Four New Wolfcamp Wells Generate Excellent Rates

EGN

2014 Production, Capital Guidance Announced Energen Reports 4th Quarter 2013 Operating, Financial Results

Energen Corporation (NYSE: EGN) has tested six new Wolfcamp wells in the Permian Basin, including two “B” bench wells in western Reeves County and two “B” bench well with 7,000-foot drilled lateral lengths in southern Glasscock County. All produced at very attractive initial rates. [See locator maps at www.energen.com].

The Winchester 57-10 #1H in western Reeves County produced at a peak 24-hour rate (3-stream) of 2,387 boepd, which is the highest initial production (IP) rate for a southern Delaware Wolfcamp well known to have been publicly disclosed to date. Were it not for its shorter completed lateral length, the Tisdale 56-8 #1H – also in western Reeves County – likely would have been comparable to the Winchester.

In the Midland Basin, the company’s first “B’ bench wells and first wells with 7,000-foot lateral lengths, the San Saba NS 37-48 #205H and #204H, tested without artificial lift at peak 24-hour rates (3-stream) of 1,387 boepd and 1,205 boepd, respectively. Oil comprised 79- 80 percent of the product mix in both wells.

“We continue to be very pleased with the Wolfcamp results we are achieving in the “A” and “B” benches in both the Midland and Delaware basins,” said James McManus, Energen’s chairman and chief executive officer. “We have six horizontal rigs currently drilling in the Midland Basin, as we significantly ramp up our activity level there. During 2014 we plan to drill and operate 57 gross Wolfcamp wells and 2 gross Cline wells.

“Our horizontal development plan in the Midland Basin is designed to maximize drilling and completion efficiencies; optimize spacing, work flow, and rig utilization; maximize stimulated reservoir volume for enhanced fracture complexity; and minimize stimulation impacts.”

“In the Delaware Basin, we are concentrating on drilling to hold leases, to further delineate our extensive acreage position there, and to drive down well costs. We plan to have two rigs working the Wolfcamp play in the Delaware Basin throughout 2014 and expect to drill and operate 12 gross Wolfcamp wells there,” he said.

“All-in-all, we expect our drilling and development capital spending in 2014 to approximate $1.05 billion, or about $225 million more than our estimated E&P after-tax cash flows,” McManus added. “In this transition year, we expect production to be relatively flat during the first half of 2014 before picking up steam as our Wolfcamp production accelerates in the second half of the year. Our 2014 exit rate (December average at midpoint) could well be approximately 73 mboe per day, up from some 64 mboe per day at mid-year (June average at midpoint).

“I am really looking forward to 2014 as a year of significant progress for Energen,” McManus said. “I believe the results of our aggressive drilling program in the Midland Basin in 2014 will provide a springboard for even greater acceleration in 2015 and beyond as we pursue 2,475 potential net Wolfcamp and Cline locations on our 81,500 net acres in the Midland Basin and Eastern Shelf.

“And another year of delineation in the Delaware Basin could well lead in 2015 to the start of development of the more than 3,100 potential net Wolfcamp locations we have identified on our 106,000 net acres in Ward, Winkler, Loving and Reeves counties.”

2013 Earnings Summary

For the 12 months ended December 31, 2013, Energen reported consolidated net income of $204.6 million, or $2.82 per diluted share. After adjusting for non-cash and/or non-recurring items and for discontinued operations, Energen’s adjusted income from continuing operations in 2013 totaled $216.9 million, or $2.99 per diluted share. In 2012, the comparable adjusted income from continuing operations totaled $218.0 million, or $3.01 per diluted share.

Non-cash and/or non-recurring items in 2013 included non-cash mark-to-market revenue losses, a gain on the sale of the company’s Black Warrior Basin assets partially offset by the non-cash impairment of properties held for sale in North Louisiana/East Texas, a gain on the sale of the company’s Birmingham utility service center, and income from discontinued operations.

 

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

[See “Non-GAAP Financial Measures” beginning on pp. 18 for more information]

       
CY13 CY12
  $M   $/dil. sh.   $M   $/dil. sh.
Net Income All Operations (GAAP) $ 204,554     $ 2.82     $ 253,562     $ 3.51  
Less: Non-cash Mark-to-Market gain/(loss)   (30,574 )     (0.42 )     37,247       0.52  
Adjusted Net Income All Operations (Non-GAAP) $ 235,128     $ 3.24     $ 216,315     $ 2.99  
Less: Gain on Sale of Utility Service Center 6,772   0.09 --   --
Less: E&P Discontinued Operations
Impairment (Loss)/Gain on Disposal 3,594 0.05 (13,416 ) (0.19 )
Income from Discontinued Operations   7,813       0.10       11,758       0.16  
Adj. Income Continuing Operations (Non-GAAP) $ 216,949     $ 2.99     $ 217,973     $ 3.01  

Note: Per share amounts may not sum due to rounding

 

In comparing the two years: The impact of a 10 percent increase in 2013 production from continuing operations, including a 20 percent increase in oil and natural gas liquids (NGL), and higher realized oil and natural gas prices were essentially offset by higher depreciation, depletion and amortization (DD&A) expense, greater lease operating expense (LOE) and production taxes, increased net administrative expenses, and increased exploration expense primarily associated with write-offs of miscellaneous parcels of leasehold expiring in first half of 2014.

Relative to the company’s calendar year guidance issued on October 30, 2013, adjusted income from continuing operations fell below the midpoint largely due to the negative impact on production and expenses of two Permian Basin ice storms ($0.10) and a write-off of approximately 5,000 miscellaneous acres of unproved leasehold ($0.06). In addition, lower net general and administrative expense, a change in the effective tax rate, and higher commodity prices were offset by a slight decrease in expected production and greater-than-anticipated LOE.

 

     

Production by Commodity (MBOE)

Commodity   CY13   CY12   Change
Continuing Operations
Oil 10,364 8,749

18 %

NGL 3,233 2,573 26 %
Natural Gas   9,684   9,861   (2) %
Total Continuing Operations   23,281   21,183   10 %
             
Discontinued Operations   2,081   2,883   (28) %
Total All Operations   25,362   24,066   5 %
 

Energen’s adjusted EBITDAX from continuing operations (excluding non-cash and/or non-recurring items) totaled $937 million in 2013 and compared with $818 million in 2012. Energen Resources, the company’s oil and gas exploration and production subsidiary, had adjusted EBITDAX from continuing operations (excluding mark-to-market) of $797 million in 2013 and $681 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 18 for more information and reconciliation.]

4th Quarter 2013 Earnings Summary

For the 3 months ended December 31, 2013, Energen reported consolidated net income of $84.1 million, or $1.15 per diluted share. After adjusting for non-cash and/or non-recurring items and for discontinued operations, Energen’s adjusted income from continuing operations in the fourth quarter of 2013 totaled $56.4 million, or $0.77 per diluted share. In the fourth quarter of 2012, the comparable adjusted income from continuing operations totaled $44.9 million, or $0.62 per diluted share.

Non-cash and/or non-recurring items in the fourth quarter of 2013 included non-cash mark-to-market revenue gains, a gain on the sale of the company’s Black Warrior Basin assets partially offset by the non-cash impairment of properties held for sale in North Louisiana/East Texas, a gain on the sale of the company’s Birmingham utility service center, and income from discontinued operations.

   

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

[See “Non-GAAP Financial Measures” beginning on pp. 18 for more information]

         
4Q13 4Q12
    $M   $/dil. sh.   $M   $/dil. sh.
Net Income All Operations (GAAP)   $ 84,093   $ 1.15   $ 62,823   $ 0.87
Less: Non-cash Mark-to-Market gain/(loss)     157     0.00     15,669     0.22
Adjusted Net Income All Operations (Non-GAAP)   $ 83,936   $ 1.15   $ 47,154   $ 0.65
Less: Gain on Sale of Utility Service Center 6,772   0.09 --   --
Less: E& P Discontinued Operations
Impairment (Loss)/Gain on Disposal 19,272 0.27 -- --
Income from Discontinued Operations     1,496     0.02     2,271     0.03
Adj. Income Continuing Operations (Non-GAAP)   $ 56,396   $ 0.77   $ 44,883   $ 0.62

Note: Per share amounts may not sum due to rounding

 

In comparing the two periods: The impact of a 9 percent increase in fourth quarter 2013 production from continuing operations, including an 18 percent increase in oil and natural gas liquids, and higher realized oil, NGL, and natural gas prices were partially offset by modest increases in DD&A expense, LOE and production taxes, net general and administrative expense, and exploration expense primarily associated with write-offs of miscellaneous parcels of expiring leasehold.

     

Production by Commodity (MBOE)

Commodity   4Q13   4Q12   Change
Continuing Operations
Oil 2,694 2,335

15 %

NGL 888 692

28 %

Natural Gas   2,446   2,515  

(3) %

Total Continuing Operations   6,028   5,542  

9 %

             
Discontinued Operations   175   674    
Total All Operations   6,203   6,216    
 

Energen’s adjusted EBITDAX from continuing operations (excluding non-cash and/or non-recurring items) totaled $249 million in the fourth quarter of 2013 and compared with $204 million in the same period last year. Energen Resources had adjusted EBITDAX from continuing operations (excluding mark-to-market) of $213 in the fourth quarter of 2013 and $170 million in the same period a year ago. [See “Non-GAAP Financial Measures” beginning on pp. 18 for more information and reconciliation.]

Wolfcamp Shale Exploration Results

(Locator map available at www.energen.com)

 

MIDLAND BASIN WOLFCAMP EXPLORATORY WELLS – GLASSCOCK COUNTY

                 
Well   Zone   Lateral length  

Frac
Stages

  Peak 24-Hour IP
    Drilled*   Completed     Boepd  

Oil
(Bopd)

 

NGL
(Bpd)

 

Gas
(Mcfd)

Guadalupe
48 #101H

  A   5,300’   5,246’   21   1,000   743   139   709

San Saba
NS 37-48
#204H

  B   7,000’   6,706’   27   1,205   957   132   693

San Saba
NS 37-48
#205H

  B   7,000’   6,782’   27   1,387   1,115   134   830

* Represents distance from surface to toe

       

Energen’s first two Wolfcamp “B” wells in southern Glasscock County and its first two wells drilled to a 7,000-foot lateral length have generated excellent results. The San Saba NS 37-48 #205H and #204H tested at attractive peak 24-hour IP rates of 1,387 boepd (80% oil, 10% NGL, and 10% gas) and 1,205 boepd (79% oil, 11% NGL, and 10% gas), respectively. The #205H has the highest peak 24-hour IP drilled by the company in the Midland Basin to-date. The Guadalupe 48 #101H is an “A” bench well with a 5,300-foot drilled lateral length. Its peak 24-hour IP was a solid 1,000 boepd (74% oil, 14% NGL, and 12% gas).

Management said it does not have 30-day rates for these wells yet because the company is fracture-stimulating neighboring wells before these are brought on production; however, management said it is comfortable disclosing just the peak 24-hour IP given the consistency of results being generating by its southern Glasscock County wells.

The last two wells in Energen’s 2013 exploratory drilling program in the Midland Basin are flowing back or awaiting completion.

The company’s 2014 exploratory drilling program in the Midland Basin consists of 17 gross (16 net) Wolfcamp wells and 2 gross (2 net) Cline wells. The first three wells in the 2014 exploratory program currently are awaiting completion or drilling, including the company’s first well in Martin County and its first Cline test well.

Another 40 gross (39 net) Wolfcamp development wells are scheduled to be drilled in 2014 in southern Glasscock County. Our 2014 Wolfcamp development program is focused on drilling stacked laterals in the “A” and “B” benches with lateral lengths of 6,700 feet and 7,500 feet. The company estimates that unrisked ultimate recoveries (EURs) from these development wells will range from 550-750 MBOE for a 6,700-foot lateral and 650-850 MBOE for a 7,500-foot lateral.

         

DELAWARE BASIN

                     
Well Zone Lateral length

Frac
Stages

Peak 24-Hour IP Peak 30-day Average
    Drilled*   Completed     Boepd   Oil (Bopd)   NGL (Bpd)   Gas (Mcfd)   Boepd   Oil (Bopd)   NGL (Bpd)   Gas (Mcfd)
Winchester 57-10 #1H   B   4,400’   4,218   18   2,387   972   648   4,598   2,186   840   617   4,376
Tisdale 56-8 #1H   B   4,400’   3,242’   14   2,081   657   682   4,451   1,804   535   608   3,968
Red Rock 6-6 #1H   A   4,400’   4,437   19   1,471   956   265   1,500   1,137   731   209   1,180

* Represents distance from surface to toe

             

Energen’s first two Wolfcamp “B” wells in the Delaware Basin were drilled in far west Reeves County approximately 10 miles apart. Both have generated excellent results. The Winchester 57-10 #1H tested at an outstanding peak 24-hour IP rate of 2,387 boepd (41% oil, 27% NGL, and 32% gas). This not only is the highest rate among Energen’s Wolfcamp wells, the Winchester has the highest known 24-hour peak IP of any southern Delaware Basin Wolfcamp well reported to date. The peak 30-day average rate was 2,186 boepd (38% oil, 28% NGL, and 33% gas).

The Tisdale 56-8 #1H, despite a shorter, completed lateral length, tested at a peak 24-hour IP rate of 2,081 boepd; this 3-stream rate was 32% oil, 33% NGL, and 36% gas. The peak 30-day average rate (3-stream) was 1,804 boepd (30% oil, 34% NGL, 37% gas).

Also in Reeves County, located near the previously disclosed Bodacious C7-19 #1H, Energen drilled the Red Rock 6-6 #1H in the “A” bench of the Wolfcamp shale. The Red Rock was a solid well that tested at a peak 24-hour IP rate of 1,471 boepd. The 3-stream rate was 65% oil, 18% NGL, and 17% gas. The peak 30-day average rate (3-stream) was 1,137 boepd (64% oil, 18% NGL, and 17% gas).

The last two wells in Energen’s 2013 exploratory program are “A” bench wells in Reeves County that are drilling or awaiting completion. The company’s 2014 exploratory drilling program in the Delaware Basin consists of 12 gross (10 net) Wolfcamp wells. The first two wells in the 2014 exploratory program currently are drilling.

2014 Capital and Production Guidance

Energen estimates that it will invest approximately $1.1 billion in 2014, including $1.05 billion for oil and gas drilling and development and $75 million for utility system maintenance, information technology, and construction of new service centers in Birmingham.

In accelerating the drilling of its horizontal Wolfcamp and Cline potential in the Midland Basin, Energen is committing 45 percent of its planned capital spending of $1.05 billion to drill 55 net Wolfcamp shale wells and 2 net Cline shale wells in 2014. The average drill-and-complete cost of a Wolfcamp well in 2014 is estimated to be $8.5 MM; 24 net Wolfcamp wells have a planned drilled lateral length of 6,700 feet, while the other 31 are to be drilled to 7,500 feet. The drill-and-complete cost of the two, planned Cline wells with 7,200-foot drilled lateral lengths is estimated to average $9 million.

Elsewhere in the Midland Basin, the company is scaling back its vertical Wolfberry program in 2014 as it focuses on the higher-return horizontal program. Two vertical drilling rigs are expected to drill an estimated 49 net wells, which is sufficient to meet Energen’s continuous drilling obligations in the Wolfberry play.

With significant Wolfcamp potential in the Delaware Basin, as well, the company will be running two rigs and investing approximately $108 million to drill 10 net wells that will further delineate its 106,000 net acres and secure expiring leases. Still in the exploratory phase, these wells are expected to cost approximately $10 million to drill, complete, and install surface facilities.

Elsewhere in the Delaware Basin, Energen plans to drill 22 net 3rd Bone Spring wells in the southern Delaware Basin and two net 2nd Bone Spring wells in the northern Delaware Basin in New Mexico for approximately $173 million. Energen’s 3rd Bone Spring program has been one of the two major drivers of the company’s oil and NGL production growth over the last three years. With only 5 net locations remaining to be drilled after this year, the company anticipates concluding its 3rd Bone Spring drilling program in early 2015.

Energen’s legacy Permian Basin assets are in the Central Basin Platform, where the company plans to invest $17 million to drill 13 net producers and 8 net injector wells in 2014. And in the San Juan Basin, which is home to approximately 65 percent of the company’s proved natural gas reserves, Energen will be investing only $15 million in 2014; of that amount, 40 percent reflects the company’s 50 percent working interest in two non-operated Niobrara oil shale wells to be drilled by WPX Energy.

 

2014e Drilling and Development Capital and Production Summary

 
    Operated Wells   Operated   Production Midpoint
Capital ($MM) To Be Drilled Rig Count Continuing Ops -- MMBOE
        Gross (Net)      

2014e

 

2013

 

 

 

 
Midland Basin

$

668

113 (106

)

8

7.4

5.1

Wolfcamp/Cline

475 59 (57 ) 6 2.2 0.0

Wolfberry/Other

121 54 (49 ) 2 5.2 5.1

Facilities/Other

72
 
Delaware Basin

$

315

41 (34

)

5-6

5.4

4.7

3rd Bone Spring/Other

173 29 (24 ) 3-4 4.5 4.2

Wolfcamp

108 12 (10 ) 2 0.9 0.5

Facilities/Other

34
 
Other Permian

$

42

26 (21

)

*

1

3.7

4.4

Waterfloods/CO(2) floods

17

26 (21

)

*

Facilities/Other

25
 
San Juan Basin/Other

$

15

0 (0

)

0

8.4

9.1

Facilities/Other

15
 
Net Carry In/Carry Out  

$

10

                 

 

TOTAL – Contg. Ops

 

 

$

 

1,050

 

180 (161

)

   

 

14

 

 

24.9

 

 

23.3

 

Note: “Facilities” capital includes salt water disposal wells, artificial lift, and central gathering facilities; “Other” capital includes payadds, refracs, and non-operated activities.

 

* Includes 10 gross (8 net) injectors

 

Production from continuing operations in 2014 is estimated to range from 24.4 MMBOE to 25.4 MMBOE, with a midpoint of 24.9 MMBOE. At the midpoint, this reflects a 16 percent increase (YOY) in total Permian Basin production while production in the San Juan Basin, the company’s primary natural gas-producing region, is expected to see production decline 8 percent in 2014.

In the Midland Basin, where the company is transitioning from its vertical Wolfberry focus to a focus on the Wolfcamp and Cline shales, production is estimated to increase 45 percent (YOY). In the Delaware Basin, where growth from the maturing 3rd Bone Spring program is slowing in 2014, production is estimated to increase approximately 15 percent. Production from Energen’s legacy oil assets in the Central Basin Platform is expected to decline some 16 percent.

     

Production from Continuing Operations by Area (MMBOE)

             
Area   2014e Midpoint   2013   Change
Midland Basin 7.4 5.1 45 %
Delaware Basin 5.4 4.7 15 %
Central Basin Platform   3.7   4.4   (16) %
Total Permian Basin 16.5 14.2 16 %
San Juan Basin/Other   8.4   9.1   (8) %
Total Continuing Operations   24.9   23.3   7 %
 

Oil and NGL production is estimated to grow 12 percent in 2014, while natural gas production is expected to remain essentially flat as a result of associated gas in the Permian Basin offsetting natural gas declines in the San Juan Basin.

     

Production from Continuing Operations by Product (MMBOE)

             
Commodity   2014e Midpoint   2013   Change
Oil 11.4 10.4 10 %
NGL 3.8 3.2 19 %
Natural Gas   9.7   9.7   0 %
Total Continuing Operations   24.9   23.3   7 %
 
       

Production from Continuing Operations by Basin and Product (MMBOE)

                 
Basin   Oil   NGL   Gas   Total
2014e   2013   2014e   2013   2014e   2013   2014e   2013
Midland Basin 4.6   3.2 1.5   1.0 1.3   0.9 7.4   5.1
Delaware Basin 3.3 3.1 0.9 0.7 1.2 0.9 5.4 4.7
Central Basin Platform/Other 3.4 3.9 0.2 0.2 0.1 0.2 3.7 4.4
San Juan Basin/Other   0.1   0.1   1.2   1.3   7.1   7.7   8.4   9.1
Total Continuing Operations   11.4   10.4   3.8   3.2   9.7   9.7   24.9   23.3

NOTE: 2014e production reflects the midpoint of guidance

 

Production is expected to remain relatively flat through the first six months of 2014, then accelerate in the second half as a result of the company’s Wolfcamp drilling in the Midland Basin.

 

       

2014e Production from Continuing Operations by Basin per Quarter (MMBOE)

                 
Basin  

1st Quarter

  2nd Quarter   3rd Quarter   4th Quarter
2014e   2013 2014e   2013 2014e   2013 2014e   2013
Midland Basin 1.5 1.0 1.5 1.2 2.1 1.4 2.3 1.5
Delaware Basin 1.3 1.0 1.3 1.2 1.3 1.3 1.5 1.2
Central Basin Platform/Other 1.0 1.1 0.9 1.1 0.9 1.1 0.9 1.1
San Juan Basin/Other   2.1   2.2   2.1   2.4   2.1   2.3   2.1   2.2
Total Production – Contg Ops   5.9   5.3   5.8   5.9   6.4   6.1   6.8   6.0

NOTE: 2014e production reflects the midpoint of guidance

 

Energen’s 2014 guidance range for consolidated after-tax cash flows is an estimated $907 million to $937 million. Energen Resources’ after-tax cash flows are estimated to be $812 million to $842 million, and Alagasco is expected to generate after-tax cash flows of approximately $95 million. [See “Non-GAAP Financial Measures” beginning on pp 18 for more information and reconciliation.]

Consolidated earnings from continuing operations in 2014 are estimated to range from $200 million to $230 million, or $2.74-$3.14 per diluted share, with Alagasco’s utility operations contributing approximately 20 percent.

Energen Resources’ estimated exploration and production expenses from continuing operations per barrels of oil equivalents (BOE) in calendar year 2014 are:

 
Lease Operating expense
Base, marketing, and transportation $ 11.25 - $ 11.75
Production taxes $ 2.75 - $ 2.95
DD&A expense $ 20.50 - $ 21.50
General & Administrative expense, net $ 4.75 - $ 5.25
Interest expense $ 2.25 - $ 2.45

Exploration expense (delay rentals, seismic, G&G)

$ 0.85 - $ 0.95
 

Approximately 74 percent of the company’s total estimated midpoint of 2014 production from continuing operations is hedged. Assumed prices applicable to Energen Resources’ unhedged volumes for the remainder of the year are $90.00 per barrel of oil, $0.89 per gallon of NGL, and $4.00 per Mcf of natural gas.

Energen’s 2014 guidance also includes assumed prices for various basis differentials. These assumptions for oil are $2.58 per barrel (WTS Midland to WTI Cushing, “sour oil”) and $1.75 per barrel (WTI Midland to WTI Cushing). Energen estimates that approximately 70 percent of its oil production in 2014 is sweet. Gas basis assumptions are $0.19 per Mcf in both the San Juan and Permian basins.

The company’s current hedge position for 2014 is as follows:

                 

Commodity

 

Hedge Volumes

 

2014e Production

(Contg Ops) Midpoint

  Hedge %  

NYMEX Price

       

Oil

9.8 MMBO

11.4 MMBO

86 %

$ 92.64 per barrel

 

NGL

--

159.8 MMgal

--

--

 

Natural Gas

51.8 Bcf

57.8 Bcf

90 %

$ 4.61 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.

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 $2.60 per barrel in 2014; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.09 per gallon in the Permian Basin and $0.12-$0.17 per gallon in the San Juan Basin. The company also has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price.

As a result of Energen’s 2014 hedge position for oil and gas, changes in commodity prices will have a significantly lessened impact on Energen's 2014 cash flows. Every $1.00 change in the average NYMEX price of oil from $90 per barrel represents an estimated net impact of $670,000, and every 10-cent change in the average NYMEX price of gas from $4.00 represents an immaterial impact. Because NGL production is unhedged, the net income impact of every 1-cent change in the average price of NGL from $0.89 per gallon is estimated to be approximately $840,000. Price-related events such as substantial basis differential changes could cause these sensitivities to be different from those outlined.

CY2013 Earnings Detail

Excluding non-cash and/or non-recurring items, Energen Resources’ adjusted income from continuing operations totaled $166.0 million in 2013 and $168.5 million in 2012.

     

Production from Continuing Operations by Area (MBOE)

             
Area   CY13   CY12   Change
Midland Basin 5,092 3,516 45 %
Delaware Basin 4,672 2,908 61 %
Central Basin Platform   4,423   4,774   (7) %
Total Permian Basin 14,187 11,198 27 %
San Juan Basin/Other   9,094   9,985   (9) %
Total Continuing Operations   23,281   21,183   10 %
 
     

Average Realized Sales Prices from Continuing Operations

             
Commodity   CY13   CY12   Change
Oil (per barrel) $ 87.65 $ 83.46 5 %
NGL (per gallon) $ 0.75 $ 0.79 (5 ) %
Natural Gas (per Mcf)   $ 4.19   $ 3.66   14 %

Per-unit LOE from continuing operations in 2013 increased approximately 15 percent YOY to $15.10 per BOE. Base LOE and marketing and transportation expenses increased approximately 15 percent to $12.20 per BOE largely due to increased workovers and repairs, equipment rental, gathering costs, and environmental compliance. Commodity price-driven production taxes increased approximately 15 percent on a per-unit basis to $2.90 per BOE.

Per-unit DD&A expense from continuing operations in 2013 totaled $19.32 per BOE, increasing approximately 21 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 35 percent from the same period last year to $4.61 per BOE. This largely was due to increased stock-based compensation.

Alagasco generated 2013 net income of $57.4 million, including an after-tax gain of $6.8 million on the sale of its Birmingham service center. Utility net income in 2012 totaled $49.4 million in 2012.

Fourth Quarter Earnings Detail

Excluding non-cash and/or non-recurring items, Energen Resources’ adjusted income from continuing operations totaled $43.5 million in the fourth quarter of 2013 and $32.6 million in the same period a year ago.

     

Production from Continuing Operations by Area (MBOE)

             
Area   4Q13   4Q12   Change
Midland Basin 1,477 934 58 %
Delaware Basin 1,229 984 25 %
Central Basin Platform   1,096   1,164   (6) %
Total Permian Basin 3,802 3,082 23 %
San Juan Basin/Other   2,226   2,461   (10) %
Total Continuing Operations   6,028   5,543   9 %
 
     

Average Realized Sales Prices from Continuing Operations

             
Commodity   4Q13   4Q12   Change
Oil (per barrel) $ 87.80 $ 80.66 9 %
NGL (per gallon) $ 0.79 $ 0.77 3 %
Natural Gas (per Mcf)   $ 4.35   $ 3.72   17 %
 

Per-unit LOE from continuing operations in the fourth quarter of 2013 increased approximately 6 percent from the same period a year ago to $15.18 per BOE. Base LOE and marketing and transportation expenses increased approximately 3 percent to $12.21 per BOE largely due to increased workovers and repairs, labor, non-operated activities, environmental compliance, and increased ad valorem taxes partially offset by decreased water disposal costs and equipment rental. Commodity price-driven production taxes increased approximately 19 percent on a per-unit basis to $2.97 per BOE.

Per-unit DD&A expense from continuing operations in the 4th quarter of 2013 totaled $19.96 per BOE, increasing approximately 14 percent from the same period last year largely due to year-over-year increases in development costs and production.

Per-unit net G&A expense increased approximately 50 percent in the fourth quarter of 2013 to $4.28 per BOE primarily due to increased stock-based compensation.

Alagasco’s net income in the fourth quarter of 2013 totaled $19.8 million, including an after-tax gain of $6.8 million on the sale of its Birmingham service center. Net income totaled $12.2 million in the same period a year ago.

Contingent Resources Increase 172%

The strength of Energen’s extensive inventory of unrisked Wolfcamp and Cline drilling locations is reflected in the 172 percent increase in the company’s year-end 2013 contingent resources.

Contingent resources are defined by the Petroleum Resource Management System as “those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.”

After consultation with its third party reserve engineers, Energen determined that much of its Wolfcamp and Cline potential in the Midland and Delaware basins does not have sufficient well control data to support a 3P reserve classification. The driver of that conclusion was the limited number of wells drilled and completed in the two basins. As Energen’s continuing exploration and development drilling increases the body of geologic and engineering data for these plays, the company expects its contingent resources to begin moving into 3P reserve categories.

Energen’s proved reserves at year-end 2013 totaled a record 348 MMBOE and were essentially unchanged from the prior year as record production and divestures essentially offset the addition of previously classified unproved reserves and contingent resources and upward price-related revisions.

Oil and NGL reserves at year end represented more than 65 percent of total proved reserves and are expected to increase as Energen continues to focus on the exploration and development of the liquids-rich Permian Basin.

Commodity prices used for calculating reserves at year-end 2013 were $96.94 per barrel of oil (up from $94.71 in 2012), $3.67 per thousand cubic feet (Mcf) for natural gas (up from $2.76 in 2012); and an average of $0.76 per gallon of NGL before transportation and fractionation (down from $0.88 per gallon in 2012).

           

Proved Reserves by Basin (MMBOE)

                         
Basin   YE12  

2013
Production

 

2013
Acquisitions/
(Divestitures)

  Additions   Price/Other

Revisions

  YE13
Permian 225.0 (14.2) 0.1 34.5 1.2 246.6
San Juan Basin/Other 101.8 (9.1) 0.0 2.3 2.3 97.3
Black Warrior/NL/ETX   19.6   (2.1)   (14.7)   0.0   1.1   3.9
TOTAL   346.4   (25.4)   (14.6)   36.8   4.6   347.8
 
     

Proved Reserves by Commodity (MMBOE)

             
Commodity   2013   2012   % Change
Oil 164.9 155.3 6.2
Natural gas liquids 63.0 56.2 12.1
Natural gas   119.9   134.9   (11.1 )
TOTAL   347.8   346.4   0.4  
 
         

YE2013 3P Reserves & Contingent Resources (MMBOE)

                     
Basin   Proved   Probable   Possible   Contingent  

Total

Permian Basin 247 46 152 2,230 2,675
Delaware Basin 42 9 19 1,379 1,448

-Wolfcamp

8 3 19 1,378 1,408

-3rd Bone Spring/Other

34 6 0 0 40
Midland Basin 134 26 91 851 1,102

-Wolfcamp/Cline

6 4 86 851 947

-Wolfberry

128 22 5 0 155
Central Basin Platform 71 11 42 0.0 125
San Juan/Other 97 59 167 255 578
North Louisiana/East TX 4 2 1 3 10
TOTAL   348   107   320   2,488   3,263
 
 

Contingent Resources, 2013 vs 2012 (MMBOE)

     
Basin Contingent
  2013   2012
Permian Basin 2,230   569
Delaware Basin 1,379 199

-Wolfcamp

1,378 199

-3rd Bone Spring/Other

0 0
Midland Basin 851 370

-Wolfcamp/Cline

851 370

-Wolfberry

0 0
Central Basin Platform 0.0 0
San Juan/Other 255 341
North Louisiana/East TX 3 3
TOTAL   2,488   913
 

The definitions of probable and possible reserves imply different probabilities of potential recovery in each classification; the quantities reported here are unrisked and based on the Company’s best estimate of current costs to drill wells in each basin/area and bring associated production to market.

CONFERENCE CALL

Energen will hold its quarterly conference call Wednesday, February 12, at 11:00 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 775 million barrels of oil-equivalent proved, probable, and possible reserves and another 2.5 billion barrels of 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: 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. Adjusted Income from continuing operations further excludes a gain on the sale of utility service center, a gain on disposal of discontinued operations, non-cash impairment charges and 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 12/31/2013
Consolidated Net Income ($ in millions except per share data)   Net Income  

Per Diluted Share

Net Income (GAAP) 84.1 1.15
Non-cash mark-to-market gains (net of $0.5 tax)   (0.2 )   (0.00 )
Adjusted Net Income from All Operations (Non-GAAP)   83.9     1.15  
Gain on sale of utility service center (net of $4.1 tax) (6.8 ) (0.09 )
Gain on disposal of discontinued operations (net of $12.9 tax) (22.5 ) (0.31 )
Non-cash impairment charge (net of $2.0 tax) (1) 3.2 0.04
Income from discontinued operations (net of $1.5 tax)   (1.5 )   (0.02 )
Adjusted Income from Continuing Operations (Non-GAAP)   56.4     0.77  
 
     
Quarter Ended 12/31/2012
Consolidated Net Income ($ in millions except per share data)   Net Income  

Per Diluted Share

Net Income (GAAP) 62.8 0.87
Non-cash mark-to-market gains (net of $9.0 tax)   (15.7 )   (0.22 )
Adjusted Net Income from All Operations (Non-GAAP)   47.2     0.65  
Income from discontinued operations (net of $1.3 tax)   (2.3 )   (0.03 )
Adjusted Income from Continuing Operations (Non-GAAP)   44.9     0.62  
 
     
Year-to-Date Ended 12/31/2013
Consolidated Net Income ($ in millions except per share data)   Net Income  

Per Diluted Share

Net Income (GAAP) 204.6 2.82
Non-cash mark-to-market losses (net of $17.3 tax)   30.6     0.42  
Adjusted Net Income from All Operations (Non-GAAP)   235.1     3.24  
Gain on sale of utility service center (net of $4.1 tax) (6.8 ) (0.09 )
Gain on disposal of discontinued operations (net of $12.9 tax) (22.5 ) (0.31 )
Non-cash impairment charge (net of $10.9 tax) (1) 18.9 0.26
Income from discontinued operations (net of $2.2 tax)   (7.8 )   (0.10 )
Adjusted Income from Continuing Operations (Non-GAAP)   216.9     2.99  
 
     
Year-to-Date Ended 12/31/2012
Consolidated Net Income ($ in millions except per share data)   Net Income  

Per Diluted Share

Net Income (GAAP) 253.6 3.51
Non-cash mark-to-market gains (net of $21.5 tax)   (37.2 )   (0.52 )
Adjusted Net Income from All Operations (Non-GAAP)   216.3     2.99  
Non-cash write-down of natural gas properties (net of $8.1 tax) (2) 13.4 0.19
Income from discontinued operations (net of $7.3 tax)   (11.8 )   (0.16 )
Adjusted Income from Continuing Operations (Non-GAAP)   218.0     3.01  
 
Note: Amounts may not sum due to rounding
 

(1) Current year-to-date and quarter-to-date loss on impairment ($18.9 and $3.2, respectively) 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

 

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 a gain on disposal of discontinued operations, non-cash impairment charges and 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 12/31/2013   Year-to-date 12/31/2013
Net Income (GAAP) 64.4 146.8
Non-cash mark-to-market (gains) losses (net of ($0.5) and $17.3 tax)   (0.2 )   30.6  
Adjusted Net Income from All Operations (Non-GAAP)   64.2     177.4  
Gain on disposal of discontinued operations (net of $12.9 and $12.9 tax) (22.5 ) (22.5 )
Non-cash impairment charge (net of $2.0 and $10.9 tax) (1) 3.2 18.9
Income from discontinued operations (net of $1.5 and $2.2 tax)   (1.5 )   (7.8 )
Adjusted Income from Continuing Operations (Non-GAAP)   43.5     166.0  
 
     
Energen Resources Net Income ($ in millions)   Quarter Ended 12/31/2012   Year-to-date 12/31/2012
Net Income (GAAP) 50.6 204.1
Non-cash mark-to-market gains (net of $9.0 and $21.5 tax)   (15.7 )   (37.2 )
Adjusted Net Income from All Operations (Non-GAAP)   34.9     166.9  
Non-cash write-down of natural gas properties (net of $8.1 tax) (2) - 13.4
Income from discontinued operations (net of $1.3 and $7.3 tax)   (2.3 )   (11.8 )
Adjusted Income from Continuing Operations (Non-GAAP)   32.6     168.5  
 
Note: Amounts may not sum due to rounding
 

(1) Current year-to-date and quarter-to-date loss on impairment ($18.9 and $3.2, respectively) 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, 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 a gain on the sale of utility service center, non-cash asset impairments, a gain on disposal of discontinued operations, certain non-cash mark-to-market derivative financial instruments, and 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 12/31 Quarter Ended 12/31
($ in millions)   2012   2013 2012   2013
 
Consolidated Net Income (GAAP) 253.6 204.6 62.8 84.1
Interest expense 65.5 69.2 17.1 17.4
Income tax expense 144.5 105.3 34.0 31.4
Depreciation, depletion and amortization 385.5 497.4 109.0 132.0
Accretion expense 6.3 7.0 1.6 1.8
Exploration expense 19.4 27.9 6.0 14.0
Adjustment for gain on sale of utility service center - (10.9 ) - (10.9 )
Adjustment for asset impairment, net of tax (1) 13.4 18.9 - 3.2
Adjustment for gain on disposal of discontinued operations,net of tax - (22.5 ) - (22.5 )
Adjustment for mark-to-market (gains) losses (58.8 ) 47.8 (24.7 ) (0.6 )
Adjustment for income from discontinued operations, net of tax   (11.8 )   (7.8 ) (2.3 )   (1.5 )
Consolidated Adjusted EBITDAX from Continuing Operations (Non-GAAP)   817.7     936.9   203.6     248.5  
   
Reconciliation To GAAP Information Year-to-Date Ended 12/31 Quarter Ended 12/31
($ in millions)   2012   2013 2012   2013
 
Energen Resources Net Income (GAAP) 204.1 146.8 50.6 64.4
Interest expense 50.0 54.0 13.1 13.5
Income tax expense 115.1 71.3 27.0 19.8
Depreciation, depletion and amortization 343.2 453.5 98.3 120.8
Accretion expense 6.3 7.0 1.6 1.8
Exploration expense 19.4 27.9 6.0 14.0
Adjustment for asset impairment, net of tax (1) 13.4 18.9 - 3.2
Adjustment for gain on disposal of discontinued operations,net of tax - (22.5 ) - (22.5 )
Adjustment for mark-to-market (gains) losses (58.8 ) 47.8 (24.7 ) (0.6 )
Adjustment for income from discontinued operations, net of tax   (11.8 )   (7.8 ) (2.3 )   (1.5 )
Energen Resources Adjusted EBITDAX from Continuing Operations (Non-GAAP)   681.0     796.9   169.6     212.9  
 
Note: Amounts may not sum due to rounding
 

(1) Current year-to-date and quarter-to-date loss on impairment ($18.9 and $3.2, respectively) 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

 

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)   2012 Actual   2013 Actual   2014 Estimate (e)
                 
Consolidated Net Income (GAAP)   254   205   200   230
Depreciation, depletion and amortization 441 558 572 572
Deferred income taxes 124 83 96 96
Exploratory expense 17 16 - -
Other   (34)   48   39   39
After-tax Cash Flows (Non-GAAP) 802 910 907 937
Changes in assets and liabilities and other adjustments   (66)   15   2   2
Net Cash Provided by Operating Activities (GAAP)   736   925   909   939
 
             
Reconciliation To GAAP Information Years Ended 12/31
($ in millions)   2012 Actual   2013 Actual   2014 Estimate (e)
 
Net Cash Provided by Operating Activities (GAAP) 736 925 909 939
Changes in assets and liabilities and other adjustments   66   (15)   (2)   (2)
After-tax Cash Flow (Non-GAAP) 802 910 907 937
Less: AGC cash flows from operations and other   (103)   (116)   (95)   (95)
Adj. After-tax Cash Flows Excluding Alagasco (Non-GAAP)   699   794   812   842
 
 
                 

(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 December 31, 2013 and 2012

           
4th Quarter
 
(in thousands, except per share data)   2013   2012   Change
 
Operating Revenues
Oil and gas operations $ 329,962 $ 289,891 $ 40,071
Natural gas distribution     142,771       124,406       18,365  
 
Total operating revenues     472,733       414,297       58,436  
 
Operating Expenses
Cost of gas 52,007 48,049 3,958
Operations and maintenance 148,949 121,516 27,433
Depreciation, depletion and amortization 132,026 108,988 23,038
Taxes, other than income taxes 27,313 22,487 4,826
Accretion expense     1,808       1,648       160  
 
Total operating expenses     362,103       302,688       59,415  
 
Operating Income     110,630       111,609       (979 )
 
Other Income (Expense)
Interest expense (17,449 ) (17,095 ) (354 )
Other income 1,674 662 1,012
Other expense     (145 )     (598 )     453  
 
Total other expense     (15,920 )     (17,031 )     1,111  
 
Income From Continuing Operations Before Income Taxes

94,710

94,578

132

Income tax expense     31,385       34,026       (2,641 )
 
Income From Continuing Operations     63,325       60,552       2,773  
 
Discontinued Operations, net of taxes
Income from discontinued operations 1,496 2,271 (775 )

Gain on disposal of discontinued operations, net

    19,272      

    19,272  
 
Income From Discontinued Operations     20,768       2,271       18,497  
 
Net Income   $ 84,093     $ 62,823     $ 21,270  
 
Diluted Earnings Per Average Common Share
Continuing operations $ 0.87 $ 0.84 $ 0.03
Discontinued operations     0.28       0.03       0.25  
 
Net Income   $ 1.15     $ 0.87     $ 0.28  
 
Basic Earnings Per Average Common Share
Continuing operations $ 0.87 $ 0.84 $ 0.03
Discontinued operations     0.29       0.03       0.26  
 
Net Income   $ 1.16     $ 0.87     $ 0.29  
 
Diluted Avg. Common Shares Outstanding     73,086       72,319       767  
 
Basic Avg. Common Shares Outstanding     72,628       72,138       490  
 
Dividends Per Common Share   $ 0.145     $ 0.14     $ 0.005  
 
   

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the 12 months ending December 31, 2013 and 2012

           
 
Year-to-date
 
(in thousands, except per share data)   2013   2012   Change
 
Operating Revenues
Oil and gas operations $ 1,205,312 $ 1,089,230 $ 116,082
Natural gas distribution     533,338       451,589       81,749  
 
Total operating revenues     1,738,650       1,540,819       197,831  
 
Operating Expenses
Cost of gas 215,455 142,228 73,227
Operations and maintenance 562,350 458,084 104,266
Depreciation, depletion and amortization 497,381 385,453 111,928
Taxes, other than income taxes 105,268 86,801 18,467
Accretion expense     6,995       6,339       656  
 
Total operating expenses     1,387,449       1,078,905       308,544  
 
Operating Income     351,201       461,914       (110,713 )
 
Other Income (Expense)
Interest expense (69,200 ) (65,542 ) (3,658 )
Other income 16,803 4,285 12,518
Other expense     (375 )     (903 )     528  
 
Total other expense     (52,772 )     (62,160 )     9,388  
 
Income From Continuing Operations Before Income Taxes

298,429

399,754

(101,325

)

Income tax expense     105,282       144,534       (39,252 )
 
Income From Continuing Operations     193,147       255,220       (62,073 )
 
Discontinued Operations, net of taxes
Income (loss) from discontinued operations 7,813 (1,658 ) 9,471

Gain on disposal of discontinued operations, net

    3,594           3,594  
 
Income (Loss) From Discontinued Operations     11,407       (1,658 )     13,065  
 
Net Income   $ 204,554     $ 253,562     $ (49,008 )
 
Diluted Earnings Per Average Common Share
Continuing operations $ 2.67 $ 3.53 $ (0.86 )
Discontinued operations     0.15       (0.02 )     0.17  
 
Net Income   $ 2.82     $ 3.51     $ (0.69 )
 
Basic Earnings Per Average Common Share
Continuing operations $ 2.67 $ 3.54 $ (0.87 )
Discontinued operations     0.16       (0.02 )     0.18  
 
Net Income   $ 2.83     $ 3.52     $ (0.69 )
 
Diluted Avg. Common Shares Outstanding     72,471       72,316       155  
 
Basic Avg. Common Shares Outstanding     72,318       72,119       199  
 
Dividends Per Common Share   $ 0.58     $ 0.56     $ 0.02  
 
 
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of December 31, 2013 and December 31, 2012
 
 
   
(in thousands)   December 31, 2013   December 31, 2012

 

 
ASSETS
Current Assets
Cash and cash equivalents $ 5,555 $ 9,704
Accounts receivable, net of allowance 257,545 277,900
Inventories 52,330 63,994
Regulatory asset 2,756 45,515
Assets held for sale 51,104
Other     57,941     28,007
 
Total current assets     427,231     425,120
 
Property, Plant and Equipment
Oil and gas properties, net 5,087,573 4,673,886
Utility plant, net 885,509 842,643
Other property, net     30,556     25,107
 
Total property, plant and equipment, net     6,003,638     5,541,636
 
Other Assets
Regulatory asset 84,890 110,566
Long-term derivative instruments 5,439 40,577
Other     101,014     57,991
 
Total other assets     191,343     209,134
 
TOTAL ASSETS   $ 6,622,212   $ 6,175,890
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year $ 60,000 $ 50,000
Notes payable to banks 539,000 643,000
Accounts payable 250,756 257,579
Regulatory liability 49,006 45,116
Other     211,131     164,087
 
Total current liabilities     1,109,893     1,159,782
 
Long-term debt     1,343,464     1,103,528
 
Deferred Credits and Other Liabilities
Regulatory liability 94,125 80,404
Deferred income taxes 1,013,245 905,601
Long-term derivative instruments 398 11,305
Other     203,068     238,580
 
Total deferred credits and other liabilities     1,310,836     1,235,890
 
Total Shareholders’ Equity     2,858,019     2,676,690
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY   $ 6,622,212   $ 6,175,890
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending December 31, 2013 and 2012

           
  4th Quarter  
 
(in thousands, except sales price data)   2013   2012   Change
 
Oil and Gas Operations (GAAP)
Operating revenues from continuing operations
Natural gas $ 43,332 $ 59,765 $ (16,433 )
Oil 257,125 210,770 46,355
Natural gas liquids 29,994 20,968 9,026
Other     (489 )     (1,612 )     1,123  
 
Total (GAAP)   $ 329,962     $ 289,891     $ 40,071  
 
Oil and Gas Operations excluding

mark-to-market (Non-GAAP)

Operating revenues from continuing operations
Natural gas $ 63,861 $ 56,159 $ 7,702
Oil 236,525 188,339 48,186
Natural gas liquids 29,438 22,290 7,148
Other     (489 )     (1,612 )     1,123  
 
Total (Non-GAAP)*   $ 329,335     $ 265,176     $ 64,159  
 
Production volumes from continuing operations
Natural gas (MMcf) 14,676 15,090 (414 )
Oil (MBbl) 2,694 2,335 359
Natural gas liquids (MMgal) 37.3 29.1 8.2
 
Total production volumes (MMcfe) 36,168 33,252 2,916
Total production volumes (MBOE) 6,028 5,542 486
 

Revenue per unit of production including effects of designated cash flow hedges

Natural gas (Mcf) $ 4.35 $ 3.72 $ 0.63
Oil (barrel) $ 87.80 $ 80.66 $ 7.14
Natural gas liquids (gallon) $ 0.79 $ 0.77 $ 0.02
 

Revenue per unit of production excluding effects of all derivative instruments

 

Natural gas (Mcf) $ 3.50 $ 3.23 $ 0.27
Oil (barrel) $ 92.84 $ 81.10 $ 11.74
Natural gas liquids (gallon) $ 0.73 $ 0.68 $ 0.05
 
Other data from continuing operations
Lease operating expense (LOE)
LOE and other $ 73,598 $ 65,451 $ 8,147
Production taxes     17,890       13,808       4,082  
 
Total   $ 91,488     $ 79,259     $ 12,229  
 
Depreciation, depletion and amortization $ 120,784 $ 98,269 $ 22,515
General and administrative expense $ 25,827 $ 15,873 $ 9,954
Capital expenditures $ 212,054 $ 333,298 $ (121,244 )
Exploration expenditures $ 14,040 $ 5,974 $ 8,066
Operating income   $ 76,015     $ 88,868     $ (12,853 )
 

*Operating revenues excluding mark-to-market gains of $627 and $24,715 in fourth quarter 2013 and 2012, respectively.

 
 
 
Natural Gas Distribution
Operating revenues
Residential $ 81,072 $ 76,161 $ 4,911
Commercial and industrial 33,572 30,822 2,750
Transportation 15,993 16,093 (100 )
Other     12,134       1,330       10,804  
 
Total   $ 142,771     $ 124,406     $ 18,365  
 
Gas delivery volumes (MMcf)
Residential 4,900 4,413 487
Commercial and industrial 2,534 2,235 299
Transportation     12,801       13,271       (470 )
 
Total     20,235       19,919       316  
 
Other data
Depreciation and amortization $ 11,242 $ 10,719 $ 523
Capital expenditures $ 20,979 $ 20,083 $ 896
Operating income   $ 34,800     $ 22,951     $ 11,849  
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 12 months ending December 31, 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 $ 239,643 $ 216,073 $ 23,570
Oil 865,100 788,937 76,163
Natural gas liquids 101,550 85,938 15,612
Other     (981 )     (1,718 )     737  
 
Total (GAAP)   $ 1,205,312     $ 1,089,230     $ 116,082  
 
Oil and Gas Operations excluding

mark-to-market (Non-GAAP)

Operating revenues from continuing operations
Natural gas $ 243,562 $ 216,588 $ 26,974
Oil 908,361 730,151 178,210
Natural gas liquids 102,202 85,459 16,743
Other     (981 )     (1,718 )     737  
 
Total (Non-GAAP)*   $ 1,253,144     $ 1,030,480     $ 222,664  
 
Production volumes from continuing operations
Natural gas (MMcf) 58,104 59,166 (1,062 )
Oil (MBbl) 10,364 8,749 1,615
Natural gas liquids (MMgal) 135.8 108.1 27.7
 
Total production volumes (MMcfe) 139,686 127,098 12,588
Total production volumes (MBOE) 23,281 21,183 2,098
 

Revenue per unit of production including effects of designated cash flow hedges

Natural gas (Mcf) $ 4.19 $ 3.66 $ 0.53
Oil (barrel) $ 87.65 $ 83.46 $ 4.19
Natural gas liquids (gallon) $ 0.75 $ 0.79 $ (0.04 )
 

Revenue per unit of production excluding effects of all derivative instruments

 

Natural gas (Mcf) $ 3.51 $ 2.69 $ 0.82
Oil (barrel) $ 92.73 $ 87.56 $ 5.17
Natural gas liquids (gallon) $ 0.67 $ 0.75 $ (0.08 )
 
Other data from continuing operations
Lease operating expense (LOE)
LOE and other $ 284,053 $ 224,503 $ 59,550
Production taxes     67,488       53,690       13,798  
 
Total   $ 351,541     $ 278,193     $ 73,348  
 
 
Depreciation, depletion and amortization $ 453,474 $ 343,183 $ 110,291
General and administrative expense $ 107,397 $ 72,394 $ 35,003
Capital expenditures $ 1,104,745 $ 1,291,211 $ (186,466 )
Exploration expenditures $ 27,942 $ 19,356 $ 8,586
Operating income   $ 257,963     $ 369,765     $ (111,082 )
 

* Operating revenues excluding mark-to-market loss of $47,832 and gain of $58,750 in 2013 and 2012, respectively.

 
 
 
Natural Gas Distribution
Operating revenues
Residential $ 340,563 $ 277,698 $ 62,865
Commercial and industrial 136,990 115,711 21,279
Transportation 61,254 58,857 2,397
Other     (5,469 )     (677 )     (4,792 )
 
Total   $ 533,338     $ 451,589     $ 81,749  
 
Gas delivery volumes (MMcf)
Residential 20,279 16,014 4,265
Commercial and industrial 9,968 8,372 1,596
Transportation     47,534       48,106       (572 )
 
Total     77,781       72,492       5,289  
 
Other data
Depreciation and amortization $ 43,907 $ 42,270 $ 1,637
Capital expenditures $ 88,769 $ 71,869 $ 16,900
Operating income   $ 93,768     $ 93,216     $ 552  
 


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