Energen Reports 4th Quarter And CY12 Operating And Financial Results

Energen Corporation (NYSE: EGN) announced today that its earnings in the three months ended December 31, 2012, totaled $62.8 million, or $0.87 per diluted share. Excluding non-cash mark-to-market gains on certain financial commodity contracts, Energen’s adjusted net income (a non-GAAP measure) totaled $47.2 million, or $0.65 per diluted share, and compared with 4 th quarter 2011 adjusted net income of $71.0 million, or $0.98 per diluted share.

Non-cash, mark-to-market revenue gains in the 4th quarter 2012 were $24.7 million ($15.7 million after tax, or $0.22 per diluted share). Non-cash, mark-to-market revenue losses in the same period in 2011 totaled $90.8 million ($56.6 million after tax, or $0.78 per diluted share). [See “Non-GAAP Financial Measures” for more information and reconciliation.]

Relative to the same period a year ago, production in the 4th quarter of 2012 increased 14 percent and realized oil prices rose 3 percent. More than offsetting these gains were significantly lower natural gas and natural gas liquids (NGL) prices, increased depreciation expense (DD&A), and higher lease operating expense (LOE). Also in the 4 th quarter of 2012, Energen wrote off $5.3 million ($3.4 million after tax, or $0.05 per diluted share) of Delaware Basin leasehold set to expire in the first half of 2013; the bulk of this acreage was located west of the Pecos River in Reeves County, Texas. ( See pp 9-10 for additional 4 th quarter information).

Consolidated adjusted EBITDA (a non-GAAP measure) totaled $209.3 million and compared with $208.5 million in the prior-year 4th quarter. The company’s oil and gas exploration and production unit, Energen Resources Corporation, had adjusted EBITDA of $175.3 million in the 4th quarter of 2012 and $177.2 million in the same period a year ago. [ See “Non-GAAP Financial Measures” for more information and reconciliation.]

“2012 was an exciting year for Energen. Record activity in the Permian Basin led to excellent performances from our 3 rd Bone Spring and Wolfberry wells as well as double-digit production growth,” said James McManus, Energen’s chairman and chief executive officer.

“We expect our continued development of the 3 rd Bone Spring sand east of the Pecos River in the Delaware Basin and the vertical Wolfberry in the Midland Basin to drive strong, double-digit production growth in the Permian Basin in 2013.

“And, at the same time, we are looking forward to exploring the potential offered by emerging horizontal plays in the Midland and Delaware basins.”

2012 Financial Results

Energen’s 2012 net income totaled $253.6 million, or $3.51 per diluted share. Excluding non-cash items, adjusted net income (a non-GAAP measure) totaled $229.7 million, or $3.18 per diluted share, and compared with prior-year adjusted results of $283.0 million, or $3.91 per diluted share.

Non-cash items in 2012 were mark-to-market revenue gains on certain financial commodity contracts of $58.8 million ($37.2 million after tax, or 52 cents per diluted share) and a commodity price-related write-down of natural gas properties in East Texas of $21.5 million ($13.4 million after tax, or 19 cents per diluted share). Mark-to-market revenue losses in 2011 totaled $37.6 million ($23.4 million after tax, or 32 cents per diluted share). [ See “Non-GAAP Financial Measures” for explanation and reconciliation.]

Excluding non-cash items, Energen Resources’ adjusted 2012 net income totaled $180.3 million as compared with $236.4 million in 2011.

Consolidated adjusted EBITDA (a non-GAAP measure) in 2012 totaled $845.3 million and increased 10 percent from 2011 adjusted EBITDA of $771.7 million. Energen Resources’ adjusted 2012 EBITDA totaled $708.6 million and compared with 2011 adjusted EBITDA of $645.7 million. [ See “Non-GAAP Financial Measures” for more information and reconciliation.].

Production in 2012 increased 18 percent year-over-year, including a 40 percent increase in oil production; and the average realized sales price of oil increased 5 percent. The company’s decreased net income relative to 2011 was driven largely by substantially lower natural gas and NGL prices, increased DD&A expense, and higher LOE.
 

Production (MMBOE)
Commodity     2012     2011     Change
Oil     8.8     6.3     40 %
NGL 2.6 2.2 18 %
Natural Gas       12.7       12.0     6 %
Total       24.1       20.5     18 %
 
 

Production by Area (MMBOE)
Area     2012     2011     Change
Permian Basin 11.2 7.8 44 %
San Juan Basin 9.9 9.6 3 %
Other       3.0       3.1     (3

)%
 
 

Average Realized Sales Prices
Commodity     2012     2011     Change
Oil (per barrel) $ 83.45 $ 79.72 5 %
NGL (per gallon) $ 0.79 $ 0.96 (18

)%
Natural Gas (per Mcf)     $ 3.79     $ 5.39     (30

)%
 

Total LOE per unit in 2012 increased approximately 1 percent from the prior year to $12.73 per BOE. Base LOE and marketing and transportation expenses increased 5 percent to $10.41 per BOE largely due to increased water disposal costs, ad valorem taxes, and equipment rental partially offset by lower operations and maintenance expense. Commodity price-driven production taxes declined approximately 14 percent on a per-unit basis to $2.32 per unit.

DD&A expense per unit in 2012, excluding the first quarter write-down of natural gas properties in East Texas, increased approximately 32 percent from the same period last year to $15.50 per BOE; this increase generally reflected year-over-year increases in development costs.

ALAGASCO

Energen’s utility operations under Alagasco generated net income of $49.4 million in 2012; this $2.8 million increase from 2011 reflects the utility’s ability to earn on a higher level of equity representing investment in utility plant.

3 rd Bone Spring and Wolfberry Programs Generate Excellent Results in 2012

Energen Resources’ 3rd Bone Spring and Wolfberry programs wrapped up a successful 2012 with continued strong results in the 4 th quarter.

In the company’s horizontal 3 rd Bone Spring program in the Delaware Basin, Energen Resources tested 10 gross (10 net) wells in the 4 th quarter of 2012 that had an average initial stabilized rate of 1,007 BOE per day (61% oil). The 30-day average production rate of 7 gross (7 net) wells tested was 609 BOE per day (57% oil).

For the calendar year 2012, Energen Resources drilled 42 gross (40 net) 3 rd Bone Spring wells. The average initial stabilized rate of 38 gross (35 net) wells was 1,031 BOE per day (68% oil). The 30-day average production rate of 35 gross (32 net) wells with sufficient production history was 661 BOE per day (65% oil).

On the east side of the Pecos River, the company’s core holdings total approximately 30,000 net acres, of which 9,500 remain undeveloped. Energen Resources estimates that it has approximately 59 potential locations remaining to be drilled on 160-acre spacing in this core area.

Energen Resources’ vertical Wolfberry program in the Midland Basin finished the year strong. During 2012 the company drilled 172 gross (167 net) Wolfberry wells. Some 179 gross (172 net) wells -- including 7 drilled in late 2011 – were completed and tested at an average initial stabilized rate of 90 BOE per day (75% oil); the average 30-day rate of the wells was 76 BOE per day (77% oil).

Through acquisition of proved property and leasehold during 2012, Energen Resources now has approximately 65,000 net acres in the Midland Basin that are prospective for the vertical Wolfberry play; approximately 34,000 net acres remain undeveloped. Based on 40-acre spacing, Energen Resources estimates that it has 850 potential locations remaining to be drilled; 20-acre downspacing could add another 800 locations.

Testing of the horizontal Wolfcamp shale continues in the Delaware Basin. The 4 wells remaining in the 2012 drilling program are in various stages of completion or testing. Successful results from these wells could help prove up the Wolfcamp potential in this region and add substantially to the company’s drilling inventory in the Delaware Basin.

Year-end Proved Reserves Total 346 MMBOE

Energen’s proved reserves at year-end 2012 totaled a record 346 MMBOE and were essentially unchanged from the prior year as record production and price-related, downward revisions offset the addition of previously classified unproved reserves and acquisition-related reserves. Oil and NGL reserves represent 61 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.

Natural gas and NGL prices used for calculating reserves were down substantially in 2012 relative to 2011. Reserves pricing in 2012 was $2.76 per Mcf of gas vs $4.12 per Mcf in 2011; $0.88 per gallon of NGL (before transportation and fractionation) vs $1.23 per gallon in 2011; and $94.71 per barrel of oil vs $96.19 per barrel in the prior year.

The bulk of proved reserves added through acquisition were vertical Wolfberry in the Midland Basin. Of reserves that moved from unproved to proved, approximately 50 percent were 3 rd Bone Spring sands in the Delaware Basin, approximately 45 percent were vertical Wolfberry in the Midland Basin, and approximately 5 percent were waterfloods in the Central Basin Platform. Twenty-five percent of Energen’s proved reserves are undeveloped.

 

Proved Reserves by Basin (MMBOE)
Basin     YE11    

2012 Production
   

2012 Acquisitions
    Additions    

Price/Other Revisions
    YE12
Permian     183.6     (11.2 )     12.3     56.9     (16.6 )     225.0
San Juan Basin 129.6 (9.9 ) 0.0 0.9 (19.7 ) 100.9
Black Warrior/Other     29.9     (3.0 )     0.0     0.1     (6.5 )     20.5
TOTAL     343.1     (24.1 )     12.3     57.9     (42.8 )     346.4
 
 

Proved Reserves by Commodity (MMBOE)
Commodity     2012     2011     % Change
Oil     155.3     129.6     19.8
Natural gas liquids 56.2 54.0 4.1
Natural gas     134.9     159.5     (15.4 )
TOTAL     346.4     343.1     1.0  
 

100 Net Upper Wolfcamp Locations Added to Midland Basin Unproved Reserves

Probable and possible reserves at year-end 2012 declined to 407 MMBOE. Substantially lower gas and NGL prices resulted in the loss of approximately 137 MMBOE of unproved San Juan reserves at the end of the 2012. In the Delaware Basin, 3 rd Bone Spring reserves west side of the Pecos River were revised down by some 64 MMBOE. Approximately 54 MMBOE of prior-year unproved reserves – primarily in the Delaware and Midland basins – were proved up.

The company added net reserves of approximately 36 MMBOE for 100 net Upper Wolfcamp locations in Glasscock County; this represents gross EURs of 460 MBOE per well assuming 160-acre spacing and 4,400’ horizontal lengths. Energen also gained 18 MMBOE of unproved Wolfberry reserves through acquisition.

Potential reserves not yet reflected in Energen’s probable and possible reserves include Wolfberry downspacing, horizontal Cline in the Midland Basin, horizontal Wolfcamp in the Delaware Basin, and horizontal Avalon shale in the Delaware Basin. Energen also has identified 685 net horizontal Wolfcamp locations (Upper, Middle, and Lower) that are not currently included in the company’s unproved reserves.

Oil and natural gas liquids now comprise more than 55 percent of Energen’s proved and unproved (3P) reserves, and the Permian Basin is home to 52 percent of the company’s 3P reserves.
 

YE2012 3P Reserves (MMBOE)
Basin     Proved     Probable     Possible     Total Unproved     3P Total
Permian     225.0     62.8     101.6     164.4     389.4
  • Delaware Basin
35.7 4.6 3.4 8.0 43.7
  • Midland Basin
110.1 44.8 38.6 83.4 193.5
  • Central Basin Platform
79.2 13.4 59.6 73.0 152.2
San Juan 100.9 49.4 188.5 237.9 338.9
 
Other     20.5     2.0     2.3     4.3     24.7
TOTAL     346.4     114.2     292.4     406.6     753.0
 

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.

2013 Capital, Production Outlook Affirmed

Energen today affirmed its guidance for 2013 capital, production, cash flows, and earnings.

2013e Capital, Drilling, and Production Summary
   

2013e Capital
    2013e Wells     2013e    

Production
     

($MM)
    Gross (Net)     Rig Count    

2013e
   

2012
Midland Basin $ 465 185 (173 ) 10-11

5.6
   

3.5

Wolfberry

$

420

179 (167

)

9-10

 

 

Wolfcamp/Cline

$

45

6 (6

)

1
 
Delaware Basin $ 325 44 (38 ) 6

4.6

2.9

3 rd Bone Spring

$

240

32 (28

)

4

 

 

Wolfcamp/Wolfbone

$

85

12 (10

)

2
 
Other Permian* $ 85 110 (88 ) 1-2 4.5 4.8
 

San Juan Basin/Other
   

$

25
     

0
     

0
   

11.4
   

12.9

TOTAL
   

$

900
     

339 (299

)
   

17-19
   

26.1
   

24.1

* Includes 5 gross (4 net) injector wells
 
 

Production (MMBOE)
Commodity     2013e     2012     Change
Oil     10.6     8.8     20 %
NGL 3.4 2.6 31 %
Natural Gas     12.1     12.7     (5

)%
Total     26.1     24.1     8 %
 

Energen’s guidance range for 2013 consolidated after-tax cash flows is $917-$946 million. Energen Resources’ after-tax cash flows are estimated to be $822-$851 million, and Alagasco’s utility operations are expected to generate after-tax cash flows of approximately $95 million. Net income in 2013 is estimated to be $219-$248 million, or $3.03-$3.43 per diluted share, and includes $22.2 million, or 31 cents per diluted share, of potential dry hole expense. 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 $ 10.25
Production taxes $ 2.48
DD&A expense $ 18.46
General & Administrative expense, net $ 3.57
Interest expense $ 2.27
 

Approximately 70 percent of the company’s total estimated production in 2013 is hedged, including 84 percent of estimated oil production, 31 percent of estimated NGL production, and 69 percent of estimated natural gas. Assumed prices applicable to Energen Resources unhedged volumes are $90.00 per barrel of oil, $0.89 per gallon of NGL, and $3.50 per Mcf of natural gas.

Hedges also are in place that limit the company’s exposure to the Midland to Cushing differential to only about 40 percent of its estimated oil production in 2013. Energen Resources has hedged the WTS Midland to WTI Cushing (sour oil) differential for 3.6 million barrels of oil production at an average price of $3.03 per barrel and the WTI Midland to WTI Cushing differential for 2.8 million barrels at an average price of $1.01 per barrel.

Energen’s 2013 guidance includes assumed prices applicable to Energen Resources’ unhedged oil basis differentials; on an annualized basis, these are $3.35 per barrel (sour) and $2.90 per barrel (WTI Midland to WTI Cushing). Energen estimates that 64 percent of its oil production in 2013 will be sweet.
 

The company’s current hedge position for 2013 is as follows:
 

Commodity
   

Hedge Volumes
   

Estimated Production
   

Hedge %
   

NYMEX Price

Oil
   

8.9 MMBO
   

10.6 MMBO
   

84%
   

$ 90.95 per barrel

NGL

44.5 MMgal

143.4 MMgal

31%

$ 1.02 per gallon

Natural Gas
   

50.0 Bcf
   

72.7 Bcf
   

69%
   

$ 4.63 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 $0.15 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 in 2013; and average realized NGL prices will be net of transportation and fractionation fees that are estimated to average $0.11-$0.16 per gallon in 2013. The company also has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price.

Gains and losses from the change in fair value of derivative instruments that do not qualify for cash flow hedge accounting are reported in operating revenues each applicable reporting period and, therefore, can cause non-cash earnings volatility.

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 $750,000, or 1.0 cent per diluted share.
  • Every 1-cent change in the average price of liquids from $0.89 per gallon represents an estimated net impact of approximately $760,000, or 1.0 cent per diluted share.
  • Every 10-cent change in the average NYMEX price of gas from $3.50 represents an estimated net impact of $1.0 million, or 1.4 cents per diluted share.

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

The company’s utility subsidiary has the opportunity to earn a return on average equity that is estimated to be approximately $375-$380 million in 2013.

4Q12 Financial Data

Excluding non-cash mark-to-market revenue gains, Energen Resources generated adjusted 4 th quarter 2012 net income of $34.9 million as compared with $59.9 million in 2011. [See “Non-GAAP Financial Measures” for more information and reconciliation.]
 

Production (MBOE)
Commodity     4Q12     4Q11     Change
Oil     2,339     1,744     34 %
NGL 692 591 17 %
Natural Gas       3,185       3,135     2 %
Total       6,216       5,470     14 %
 
 

Production by Area (MBOE)
Area     4Q12     4Q11     Change
Permian Basin 3,082 2,216 39 %
San Juan Basin 2,446 2,480 (1

)%
Other       688       774     (11

)%
 
 

Average Realized Sales Prices
Commodity     4Q12     4Q11     Change
Oil (per barrel) $ 80.65 $ 78.52 3 %
NGL (per gallon) $ 0.77 $ 0.97 (21

)%
Natural Gas (per Mcf)     $ 3.87     $ 5.14     (25

)%
 

Total LOE per unit in the 4 th quarter of 2012 increased approximately 18 percent from the same period a year ago to $13.81 per BOE. Base LOE and marketing and transportation expenses increased approximately 26 percent to $11.48 per BOE largely due to increased water disposal costs, workovers, ad valorem taxes, and equipment rental partially offset by lower operations and maintenance expense. Commodity price-driven production taxes declined approximately 10 percent on a per-unit basis to $2.32 per unit.

DD&A expense per unit in the 4 th quarter of 2012 increased approximately 28 percent from the same period last year to $17.19 per BOE; this increase generally reflected year-over-year increases in development costs.

ALAGASCO

Energen’s utility operations under Alagasco generated net income of $12.2 million in the 4 th quarter of 2012; this $0.9 million increase from the same period last year reflects the utility’s ability to earn on a higher level of equity representing investment in utility plant.

ENERGEN MAINTAINS STRONG HEDGE POSITIONS THROUGH 2014

Energen Resources has hedges in place through 2014 to help protect its future cash flows from commodity.

 

Energen Resources’ 2014 hedges are as follows:

Commodity
   

Hedge Volumes
   

NYMEX Price

Oil
   

9.8 MMBO
   

$ 92.64 per barrel

Natural Gas
   

46.1 Bcf
   

$ 4.61 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 $0.16 per Mcf and $0.13, respectively.
 

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 transportation charges; and average realized NGL prices will be net of transportation and fractionation fees. The company has basin-specific natural gas contracts whereby Energen Resources will receive the contracted hedge price. Gains and losses from the change in fair value of derivative instruments that do not qualify for cash flow hedge accounting are reported in operating revenues each applicable reporting period and, therefore, can cause non-cash earnings volatility.

CONFERENCE CALL

Energen will hold its quarterly conference call Thursday, January 24, at 11:00 a.m. EST. Members of the investment community may participate by calling 1-866-901-2585. 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 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 (Non-GAAP)     47.2       0.65  
 
 
Quarter Ended 12/31/2011
Consolidated Net Income ($ in millions except per share data)     Net Income     Per Diluted Share
Net Income (GAAP) 14.4 0.20
Non-cash mark-to-market losses (net of $34.2 tax)     56.6       0.78  
Adjusted Net Income (Non-GAAP)     71.0       0.98  
 
 
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 $21.6 tax) (37.2 ) (0.52 )
Non-cash write-down of natural gas properties (net of $8.1 tax)     13.4       0.19  
Adjusted Net Income (Non-GAAP)     229.7       3.18  
 
 
Year-to-Date Ended 12/31/2011
Consolidated Net Income ($ in millions except per share data)     Net Income     Per Diluted Share
Net Income (GAAP) 259.6 3.59
Non-cash mark-to-market losses (net of $14.2 tax)     23.4       0.32  
Adjusted Net Income (Non-GAAP)     283.0       3.91  
 
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 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 $21.6 tax) (15.7 ) (37.2 )
Non-cash write-down of natural gas properties (net of $8.1 tax)     -       13.4  
Adjusted Net Income (Non-GAAP)     34.9       180.3  
 
 
Energen Resources Net Income ($ in millions)    

Quarter Ended 12/31/2011
   

Year-to-date 12/31/2011
Net Income (GAAP) 3.3 213.0
Non-cash mark-to-market losses (net of $34.2 and $14.2 tax)     56.6       23.4  
Adjusted Net Income (Non-GAAP)     59.9       236.4  
 
 

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 12/31 Quarter Ended 12/31
($ in millions)     2011     2012 2011     2012
       
Consolidated Net Income (GAAP) 259.6 253.6 14.4 62.8
Interest expense 44.8 65.6 14.0 17.1
Income tax expense 145.7 143.8 4.8 35.4
Depreciation, depletion and amortization     284.0     419.6   84.4       118.7  
EBITDA (Non-GAAP)     734.1     882.5   117.7       234.0  
Adjustment for asset impairment - 21.5 - -
Adjustment for mark-to-market (gains) / losses     37.6     (58.8 ) 90.8       (24.7 )
Consolidated Adjusted EBITDA (Non-GAAP)     771.7     845.3   208.5       209.3  
 
 
   
Reconciliation To GAAP Information Year-to-Date Ended 12/31 Quarter Ended 12/31
($ in millions)     2011     2012 2011     2012
 
Energen Resources Net Income (GAAP) 213.0 204.1 3.3 50.6
Interest expense 30.9 50.0 10.4 13.1
Income tax expense 120.1 114.4 (1.5 ) 28.3
Depreciation, depletion and amortization     244.1     377.3   74.1       108.0  
Energen Resources EBITDA (Non-GAAP)     608.1     745.8   86.4       200.0  
Adjustment for asset impairment - 21.5 - -
Adjustment for mark-to-market (gains) / losses     37.6     (58.8 ) 90.8       (24.7 )
Energen Resources Adjusted EBITDA (Non-GAAP)     645.7     708.6   177.2       175.3  
 
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) 260 268 219 248
Asset impairment     -       (14 )     -       -  
Consolidated Net Income (GAAP)     260       254       219       248  
Depreciation, depletion and amortization (Including asset impairment) 284 441 530 530
Deferred income taxes, net 129 124 110 110
Exploratory expense 11 17 35 35
Other     53       (34 )     23       23  
After-tax Cash Flows (Non-GAAP) 737 802 917 946
Changes in assets and liabilities and other adjustments     25       (64 )     -       -  
Net Cash Provided by Operating Activities (GAAP)     762       738       917       946  
 
 
Reconciliation To GAAP Information Years Ended 12/31
($ in millions)     2011 Actual     2012 Actual     2013 Estimate (e)
 
Net Cash Provided by Operating Activities (GAAP) 762 738 917 946
Changes in assets and liabilities and other adjustments     (25 )     64       -       -  
After-tax Cash Flow (Non-GAAP) 737 802 917 946
Less: AGC cash flows from operations and other     (115 )     (103 )     (95 )     (95 )
Adj. After-tax Cash Flows Excluding Alagasco (Non-GAAP)     622       699       822       851  
 

(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, 2012 and 2011
 
    4th Quarter    
   
( in thousands, except per share data)     2012     2011     Change
 
Operating Revenues
Oil and gas operations $ 308,640 $ 168,692 $ 139,948
Natural gas distribution       124,406         119,456         4,950  
 
Total operating revenues       433,046         288,148         144,898  
 
Operating Expenses
Cost of gas 48,049 47,607 442
Operations and maintenance 126,022 100,356 25,666
Depreciation, depletion and amortization 118,735 84,438 34,297
Taxes, other than income taxes 23,121 22,335 786
Accretion expense       1,953         1,771         182  
 
Total operating expenses       317,880         256,507         61,373  
 
Operating Income       115,166         31,641         83,525  
 
Other Income (Expense)
Interest expense (17,098 ) (13,979 ) (3,119 )
Other income 708 1,706 (998 )
Other expense       (598 )       (106 )       (492 )
 
Total other expense       (16,988 )       (12,379 )       (4,609 )
 
Income Before Income Taxes 98,178 19,262 78,916
Income tax expense       35,355         4,830         30,525  
 
Net Income     $ 62,823       $ 14,432       $ 48,391  
 
Diluted Earnings Per Average Common Share     $ 0.87       $ 0.20       $ 0.67  
 
Basic Earnings Per Average Common Share     $ 0.87       $ 0.20       $ 0.67  
 
Diluted Avg. Common Shares Outstanding       72,319         72,269         50  
 
Basic Avg. Common Shares Outstanding       72,138         72,082         56  
 
Dividends Per Common Share     $ 0.14       $ 0.135       $ 0.005  
 
 
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) For the 12 months ending December 31, 2012 and 2011
   
    Year-to-date    
   
( in thousands, except per share data)     2012     2011     Change
 
Operating Revenues
Oil and gas operations $ 1,165,580 $ 948,526 $ 217,054
Natural gas distribution       451,589         534,953         (83,364 )
 
Total operating revenues       1,617,169         1,483,479         133,690  
 
Operating Expenses
Cost of gas 142,228 233,523 (91,295 )
Operations and maintenance 477,883 419,119 58,764
Depreciation, depletion and amortization 419,598 283,997 135,601
Asset impairment 21,545

21,545
Taxes, other than income taxes 88,989 91,734 (2,745 )
Accretion expense       7,534         6,837         697  
 
Total operating expenses       1,157,777         1,035,210         122,567  
 
Operating Income       459,392         448,269         11,123  
 
Other Income (Expense)
Interest expense (65,556 ) (44,822 ) (20,734 )
Other income 4,448 2,334 2,114
Other expense       (903 )       (456 )       (447 )
 
Total other expense       (62,011 )       (42,944 )       (19,067 )
 
Income Before Income Taxes 397,381 405,325 (7,944 )
Income tax expense       143,819         145,701         (1,882 )
 
Net Income     $ 253,562       $ 259,624       $ (6,062 )
 
Diluted Earnings Per Average Common Share     $ 3.51       $ 3.59       $ (0.08 )
 
Basic Earnings Per Average Common Share     $ 3.52       $ 3.60       $ (0.08 )
 
Diluted Avg. Common Shares Outstanding       72,316         72,332         (16 )
 
Basic Avg. Common Shares Outstanding       72,119         72,056         63  
 
Dividends Per Common Share     $ 0.56       $ 0.54       $ 0.02  
 
 

CONSOLIDATED BALANCE SHEETS (UNAUDITED) As of December 31, 2012 and December 31, 2011
 
           
(in thousands)     December 31, 2012     December 31, 2011
   
ASSETS
Current Assets
Cash and cash equivalents $ 17,014 $ 9,541
Accounts receivable, net of allowance 282,405 231,925
Inventories 63,994 74,012
Regulatory asset 45,515 57,143
Other       28,007       71,547
 
Total current assets       436,935       444,168
 
Property, Plant and Equipment
Oil and gas properties, net 4,673,886 3,783,842
Utility plant, net 842,643 813,428
Other property, net       25,107       23,506
 
Total property, plant and equipment, net       5,541,636       4,620,776
 
Other Assets
Regulatory asset 110,566 95,633
Long-term derivative instruments 40,577 31,056
Other       53,486       45,783
 
Total other assets       204,629       172,472
 
TOTAL ASSETS     $ 6,183,200     $ 5,237,416
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year $ 50,000 $ 1,000
Notes payable to banks 643,000 15,000
Accounts payable 264,889 302,048
Regulatory liability 45,116 58,279
Other       164,087       167,552
 
Total current liabilities       1,167,092       543,879
 
Long-term debt       1,103,528       1,153,700
 
Deferred Credits and Other Liabilities
Regulatory liability 80,404

87,234
Deferred income taxes 905,601 806,127
Long-term derivative instruments 11,305 34,663
Other       238,580       179,650
 
Total deferred credits and other liabilities       1,235,890       1,107,674
 
Total Shareholders’ Equity       2,676,690       2,432,163
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY     $ 6,183,200     $ 5,237,416
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 3 months ending December 31, 2012 and 2011
 
    4th Quarter    
   
( in thousands, except sales price data)     2012     2011     Change
 
Oil and Gas Operations (GAAP)
Operating revenues
Natural gas $ 77,608 $ 96,654 $ (19,046 )
Oil 211,067 47,490 163,577
Natural gas liquids 20,968 23,975 (3,007 )
Other       (1,003 )       573       (1,576 )
 
Total (GAAP)     $ 308,640       $ 168,692     $ 139,948  
 

Oil and Gas Operations excluding mark-to-market (Non-GAAP)
Operating revenues
Natural gas $ 74,002 $ 96,654 $ (22,652 )
Oil 188,636 138,093 50,543
Natural gas liquids 22,290 24,184 (1,894 )
Other       (1,003 )       573       (1,576 )
 
Total (Non-GAAP)*     $ 283,925       $ 259,504     $ 24,421  
 
Production volumes
Natural gas (MMcf) 19,110 18,810 300
Oil (MBbl) 2,339 1,744 595
Natural gas liquids (MMgal) 29.1 24.8 4.3
 
Total production volumes (MMcfe) 37,296 32,820 4,476
Total production volumes (MBOE) 6,216 5,470 746
 
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf) $ 3.87 $ 5.14 $ (1.27 )
Oil (barrel) $ 80.65 $ 78.52 $ 2.13
Natural gas liquids (gallon) $ 0.77 $ 0.97 $ (0.20 )
 

Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf) $ 3.27 $ 3.45 $ (0.18 )
Oil (barrel) $ 81.09 $ 90.89 $ (9.80 )
Natural gas liquids (gallon) $ 0.68 $ 1.14 $ (0.46 )
 
Other data
Lease operating expense (LOE)
LOE and other $ 71,375 $ 49,874 $ 21,501
Production taxes       14,442         14,109       333  
 
Total     $ 85,817       $ 63,983     $ 21,834  
 
Depreciation, depletion and amortization $ 108,016 $ 74,128 $ 33,888
General and administrative expense $ 14,453 $ 16,973 $ (2,520 )
Capital expenditures $ 333,298 $ 448,851 $ 115,553
Exploration expenditures $ 5,976 $ 514 $ 5,462
Operating income     $ 92,425       $ 11,323     $ 81,102  
 

*Operating revenues excluding mark-to-market gains of $24,715 and losses of $90,812 in fourth quarter 2012 and 2011, respectively.
 
Natural Gas Distribution
Operating revenues
Residential $ 76,161 $ 74,157 $ 2,004
Commercial and industrial 30,822 29,186 1,636
Transportation 16,093 14,665 1,428
Other       1,330         1,448       (118 )
 
Total     $ 124,406       $ 119,456     $ 4,950  
 
Gas delivery volumes (MMcf)
Residential 4,413 4,407 6
Commercial and industrial 2,235 2,151 84
Transportation       13,271         10,901       2,370  
 
Total       19,919         17,459       2,460  
 
Other data
Depreciation and amortization $ 10,719 $ 10,310 $ 409
Capital expenditures $ 20,083 $ 16,814 $ 3,269
Operating income     $ 22,951       $ 20,675     $ 2,276  
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED) For the 12 months ending December 31, 2012 and 2011
     
    Year-to-date    
   
( in thousands, except sales price data)     2012     2011     Change
 
Oil and Gas Operations (GAAP)
Operating revenues
Natural gas $ 288,979 $ 386,894 $ (97,915 )
Oil 790,345 467,320 323,025
Natural gas liquids 85,938 87,466 (1,528 )
Other       318         6,846         (6,528 )
 
Total (GAAP)     $ 1,165,580       $ 948,526       $ 217,054  
 

Oil and Gas Operations excluding mark-to-market (Non-GAAP)
Operating revenues
Natural gas $ 289,494 $ 386,894 $ (97,400 )
Oil 731,559 504,793 226,766
Natural gas liquids 85,459 87,580 (2,121 )
Other       318         6,846         (6,528 )
 
Total (Non-GAAP)*     $ 1,106,830       $ 986,113       $ 120,717  
 
Production volumes
Natural gas (MMcf) 76,362 71,718 4,644
Oil (MBbl) 8,766 6,318 2,448
Natural gas liquids (MMgal) 108.1 91.4 16.7
 
Total production volumes (MMcfe) 144,396 122,688 21,708
Total production volumes (MBOE) 24,066 20,448 3,618
 
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf) $ 3.79 $ 5.39 $ (1.60 )
Oil (barrel) $ 83.45 $ 79.72 $ 3.73
Natural gas liquids (gallon) $ 0.79 $ 0.96 $ (0.17 )
 

Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf) $ 2.71 $ 3.93 $ (1.22 )
Oil (barrel) $ 87.56 $ 90.53 $ (2.97 )
Natural gas liquids (gallon) $ 0.75 $ 1.11 $ (0.36 )
 
Other data
Lease operating expense (LOE)
LOE and other $ 250,497 $ 202,094 $ 48,403
Production taxes       55,878         54,951         927  
 
Total     $ 306,375       $ 257,045       $ 49,330  
 
Depreciation, depletion and amortization $ 377,328 $ 244,081 $ 133,247
Asset impairment $ 21,545

$

$ 21,545
General and administrative expense $ 66,192 $ 64,322 $ 1,870
Capital expenditures $ 1,291,211 $ 1,115,452 $ 175,759
Exploration expenditures $ 19,363 $ 13,110 $ 6,253
Operating income     $ 367,243       $ 363,131       $ 4,112  
 

*Operating revenues excluding mark-to-market gains of $58,750 and losses of $37,587 in 2012 and 2011, respectively.
 
Natural Gas Distribution
Operating revenues
Residential $ 277,698 $ 343,740 $ (66,042 )
Commercial and industrial 115,711 136,469 (20,758 )
Transportation 58,857 55,234 3,623
Other       (677 )       (490 )       (187 )
 
Total     $ 451,589       $ 534,953       $ (83,364 )
 
Gas delivery volumes (MMcf)
Residential 16,014 21,132 (5,118 )
Commercial and industrial 8,372 9,994 (1,622 )
Transportation       48,106         44,614         3,492  
 
Total       72,492         75,740         (3,248 )
 
Other data
Depreciation and amortization $ 42,270 $ 39,916 $ 2,354
Capital expenditures $ 71,869 $ 73,984 $ (2,115 )
Operating income     $ 93,216       $ 86,216       $ 7,000  
 

Copyright Business Wire 2010