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Energen Adds 676 Net Lower Spraberry Locations to Drilling Inventory

May 6, 2015 4:13 PM EDT

2 Lower Spraberry Wells in Martin Co. Test at 30-Day Average Peak Rates Over 830 BOEPD

Energen to Drill 16 Additional Net Wells in Midland Basin with Cost Savings

CY15 Production Midpoint Estimate Increased to 22.2 MMBOE

Highlights

  • Supported by excellent results, Energen adds 676 net Lower Spraberry locations to its Midland Basin drilling inventory
  • 9 Lower Spraberry wells now to be drilled along with 9 Wolfcamp A and B wells as part of stacked lateral development program in Martin County
  • Total of 16 new net drills in Midland Basin added to 2015 plans as result of drilling efficiencies and service cost savings
  • 1Q15 production totals 54,100 boepd; CY15 production midpoint guidance increased to 60,729 boepd
  • December 2015 exit rate estimated to exceed 65,500 boepd

BIRMINGHAM, Ala.--(BUSINESS WIRE)-- For the 3 months ended March 31, 2015, Energen Corporation (NYSE: EGN) reported a GAAP net loss from all operations of $15.4 million, or $(0.21) per diluted share. After adjusting for mark-to-market losses on derivatives, impairment losses, and income from the sale of the majority of the company’s San Juan Basin assets, Energen’s adjusted income in the 1st quarter of 2015 totaled $3.7 million, or $0.05 per diluted share. This compares with adjusted income from continuing operations in the 1st quarter of 2014 of $24.2 million, or $0.33 per diluted share. The variance between the periods largely is attributable to a 23 percent decline in realized oil and natural gas liquids (NGL) prices partially offset by a 14 percent increase in oil and NGL production. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

Energen’s adjusted EBITDAX totaled $145.0 million in the 1st quarter of 2015 and compared with prior-year adjusted EBITDAX from continuing operations of $168.1 million. [See “Non-GAAP Financial Measures” beginning on pp 13 for more information and reconciliation.]

The company’s adjusted 1st quarter earnings per diluted share surpassed internal expectations by $4.4 million ($0.06 per diluted share) largely due to greater production partially offset by lower realized sales prices.

Production in the 1st quarter of 2015 (excluding production from the San Juan Basin divestiture) exceeded the guidance range midpoint by 6 percent (approximately 300,000 BOE) largely due to accelerated completions in the Delaware and Midland basins, less-than-expected negative impact from a 3rd party gas handling issue in the Delaware Basin, and better-than-expected well performance from Wolfcamp and 3rd Bone Spring wells in the Delaware Basin.

“It is great to have 2015 get off to such a good start,” said James McManus, chairman and chief executive officer of Energen Corporation. “As we disclosed a few weeks ago, we made significant progress during the 1st quarter in reducing the number of days to drill our wells, particularly in the Delaware Basin, and our costs to drill and complete all our wells have further declined due to reductions in drilling and completion service costs. We estimate that drilling efficiencies and additional service cost reductions are saving us approximately $100 million in 2015 relative to our original budget. We plan to use the majority of these savings to drill 16 more net wells in the Lower Spraberry and Wolfcamp shales in the 4th quarter. At this time, we do not plan to complete these wells until 2016.

“Not only do we plan to drill 9 more net lower Spraberry wells this year, these will be drilled in conjunction with 9 Wolfcamp A and B wells in Martin County, representing a new, 3-well, pad drilling development program. We are very excited by this prospect given the strength of our first Lower Spraberry well results in Martin County,” McManus added. “These wells are among the best Lower Spraberry wells drilled to date in Martin County. We also are pleased with the solid result from our first Glasscock County lower Spraberry well. We believe we can continue to perfect our landing and improve performance with additional testing and fully expect to move from our current 2-well, pad drilling development program in Glasscock County to a 3-well program in 2016 that incorporates the Lower Spraberry.

“Based on the strength of our Lower Spraberry results, we have identified 676 net, unrisked drilling locations in the play on our Midland Basin acreage position. These additions give us a Midland Basin drilling inventory of 2,803 net, unrisked drilling locations, a total Permian Basin drilling inventory of 5,701 net, unrisked drilling locations, and a company-wide drilling inventory of 6,266 net, unrisked drilling locations – all engineered locations. And we think there could be more to come, as the thick Wolfcamp B and C benches in Glasscock County may well offer the potential for two laterals per zone.

“These are very exciting times for Energen. We have a high-quality asset base that is driving double-digit, year-over-year production growth; we have an extensive drilling inventory that we are prepared to pursue more aggressively when commodity prices rebound; we have a solid hedge position; and we have a clean balance sheet. We also are improving our drilling efficiency and working hard to capture the lower service costs resulting from low oil prices in order to do more with the same dollars in 2015.”

1st Quarter Financial Review

After adjusting for mark-to-market losses on derivatives, impairment losses, and income from the sale of the majority of the company’s San Juan Basin assets, Energen’s adjusted income in the 1st quarter of 2015 totaled $3.7 million, or $0.05 per diluted share. This compares with adjusted income from continuing operations in the 1st quarter of 2014 of $24.2 million, or $0.33 per diluted share. The variance between the periods largely is attributable to a 23 percent decline in realized oil and NGL prices partially offset by a 14 percent increase in oil and NGL production.

   

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations

[See “Non-GAAP Financial Measures” beginning on pp 13 for more information]

         
1Q15 1Q14
$M   $/dil. sh. $M   $/dil. sh.
Net Income/(Loss) All Operations (GAAP) $ (15,420 )   $ (0.21 ) $ 53,316   $ 0.73
Less: Non-cash Mark-to-Market gain/(loss) (38,350 ) (0.53 ) (21,536 ) (0.29 )
Less: Asset Impairment, other (4,231 ) (0.06 ) (791 ) (0.01 )
Less: Income Associated w/ San Juan Basin Divestment 23,431 0.32 13,798 0.19
Less: Discontinued Operations     --       --       37,669       0.52  
Adj. Income Continuing Operations (Non-GAAP)   $ 3,730     $ 0.05     $ 24,176     $ 0.33  

Note: Per share amounts may not sum due to rounding

 
         

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

               
Commodity 1Q15 1Q14 Change 4Q14
MBOE   boepd MBOE   boepd   MBOE   boepd
Oil 3,233   35,922 2,748   30,533 18 % 3,209   34,880
NGL 732 8,133 741 8,233 (1) % 879 9,554
Natural Gas   904   10,044   877   9,744   3 % 1,033   11,228
Total   4,869   54,100   4,366   48,511   12 % 5,121   55,663

Note: Totals may not sum due to rounding

 
         

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

               
Area 1Q15 1Q14 Change 4Q14
MBOE   boepd MBOE   boepd   MBOE   boepd
Midland Basin 2,320   25,778 1,537   17,078 51 % 2,238   24,326
Wolfberry 1,027 11,411 1,474 16,378

 

1,189 12,924
Wolfcamp/Cline/Spraberry 1,293 14,367 63 700 1,049 11,402
Delaware Basin 1,225 13,611 1,404 15,600 (13)% 1,421 15,446
3rd Bone Spring/Other 875 9,722 1,135 12,611 1,129 12,272
Wolfcamp 350 3,889 269 2,989 292 3,174
Central Basin Platform   909   10,100   1,016   11,289   (11) % 979   10,641
Total Permian Basin 4,454 49,489 3,957 43,967 13 % 4,638 50,413
San Juan Basin/Other   415   4,611   409   4,544   1 % 483   5,250
Total   4,869   54,100   4,366   48,511   12 % 5,121   55,663

Note: Totals may not sum due to rounding

 
     

Average Realized Sales Prices from Continuing Operations

               
Commodity 1Q15 1Q14 Change
Oil (per barrel) $ 67.89 $ 86.86 (22 ) %
NGL (per gallon) $ 0.30 $ 0.76 (61 ) %
Natural Gas (per Mcf)   $ 3.82  

$

2.72

*

  40

  %

* 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 1Q14 was $4.51 per Mcf.

 
     

Expenses from Continuing Operations (per BOE, except interest expense)

               
Expenses 1Q15 1Q14 Change
LOE* $ 11.32 $ 12.16 (7 ) %
Production & ad valorem taxes $ 3.50 $ 5.31 (34 ) %
DD&A $ 25.63 $ 24.93 3

  %

Net G&A

$

6.30

$ 7.48 (16 ) %
Interest ($MM)   $ 11.8     $ 7.9   49

  %

* Production costs + workovers and repairs + marketing and transportation

 

† Excludes $0.40 per unit for pension and pension settlement expenses

 

1st Quarter Comparisons, 2015 vs 2014 (Excluding San Juan Basin Assets Sold March 31, 2015)

  • The strength of Energen’s successful Wolfcamp development program led to a 51 percent increase in Midland Basin production and more than compensated for expected declines in the Delaware Basin and Central Basin Platform to result in total Permian Basin production growth of 13 percent.
  • The company’s average realized oil price fell 22 percent, while the realized price of NGL dropped 61 percent. Excluding the impact of commodity and differential hedges, the average realized price of oil would have been $43.93 per barrel.
  • LOE per unit declined 7 percent to $11.32 per barrel largely due to fewer workovers and repairs and lower costs for electricity and water hauling. Per-unit production taxes and ad valorem taxes declined 34 percent.
  • Per-unit DD&A expense increased 3 percent to $25.63 per BOE largely due to year-over-year increases in development costs and production.
  • Per-unit net G&A expense of $6.30 per BOE (excluding pension and pension settlement expenses) declined 16 percent from the same period a year ago largely due to increased production.
  • Interest expense increased 49 percent to total $11.8 million largely due to a prior-year reclassification of certain interest expense to discontinued operations as well as increased interest and fees associated with the company’s credit facility.
       

Midland Basin Development Program Results

           
Development program wells drilled in 1Q15 (gross/net) 34/34
Development program wells completed in 1Q15 (gross/net) 33/33
Development program wells awaiting completion at end of 1Q15 (gross/net) (gross/net) 25/25
Development program wells awaiting completion at YE15e (gross/net)         39/39
 

In its 2-well, pad drilling development program in Glasscock County, Energen tested 22 gross (22 net) wells of 6,700’ and 7,500’ lateral lengths during the 1st quarter of 2015. These wells generated average peak 24-hour IP rates (3-stream) of 825 boepd (88% oil) and peak 30-day average rates (3-stream) of 607 boepd (75% oil).

The 49 gross (48 net) wells tested since the program’s inception in 2014 have generated average peak 24-hour IPs (3-stream) of 906 boepd (81% oil) and peak 30-day average rates (3-stream) of 723 boepd (75% oil). In aggregate, these wells continue to meet or exceed the company’s unrisked type curve that supports EURs of 770 MBOE for 6,700’ lateral lengths and 850 MBOE for 7,500’ lateral lengths.

When the development program is expanded to Martin County later this year, the company plans shift from its 2-well, pad-drilling program to a new 3-well program that incorporates the Lower Spraberry, the Wolfcamp A, and the Wolfcamp B. This development design is also expected to be utilized in Glasscock County in 2016.

All 20 gross (20 net) wells with 4,400’ lateral lengths in Energen’s down-spacing test in Glasscock County have now been drilled and are in various stages of completion and flowback.

Midland and Delaware Basin Appraisal Program Results

Energen tested 11 new appraisal wells in the Permian Basin during the 1st quarter of 2015, including its first three Lower Spraberry wells in the Midland Basin and two new eastern wells in the Delaware Basin. [See locator maps at www.energen.com]

         

Midland Basin Appraisal Well Results (3-Stream)

                     
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
Campbell #501H   LSB/Martin   7,186   6,628   31   1,007   85   9   6   897   81   11   8
Wilbanks SN 16-15 #501H   LSB/Martin   7,123   6,628   31   946   78   14   8   831   78   14   8
San Saba NS 37-48 #501H   LSB/Glasscock   6,661   6,163   25   732   67   18   15   596   57   23   20
Campbell #101H   WCA/Martin   7,267   6,725   32   792   89   7   4   635   85   9   6
Smith SN 48-37 #201H   WCB/Howard   7,486   7,076   29   825   85   7   8   639   81   9   10
San Saba NS 37-48 #307H   WCC/Glasscock   7,312   6,824   28   753   53   27   20   600   63   21   16

* Represents distance from vertical departure to toe

             

The Campbell #501H and the Wilbanks SN 16-15 #501H, both Lower Spraberry wells in Martin County, generated excellent 3-stream results. The two wells generated 24-hour peak rates of 1,007 boepd and 946 boepd, respectively. In addition, the oil content of the two product streams was high, at 85% and 78%, respectively. The peak 30-day average rates were equally strong at 897 boepd (81% oil) and 831 boepd (78% oil). In Glasscock County, the Lower Spraberry well San Saba NS 37-48 #501H generated solid results and is expected to be an economic zone for future development; in addition, the company plans to continue perfecting its landing target and improving performance with future Lower Spraberry tests.

In the 1st quarter of 2015, Energen drilled 6 gross (6 net) wells in its 2015 Midland Basin appraisal program; 5 gross (5 net) wells – including 4 gross (4 net) wells in the 2014 program -- were completed, tested, and reported above; another 5 gross (5 net) wells drilled were completed and currently are flowing back; and 1 gross (1 net) well is waiting on completion. Among the wells currently flowing back are Lower Spraberry tests in Howard and Midland counties. All 15 gross (15 net) wells in Energen’s 2015 Midland Basin appraisal program are expected to be completed by year-end 2015.

         

Delaware Basin Appraisal Well Results (3-Stream)

                     
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
University 4-21 #1   WCA/Winkler   4,615   4,242   20   1,412   80   10   10   951   79   11   10
University 35-20 #2H   WCA/Winkler   5,048   4,565   22   1,292   81   10   9   797   80   10   10
Jupiter 2-36 #1H   WCB/Reeves   4,485   4,063   18   1,549   43   24   33   899   55   19   26
             
Well Name Zone/

County

Lateral length (ft)

Frac Stages

Peak 24-Hour IP Peak 20-day Avg.
    Drilled*   Completed     Boepd   %Oil   %NGL   %Gas   Boepd   %Oil   %NGL   %Gas
Wilson 56-7 #1H   WCA/Reeves   4,349   3,842   16   534   35   29   36   313   35   29   36
Enterprise C19-5 #2H   WCA/Reeves   5,194   4,648   22   754   32   24   44   609   22   28   50

* Represents distance from vertical departure to toe

 

In the Delaware Basin, two Winkler County wells generated solid results in testing the Wolfcamp A. The Tier 2 University 4-21 #1 and the Tier 1 University 35-20 #2H had strong 24-hour and 30-day average peak rates; oil comprised approximately 80 percent of the 3-stream product mix on both wells.

In the 1st quarter of 2015, Energen drilled 7 gross (7 net) wells in its 2015 Delaware Basin appraisal program; 5 gross (5 net) wells – including 4 gross (4 net) wells in the 2014 program – were completed, tested, and reported above; 5 gross (5 net) wells drilled were completed and currently are flowing back; 1 gross (1 net) well is waiting on completion; and 1 gross (1 net) well is drilling. All 8 gross (8 net) wells in Energen’s 2015 Delaware Basin appraisal program are expected to be completed by mid-year 2015.

San Juan Basin Mancos Appraisal Program

Energen plans to drill 8 gross (8 net) wells in the second half of 2015 to test its acreage position in the Mancos oil play in the San Juan Basin. The company also is participating as a 50 percent non-operated participant in 6 gross (3 net) wells drilled by WPX Energy. These non-operated wells have been drilled and are in various stages of completion and flowback.

676 Net Lower Spraberry Locations Added

On the strength of its first three Lower Spraberry wells and known results of other operators, Energen has updated its unrisked potential drilling inventory in the Midland Basin to include the addition of 676 net, engineered Lower Spraberry locations across approximately 67,700 net acres. Together with three benches of the Wolfcamp shale and the Cline shale, the Lower Spraberry additions increase the company’s total unrisked potential drilling inventory of engineered net locations to 2,803. [See Midland Basin location details at www.energen.com]

The company has previously identified a Delaware Basin Wolfcamp drilling inventory of 2,898 net locations in four Wolfcamp intervals and 565 potential locations in one target zone of the Mancos oil formation in the San Juan Basin. Energen’s company-wide drilling inventory now totals of 6,266 engineered, unrisked, net drilling locations.

Capital, Production, and Financial Guidance

Energen’s total capital spending remains essentially unchanged at $1.0 billion. The company estimates that it will realize approximately $100 million in savings (relative to the original capital budget) as a result of drilling efficiency gains and additional service cost reductions. These savings will be used primarily to drill 16 more net Lower Spraberry and Wolfcamp wells in the Midland Basin in the 4th quarter. At present, the company does not plan to complete these well until 2016. Also included in the revised capital budget is $5.5 million for the acquisition of unproved leasehold, primarily in the Delaware Basin.

     

2015 Capital, Drilling and Production Summary

               

2015e Capital ($MM)

Operated

Rigs

Operated Wells

to Be Drilled

Gross (Net)

Midland Basin

$

695

5-8

108 (104)

Wolfcamp

 

 

(2 H rigs and
Development

440

1 V rig run ½ year)

74 (71)

Appraisal

65

8 (8)

Spraberry

 

Development

53

9 (9)

Appraisal

49

7 (7)

Wolfberry

22

10 (9)

SWD/Facilities

56

 

Non-operated/Other

10

 

 

 

Delaware Basin $ 160 2

15 (14)

Bone Spring 18 (1/2 yr)

3 (2)

Wolfcamp 74

8 (8)

Wolfbone 19

4 (4)

SWD/Facilities 44

 

Non-operated/Other 5

 

 
Other Permian $ 10

0 (0)

Waterflood injectors 0
Facilities/C02 5
Non-operated/Other 5

 

 
San Juan Basin/Other

$

64

1

8 (8)

Mancos

 

43

(1/2 yr)

8 (8)

Facilities

1

Non-operated/Other

20

 

Net Carry-in/Carry Out   $ 21      

 

Drilling & Development $

950

8-11 131 (126)
Acquisitions/Lease Extensions/UPL $ 45
Miscellaneous   $ 5        
Total Capital $ 1,000
 

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 to reflect 1st quarter results that were approximately 0.3 MMBOE higher than expected largely due to accelerated completions in the Delaware and Midland basins, less-than-expected negative impact from a 3rd party gas handling issue, and better-than-expected well performance from Wolfcamp and 3rd Bone Spring wells in the Delaware Basin.

Production for the year is now estimated to range from 21.7-22.7 MMBOE (59,452–62,192 boepd), with a midpoint of 22.2 MMBOE (60,729 boepd). This reflects an increase of approximately 16 percent from comparable, adjusted 2014 production volumes of 19.1 MMBOE. Production in the 2nd quarter of 2015 is estimated to range from 5.2-5.6 MMBOE (57,143-61,538 boepd), with a midpoint of 5.4 MMBOE (59,165 boepd).

     

Production by Play (Excluding San Juan Basin Divestiture)

             
Area 2015e Midpoint 2014 Change
MMBOE MMBOE  
Midland Basin 11.7 7.4 58 %
Wolfcamp/Spraberry/Cline 7.6 2.1

 

Wolfberry 4.1 5.3
Delaware Basin 5.0 5.8 (14) %
3rd Bone Spring/Other 3.4 4.6
Wolfcamp 1.6 1.2
Central Basin Platform   3.5   4.1   (15) %
Total Permian Basin 20.2 17.3 17 %
San Juan Basin/Other   2.0   1.8   11 %
Total   22.2   19.1   16 %

NOTE: Totals may not sum due to rounding

 
     

Production by Product (Excluding San Juan Basin Divestiture)

             
Commodity

2015e Midpoint

MMBOE boepd

2014

MMBOE boepd

% change
Oil 14.3   39,079 11.8   32,323 21 %
NGL 3.7 10,132 3.4 9,337 9 %
Natural Gas   4.2   11,518   3.9   10,660   8 %
Total Continuing Operations   22.2   60,729   19.1   52,320   16 %
 
       

Production by Basin/Quarter (Excluding San Juan Divestiture)

                 
Basin 1Q15a 2Q15e Midpoint 3Q15e Midpoint 4Q15e Midpoint
MMBOE   boepd MMBOE   boepd MMBOE   boepd MMBOE   boepd
Midland Basin 2.3 1 25,778 2.8 30,934 3.2 34,793 3.4 36,413
Delaware Basin 1.2 1 13,611 1.3 13,747 1.3 13,989 1.2 13,348
Central Basin Platform/Other 0.9 1 10,100 0.9 9,835 0.9 9,543 0.9 9,283
San Juan Basin/Other   0.4   4,611   0.4   4,648   0.5   5,913   0.6   6,207
Total Production   4.9   54,100   5.4   59,165   5.9   64,239   6.0   65,250

NOTE: Totals may not sum due to rounding

 
       

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

                 
Commodity 1Q15a 2Q15e Midpoint 3Q15e Midpoint 4Q15e Midpoint
MMBOE   boepd MMBOE   boepd MMBOE   boepd MMBOE   boepd
Oil 3.2 35,922 3.5 38,352 3.8 40,880 3.8 41,087
NGL 0.7 8,133 0.9 9,780 1.0 11,087 1.1 11,478
Gas   0.9   10,044   1.0   11,033   1.1   12,272   1.2   12,685
Total Production   4.9   54,100   5.4   59,165   5.9   64,239   6.0   65,250

NOTE: Totals may not sum due to rounding

 
   

2Q15 AND CY15 FINANCIAL GUIDANCE

 

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

         
Per BOE, except where noted 2Q15 CY15
LOE (production costs, marketing & transportation) $10.15- $10.95 $10.15-$10.95
Production & ad valorem taxes (% of revenues, excluding hedges) 8.8%
DD&A expense $24.60-$26.10 $23.50-$25.75
General & administrative expense, net* $6.04 $5.68
Exploration expense (seismic, delay rentals, etc.) $0.30-$0.40 $0.40-$0.55
Interest expense ($MM)   $10.5-$11.5   $40.0-$50.0

* Excludes $0.33 per BOE in 2Q15 and $1.53 per BOE in CY15 for pension and pension settlement expenses.

 

2Q15 and ROY 2015 Hedges

For the remaining 9 months of 2015, approximately 55 percent of the company’s production guidance midpoint of 17.3 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 1.6 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 5.7 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 (May-December) are $0.22 per Mcf (basis actuals in April were approximately $0.22 per Mcf).

       

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

                 

Commodity

Hedge Volumes

ROY15e Production

Midpoint

Hedge %

NYMEXe Price

Oil

 

6.2 MMBO

 

11.1 MMBO

 

56 %

 

$ 89.30 per barrel

Natural Gas

 

19.8 Bcf

 

19.8 Bcf

 

100 %

 

$ 4.38 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 $2.41 per barrel for the remainder 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 $58.75 per barrel of oil (April-December), $2.70 per Mcf of gas (May-December), and $0.52 per gallon of NGL (April-December). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (April-December) are $0.73 and $0.32, respectively.

For unhedged production, every $1.00 change in the average NYMEX price of oil from $58.75 per barrel is estimated to have a $4.2 million impact on cash flows, and every 1-cent change in the average price of NGL from $0.52 per gallon is estimated to have a cash flows impact of $960,000.

For the 2nd quarter of 2015, approximately 57 percent of the company’s production guidance midpoint of 5.4 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 78 percent of its oil production in the 2nd quarter of 2015 will be sweet. Gas basis assumptions (May-June) are $0.21 per Mcf (basis actuals in April were $0.22 per Mcf).

       

The company’s hedge position for the 2nd quarter of 2015 is:

                 

Commodity

Hedge Volumes

CY15e Production

Midpoint

Hedge %

NYMEXe Price

Oil

 

2.1 MMBO

 

3.5 MMBO

 

60 %

 

$ 89.30 per barrel

Natural Gas

 

6.0 Bcf

 

6.0 Bcf

 

100 %

 

$ 4.39 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 $2.41 per barrel in the 2nd 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 2nd quarter of 2015.

Energen’s assumptions for the commodity prices of unhedged production in the 2nd quarter of 2015 are $55.50 per barrel of oil (April-June), $2.55 per Mcf of gas (May-June), and $0.52 per gallon of NGL (April-June). Assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil are $0.67 and $0.26, respectively.

For unhedged production, every $1.00 change in the average NYMEX price of oil from $55.50 per barrel is estimated to have a $1.1 million impact on cash flows, and every 1-cent change in the average price of NGL from $0.52 per gallon is estimated to have a cash flows impact of $300,000.

Conference Call

Energen will hold its quarterly conference call Thursday, May 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.

 
     
Three Months Ended 3/31/2015
Energen Net Income ($ in millions except per share data)   Net Income  

Per Diluted Share

Net Income (Loss) All Operations (GAAP) (15.4 ) (0.21 )
Non-cash mark-to-market losses (net of $21.3 tax) 38.4 0.53
Asset impairment, other (net of $2.4 tax) 4.2 0.06
Income associated w/ San Juan Basin divestment (net of $14.1 tax)   (23.4 )   (0.32 )
Adjusted Income from Continuing Operations (Non-GAAP)   3.7     0.05  
 
     

Three Months Ended 3/31/2014

Energen Net Income ($ in millions except per share data)   Net Income  

Per Diluted Share

Net Income (Loss) All Operations (GAAP) 53.3 0.73
Non-cash mark-to-market losses (net of $12.1 tax) 21.5 0.29
Asset impairment, other (net of $0.5 tax) 0.8 0.01
Income associated w/ San Juan Basin divestment (net of $7.6 tax)   (13.8 )   (0.19 )
Adjusted Net Income from All Operations (Non-GAAP)   61.8     0.85  
Income from discontinued operations (net of $23.6 tax) (38.7 ) (0.53 )
Loss on disposal of discontinued operations (net of $0.6 tax)   1.1     0.01  
Adjusted Income from Continuing Operations (Non-GAAP)   24.2     0.33  
 
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 Three Months Ended 3/31
($ in millions)   2015   2014
 
Energen Net Income (Loss) (GAAP) (15.4 ) 53.3
Income associated w/ San Juan Basin divestment, net of tax   (23.4 )   (13.8 )
Adjusted Net Income from Continuing Operations (Non-GAAP)   (38.9 )   39.5  
Interest expense * 11.8 7.9
Income tax expense (benefit) * (22.8 ) 0.6
Depreciation, depletion and amortization * 126.3 109.7
Accretion expense * 1.6 1.5
Exploration expense * 0.8 11.6
Adjustment for asset impairment * 6.6 1.2
Adjustment for mark-to-market losses 59.7 33.7
Adjustment for income from discontinued operations, net of tax 0.0 (38.7 )
Adjustment for loss on disposal of discontinued operations, net of tax   0.0     1.1  
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)   145.0     168.1  
 
Note: Amounts may not sum due to rounding
 
* Amount adjusted to exclude San Juan Basin divestment. See reconciliation to GAAP Information for the Three Months Ended 3/31/2015 and 3/31/2014.
                         

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 Three Months Ended
March 31, 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 $ 187,822 $ 23,645 $ 164,177
Gain (loss) on derivative instruments     34,036           8,369           25,667      
Total Revenues     221,858           32,014           189,844      
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production 67,754 $ 10.74 12,637 $ 8.78 55,117 $ 11.32
Production and ad valorem taxes 19,065 $ 3.02 2,001 $ 1.39 17,064 $ 3.50
O&G Depreciation, depletion and amortization 132,839 $ 21.06 8,068 $ 5.60 124,771 $ 25.63
FF&E Depreciation, depletion and amortization 1,542 $ 0.24 - $ 0.00 1,542 $ 0.32
Asset impairment 6,583 - 6,583
Exploration 763 - 763
General and administrative 32,055 $ 5.08 (559 ) ($0.39 ) 32,614 $ 6.70
Accretion of discount on asset retirement obligations 2,010 433 1,577
(Gain) loss on sale of assets and other     (28,344 )         (28,054 )         (290 )    
Total costs and expenses     234,267           (5,474 )         239,741      
Operating Income (Loss)     (12,409 )         37,488           (49,897 )    
Other Income/(Expense)
Interest Expense (11,758 ) - (11,758 )
Other income     46           -           46      
Total other expense     (11,712 )         -           (11,712 )    
 
Income (Loss) from Continuing Operations Before Income Taxes (24,121 ) 37,488 (61,609 )
Income tax expense (benefit)     (8,701 )         14,057           (22,758 )    
Income (Loss) From Continuing Operations     (15,420 )         23,431           (38,851 )    
Discontinued Operations, net of tax
Income from discontinued operations - - -
Loss on Disposal of discontinued ops     -           -           -      
Income from discontinued ops     -           -           -      
Net Income (Loss)   $ (15,420 )       $ 23,431         $ (38,851 )    
 
Diluted Earnings Per Average Common Share
Continuing Operations $ (0.21 ) $ 0.32 $ (0.53 )
Discontinued Operations   $ -         $ -         $ -      
Net Income (Loss)   $ (0.21 )       $ 0.32         $ (0.53 )    
 
Basic earning Per Average Common Share
Continuing Operations $ (0.21 ) $ 0.32 $ (0.53 )
Discontinued Operations   $ -         $ -         $ -      
Net Income (Loss)   $ (0.21 )       $ 0.32         $ (0.53 )    
 
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      
 
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 Three Months Ended
March 31, 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 $ 350,822 $ 48,399 $ 302,423
Gain (loss) on derivative instruments     (53,391 )         5,942           (59,333 )    
Total Revenues     297,431           54,341           243,090      
Operating Costs and Expenses
Oil, natural gas liquids & natural gas production 67,444 $ 11.23 14,361 $ 8.75 53,083 $ 12.16
Production and ad valorem taxes 27,324 $ 4.55 4,160 $ 2.53 23,164 $ 5.31
O&G Depreciation, depletion and amortization 123,314 $ 20.52 14,437 $ 8.79 108,877 $ 24.93
FF&E Depreciation, depletion and amortization 906 $ 0.15 65 $ 0.04 841 $ 0.18
Asset impairment 1,246 - 1,246
Exploration 11,568 (3 ) 11,571
General and administrative 32,173 $ 5.36 (465 ) ($0.28 ) 32,638 $ 7.48
Accretion of discount on asset retirement obligations 1,843 381 1,462
(Gain) loss on sale of assets and other     153           -           153      
Total costs and expenses     265,971           32,936           233,035      
Operating Income (Loss)     31,460           21,405           10,055      
Other Income/(Expense)
Interest Expense (7,888 ) - (7,888 )
Other income     323           -           323      
Total other expense     (7,565 )         -           (7,565 )    
 
Income (Loss) from Continuing Operations Before Income Taxes 23,895 21,405 2,490
Income tax expense (benefit)     8,248           7,607           641      
Income (Loss) From Continuing Operations     15,647           13,798           1,849      
Discontinued Operations, net of tax
Income from discontinued operations 38,719 - 38,719
Loss on Disposal of discontinued ops     (1,050 )         -           (1,050 )    
Income from discontinued ops     37,669           -           37,669      
Net Income (Loss)   $ 53,316         $ 13,798         $ 39,518      
 
Diluted Earnings Per Average Common Share
Continuing Operations $ 0.21 $ 0.19 $ 0.03
Discontinued Operations   $ 0.52         $ -         $ 0.52      
Net Income (Loss)   $ 0.73         $ 0.19         $ 0.54      
 
Basic earning Per Average Common Share
Continuing Operations $ 0.21 $ 0.19 $ 0.03
Discontinued Operations   $ 0.52         $ -         $ 0.52      
Net Income (Loss)   $ 0.73         $ 0.19         $ 0.54      
 
Oil 2,751 3 2,748
NGL 903 162 741
Gas     2,354           1,477           877      
Total Production (mboe)     6,008           1,642           4,366      
Total Production (boepd)     66,756           18,244           48,511      
 
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 Three Months Ended
December 31, 2014
         
GAAP San Juan Basin Non-GAAP
 
Oil 3,213 4 3,209
NGL 1,027 148 879
Gas   2,441   1,408   1,033
Total Production (mboe)   6,681   1,560   5,121
Total Production (boepd)   72,620   16,957   55,663
 
Note: Amounts may not sum due to rounding
 
   

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)For the 3 months ending March 31, 2015 and 2014

           
 
1st Quarter
 
(in thousands, except per share data)     2015     2014     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 187,822 $ 350,822 $ (163,000 )
Gain (loss) on derivative instruments, net     34,036       (53,391 )     87,427  
 
Total revenues     221,858       297,431       (75,573 )
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 67,754 67,444 310
Production and ad valorem taxes 19,065 27,324 (8,259 )
Depreciation, depletion and amortization 134,381 124,220 10,161
Asset impairment 6,583 1,246 5,337
Exploration 763 11,568 (10,805 )
General and administrative 32,055 32,173 (118 )
Accretion of discount on asset retirement obligations 2,010 1,843 167
(Gain) loss on sale of assets and other     (28,344 )     153       (28,497 )
 
Total costs and expenses     234,267       265,971       (31,704 )
 
Operating Income (Loss)     (12,409 )     31,460       (43,869 )
 
Other Income (Expense)
Interest expense (11,758 ) (7,888 ) (3,870 )
Other income     46       323       (277 )
 
Total other expense     (11,712 )     (7,565 )     (4,147 )
 

Income (Loss) From Continuing Operations Before Income Taxes

(24,121

)

23,895

(48,016

)

Income tax expense (benefit)     (8,701 )     8,248       (16,949 )
 
Income (Loss) From Continuing Operations     (15,420 )     15,647       (31,067 )
 
Discontinued Operations, net of tax
Income from discontinued operations 38,719 (38,719 )
Loss on disposal of discontinued operations           (1,050 )     1,050  
 
Income From Discontinued Operations           37,669       (37,669 )
 
Net Income (Loss)   $ (15,420 )   $ 53,316     $ (68,736 )
 
Diluted Earnings Per Average Common Share
Continuing operations $ (0.21 ) $ 0.21 $ (0.42 )
Discontinued operations           0.52       (0.52 )
 
Net Income (Loss)   $ (0.21 )   $ 0.73     $ (0.94 )
 
Basic Earnings Per Average Common Share
Continuing operations $ (0.21 ) $ 0.21 $ (0.42 )
Discontinued operations           0.52       (0.52 )
 
Net Income (Loss)   $ (0.21 )   $ 0.73     $ (0.94 )
 
Diluted Avg. Common Shares Outstanding     72,830       73,045       (215 )
 
Basic Avg. Common Shares Outstanding     72,830       72,629       201  
 
Dividends Per Common Share   $ 0.02     $ 0.15     $ (0.13 )
 
 

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

     
             
(in thousands)     March 31, 2015       December 31, 2014
   
ASSETS
Current Assets
Cash and cash equivalents

$

1,530

$

1,852
Short-term investments

 

309,000

 

Accounts receivable, net of allowance 137,720 157,678
Inventories 17,763 14,251
Assets held for sale 395,797
Derivative instruments 272,675 322,337
Prepayments and other     18,009       27,445
 
Total current assets     756,697       919,360
 
Property, Plant and Equipment
Oil and natural gas properties, net 5,410,933 5,152,748
Other property and equipment, net     46,248       46,389
 
Total property, plant and equipment, net     5,457,181       5,199,137
 
Other assets     14,865       19,761
 
TOTAL ASSETS   $ 6,228,743     $ 6,138,258
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable

$

97,563

$

101,453
Accrued taxes 17,199 5,530
Accrued wages and benefits 16,089 21,553
Accrued capital costs 159,026 207,461
Revenue and royalty payable 66,761 72,047
Liabilities related to assets held for sale 24,230
Pension liabilities

 

29,442

 

24,609
Deferred income taxes

Derivative instruments

53,867

12,870

79,164

988

Other     17,658       23,288
 
Total current liabilities     470,475       560,323
 
Long-term debt 1,238,569 1,038,563
Asset retirement obligations 97,315 94,060
Deferred income taxes 1,010,770 1,000,486
Noncurrent derivative instruments 1,018
Other long-term liabilities     11,419       30,222
 
Total liabilities     2,829,566       2,723,654
 
Total Shareholders’ Equity     3,399,177       3,414,604
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY   $ 6,228,743     $ 6,138,258
 
   

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)For the 3 months ending March 31, 2015 and 2014

           
1st 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 $ 142,028 $ 253,759 $ (111,731 )
Natural gas liquids 10,834 28,203 (17,369 )
Natural gas     34,960       68,860       (33,900 )
Total   $ 187,822     $ 350,822     $ (163,000 )
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ (51,769 ) $ (21,464 ) $ (30,305 )
Natural gas liquids 287 (287 )
Natural gas     (7,882 )     (12,504 )     4,622  
Total   $ (59,651 )   $ (33,681 )   $ (25,970 )
Closed gains (losses) on derivative instruments
Oil $ 77,483 $ (14,802 ) $ 92,285
Natural gas liquids 196 (196 )
Natural gas     16,204       (5,104 )     21,308  
Total   $ 93,687     $ (19,710 )   $ 113,397  
Total revenues   $ 221,858     $ 297,431     $ (75,573 )
Production volumes
Oil (MBbl) 3,235 2,751 484
Natural gas liquids (MMgal) 36.2 37.9 (1.7 )
Natural gas (MMcf)     13,278       14,124       (846 )
Total production volumes (MBOE)     6,309       6,008       301  

Average daily production volumes Oil (MBbl/d)

35.9

30.6

5.3

Natural gas liquids (MMgal/d) 0.4 0.4 0.0
Natural gas (MMcf/d)     147.5       156.9       (9.4 )
Total average daily production volumes (MBOE/d)     70.1       66.8       3.3  
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 67.86 $ 86.86 $ (19.00 )
Natural gas liquids (per gallon) $ 0.30 $ 0.75 $ (0.45 )
Natural gas (per Mcf) $ 3.85 $ 4.51 $ (0.66 )
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 43.90 $ 92.24 $ (48.34 )
Natural gas liquids (per gallon) $ 0.30 $ 0.74 $ (0.44 )
Natural gas (per Mcf) $ 2.63 $ 4.88 $ (2.25 )
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

10.74

$

11.23

$

(0.49

)

Production and ad valorem taxes $ 3.02 $ 4.55 $ (1.53 )
Depreciation, depletion and amortization $ 21.30 $ 20.68 $ 3.04
Exploration expense $ 0.12 $ 1.93 $ (1.81 )
General and administrative $ 5.08 $ 5.36 $ (0.28 )
Net capital expenditures   $ 375,827     $ 271,696     $ 104,131  
 

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

Source: Energen Corporation



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