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Four New Wolfcamp A Wells Generate Exciting Rates

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Click here for a PDF version of the Wolfcamp locator maps

Energen Reports 3RD Quarter 2013 Operating, Financial Results

North Louisiana/East Texas Assets Held for Sale

Highlights

  • New Wolfcamp A well in Reeves County sets known record for peak 24-hour IP (3-phase) of 2,229 boepd
  • New well data enhances Wolfcamp potential in southern Delaware and Midland basins
  • 3rd Bone Spring, Wolfberry performance continues to be strong
  • Oil production increases 21% from prior-year 3rd quarter; Permian Basin production rises 36%
  • North Louisiana/East Texas assets held for sale

BIRMINGHAM, Ala.--(BUSINESS WIRE)--Oct. 30, 2013-- Energen Corporation (NYSE: EGN) has tested four new Wolfcamp A wells in the Permian Basin during the third quarter of 2013. All produced at attractive initial rates, and oil accounted for more than 50 percent of the product stream in each well. The Bodacious C7-19 #1H in eastern Reeves County produced at a peak 24-hour rate of 2,229 boepd, which is the highest initial production (IP) rate for a southern Delaware Wolfcamp well to have been publicly disclosed to date. [See locator maps at www.energen.com]

“We are very pleased with our latest Wolfcamp results and increasingly excited about the potential success of this play not only in the Midland Basin but in the southern Delaware Basin, as well,” said James McManus, Energen’s chairman and chief executive officer. “We are looking forward in 2014 to accelerating the pace of Wolfcamp development in the Midland Basin, where we are seeing great consistency in Wolfcamp A results in Glasscock County, and to continuing the delineation of our sizeable acreage position in the southern Delaware Basin. With approximately 180,000 net Permian acres identified as having Wolfcamp potential, Energen’s unrisked drilling inventory could approach 5,300 locations (based on 80-acre spacing and 4,400-foot lateral lengths) if the play is successful on a large-scale basis.”

Non-Core Assets Held-for-Sale

Energen has classified its non-core North Louisiana/East Texas properties as held-for-sale effective September 30, 2013. At year-end 2012, proved reserves associated with these properties totaled 20.4 billion cubic feet equivalent (Bcfe), of which more than 98 percent are natural gas.

As a result, included in third quarter and year-to-date 2013 financial results is a write down of the book value of the North Louisiana/East Texas assets to the estimated fair value. This non-cash impairment charge is $24.6 million ($15.7 million after taxes, or $0.22 per diluted share) and is included in discontinued operations on the company’s income statement along with income from these properties and the company’s recently sold Black Warrior Basin assets.

Third Quarter Earnings

For the three months ended September 30, 2013, Energen reported a consolidated net loss of $19.3 million, or $0.27 per diluted share. Excluding non-cash items, Energen’s adjusted income from all operations (a non-GAAP measure) totaled $36.1 million, or $0.50 per diluted share, in the third quarter of 2013; in the same period last year, adjusted income from all operations was $31.8 million, or $0.44 per diluted share.

Non-cash items in the current-year third quarter were mark-to-market revenue losses of $63.6 million ($39.7 million after tax, or $0.55 per diluted share) and a write-down of North Louisiana/East Texas assets totaling $24.6 million ($15.7 million after tax, or $0.22 per diluted share). In the third quarter of 2012, mark-to-market revenue losses totaled $46.8 ($29.7 million after tax, or $0.41 per diluted share). [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

After excluding income from discontinued operations (Black Warrior Basin and North Louisiana/East Texas), Energen’s adjusted income from continuing operations in the third quarter 2013 totaled $34.2 million, or $0.47 per diluted share in 2013, as compared with $28.2 million, or $0.39 per diluted share, in 2012. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

The impact of a 15 percent increase in production from continuing operations, including a 21 percent increase in oil volumes, and higher realized oil and natural gas prices was partially offset by increased depreciation, depletion and amortization expense (DD&A), lease operating expense including production taxes (LOE), and administrative expense.

Relative to the company’s budget, third quarter 2013 adjusted income from all operations ($0.50 per diluted share) was below expectations largely due to higher stock-based compensation expense ($0.04 per diluted share) and increased exploration expense ($0.07 per diluted share) primarily associated with the write-off of approximately 4,200 miscellaneous acres of unproved leasehold.

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

[See “Non-GAAP Financial Measures” beginning on pp. 15 for more information]

         
3Q13 3Q12
$MM     $/dil. sh. $MM     $/dil. sh.
Net Income All Operations (GAAP)       $ (19,298 )     $ (0.27 )     $ 2,046       $ 0.03  
Less: Non-cash Mark-to-Market gain/(loss)         (39,674 )       (0.55 )       (29,734 )       (0.41 )
Adjusted Net Income All Operations (Non-GAAP)       $ 20,376       $ 0.28       $ 31,780       $ 0.44  
Less: Discontinued Operations
Non-cash North Louisiana Asset Impairment         (15,678 )       (0.22 )       --         --  
Adj. Income All Operations (ex non-cash)       $ 36,054         0.50       $ 31,780       $ 0.44  
Income from Discontinued Operations         1,866         0.03         3,551         0.05  
Adj. Income Continuing Operations (Non-GAAP)       $ 34,188       $ 0.47       $ 28,229       $ 0.39  
 

Energen’s adjusted EBITDA from all operations (excluding non-cash items) totaled $210.1 million in the third quarter of 2013 and compared with $162.3 million in the prior-year third quarter. The company’s oil and gas exploration and production unit, Energen Resources Corporation, had adjusted EBITDA from all operations (excluding non-cash items) of $209.9 million in the third quarter of 2013 and $163.9 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

Energen’s adjusted EBITDA from continuing operations (excluding mark-to-market) totaled $208.3 million in the third quarter of 2013 and compared with $158.8 million in the prior-year third quarter. Energen Resources had adjusted EBITDA from continuing operations (excluding mark-to-market) of $208.1 million in the third quarter of 2013 and $160.4 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

Wolfcamp Shale Exploration Results

(Locator map available at www. Energen.com)

 

MIDLAND BASIN WOLFCAMP

Well     County    

Target
Zone

   

Lateral
length

   

Stimulation/
Frac Stages

    Peak 24-Hour IP     Peak 30-day Average
                    Boepd    

Oil
(Bopd)

   

NGL
(Bpd)

   

Gas
(Mcfd)

    Boepd    

Oil
(Bopd)

   

NGL
(Bpd)

   

Gas
(Mcfd)

Llano 8-
8A 101H

    Glasscock     A     4,250’    

Slick water/
17

    784     538     136     662     683     446     131     638
                           

The early performance of the Llano 8-8A 101H, which was drilled in Glasscock County approximately 4 miles northwest of the Lavaca 38-101 #1H that was tested last quarter, was consistent with the Lavaca well. The Llano 8-8A 101H tested at peak 24-hour IP rate of 784 boepd (69% oil, 17% NGL, and 14% gas). The peak 30-day rate was 683 boepd (65% oil 19% NGL, and 16% gas).

Energen plans to drill 7 gross (7 net) Wolfcamp wells in Glasscock County this year. Three wells currently are in various stages of drilling and completion: one is an A-bench well with a 5,300 foot lateral, and two are B-bench wells with 6,700-foot laterals. Two spuds previously slated for December are now expected to be drilled in January.

 

DELAWARE BASIN

Well     County    

Target
Zone

   

Lateral
length

   

Stimulation/
Frac Stages

    Peak 24-Hour IP     Peak 30-day Average
                    Boepd    

Oil
(Bopd)

   

NGL
(Bpd)

   

Gas
(Mcfd)

    Boepd    

Oil
(Bopd)

   

NGL
(Bpd)

   

Gas
(Mcfd)

Bodacious
C7-19 #1H

    Reeves     A     4,500’    

Slick water/
19

    2,229     1,375     458     2,375     1,671     1,015     352     1,824

University
25-17 #1H

    Ward     A     4,000’    

Slick water/
17

 

    1,079     760     167     914     769     500     141     771
                           
Well     County    

Target
Zone

   

Lateral
length

   

Stimulation/
Frac Stages

    Peak 24-Hour IP     Peak 20-day Average
                    Boepd    

Oil
(Bopd)

   

NGL
(Bpd)

   

Gas
(Mcfd)

    Boepd    

Oil
(Bopd)

   

NGL
(Bpd)

   

Gas
(Mcfd)

Benton
3-12 #1H

    Reeves     A     4,700    

Slick water/
19

    1,462     812     306     2,069     1,163     632     250     1,690
                           

Energen’s second Reeves County Wolfcamp A well was drilled further east in the southern Delaware Basin. The Bodacious C7-19 #1H, tested at an outstanding peak 24-hour IP rate of 2,229 boepd; this 3-stream rate was 62% oil, 20% NGL, and 18% gas. The peak 30-day average rate (3-stream) was 1,671 boepd (61% oil, 21% NGL, 18% gas).

Also in Reeves County, close to the Pecos River near the intersection of Loving, Ward, and Reeves counties, Energen drilled the Benton 3-12 #1H that tested at a peak 24-hour IP rate of 1,462 boepd. This 3-stream rate was 56% oil, 21% NGL, and 23% gas. The peak 20-day average rate (3- stream) was 1,163 boepd (54% oil, 21% NGL, and 25% gas).

The University 25-17 #1H in Ward County produced at a peak 24-hour initial rate (3-stream) of 1,079 boepd (70% oil, 16% NGL, 14% gas); the peak 30-day average rate (3-stream) was 769 boepd (65% oil, 18% NGL, and 17% gas).

Energen expects to drill a total of 10 gross (9 net) Wolfcamp wells in the basin this year. Three wells in Reeves County, including two B-bench wells, currently are in various stages of drilling, completion, and flow-back.

Permian Basin Development Results

Vertical Wolfberry Wells Continue Strong Performance

Energen Resources’ vertical Wolfberry wells continued to generate strong results in the third quarter. Forty-five gross (42 net) wells tested at an average peak 24-hour initial production rate (2-stream) of 129 boepd (68% oil). The peak 30-day average rate (2-stream) was 122 boepd (69% oil).

Energen has drilled 116 gross (106 net) Wolfberry wells through the first nine months of the year and plans to drill another 21 gross (20 net) wells in the fourth quarter. Energen estimates that its 26,700 net undeveloped Wolfberry acres in the Midland Basin support 668 net drilling locations on 40-acre spacing.

3rd Bone Spring Development Wells Continue Solid Performance

In the company’s horizontal 3rd Bone Spring program in the southern Delaware Basin, Energen Resources tested 9 gross (9 net) wells in the third quarter of 2013 that had an average 24-hour peak rate (2-stream) of 1,153 boepd (66% oil). The 30-day average production rate (2-stream) of 8 gross (8 net) wells tested was 642 boepd (69% oil).

Energen plans to drill another 11 gross (10 net) wells in the fourth quarter – 4 net wells more than originally planned. On the east side of the Pecos River, the company’s core 3rd Bone Spring holdings total approximately 30,000 net acres, of which 5,700 remain undeveloped. Energen Resources estimates that it has 36 potential locations remaining to be drilled on 160-acre spacing in this core area.

Third Quarter 2013 Financial & Operating Results

ENERGEN RESOURCES

Excluding non-cash items, Energen Resources’ adjusted income from all operations totaled $45.1 million in the third quarter of 2013 and $42.1 million in the same period a year ago. Energen Resources’ adjusted income from continuing operations totaled $43.3 million in the third quarter of 2013 and $38.6 million in the same period a year ago.

Production from continuing operations in the third quarter increased 15 percent year-over-year. Oil and natural gas liquids (NGL) volumes increased 27 percent, reflecting the company’s focus on its assets in the liquids-rich Permian Basin. Third quarter production in the Permian Basin grew 36 percent year-over-year, including 62 percent in the Midland Basin and 78 percent in the Delaware Basin.

             

Production (MBOE)

Commodity 3Q13 3Q12 Change
Continuing Operations
Oil 2,764 2,275 21 %
NGL 874 600 46 %
Natural Gas       2,478     2,437     2 %
Total Continuing Operations       6,116     5,312     15 %
Total Discontinued Operations       642     714     (10

)%

Total All Operations       6,758     6,026     12 %
 
 

Production from Continuing Operations by Area (MBOE)

Area       3Q13     3Q12     Change
Midland Basin 1,407 871 62 %
Delaware Basin 1,301 732 78 %
Central Basin Platform       1,106     1,207     (8

)%

Total Permian Basin 3,814 2,810 36 %
San Juan Basin/Other       2,302     2,502     (8

)%

Total Continuing Operations       6,116     5,312     15 %
 
 

Average Realized Sales Prices from Continuing Operations

Commodity       3Q13     3Q12     Change
Oil (per barrel) $ 89.67 $ 82.76 8 %
NGL (per gallon) $ 0.75 $ 0.78 (4

)%

Natural Gas (per Mcf)       $ 4.06     $ 3.66     11 %
 

Per-unit LOE from continuing operations in the third quarter of 2013 increased approximately 8 percent from the same period a year ago to $14.39 per barrel of oil equivalent (BOE). Base LOE and marketing and transportation expenses increased approximately 4.5 percent to $11.29 per BOE largely due to increased workovers and repairs and gathering and water disposal expenses, partially offset by lower expected ad valorem taxes. Commodity price-driven production taxes increased approximately 22 percent on a per-unit basis to $3.10 per unit.

Per-unit DD&A expense from continuing operations in the 3rd quarter of 2013 totaled $20.27 per BOE, increasing approximately 26 percent from the same period last year largely due to year-over-year increases in development costs and production and to the impact of reduced year-end 2012 natural gas reserves resulting from lower commodity prices.

Per-unit net G&A expense increased approximately 39 percent in the third quarter of 2013 to $4.84 per BOE primarily due to increased compensation expense tied to Energen’s stock price.

ALAGASCO

Energen’s utility operations under Alagasco generated a seasonal net loss of $9.0 million in the third quarter of 2013 as compared with a net loss of $10.0 million in the same period a year ago.

Year-to-Date 2013 Financial & Operating Results

CONSOLIDATED

For the nine months ended September 30, 2013, Energen’s consolidated net income totaled $120.5 million, or $1.67 per diluted share. Excluding non-cash items, Energen’s year-to-date adjusted income from all operations (a non-GAAP measure) totaled $166.9 million, or $2.31 per diluted share; in the same period last year, adjusted income from all operations was $182.2 million, or $2.52 per diluted share.

Non-cash items in the current year-to-date period were mark-to-market revenue losses of $48.5 million ($30.7 million after tax, or $0.43 per diluted share) and a write-down of assets being held for sale in North Louisiana/East Texas totaling $24.6 million ($15.7 million after tax, or $0.22 per diluted share). In the same period in 2012, mark-to-market revenue gains totaled $34.0 ($22.0 million after tax, or $0.30 per diluted share) and a commodity price-driven write-down of East Texas assets totaled $21.5 million ($13.4 million, or 19 cents per diluted share). [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

After excluding income from discontinued operations (Black Warrior Basin and North Louisiana/East Texas), Energen’s adjusted income from continuing operations in the year-to-date 2013 totaled $160.6 million, or $2.22 per diluted share in 2013, as compared with $172.7 million, or $2.39 per diluted share, in 2012. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

Energen’s adjusted EBITDA from all operations (excluding non-cash items) totaled $675.6 million in the first nine months of 2013 and compared with $605.5 million in the same period last year. Energen Resources’ adjusted EBITDA from all operations (excluding non-cash items) was $571.3 million in the first nine months of 2013 and $502.8 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

Energen’s adjusted EBITDA from continuing operations (excluding mark-to-market) totaled $669.3 million in the year-to-date period 2013 and compared with $596.1 million in the same period a year ago. Energen Resources had adjusted EBITDA from continuing operations (excluding mark-to-market) of $565.0 million in the year-to-date period 2013 and $493.3 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 15 for more information and reconciliation.]

 

Reconciliation of GAAP Net Income to Adjusted Income from Continuing Operations

[See “Non-GAAP Financial Measures” on pp. 15 for more information]

 
      YTD13     YTD12
$MM     $/dil. sh. $MM     $/dil. sh.
Net Income All Operations (GAAP)       $ 120,461       $ 1.67       $ 190,739       $ 2.64  
Less: Non-cash Mark-to-Market gain/(loss)         (30,733 )       (0.43 )       21,987         0.30  
Adjusted Net Income All Operations (Non-GAAP)       $ 151,194       $ 2.09       $ 168,752       $ 2.33  
Less: Discontinued Operations
Non-cash Asset Impairment         (15,678 )       (0.22 )       (13,416 )       (0.19 )
Adj. Income All Operations (ex non-cash)       $ 166,872         2.31       $ 182,168       $ 2.52  
Income from Discontinued Operations         6,269         0.09         9,432         0.13  
Adj. Income Continuing Operations (Non-GAAP)       $ 160,603       $ 2.22       $ 172,736       $ 2.39  
 

ENERGEN RESOURCES

Excluding non-cash items, Energen Resources’ adjusted income from all operations totaled $128.9 million through the first nine months of 2013 and $145.0 million in the same period a year ago. Energen Resources’ adjusted income from continuing operations totaled $122.6 million in the current year-to-date period and $135.6 million in the same period a year ago.

Year-to-date 2013 production from continuing operations increased 10 percent year-over-year. Oil and NGL volumes increased 21 percent, reflecting the company’s focus on its assets in the liquids-rich Permian Basin. In the Permian Basin, year-to-date production grew 28 percent year-over-year, including 40 percent in the Midland Basin and 82 percent in the Delaware Basin.

 

Production (MBOE)

Commodity       YTD13     YTD12     Change
Continuing Operations
Oil 7,670 6,414 20 %
NGL 2,345 1,881 25 %
Natural Gas       7,238     7,346     (1

)%

Total Continuing Operations       17,253     15,641     10 %
Total Discontinued Operations       1,906     2,209     (14

)%

Total All Operations       19,159     17,850     7 %
 
 

Production from Continuing Operations by Area (MBOE)

Area       YTD13     YTD12     Change
Midland Basin 3,615 2,589 40 %
Delaware Basin 3,443 1,891 82 %
Central Basin Platform       3,328     3,635     (8

)%

Total Permian Basin 10,386 8,115 28 %
San Juan Basin/Other       6,867     7,526     (9

)%

Total Continuing Operations       17,253     15,641     10 %
 
 

Average Realized Sales Prices from Continuing Operations

Commodity       YTD13     YTD12     Change
Oil (per barrel) $ 87.59 $ 84.47 4 %
NGL (per gallon) $ 0.74 $ 0.80 (8

)%

Natural Gas (per Mcf)       $ 4.14     $ 3.64     14 %
 

Per-unit LOE from continuing operations in the first nine months of 2013 increased approximately 18 percent from the same period a year ago to $15.07 per BOE. Base LOE and marketing and transportation expenses increased approximately 20 percent to $12.20 per BOE largely due to increased workovers and repairs, equipment rental, water disposal and gathering costs, and environmental compliance. Commodity price-driven production taxes increased approximately 13 percent on a per-unit basis to $2.87 per unit.

Per-unit DD&A expense from continuing operations in the first nine months of 2013 totaled $19.10 per BOE, increasing approximately 23 percent from the same period last year largely due to year-over-year increases in development costs and production and to the impact of reduced year-end 2012 natural gas reserves resulting from lower commodity prices.

Per-unit net G&A expense in the 2013 year-to-date period increased approximately 31 percent from the same period last year to $4.73 per BOE. This largely was due to increased stock-based compensation.

ALAGASCO

Alagasco generated net income of $37.6 million through the first nine months of 2013. In the same period last year. The utility’s net income in the same period a year ago totaled $37.2 million.

2013 Guidance

Energen’s guidance range for production from continuing operations for 2013 is 23.4-23.8 MMBOE, which is slightly below prior guidance for all operations after adjusting for 2.0 MMBOE of estimated discontinued operations. (Energen’s prior guidance for production from all operations was 25.7-26.1 MMBOE, issued on August 28; adjusting for discontinued operations, the prior guidance equated to production from continuing operations of 23.7-24.1 MMBOE).

The decrease in the production guidance range largely reflects lower gas and NGL volumes in the San Juan Basin, lower NGL production in the Permian Basin, and less oil production in the Delaware Basin. In the San Juan Basin, production is less than expected largely due to unanticipated workovers on some high-volume wells, unscheduled third-party plant downtime, pipeline imbalances, and delays/reduction in scheduled pay-adds. Most of these impacts were felt in the 3rd quarter. Lower NGL production in the Permian Basin is due to drier gas being produced by some 3rd Bone Spring wells and price-driven ethane rejection in the Midland Basin; the impact of these factors was felt in the 3rd quarter and expected to continue for the remainder of the year. In the Delaware Basin, oil production is being hampered by interference issues in highly fractured areas in the 3rd Bone Spring play.

Drilling capital in 2013 is estimated to be $1.08 billion in 2013, up $80 million from the prior estimate. The increase largely is due to increased drilling costs (largely related to mechanical drilling challenges in the company’s exploratory program and to overages in some development drilling), additional working interest (primarily in the Midland Basin), and a net increase in costs associated with program changes; the latter includes four additional 3rd Bone Spring wells, additional facilities in the Delaware Basin, and increased non-operated projects partially offset by a reduction in testing, exploratory spuds, and lower drill-and-complete costs on numerous 3rd Bone Spring wells.

 

Production (MMBOE)

Commodity      

2013e Production
Midpoint

    2012
Oil 10.5 8.8
NGL 3.3 2.6
Natural Gas       9.8     9.8
Production from Continuing Operations       23.4-23.8     21.2
Production from Discontinued Operations       2.0     2.9
 
 

2013e Revised Drilling and Production Summary

     

Operated Wells Drilled
Gross (Net)

   

Production Midpoint

 

Midland Basin

144 (133 ) 5.3

Wolfberry

137 (126

)

5.2

Wolfcamp

7 (7

)

0.1

 

Delaware Basin

49 (46 ) 4.8

3(rd) Bone Spring

38 (36

)

4.3

Wolfcamp

10 (9

)

0.5

Wolfbone

1 (1

)

 
Other Permian* 81 (78 ) 4.4
 

San Juan Basin/Other

(0

)

9.1

 

Production from Continuing Operations

     

 

     

23.6

 

 

Production from Discontinued Operations

     

 

   

 

2.0

* Includes 2 gross (2 net) injector wells

 
 

2013e Capital Summary

Basin

     

Capital ($MM)

 
Midland Basin

$

500

Delaware Basin $ 470
Other Permian $ 85
San Juan Basin/Other       $ 25
Total       $ 1,080
 

Energen’s revised guidance range for 2013 consolidated after-tax cash flows (excluding disposal gains or losses) is $889-$904 million. Energen Resources’ after-tax cash flows are estimated to be $788-$803 million, and Alagasco is expected to generate after-tax cash flows of approximately $101 million. In addition, the company has received net proceeds of approximately $150 million from the October sale of its Black Warrior Basin assets; these proceeds have been used to reduce short-term debt. [See “Non-GAAP Financial Measures” beginning on pp 15 for more information and reconciliation.]

Energen narrowed and lowered its range of guidance for 2013 income from all operations (excluding mark-to-market and disposal gains or losses) to $3.10-$3.30 per diluted share to reflect increased stock-based compensation, increased exploration expense for 3rd quarter leasehold write-off, and lower production. Income from continuing operations in 2013 is estimated to be $3.05-$3.25 per diluted share.

In addition to the mark-to-market gains or losses recognized quarterly on derivative instruments, we expect a net gain on the disposal of assets in 2013. This is the result of a gain of $35.0 million ($23.2 million after tax) to be booked in the 4th quarter for the October 2013 sale of the company’s Black Warrior Basin assets. Because this gain will more than offset the loss on the impairment of North Louisiana/East Texas assets that was recognized in the third quarter, the resulting net gain (after tax) on disposal for 2013 will be $7.5 million.

Energen Resources’ estimated exploration and production expenses from continuing operations per BOE in 2013 are:

Lease Operating expense        
Base, marketing, and transportation $ 11.55 - $ 11.75
Production taxes $ 2.75 - $ 2.95
DD&A expense $ 19.05 - $ 19.25
General & Administrative expense, net $ 4.65 - $ 4.85
Interest expense $ 2.15 - $ 2.35

Approximately 78 percent of the company’s total estimated production for the remainder of 2013 is hedged. Assumed prices applicable to Energen Resources’ unhedged volumes for the remainder of the year are $90.00 per barrel of oil, $0.86 per gallon of NGL, and $4.00 per Mcf of natural gas.

Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential to approximately 30 percent of its estimated oil production for the remainder of 2013. Energen Resources has hedged the WTS Midland to WTI Cushing (sour oil) differential for 0.9 million barrels of oil production at an average price of $2.99 per barrel and the WTI Midland to WTI Cushing differential for 1.1 million barrels at an average price of $1.00 per barrel.

Energen’s 2013 guidance includes assumed prices applicable to Energen Resources’ unhedged oil basis differentials for the remainder of the year. They are $4.25 per barrel (sour oil) and $3.00 per barrel (WTI Midland to WTI Cushing). Energen estimates that approximately 68 percent of its oil production for the remainder of 2013 is sweet.

The company’s current hedge position for the last quarter of 2013 is as follows:

                 

Commodity

Hedge Volumes

2013e Production
(Contg Ops) Midpoint

Hedge %

NYMEX Price

 

Oil

2.4 MMBO

2.8 MMBO

86

%

$ 91.44 per barrel

 

NGL

12.0 MMgal

40.9 MMgal

29

%

$ 1.02 per gallon

 

Natural Gas

     

13.5 Bcf

   

15.3 Bcf

   

89

%

   

$ 4.62 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 Resources' assumed San Juan and Permian basis differentials of $0.19 per Mcf.

Average realized oil and gas prices for Energen Resources' 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 oil transportation charges of approximately $2.50 per barrel for the remainder of 2013; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11-$0.17 per gallon for the remainder of 2013. The company also has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price.

Given Energen’s hedge position for the remainder of the year, changes in commodity prices are not expected to have a significant impact on Energen's 2013 cash flows. Every $1.00 change in the average NYMEX price of oil from $90 per barrel represents an estimated net impact of $175,000; every 1-cent change in the average price of liquids from $0.86 per gallon represents an estimated net impact of approximately $210,000; and every 10-cent change in the average NYMEX price of gas from $4.00 represents an estimated net impact of $30,000.

Price-related events such as substantial basis differential changes could cause earnings sensitivities to be different from those outlined above.

At the end of September 2013, Alagasco was on track to earn within its allowed range of return on average equity of $375-$380 million.

ENERGEN HEDGE POSITION STRONG IN 2014

Energen has built a strong hedge position in 2014 and has already started establishing its hedge position in 2015.

The company’s 2014 hedges are as follows:

         

Commodity

Hedge Volumes

NYMEX Price

 

Oil

9.8 MMBO

$ 92.64 per barrel

 

Natural Gas

     

51.8 Bcf

   

$ 4.59 per Mcf

 

The company’s 2015 hedges are as follows:

         

Commodity

Hedge Volumes

NYMEX Price

 

Oil

5.8 MMBO

$ 88.85 per barrel

 

Natural Gas

     

6.0 Bcf

   

$ 4.26 per Mcf

 

Basin-specific contract prices for natural gas have been converted for comparability purposes to a NYMEX-equivalent price by adding to them Energen Resources' assumed San Juan and Permian basis differentials of $0.19 per Mcf in 2014 and 2015.

Average realized oil and gas prices for Energen Resources' production associated with NYMEX contracts and unhedged production will reflect the impact of basis differentials; average realized oil prices also will reflect transportation charges; and average realized NGL prices will be net of transportation and fractionation fees.

CONFERENCE CALL

Energen will hold its quarterly conference call today, Wednesday, October 30, at 10:30 a.m. EDT. Members of the investment community may participate by calling 1-866-939-3921. 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. Through Energen Resources Corporation, the company has approximately 750 million barrels of oil-equivalent proved, probable, and possible reserves. These all-domestic reserves are located mainly in the Permian and San Juan basins. For more information, go to http://www.energen.com.

FORWARD LOOKING STATEMENT: This release contains statements expressing expectations of future plans, objectives and performance that constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. We undertake no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. A more complete discussion of risks and uncertainties that could affect future results of Energen and its subsidiaries is included in the Company's periodic reports filed with the Securities and Exchange Commission.

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 and asset impairments of natural gas properties. Adjusted Net Income from continuing operations further excludes income 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 9/30/2013
Consolidated Net Income ($ in millions except per share data)       Net Income    

Per Diluted
Share

Net Income (GAAP) (19.3 )     (0.27 )
Non-cash mark-to-market losses (net of $23.9 tax) 39.7 0.55
Non-cash impairment charge (net of $8.9 tax) (1)       15.7       0.22  
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)       36.1       0.50  
Income from discontinued operations (net of $1.1 tax)       (1.9 )     (0.03 )
Adjusted Net Income from Continuing Operations (Non-GAAP)       34.2       0.47  
 
       
Quarter Ended 9/30/2012
Consolidated Net Income ($ in millions except per share data)       Net Income    

Per Diluted
Share

Net Income (GAAP) 2.0 0.03
Non-cash mark-to-market losses (net of $17.1 tax)       29.7       0.41  
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)       31.8       0.44  
Income from discontinued operations (net of $2.0 tax)       (3.6 )     (0.05 )
Adjusted Net Income from Continuing Operations (Non-GAAP)       28.2       0.39  
 
       
Year-to-Date Ended 9/30/2013
Consolidated Net Income ($ in millions except per share data)       Net Income    

Per Diluted
Share

Net Income (GAAP) 120.5 1.67
Non-cash mark-to-market losses (net of $17.8 tax) 30.7 0.43
Non-cash impairment charge (net of $8.9 tax) (1)       15.7       0.22  
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)       166.9       2.31  
Income from discontinued operations (net of $1.1 tax)       (6.3 )     (0.09 )
Adjusted Net Income from Continuing Operations (Non-GAAP)       160.6       2.22  
 
       
Year-to-Date Ended 9/30/2012
Consolidated Net Income ($ in millions except per share data)       Net Income    

Per Diluted
Share

Net Income (GAAP) 190.7 2.64
Non-cash mark-to-market gains (net of $12.0 tax) (22.0 ) (0.30 )
Non-cash write-down of natural gas properties (net of $8.1 tax) (2)       13.4       0.19  
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)       182.2       2.52  
Income from discontinued operations (net of $2.0 tax)       (9.4 )     (0.13 )
Adjusted Net Income from Continuing Operations (Non-GAAP)       172.7       2.39  
 
Note: Amounts may not sum due to rounding
 

(1) Current year-to-date and quarter-to-date loss on impairment ($15.7) included in gain (loss) on disposal of discontinued operations on the income statement

(2) Prior year-to-date write down of natural gas properties ($13.4) included in income (loss) from discontinued operations on the income statement

 

Non-GAAP Financial Measures

Earnings before interest, taxes, depreciation, and amortization (EBITDA) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Adjusted EBITDA from all operations reflects EBITDA adjusted for certain non-cash mark-to-market derivative financial instruments and asset impairments. Adjusted EBITDA from continuing operations further excludes income from 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     Year-to-Date Ended 9/30     Quarter Ended 9/30
($ in millions)       2012     2013     2012     2013
           
Consolidated Net Income (GAAP) 190.7 120.5 2.0 (19.3 )
Interest expense 48.4 51.8 17.2 17.7
Income tax expense 110.5 73.9 (0.3 ) (3.6 )
Depreciation, depletion and amortization 276.5 365.4 96.6 136.1
Adjustment for asset impairment, net of tax (1) 13.4 15.7 - 15.7
Adjustment for mark-to-market (gains) losses       (34.0 )     48.5     46.8       63.6  
Consolidated Adjusted EBITDA from All Operations, excluding non-cash items (Non-GAAP)       605.5       675.6     162.3       210.1  
Adjustment for income from discontinued operations, net of tax       9.4       6.3     3.6       1.9  
Consolidated Adjusted EBITDA from Continuing Operations (Non-GAAP)       596.1       669.3     158.8       208.3  
                   
Reconciliation To GAAP Information Year-to-Date Ended 9/30     Quarter Ended 9/30
($ in millions)       2012     2013     2012     2013
 
Energen Resources Net Income (GAAP) 153.6 82.4 12.4 (10.2 )
Interest expense 36.8 40.5 13.3 14.0
Income tax expense 88.1 51.5 5.4 1.8
Depreciation, depletion and amortization 244.9 332.7 86.1 125.1
Adjustment for asset impairment, net of tax (1) 13.4 15.7 - 15.7
Adjustment for mark-to-market (gains) losses       (34.0 )     48.5     46.8       63.6  
Energen Resources Adjusted EBITDA from All Operations, excluding non-cash items (Non-GAAP)       502.8       571.3     163.9       209.9  
Adjustment for income from discontinued operations, net of tax       9.4       6.3     3.6       1.9  
Energen Resources Adjusted EBITDA from Continuing Operations (Non-GAAP)       493.3       565.0     160.4       208.1  
 
Note: Amounts may not sum due to rounding
 

(1) Current year-to-date and quarter-to-date loss on impairment ($15.7) included in gain (loss) on disposal of discontinued operations on the income statement. Prior year-to-date write down of natural gas properties ($13.4) included in income (loss) from discontinued operations on the income statement.

 

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 and asset impairments of natural gas properties. Adjusted Net Income from continuing operations further excludes income 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.

 
                     
Energen Resources Net Income ($ in millions)      

Quarter Ended
9/30/2013

   

Year-to-date
9/30/2013

Net Income (GAAP) (10.2 )     82.4
Non-cash mark-to-market losses (net of $23.9 and $17.8 tax) 39.7 30.7
Non-cash impairment charge (net of $8.9 and $8.9 tax) (1)       15.7       15.7  
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)       45.1       128.9  
Income from discontinued operations (net of $1.1 and $3.7 tax)       (1.9 )     (6.3 )
Adjusted Net Income from Continuing Operations (Non-GAAP)       43.3       122.6  
     
       
Energen Resources Net Income ($ in millions)      

Quarter Ended
9/30/2012

   

Year-to-date
9/30/2012

Net Income (GAAP) 12.4 153.6
Non-cash mark-to-market losses (gains) (net of $17.1 and ($12.0) tax) 29.7 (22.0 )
Non-cash write down of natural gas properties (net of $8.1 tax) (2)       -       13.4  
Adjusted Net Income from All Operations, excluding non-cash items (Non-GAAP)       42.1       145.0  
Income from discontinued operations (net of ($2.0) and $2.0 tax)       (3.6 )     (9.4 )
Adjusted Net Income from Continuing Operations (Non-GAAP)       38.6       135.6  
 
Note: Amounts may not sum due to rounding
 

(1) Current year-to-date and quarter-to-date loss on impairment ($15.7) included in gain (loss) on disposal of discontinued operations on the income statement

(2) Prior year-to-date write down of natural gas properties ($13.4) included in income (loss) from discontinued operations on the income statement

 

Non-GAAP Financial Measures

After-tax Cash Flows is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles). Energen believes after-tax cash flows are relevant because they are a measure of cash available to fund the Company's capital expenditures, dividends, debt reduction, and other investments. Adjusted after-tax cash flows excluding Alagasco provides a measure of cash flows available to fund the Company's exploration and production activities.

                 
                   
Reconciliation To GAAP Information Years Ended 12/31
($ in millions)      

2011 Actual

   

2012 Actual

    2013 Estimate (e)
                           
Consolidated Net Income (GAAP)       260       254       225       240  
Depreciation, depletion and amortization 284 441 530 530
Deferred income taxes 129 124 109 109
Exploratory expense 11 17 - -
Other       53       (34 )     25       25  
After-tax Cash Flows (Non-GAAP) 737 802 889 904
Changes in assets and liabilities and other adjustments       25       (66 )     27       27  
Net Cash Provided by Operating Activities (GAAP)       762       736       916       931  
 
                   
Reconciliation To GAAP Information Years Ended 12/31
($ in millions)      

2011 Actual

   

2012 Actual

   

2013 Estimate (e)

 
Net Cash Provided by Operating Activities (GAAP) 762 736 916 931
Changes in assets and liabilities and other adjustments       (25 )     66       (27 )     (27 )
After-tax Cash Flow (Non-GAAP) 737 802 889 904
Less: AGC cash flows from operations and other       (115 )     (103 )     (101 )     (101 )
Adj. After-tax Cash Flows Excluding Alagasco (Non-GAAP)       622       699       788       803  
 
 

(e) This estimate is a "forward-looking statement" as defined by the Securities and Exchange Commission.  All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated.  In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts.  A discussion of risks and uncertainties, which could affect future results of Energen and its subsidiaries, is included in the Company's periodic reports filed with the Securities and Exchange Commission.

 
 

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

For the 3 months ending September 30, 2013 and 2012

 
      3rd Quarter        
           
(in thousands, except per share data)             2013           2012           Change
 
Operating Revenues
Oil and gas operations $ 272,038 $ 214,620 $ 57,418
Natural gas distribution             48,368             61,809             (13,441 )
 
Total operating revenues             320,406             276,429             43,977  
 
Operating Expenses
Cost of gas 20,435 20,924 (489 )
Operations and maintenance 141,271 123,730 17,541
Depreciation, depletion and amortization 136,123 96,634 39,489
Taxes, other than income taxes 24,858 19,572 5,286
Accretion expense             1,771             1,605             166  
 
Total operating expenses             324,458             262,465             61,993  
 
Operating Income (Loss)             (4,052 )           13,964             (18,016 )
 
Other Income (Expense)
Interest expense (17,689 ) (17,195 ) (494 )
Other income 13,062 1,488 11,574
Other expense             (434 )           (84 )           (350 )
 
Total other expense             (5,061 )           (15,791 )           10,730  
 
Income (Loss) from Continuing Operations Before Income Taxes

(9,113

)

(1,827

)

(7,286

)

Income tax expense (benefit)             (3,627 )           (322 )           (3,305 )
 
Income (Loss) from Continuing Operations             (5,486 )           (1,505 )           (3,981 )
 
Discontinued Operations, Net of Taxes
Income (loss) from discontinued operations 1,866 3,551 (1,685 )
Gain (loss) on disposal             (15,678 )                     (15,678 )
 
Income (Loss) from Discontinued Operations             (13,812 )           3,551             (17,363 )
 
Net Income (Loss)       $     (19,298 )     $     2,046       $     (21,344 )
 
Diluted Earnings Per Average Common Share $ $
Continuing operations (0.08 ) (0.02 ) (0.06 )
Discontinued operations             (0.19 )           0.05             (0.24 )
 
Net Income (Loss)       $     (0.27 )     $     0.03       $     (0.30 )
 
Basic Earnings Per Average Common Share $ $ $
Continuing operations (0.08 ) (0.02 ) (0.06 )
Discontinued operations             (0.19 )           0.05             (0.24 )
 
Net Income (Loss)       $     (0.27 )     $     0.03       $     (0.30 )
 
Diluted Avg. Common Shares Outstanding             72,346             72,316             30  
 
Basic Avg. Common Shares Outstanding             72,346             72,130             216  
 
Dividends Per Common Share       $     0.145       $     0.14       $     0.005  
 
 

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

For the 9 months ending September 30, 2013 and 2012

                     
      Year-to-date        
           
(in thousands, except per share data)             2013           2012           Change
 
Operating Revenues
Oil and gas operations $ 875,350 $ 799,339 $ 76,011
Natural gas distribution             390,567             327,183             63,384  
 
Total operating revenues             1,265,917             1,126,522             139,395  
 
Operating Expenses
Cost of gas 163,448 94,179 69,269
Operations and maintenance 413,401 336,568 76,833
Depreciation, depletion and amortization 365,355 276,465 88,890
Taxes, other than income taxes 77,955 64,314 13,641
Accretion expense             5,187             4,691             496  
 
Total operating expenses             1,025,346             776,217             249,129  
 
Operating Income (Loss)             240,571             350,305             (109,734 )
 
Other Income (Expense)
Interest expense (51,751 ) (48,447 ) (3,304 )
Other income 15,578 3,678 11,900
Other expense             (631 )           (305 )           (326 )
 
Total other expense             (36,804 )           (45,074 )           8,270  
 
Income (Loss) from Continuing Operations Before Income Taxes

203,767

305,231

(101,464

)

Income tax expense (benefit)             73,897             110,508             (36,611 )
 
Income (Loss) from Continuing Operations       $     129,870       $     194,723       $     (64,853 )
 
Discontinued Operations, Net of Taxes
Income (loss) from operations 6,269 (3,984 ) 10,253
Gain (loss) on disposal             (15,678 )                     (15,678 )
 
Income (Loss) from Discontinued Operations             (9,409 )           (3,984 )           (5,425 )
 
Net Income (Loss)             120,461             190,739             (70,278 )
 
Diluted Earnings Per Average Common Share $ $ $
Continuing operations 1.80 2.69 (0.89 )
Discontinued operations             (0.13 )           (0.05 )           (0.08 )
 
Net Income (Loss)       $     1.67       $     2.64       $     (0.97 )
 
Basic Earnings Per Average Common Share $ $ $
Continuing operations 1.80 2.70 (0.90 )
Discontinued operations             (0.13 )           (0.06 )           (0.07 )
 
Net Income (Loss)       $     1.67       $     2.64       $     (0.97 )
 
Diluted Avg. Common Shares Outstanding             72,272             72,301             (29 )
 
Basic Avg. Common Shares Outstanding             72,220             72,121             99  
 
Dividends Per Common Share       $     0.435       $     0.42       $     0.015  
 
 
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of September 30, 2013 and December 31, 2012
 

(in thousands)

     

September 30, 2013

 

 

December 31, 2012

 

       
 
ASSETS
Current Assets
Cash and cash equivalents

$

12,413

 

$

9,704

Accounts receivable, net of allowance 200,043 277,900
Inventories 61,684 63,994
Regulatory asset 11,213 45,515
Assets held for sale 183,862
Other         63,371       28,007
 
Total current assets         532,586       425,120
 
Property, Plant and Equipment
Oil and gas properties, net 4,997,661 4,673,886
Utility plant, net 876,570 842,643
Other property, net         29,733       25,107
 
Total property, plant and equipment, net         5,903,964       5,541,636
Other Assets
Regulatory asset 89,004 110,566
Long-term derivative instruments 12,786 40,577
Other         76,532       57,991
 
Total other assets         178,322       209,134
 
 
TOTAL ASSETS      

$

6,614,872

 

 

$

6,175,890

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year

$

125,000

$

50,000

Notes payable to banks 901,000 643,000
Accounts payable 256,109 257,579
Regulatory liability 40,168 45,116
Other         219,012       164,087
 
Total current liabilities         1,541,289       1,159,782
 
Long-term debt         1,028,509       1,103,528
 
Deferred Credits and Other Liabilities
Regulatory liability 81,414 80,404
Deferred income taxes 979,898 905,601
Long-term derivative instruments 1,961 11,305
Other         212,135       238,580
 
Total deferred credits and other liabilities         1,275,408       1,235,890
 
Total Shareholders’ Equity         2,769,666       2,676,690
 

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

     

$

6,614,872

   

$

6,175,890

 
 
SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
For the 3 months ending September 30, 2013 and 2012
 
      3rd Quarter      
 
         
(in thousands, except sales price data)       2013         2012         Change
 
Oil and Gas Operations (GAAP)
Operating revenues from continuing operations
Natural gas $ 62,073 $ 49,422 $ 12,651
Oil 183,950 147,710 36,240
Natural gas liquids 26,292 17,566 8,726
Other             (277 )         (78 )         (199 )
 
Total (GAAP)       $     272,038     $     214,620     $     57,418  
 
Oil and Gas Operations excluding

mark-to-market (Non-GAAP)

Operating revenues from continuing operations
Natural gas $ 60,389 $ 53,581 $ 6,808
Oil 247,839 188,279 59,560
Natural gas liquids 27,647 19,590 8,057
Other             (277 )         (78 )         (199 )
 
Total (Non-GAAP)*       $     335,598     $     261,372     $     74,226  
 
Production volumes
Natural gas (MMcf) 14,868 14,622 246
Oil (MBbl) 2,764 2,275 489
Natural gas liquids (MMgal) 36.7 25.2 11.5
 
Total production volumes (MMcfe) 36,696 31,872 4,824
Total production volumes (MBOE) 6,116 5,312 804
 
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf) $ 4.06 $ 3.66 $ 0.40
Oil (barrel) $ 89.67 $ 82.76 $ 6.91
Natural gas liquids (gallon) $ 0.75 $ 0.78 $ (0.03 )
 
Revenue per unit of production excluding effects of

all derivative instruments

Natural gas (Mcf) $ 3.39 $ 2.69 $ 0.70
Oil (barrel) $ 103.22 $ 86.55 $ 16.67
Natural gas liquids (gallon) $ 0.68 $ 0.68 $
 
Other data
Lease operating expense (LOE)
LOE and other $ 69,086 $ 57,397 $ 11,689
Production taxes             18,939           13,531           5,408  
 
Total       $     88,025     $     70,928     $     17,097  
 
Depreciation, depletion and amortization $ 125,060 $ 86,062 $ 38,998
General and administrative expense $ 29,626 $ 18,468 $ 11,158
Capital expenditures $ 257,759 $ 323,037 $ (65,278 )
Exploration expenditures $ 8,949 $ 10,644 $ (1,695 )
Operating income       $     18,607     $     26,913     $     (8,306 )
 

*Operating revenues excluding mark-to-market losses of $63,560 and $46,752 in third quarter 2013 and 2012, respectively.

 

Natural Gas Distribution

                   
Operating revenues
Residential $ 31,201 $ 30,658 $ 543
Commercial and industrial 18,194 17,695 499
Transportation 13,197 13,505 (308 )
Other           (14,224 )         (49 )         (14,175 )
 
Total     $     48,368     $     61,809     $     (13,441 )
 
Gas delivery volumes (MMcf)
Residential 1,384 1,378 6
Commercial and industrial 1,272 1,246 26
Transportation           11,237           11,252           (15 )
 
Total           13,893           13,876           17  
 
Other data
Depreciation and amortization $ 11,063 $ 10,572 $ 491
Capital expenditures $ 20,980 $ 18,813 $ 2,167
Operating income (loss)     $     (22,544 )   $     (12,743 )   $     (9,801 )
 
SELECTED BUSINESS SEGMENT DATA (UNAUDITED)
For the 9 months ending September 30, 2013 and 2012
                     
     

Year-to-date

       
           
(in thousands, except sales price data) 2013 2012 Change
 
Oil and Gas Operations (GAAP)
Operating revenues from continuing operations
Natural gas $ 196,311 $ 156,308 $ 40,003
Oil 607,975 578,167 29,808
Natural gas liquids 71,556 64,970 6,586
Other             (492 )           (106 )           (386 )
 
Total (GAAP)       $     875,350       $     799,339       $     76,011  
 
Oil and Gas Operations excluding

mark-to-market (Non-GAAP)

Operating revenues from continuing operations
Natural gas $ 179,701 $ 160,429 $ 19,272
Oil 671,836 541,812 130,024
Natural gas liquids 72,764 63,169 9,595
Other             (492 )           (106 )           (386 )
 
Total (Non-GAAP)*       $     923,809       $     765,304       $     158,505  
 
Production volumes
Natural gas (MMcf) 43,428 44,076 (648 )
Oil (MBbl) 7,670 6,414 1,256
Natural gas liquids (MMgal) 98.5 79.0 19.5
 
Total production volumes (MMcfe) 103,518 93,846 9,672
Total production volumes (MBOE) 17,253 15,641 1,612
 
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf) $ 4.14 $ 3.64 $ 0.50
Oil (barrel) $ 87.59 $ 84.47 $ 3.12
Natural gas liquids (gallon) $ 0.74 $ 0.80 $ (0.06 )
 

Revenue per unit of production excluding effects of all derivative instruments

 

Natural gas (Mcf) $ 3.51 $ 2.51 $ 1.00
Oil (barrel) $ 92.69 $ 89.92 $ 2.77
Natural gas liquids (gallon) $ 0.65 $ 0.78 $ (0.13 )
 
Other data
Lease operating expense (LOE)
LOE and other $ 210,455 $ 159,052 $ 51,403
Production taxes             49,598             39,882             9,716  
 
Total       $     260,053       $     198,934       $     61,119  
 
Depreciation, depletion and amortization $ 332,690 $ 244,914 $ 87,776
General and administrative expense $ 81,570 $ 56,521 $ 25,049
Capital expenditures $ 892,691 $ 957,913 $ (65,222 )
Exploration expenditures $ 13,902 $ 13,382 $ 52
Operating income       $     181,948       $     280,897       $     (98,949 )
 

* Operating revenues excluding mark-to-market loss of $48,459 and gain of $34,035 in 2013 and 2012, respectively.

 
                         
Natural Gas Distribution
Operating revenues
Residential $ 259,492 $ 201,537 $ 57,955
Commercial and industrial 103,419 84,889 18,530
Transportation 45,261 42,765 2,496
Other             (17,605 )           (2,008 )           (15,597 )
 
Total       $     390,567       $     327,183       $     63,384  
 
Gas delivery volumes (MMcf)
Residential 15,379 11,601 3,778
Commercial and industrial 7,434 6,137 1,297
Transportation             34,733             34,835             (102 )
 
Total             57,546             52,573             4,973  
 
Other data
Depreciation and amortization $ 32,665 $ 31,551 $ 1,114
Capital expenditures $ 67,790 $ 51,786 $ 16,004
Operating income       $     58,968       $     70,265       $     (11,297 )
 

Source: Energen Corporation

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



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Location: Denver, CO US
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