Energen Reports 2nd Quarter 2013 Operating, Financial Results

Energen Corporation (NYSE: EGN) announced today that its earnings in the three months ended June 30, 2013, totaled $83.1 million, or $1.15 per diluted share. Excluding non-cash items, Energen’s adjusted net income (a non-GAAP measure) totaled $47.6 million, or $0.66 per diluted share, in the second quarter of 2013; in the same period last year, adjusted net income was $52.8 million, or $0.73 per diluted share.

Non-cash, mark-to-market revenue gains in the second quarter of 2013 were $56.1 million ($35.5 million after tax, or $0.49 per diluted share). In the second quarter of 2012, mark-to-market revenue gains totaled $121.5 ($78.5 million after tax, or $1.09 per diluted share). [See “Non-GAAP Financial Measures” for more information and reconciliation.]

A 7 percent increase in total production, including an 18 percent increase in oil volumes, and higher realized natural gas and oil prices benefited Energen’s second quarter earnings in 2013 as compared to the same period a year ago. More than offsetting these gains were increased depreciation, depletion, and amortization expense (DD&A), lease operating expense (LOE) and production taxes, and administrative expense.

Consolidated adjusted EBITDA (a non-GAAP measure) totaled $223.1 million in the second quarter of 2013 and compared with $201.2 million in the prior-year second quarter. The company’s oil and gas exploration and production unit, Energen Resources Corporation, had adjusted EBITDA of $209.5 million in the second quarter of 2013 and $186.4 million in the same period a year ago. [ See “Non-GAAP Financial Measures” for more information and reconciliation.]

Second Quarter 2013

Excluding non-cash items, Energen Resources reported adjusted net income of $48.4 million in the second quarter of 2013 and $53.2 million in the same period a year ago. Production in the second quarter increased 7 percent year-over-year. Oil and natural gas liquids (NGL) volumes increased 19 percent, reflecting the company’s focus on its assets in the oil-rich Permian Basin; production in the basin grew 26 percent in the second quarter of 2013 from the same period last year.

A 4 percent decline in second quarter natural gas volumes year-over-year reflected the company’s limited capital investment in its natural gas properties in response to low prices; the San Juan Basin and the company’s other gas properties experienced 8 percent and 17 percent declines, respectively, in the second quarter of 2013 from the same period a year ago.

           

Production (MBOE)
                   
Commodity     2Q13     2Q12     Change
Oil 2,595 2,195 18 %
NGL 815 661 23 %
Natural Gas     3,070     3,213     (4 ) %
Total     6,480     6,069     7 %
 
           

Production by Area (MBOE)
                   
Area     2Q13     2Q12     Change
Permian Basin 3,549 2,814 26 %
San Juan Basin 2,299 2,493 (8 ) %
Other     632     762     (17 ) %
Total     6,480     6,069     7 %
 
           

Average Realized Sales Prices
                   
Commodity     2Q13     2Q12     Change
Oil (per barrel) $ 87.13 $ 85.70 2 %
NGL (per gallon) $ 0.70 $ 0.75 (7 ) %
Natural Gas (per Mcf)     $ 4.30     $ 3.55     21 %
 

Total LOE per unit in the 2 nd quarter of 2013 increased approximately 17 percent from the same period a year ago to $13.83 per barrel of oil equivalent (BOE). Base LOE and marketing and transportation expenses increased approximately 15 percent to $11.11 per BOE largely due to increased workovers and repairs, environmental compliance, increased equipment rental expense, higher ad valorem taxes, and increased power and gathering expenses. Commodity price-driven production taxes increased approximately 25 percent on a per-unit basis to $2.72 per unit.

DD&A expense per unit in the 2nd quarter of 2013 totaled $18.54 per BOE, increasing approximately 24 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 second quarter of 2013 to $3.85 per BOE largely due to performance-based compensation and higher labor costs.

ALAGASCO

Energen’s utility operations under Alagasco generated a net loss of $0.7 million in the 2nd quarter of 2013 as compared with earnings of $0.3 million in the same period a year ago; the difference primarily was due to the timing of rate recovery under the utility’s rate-setting process.

YTD FINANCIAL RESULTS

CONSOLIDATED

In the first six months of 2013, Energen’s net income totaled $139.8 million, or $1.93 per diluted share. Excluding non-cash items, adjusted net income (a non-GAAP measure) totaled $130.2 million, or $1.80 per diluted share. These non-cash items were mark-to-market revenue gains on certain financial commodity contracts of $15.1 million ($9.5 million after tax, or 13 cents per diluted share). Adjusted net income in the prior-year period totaled $149.9 million, or $2.07 per diluted share. [ See “Non-GAAP Financial Measures” for explanation and reconciliation.]

Consolidated adjusted EBITDA (a non-GAAP measure) totaled $486.4 million in the year-to-date period ended June 30, 2013, and compared with $464.0 million in same period last year. Energen Resources’ adjusted year-to-date 2013 EBITDA was $382.3 and compared with $359.6 million in the same period a year ago. [ See “Non-GAAP Financial Measures” for more information and reconciliation.]

EXPLORATION & PRODUCTION

Excluding non-cash items, Energen Resources’ adjusted year-to-date net income totaled $83.1 million in 2013 as compared with $102.4 million in the same period in 2012.
           

Production, January-June (MBOE)
                   
Commodity     YTD13     YTD12     Change
Oil 4,912 4,148 18 %
NGL 1,471 1,281 15 %
Natural Gas     6,018     6,395     (6 ) %
Total     12,401     11,824     5 %
 
           

Production by Area, January-June (MBOE)
                   
Area     YTD13     YTD12     Change
Permian Basin 6,573 5,304 24 %
San Juan Basin 4,513 4,992 (10 ) %
Other     1,315     1,528     (14 ) %
Total     12,401     11,824     5 %
 
           

Average Realized Sales Prices, January-June
                   
Commodity     YTD13     YTD12     Change
Oil (per barrel) $ 86.43 $ 85.43 1 %
NGL (per gallon) $ 0.73 $ 0.81 (10 ) %
Natural Gas (per Mcf)     $ 4.28     $ 3.75     14 %

Total LOE per unit in the first six months of 2013 increased approximately 24 percent from the same period last year to $14.96 per BOE. Base LOE and marketing and transportation expenses increased approximately 27 percent to $12.38 per BOE largely due to increased workovers and repairs, equipment rental expense, ad valorem taxes, water disposal, gathering, and environmental compliance. Commodity price-driven production taxes increased approximately 12 percent on a per-unit basis to $2.58 per BOE.

DD&A expense per unit in the first six months of 2013 increased approximately 23 percent from the same period last year, excluding the non-cash write-down of natural gas properties in East Texas, to $18.03 per BOE; this increase largely reflected year-over-year increases in development costs and production and the impact of reduced year-end 2012 natural gas reserves resulting from lower commodity prices.

Per-unit net G&A expense increased approximately 36 percent in the first six months of 2013 to $4.00 per BOE largely due to performance-based compensation and higher labor costs.

ALAGASCO

Alagasco generated net income of $46.5 million in the first six months of 2013 as compared with $47.2 million in the same period last year.

Midland Basin

First Operated Wolfcamp Well in Midland Basin Generates Strong Results

Energen reported today in a separate announcement that its first operated Wolfcamp well in the Midland Basin produced at a peak 24-hour initial rate (3-stream) of 861 boepd (60% oil, 23% NGL, 17% gas) and has a 20-day peak average rate (3-stream) of 709 boepd (65% oil, 20% NGL, 15% gas). Drilled in the upper Wolfcamp shale to a lateral length of 4,250 feet in Glasscock County, Energen’s Lavaca 38 #101H initial rates are comparable to those of similar wells operated by others in the area.

“Based on the result of this well and the results of others in the Basin, it appears that multiple benches of the Wolfcamp shale will be productive and are candidates for future pad drilling, which will only make the economics stronger,” said Energen Chief Executive Officer James McManus. The company estimates that, based on 80-acre spacing and 4,400-foot lateral lengths, success in the three benches of the Wolfcamp would translate into some 2,000 potential drilling locations (unrisked) on its approximately 70,000 net acres in the play.

In the second half of 2013, Energen plans to add a horizontal rig in the Midland Basin and increase the number of wells drilled this year from 6 gross (6 net) to 9 gross (9 net). The company also expects to drill progressively longer lateral lengths – up to 7,500 feet. Energen’s second Glasscock County well is currently being completed, and the vertical section of a third well is being drilled.

Vertical Wolfberry EURs Raised

Energen Resources’ vertical Wolfberry wells continued to generate strong results in the second quarter. Sixty-seven gross (62 net) wells tested at an average peak 24-hour initial production rate (2-stream) of 114 boepd (78% oil). The peak 30-day average rate (2-stream) was 96 boepd (78% oil).

These rates are above the company’s average Wolfberry type curve primarily due to continued performance enhancement from slick water stimulations in the southern half of the Midland Basin and to contributions from deeper formations in the northern half of the basin. In the north, by adding approximately 500 feet to total depth, Energen is now drilling below the Strawn into the Mississippian to include the Atoka, Barnett, and Mississippi Lime in its completions. In addition to enhancing current vertical production, the deeper wells are holding these zones for potential horizontal drilling in the future.

Based on an analysis of well performance, Energen believes that the improvement in results supports an increase in the estimated ultimate recovery (EUR) per well from an average of 165,000 BOE to 190,000 BOE. The new average drill and complete cost is $2.5 million, and the estimated pre-tax rate of return has increased to 31 percent at commodity prices of $100 per barrel oil and $4 per Mcf gas.

Energen has drilled 94 gross (85 net) Wolfberry wells in the first six months of the year and plans to drill another 42 gross (39 net) wells by year end. This reflects a reduction of 42 net wells from prior drilling plans as the company redeploys capital to accelerate testing of the horizontal Wolfcamp potential on its Midland Basin acreage. Energen estimates that its 27,000 net undeveloped Wolfberry acres in the Midland Basin support 670 net drilling locations on 40-acre spacing.

Delaware Basin

Wolfcamp Wells in Delaware Basin Show Potential

Energen reported today in a separate announcement that three horizontal Wolfcamp wells it drilled in the Delaware Basin have generated strong early rates. The E.J. Brady 56-1 #1H was drilled in the upper Wolfcamp to a lateral length of 3,800 feet in Reeves County. It produced at a peak 24-hour initial rate (3-stream) of 1,798 boepd (27% oil, 29% NGL, 44% gas) and had a peak 20-day average rate (3-stream) of 1,585 boepd (27% oil, 29% NGL, 44% gas).

The University 39-17 #1H and University 28-21 #1H wells were drilled in Ward and Winkler counties in the eastern side of the Delaware Basin. They both tested the upper Wolfcamp and had lateral lengths of 4,000 feet and 4,200 feet, respectively. The 39-17 #1H produced at a peak 24-hour initial rate (3-stream) of 1,187 boepd (61% oil, 18% NGL, 21% gas) and had a peak 30-day average rate (3-stream) of 950 boepd (60% oil, 18% NGL, 22% gas); the 28-21 #1H produced at a peak 24-hour initial rate (3-stream) of 969 boepd (74% oil, 14% NGL, 12% gas) and had a peak 30-day average rate (3-stream) of 652 boepd (74% oil, 14% NGL, 12% gas).

“We are pleased with our early Wolfcamp results in the Delaware Basin, but more work needs to be done to fully understand the complexities of this thick shale formation,” McManus said. With approximately 114,000 net acres in the Texas Delaware Basin estimated to have Wolfcamp potential, Energen’s potential (unrisked) drilling inventory could reach into the thousands (based on 80-acre spacing and 4,400-foot lateral lengths) if the play is successful in one or more benches of the shale on a large-scale basis.

Energen has added two more operated Delaware Basin Wolfcamp wells to its exploratory drilling schedule for 2013 and has converted a second Wolfbone well to a Wolfcamp well. This brings the total number of operated Wolfcamp wells in the company’s 2013 exploration program in the Delaware Basin to 10 gross (10 net). Three wells are currently drilling.

3 rd Bone Spring Development Wells Continue Solid Performance

In the company’s horizontal 3rd Bone Spring program in the Delaware Basin, Energen Resources tested 10 gross (10 net) wells in the second quarter of 2013 that had an average 24-hour peak rate (2-stream) of 1,035 boepd (70% oil). The 30-day average production rate (2-stream) of 7 gross (7 net) wells tested was 695 boepd (68% oil).

On the east side of the Pecos River, the company’s core 3 rd Bone Spring holdings total approximately 30,000 net acres, of which 7,500 remain undeveloped. Energen Resources estimates that it has 46 potential locations remaining to be drilled on 160-acre spacing in this core area.

2013 Guidance

Energen today affirmed its production guidance range of 26.1-26.5 million BOE (MMBOE). Included in this range is a full-year of Black Warrior Basin gas production; these assets currently are on the market. A sale of the properties prior to year-end would affect production for the year.

Drilling capital is estimated to remain approximately $1.0 billion; costs associated with additional Wolfcamp wells, deeper northern Wolfberry wells, additional working interests, and other change-in-scope items have been largely offset by a reduction in vertical Wolfberry wells.
     

2013e Revised Drilling and Production Summary
           
   

Operated Wells Drilled Gross (Net)
   

Production Midpoint
 
Midland Basin 145 (133) 5.4

Wolfberry

136 (124)

5.3

Wolfcamp

9 (9)

0.1
 
Delaware Basin

43 (41)
4.9

3 rd Bone Spring

32 (30)

4.4

Wolfcamp

10 (10)

0.5

Wolfbone

1 (1)
 
Other Permian* 83 (80) 4.3
 

San Juan Basin/Other
 

0 0
   

11.7

 

TOTAL
 

271 (254)
   

 

26.1 - 26.5

* Includes 2 gross (2 net) injector wells
 
   

Production (MMBOE)
         
Commodity  

2013e Production Midpoint
  2012
Oil 10.6 8.8
NGL 3.5 2.6
Natural Gas   12.2   12.7
Total   26.1 - 26.5   24.1
 
 

2013e Capital Summary
     

Basin
 

Capital ($MM)
Midland Basin

$

460
Delaware Basin $ 425
Other Permian $ 85
San Juan Basin/Other   $ 30
Total   $ 1,000
 

Energen’s revised guidance range for 2013 consolidated after-tax cash flows is $907-$937 million. Energen Resources’ after-tax cash flows are estimated to be $806-$836 million, and Alagasco is expected to generate after-tax cash flows of approximately $101 million.

Net income guidance for 2013 was revised down to $3.15-$3.55 per diluted share due largely to increased estimates for LOE and slight changes to product mix. A sale of the company’s Black Warrior Basin assets before year end would not materially impact earnings. Energen’s earnings guidance does not include non-cash, mark-to-market gains or losses. [See “Non-GAAP Financial Measures” for more information and reconciliation.]

 
Energen Resources’ estimated exploration and production expenses per BOE in 2013 are:
 
Lease Operating expense
Base, marketing, and transportation $

11.35

-
$ 11.60
Production taxes $

2.65

-
$ 2.75
DD&A expense $

18.65

-
$ 18.95
General & Administrative expense, net $

3.80

-
$ 4.25
Interest expense $

2.00

-
$ 2.10
 

Approximately 70 percent of the company’s total estimated production for the remainder of 2013 is hedged. In early July, to capitalize on an upswing in oil prices, Energen added hedges for an additional 195,000 barrels of its July-December 2013 oil production at a NYMEX price of $101.00 per barrel. 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 just over 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 1.8 million barrels of oil production at an average price of $3.00 per barrel and the WTI Midland to WTI Cushing differential for 2.1 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 $1.00 per barrel (sour oil) and $0.50 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 six months of 2013 is as follows:
                         

Commodity
   

Hedge Volumes
   

2013e Production

Midpoint
    Hedge %    

NYMEX Price

Oil
   

4.8 MMBO
   

5.7 MMBO
   

84

%
   

$ 91.47 per barrel

NGL

23.4 MMgal

85.9 MMgal

27

%

$ 1.02 per gallon

Natural Gas
   

27.3 Bcf
   

37.6 Bcf
   

73

%
   

$ 4.64 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 $0.20 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.

Sensitivity of 2013e Cash Flows and Earnings to Changes in Commodity Prices

Changes in commodity prices for the remainder of the year are estimated to have the following 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 $400,000, or 0.6 cents per diluted share.
  • Every 1-cent change in the average price of liquids from $0.86 per gallon represents an estimated net impact of approximately $450,000, or 0.6 cents per diluted share.
  • Every 10-cent change in the average NYMEX price of gas from $4.00 represents an estimated net impact of $200,000, or 0.3 cents per diluted share.

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

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

ENERGEN ADDS TO 2015 OIL HEDGE POSITION

During July, Energen Resources hedged another 2.5 MMBbl of 2015 oil production at a NYMEX price of $88.52 per barrel. This brings the company’s total 2015 oil hedge position to 3.2 MMBbl at an average NYMEX price of $88.87 per barrel. Energen also initiated natural gas hedging in 2015 with 6.0 Bcf of San Juan basin production hedged at a NYMEX-equivalent price of $4.27 per Mcf.

Energen’s hedge position in 2014 is unchanged and is as follows:

         

Commodity
 

Hedge Volumes
 

NYMEX Price

Oil
 

9.8 MMBO
 

$ 92.64 per barrel

Natural Gas
 

51.8 Bcf
 

$ 4.60 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 $0.20 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, July 31, 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 Energen’s 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

 

The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. Adjusted Net Income is a Non-GAAP financial measure which excludes certain non-cash mark-to-market derivative financial instruments and a commodity price-related write-down of natural gas properties. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.

 
   
     
Quarter Ended 6/30/2013
Consolidated Net Income ($ in millions except per share data)   Net Income   Per Diluted Share
Net Income (GAAP) 83.1 1.15
Non-cash mark-to-market gains (net of $20.6 tax)   (35.5 )   (0.49 )
Adjusted Net Income (Non-GAAP)   47.6     0.66  
 
     
Quarter Ended 6/30/2012
Consolidated Net Income ($ in millions except per share data)   Net Income   Per Diluted Share
Net Income (GAAP) 131.3 1.82
Non-cash mark-to-market gains (net of $43.0 tax)   (78.5 )   (1.09 )
Adjusted Net Income (Non-GAAP)   52.8     0.73  
 
     
Year-to-Date Ended 6/30/2013
Consolidated Net Income ($ in millions except per share data)   Net Income   Per Diluted Share
Net Income (GAAP) 139.8 1.93
Non-cash mark-to-market gains (net of $5.6 tax)   (9.5 )   (0.13 )
Adjusted Net Income (Non-GAAP)   130.2     1.80  
 
     
Year-to-Date Ended 6/30/2012
Consolidated Net Income ($ in millions except per share data)   Net Income   Per Diluted Share
Net Income (GAAP) 188.7 2.61
Non-cash mark-to-market gains (net of $28.6 tax) (52.2 ) (0.73 )
Non-cash write-down of natural gas properties (net of $8.1 tax)   13.4     0.19  
Adjusted Net Income (Non-GAAP)   149.9     2.07  
 
Note: Amounts may not sum due to rounding
 
         

Non-GAAP Financial Measures

 

The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. Adjusted Net Income is a Non-GAAP financial measure which excludes certain non-cash mark-to-market derivative financial instruments and a commodity price-related write-down of natural gas properties. 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 6/30/2013
 

Year-to-date 6/30/2013
Net Income (GAAP) 83.9 92.6
Non-cash mark-to-market gains (net of $20.6 and $5.6 tax)   (35.5 )   (9.5 )
Adjusted Net Income (Non-GAAP)   48.4     83.1  
 
     
Energen Resources Net Income ($ in millions)  

Quarter Ended 6/30/2012
 

Year-to-date 6/30/2012
Net Income (GAAP) 131.7 141.2
Non-cash mark-to-market gains (net of $43.0 and $28.6 tax) (78.5 ) (52.2 )
Non-cash write-down of natural gas properties (net of $8.1 tax)   -     13.4  
Adjusted Net Income (Non-GAAP)   53.2     102.4  
 
                 

Non-GAAP Financial Measures

 

The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures. Earnings before interest, taxes, depreciation, and amortization (EBITDA) is a Non-GAAP financial measure. Energen believes this measure allows analysts and investors to understand the financial performance of the company by computing earnings from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing profitability between the company and other oil and gas producing companies. Adjusted EBITDA excludes certain non-cash mark-to-market derivative financial instruments and a commodity price-related write-down of natural gas properties.
       
           
Reconciliation To GAAP Information Year-to-Date Ended 6/30 Quarter Ended 6/30
($ in millions)   2012   2013 2012   2013
 
Consolidated Net Income (GAAP) 188.7 139.8 131.3 83.1
Interest expense 31.3 34.1 15.8 17.3
Income tax expense 106.8 80.1 73.6 46.6
Depreciation, depletion and amortization   196.5     247.6   102.0     132.3  
EBITDA (Non-GAAP)   523.3     501.5   322.7     279.2  
Adjustment for asset impairment 21.5 - - -
Adjustment for mark-to-market gains   (80.8 )   (15.1 ) (121.5 )   (56.1 )
Consolidated Adjusted EBITDA (Non-GAAP)   464.0     486.4   201.2     223.1  
 
 
           
Reconciliation To GAAP Information Year-to-Date Ended 6/30 Quarter Ended 6/30
($ in millions)   2012   2013 2012   2013
 
Energen Resources Net Income (GAAP) 141.2 92.6 131.7 83.9
Interest expense 23.5 26.5 12.0 13.6
Income tax expense 78.7 52.3 72.7 46.8
Depreciation, depletion and amortization   175.5     226.0   91.5     121.4  
Energen Resources EBITDA (Non-GAAP)   418.9     397.4   307.9     265.7  
Adjustment for asset impairment 21.5 - - -
Adjustment for mark-to-market gains   (80.8 )   (15.1 ) (121.5 )   (56.1 )
Energen Resources Adjusted EBITDA (Non-GAAP)   359.6     382.3   186.4     209.5  
 
Note: Amounts may not sum due to rounding
 
 

Non-GAAP Financial Measures

 

The United States Securities and Exchange Commission requires public companies, such as Energen Corporation (the Company), to reconcile Non-GAAP (GAAP refers to generally accepted accounting principles) financial measures to related GAAP measures.  After-tax Cash Flows is a Non-GAAP financial measure.  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.
       
             
Reconciliation To GAAP Information Years Ended 12/31
($ in millions)   2011 Actual   2012 Actual   2013 Estimate (e)
 
Consolidated Net Income (Before asset impairment) 260 268 228 258
Asset impairment   -     (14 )   -     -  
Consolidated Net Income (GAAP)   260     254     228     258  
Depreciation, depletion and amortization (Including asset impairment) 284 441 536 536
Deferred income taxes, net 129 124 121 121
Exploratory expense 11 17 - -
Other   53     (34 )   22     22  
After-tax Cash Flows (Non-GAAP) 737 802 907 937
Changes in assets and liabilities and other adjustments   25     (66 )   32     32  
Net Cash Provided by Operating Activities (GAAP)   762     736     939     969  
 
             
Reconciliation To GAAP Information Years Ended 12/31
($ in millions)   2011 Actual   2012 Actual   2013 Estimate (e)
 
Net Cash Provided by Operating Activities (GAAP) 762 736 939 969
Changes in assets and liabilities and other adjustments   (25 )   66     (32 )   (32 )
After-tax Cash Flow (Non-GAAP) 737 802 907 937
Less: AGC cash flows from operations and other   (115 )   (103 )   (101 )   (101 )
Adj. After-tax Cash Flows Excluding Alagasco (Non-GAAP)   622     699     806     836  
                 

(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 June 30, 2013 and 2012
           
2nd Quarter
 
( in thousands, except per share data)   2013   2012   Change
 
Operating Revenues
Oil and gas operations $ 385,543 $ 399,468 $ (13,925 )
Natural gas distribution     104,514       70,887       33,627  
 
Total operating revenues     490,057       470,355       19,702  
 
Operating Expenses
Cost of gas 47,571 13,669 33,902
Operations and maintenance 136,204 112,713 23,491
Depreciation, depletion and amortization 132,285 101,991 30,294
Taxes, other than income taxes 25,650 19,523 6,127
Accretion expense     2,043       1,861       182  
 
Total operating expenses     343,753       249,757       93,996  
 
Operating Income     146,304       220,598       (74,294 )
 
Other Income (Expense)
Interest expense (17,306 ) (15,835 ) (1,471 )
Other income 748 659 89
Other expense     (128 )     (582 )     454  
 
Total other expense     (16,686 )     (15,758 )     (928 )
 
Income Before Income Taxes 129,618 204,840 (75,222 )
Income tax expense     46,551       73,553       (27,002 )
 
Net Income   $ 83,067     $ 131,287     $ (48,220 )
 
Diluted Earnings Per Average Common Share   $ 1.15     $ 1.82     $ (0.67 )
 
Basic Earnings Per Average Common Share   $ 1.15     $ 1.82     $ (0.67 )
 
Diluted Avg. Common Shares Outstanding     72,419       72,330       89  
 
Basic Avg. Common Shares Outstanding     72,167       72,117       50  
 
Dividends Per Common Share   $ 0.145     $ 0.14     $ 0.005  
 
   

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) For the 6 months ending June 30, 2013 and 2012
           
Year-to-date
 
( in thousands, except per share data)   2013   2012   Change
 
Operating Revenues
Oil and gas operations $ 640,537 $ 623,425 $ 17,112
Natural gas distribution     342,199       265,374       76,825  
 
Total operating revenues     982,736       888,799       93,937  
 
Operating Expenses
Cost of gas 143,013 73,255 69,758
Operations and maintenance 282,041 223,274 58,767
Depreciation, depletion and amortization 247,580 196,525 51,055
Asset impairment

21,545 (21,545 )
Taxes, other than income taxes 54,422 45,758 8,664
Accretion expense     4,040       3,674       366  
 
Total operating expenses     731,096       564,031       167,065  
 
Operating Income     251,640       324,768       (73,128 )
 
Other Income (Expense)
Interest expense (34,060 ) (31,260 ) (2,800 )
Other income 2,506 2,217 289
Other expense (197 ) (221 ) 24
 
Total other expense     (31,751 )     (29,264 )     (2,487 )
 
Income Before Income Taxes 219,889 295,504 (75,615 )
Income tax expense     80,130       106,811       (26,681 )
 
Net Income   $ 139,759     $ 188,693     $ (48,934 )
 
Diluted Earnings Per Average Common Share   $ 1.93     $ 2.61     $ (0.68 )
 
Basic Earnings Per Average Common Share   $ 1.94     $ 2.62     $ (0.68 )
 
Diluted Avg. Common Shares Outstanding     72,329       72,336       (7 )
 
Basic Avg. Common Shares Outstanding     72,155       72,110       45  
 
Dividends Per Common Share   $ 0.29     $ 0.28     $ 0.01  
 
 
CONSOLIDATED BALANCE SHEETS (UNAUDITED) As of June 30, 2013 and December 31, 2012
             
(in thousands)   June 30, 2013   December 31, 2012
   
ASSETS
Current Assets
Cash and cash equivalents $ 3,793 $ 9,704
Accounts receivable, net of allowance 226,255 277,900
Inventories 44,158 63,994
Regulatory asset 10,915 45,515
Assets held for sale 130,743
Other     31,035     28,007
 
Total current assets     446,899     425,120
 
Property, Plant and Equipment
Oil and gas properties, net 4,952,205 4,673,886
Utility plant, net 866,200 842,643
Other property, net     31,535     25,107
 
Total property, plant and equipment, net     5,849,940     5,541,636
 
Other Assets
Regulatory asset 107,189 110,566
Long-term derivative instruments 39,006 40,577
Other     62,129     57,991
 
Total other assets     208,324     209,134
 
TOTAL ASSETS   $ 6,505,163   $ 6,175,890
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year $ 100,000 $ 50,000
Notes payable to banks 800,000 643,000
Accounts payable 273,531 257,579
Regulatory liability 27,581 45,116
Liabilities related to assets held for sale 7,917
Other     187,407     164,087
 
Total current liabilities     1,396,436     1,159,782
 
Long-term debt     1,053,542     1,103,528
 
Deferred Credits and Other Liabilities
Regulatory liability 68,934 80,404
Deferred income taxes 963,727 905,601
Long-term derivative instruments 470 11,305
Other     240,577     238,580
 
Total deferred credits and other liabilities     1,273,708     1,235,890
 
Total Shareholders’ Equity     2,781,477     2,676,690
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY   $ 6,505,163   $ 6,175,890
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending June 30, 2013 and 2012
           
  2nd Quarter  
 
 
( in thousands, except sales price data)   2013     2012     Change
 
Oil and Gas Operations (GAAP)
Operating revenues
Natural gas $ 98,572 $ 68,249 $ 30,323
Oil 262,775 306,960 (44,185 )
Natural gas liquids 24,148 23,692 456
Other     48       567       (519 )
 
Total (GAAP)   $ 385,543     $ 399,468     $ (13,925 )
 

Oil and Gas Operations excluding mark-to-market (Non-GAAP)

 
Operating revenues
Natural gas $ 79,271 $ 68,494 $ 10,777
Oil 226,095 188,116 37,979
Natural gas liquids 23,980 20,832 3,148
Other     48       567       (519 )
 
Total (Non-GAAP)*   $ 329,394     $ 278,009     $ 51,385  
 
Production volumes
Natural gas (MMcf) 18,420 19,278 (858 )
Oil (MBbl) 2,595 2,195 400
Natural gas liquids (MMgal) 34.2 27.8 6.4
 
Total production volumes (MMcfe) 38,880 36,414 2,466
Total production volumes (MBOE) 6,480 6,069 411
 
Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments
Natural gas (Mcf) $ 4.30 $ 3.55 $ 0.75
Oil (barrel) $ 87.13 $ 85.70 $ 1.43
Natural gas liquids (gallon) $ 0.70 $ 0.75 $ (0.05 )
 

Revenue per unit of production excluding effects of all derivative instruments

 
Natural gas (Mcf) $ 3.90 $ 2.19 $ 1.71
Oil (barrel) $ 90.62 $ 85.70 $ 4.92
Natural gas liquids (gallon) $ 0.61 $ 0.71 $ (0.10 )
 
Other data
Lease operating expense (LOE)
LOE and other $ 72,027 $ 58,779 $ 13,248
Production taxes     17,606       13,205       4,401  
 
Total   $ 89,633     $ 71,984     $ 17,649  
 
Depreciation, depletion and amortization $ 121,412 $ 91,458 $ 29,954
General and administrative expense $ 24,969 $ 16,807 $ 8,162
Capital expenditures $ 349,879 $ 293,909 $ 55,970
Exploration expenditures $ 3,455 $ 952 $ 2,503
Operating income   $ 144,031     $ 216,406     $ (72,375 )
 

*Operating revenues excluding mark-to-market gains of $56,149 and $121,459 in second quarter 2013 and 2012, respectively.
 
 
 
Natural Gas Distribution
Operating revenues
Residential $ 65,551 $ 40,371 $ 25,180
Commercial and industrial 27,627 20,442 7,185
Transportation 13,824 13,661 163
Other     (2,488 )     (3,587 )     1,099  
 
Total   $ 104,514     $ 70,887     $ 33,627  
 
Gas delivery volumes (MMcf)
Residential 3,613 1,985 1,628
Commercial and industrial 1,955 1,449 506
Transportation     10,706       11,547       (841 )
 
Total     16,274       14,981       1,293  
 
Other data
Depreciation and amortization $ 10,873 $ 10,533 $ 340
Capital expenditures $ 27,113 $ 18,030 $ 9,083
Operating income   $ 2,219     $ 4,448     $ (2,229 )
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 6 months ending June 30, 2013 and 2012
           
  Year-to-date  
 
( in thousands, except sales price data)   2013     2012     Change
 
Oil and Gas Operations (GAAP)
Operating revenues
Natural gas $ 169,644 $ 143,829 $ 25,815
Oil 424,587 431,274 (6,687 )
Natural gas liquids 45,264 47,404 (2,140 )
Other     1,042       918       124  
 
Total (GAAP)   $ 640,537     $ 623,425     $ 17,112  
 

Oil and Gas Operations excluding mark-to-market (Non-GAAP)
Operating revenues
Natural gas $ 154,718 $ 143,791 $ 10,927
Oil 424,559 354,350 70,209
Natural gas liquids 45,117 43,579 1,538
Other     1,042       918       124  
 
Total (Non-GAAP)*   $ 625,436     $ 542,638     $ 82,798  
 
Production volumes
Natural gas (MMcf) 36,108 38,370 (2,262 )
Oil (MBbl) 4,912 4,148 764
Natural gas liquids (MMgal) 61.8 53.8 8.0
 
Total production volumes (MMcfe) 74,406 70,944 3,462
Total production volumes (MBOE) 12,401 11,824 577
 

Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments
Natural gas (Mcf) $ 4.28 $ 3.75 $ 0.53
Oil (barrel) $ 86.43 $ 85.43 $ 1.00
Natural gas liquids (gallon) $ 0.73 $ 0.81 $ (0.08 )
 

Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf) $ 3.61 $ 2.43 $ 1.18
Oil (barrel) $ 86.77 $ 91.77 $ (5.00 )
Natural gas liquids (gallon) $ 0.64 $ 0.83 $ (0.19 )
 
Other data
Lease operating expense (LOE)
LOE and other $ 153,573 $ 115,391 $ 38,182
Production taxes     31,969       27,367       4,602  
 
Total   $ 185,542     $ 142,758     $ 42,784  
 
Depreciation, depletion and amortization $ 225,978 $ 175,546 $ 50,432
Asset impairment $ 21,545 (21,545 )
General and administrative expense $ 49,664 $ 34,750 $ 14,914
Capital expenditures $ 634,932 $ 634,876 $ 56
Exploration expenditures $ 4,955 $ 2,741 $ 2,214
Operating income   $ 170,358     $ 242,411     $ (72,053 )
 

*Operating revenues excluding mark-to-market gains of $15,101 and $80,787 in 2013 and 2012, respectively.
 
 
 
Natural Gas Distribution
Operating revenues
Residential $ 228,291 $ 170,879 $ 57,412
Commercial and industrial 85,225 67,198 18,027
Transportation 32,064 29,259 2,805
Other     (3,381 )     (1,962 )     (1,419 )
 
Total   $ 342,199     $ 265,374     $ 76,825  
 
Gas delivery volumes (MMcf)
Residential 13,995 10,223 3,772
Commercial and industrial 6,162 4,891 1,271
Transportation     23,496       23,583       (87 )
 
Total     43,653       38,697       4,956  
 
Other data
Depreciation and amortization $ 21,602 $ 20,979 $ 623
Capital expenditures $ 46,810 $ 32,973 $ 13,837
Operating income   $ 81,512     $ 83,008     $ (1,496 )
 

Copyright Business Wire 2010

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