     $ 0.62       $ (2.36 )
 
Basic Earnings Per Average Common Share
Continuing operations $ (1.74 ) $ 0.17 $ (1.91 )
Discontinued operations               0.45         (0.45 )
 
Net Income (Loss)     $ (1.74 )     $ 0.62       $ (2.36 )
 
Diluted Avg. Common Shares Outstanding       73,143         73,031         112  
 
Basic Avg. Common Shares Outstanding       73,143         72,737         406  
 
Dividends Per Common Share     $ 0.04       $ 0.30       $ (0.26 )
 
 

CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of June 30, 2015 and December 31, 2014

                 
(in thousands)       June 30, 2015         December 31, 2014
     
 
ASSETS
Current Assets
Cash and cash equivalents $ 1,510 $ 1,852
Accounts receivable, net of allowance 128,564 157,678
Inventories 17,988 14,251
Assets held for sale 395,797
Derivative instruments 147,789 322,337
Prepayments and other         22,419         27,445
 
 
Total current assets         318,270         919,360
 
 
Property, Plant and Equipment
Oil and natural gas properties, net 5,493,509 5,152,748
Other property and equipment, net         46,773         46,389
 
 
Total property, plant and equipment, net         5,540,282         5,199,137
 
 
Other assets 14,094 19,761
 
 
TOTAL ASSETS       $ 5,872,646       $ 6,138,258
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable 94,953 101,453
Accrued taxes 14,055 5,530
Accrued wages and benefits 22,217 21,553
Accrued capital costs 110,485 207,461
Revenue and royalty payable 62,179 72,047
Liabilities related to assets held for sale 24,230
Pension liabilities $ 29,616 $ 24,609
Deferred income taxes 11,970 79,164
Derivative instruments 10,220 988
Other         23,220         23,288
 
 
Total current liabilities         378,915         560,323
 
 
Long-term debt 686,575 1,038,563
Asset retirement obligations 99,049 94,060
Deferred income taxes 1,001,251 1,000,486
Noncurrent derivative instruments 3,902
Other long-term liabilities         12,906         30,222
 
 
Total liabilities         2,182,598         2,723,654
 
 
Total Shareholders’ Equity         3,690,048         3,414,604
 
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY       $ 5,872,646       $ 6,138,258
 
       

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending June 30, 2015 and 2014

 
2nd Quarter
   
(in thousands, except sales price and per unit data)     2015     2014     Change
 
 
Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
Oil $ 188,599 $ 262,746 $ (74,147 )
Natural gas liquids 14,781 31,163 (16,382 )
Natural gas       15,910         61,943         (46,033 )
Total $ 219,290 $ 355,852 $ (136,562 )
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ (103,734 ) $ (66,172 ) $ (37,562 )
Natural gas liquids 40 (40 )
Natural gas       (13,133 )       6,511         (19,644 )
Total     $ (116,867 )     $ (59,621 )     $ (57,246 )
 
Closed gains (losses) on derivative instruments
Oil $ 55,330 $ (25,754 ) $ 81,084
Natural gas liquids 159 (159 )
Natural gas       10,573         370         10,203  
Total     $ 65,903       $ (25,225 )     $ 91,128  
Total revenues     $ 168,326       $ 271,006       $ (102,680 )
 
Production volumes
Oil (MBbl) 3,594 2,833 761
Natural gas liquids (MMgal) 44.9 44.7 0.20
Natural gas (MMcf)       7,134         14,676         (7,542 )
Total production volumes (MBOE)       5,853         6,344         (491 )
 
Average daily production volumes

Oil (MBbl/d)

39.5

31.1

8.4

Natural gas liquids (MMgal/d) 0.5 0.5
Natural gas (MMcf/d)       78.4         161.3         (82.9 )
Total average daily production volumes (MBOE/d)       64.3         69.7         (5.4 )
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 67.87 $ 83.65 $ (15.78 )
Natural gas liquids (per gallon) $ 0.33 $ 0.70 $ (0.37 )
Natural gas (per Mcf) $ 3.71 $ 4.25 $ (0.54 )
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 52.48 $ 92.74 $ (40.26 )
Natural gas liquids (per gallon) $ 0.33 $ 0.70 $ (0.37 )
Natural gas (per Mcf) $ 2.23 $ 4.22 $ (1.99 )
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

9.15

$

10.20

$

(1.05

)

Production and ad valorem taxes $ 2.28 $ 4.42 $ (2.14 )
Depreciation, depletion and amortization $ 25.60 $ 21.48 $ 4.12
Exploration expense $ 1.88 $ 0.19 $ 1.69
General and administrative* $ 6.60 $ 5.29 $ 1.31
Net capital expenditures     $ 284,764       $ 322,572       $ (37,808 )
 

*Includes pension and pension settlement expenses of $0.19 and $0.50 for the three months ended June 30, 2015 and 2014, respectively.

 
       

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 6 months ending June 30, 2015 and 2014

 
Year-to-date
 
   
(in thousands, except sales price and per unit data)     2015     2014     Change
 
 
Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
Oil $ 330,627 $ 516,505 $ (185,878 )
Natural gas liquids 25,615 59,366 (33,751 )
Natural gas       50,870         130,803         (79,933 )
Total     $ 407,112       $ 706,674       $ (299,562 )
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ (155,503 ) $ (87,636 ) $ (67,867 )
Natural gas liquids 327 (327 )
Natural gas       (21,015 )       (5,993 )       (15,022 )
Total     $ (176,518 )     $ (93,302 )     $ (83,216 )
 
Closed gains (losses) on derivative instruments
Oil $ 132,813 $ (40,556 ) $ 173,369
Natural gas liquids 355 (355 )
Natural gas       26,777         (4,734 )       31,511  
Total     $ 159,590       $ (44,935 )     $ 204,525  
Total revenues     $ 390,184       $ 568,437       $ (178,253 )
 
Production volumes
Oil (MBbl) 6,829 5,584 1,245
Natural gas liquids (MMgal) 81.1 82.7 (1.6 )
Natural gas (MMcf)       20,412         28,800         (8,388 )
Total production volumes (MBOE)       12,162         12,352         (190 )
 
Average daily production volumes
Oil (MBbl/d) 37.7 30.9 6.8
Natural gas liquids (MMgal/d) 0.5 0.5
Natural gas (MMcf/d)       112.8         159.1         (46.3 )
Total average daily production volumes (MBOE/d)       67.2         68.2         (1.0 )
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 67.86 $ 85.23 $ (17.37 )
Natural gas liquids (per gallon) $ 0.32 $ 0.72 $ (0.40 )
Natural gas (per Mcf) $ 3.80 $ 4.38 $ (0.58 )
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 48.42 $ 92.50 $ (44.08 )
Natural gas liquids (per gallon) $ 0.32 $ 0.72 $ (0.40 )
Natural gas (per Mcf) $ 2.49 $ 4.54 $ (2.05 )
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

9.98

$

10.70

$

(0.72

)

Production and ad valorem taxes $ 2.67 $ 4.48 $ (1.81 )
Depreciation, depletion and amortization $ 23.37 $ 21.09 $ 2.28
Exploration expense $ 0.97 $ 1.04 $ (0.07 )
General and administrative* $ 5.81 $ 5.32 $ 0.49
Net capital expenditures     $ 660,591       $ 594,268       $ 66,323  
 

*Includes pension and pension settlement expenses of $0.34 and $0.79 for the six months ended June 30, 2015 and 2014, respectively.

 

Source: Energen Corporation

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