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New Energen Wells with Generation 3 Fracs Significantly Outperforming
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New Gen 3 Wells Drive 5% Production Beat in 1Q17; Oil Production Outpaces Guidance by 6%

Energen Adds >6,900 Net Lease Acres to Permian Basin Footprint through YTD Bolt-On Acquisitions

FINANCIAL AND OPERATING HIGHLIGHTS

1Q17

  • Driven by performance of new wells with Generation 3 fracs, 1Q17 production increases 5% to 52.8 mboepd
  • 1Q17 oil production outpaces guidance by 6%
  • Delaware Basin production exceeds guidance by 13%
  • Per-unit net SG&A outperformed midpoint of guidance range by 16%
  • 1Q17 adjusted EBITDAX exceeds internal expectations by 15%
  • Latest bolt-on acquisitions bring total for first four months of 2017 to 6,923 net lease acres for ≈$147 mm

WELL RESULTS

  • Average cumulative production of wells completed with Generation 3 fracs outperforming across the board
  • 5 new Wolfcamp A/B wells in Glasscock County with 75 days of production history completed in 1Q17
  • Average cumulative production ≈15% above the high-end, 1.3 MMBOE EUR type curve for a 10,000’ lateral (77% oil)
  • Average 24-hour IP of 1,684 boepd (74% oil) and peak 30-day average of 1,465 boepd (74% oil); average completed lateral length 9,541’
  • 2 new Wolfcamp A/B wells with 80 days of production history completed in Delaware Basin in 1Q17
  • Average cumulative production ≈80% above the high-end, 2.0 MMBOE EUR type curve for a 10,000’ lateral (61% oil)
  • Average 24-hour IP of 2,033 boepd (62% oil) and peak 30-day average of 1,825 boepd (60% oil); average completed lateral length 4,654’

CY17 UPDATE

  • $60-$65 mm increase in CY17 estimated drilling and development capital associated with additional operated completions and non-op new drills, increased operated working interests and facilities
  • Operated horizontal projects in 2017 include drilling 77 net wells, completing 115 net wells (including 60 net DUCs), and ending the year with 22 net DUCs
  • Non-operated projects include additional 12 gross (2.8 net) wells for total of 26 gross (4 net) wells

NOTE: 1Q17 supplemental slides available at www.energen.com

BIRMINGHAM, Ala.--(BUSINESS WIRE)--May 4, 2017-- For the 3 months ended March 31, 2017, Energen Corporation (NYSE: EGN) reported GAAP net income from all operations of $33.4 million, or $0.34 per diluted share. Adjusting for a non-cash gain on mark-to-market derivatives and a small non-cash impairment loss, Energen had an adjusted loss in 1Q17 of $(12.4 million), or $(0.13) per diluted share. This compares with an adjusted loss in 1Q16 of $(53.6 million), or $(0.62) per diluted share. [See “Non-GAAP Financial Measures” beginning on pp 10 for more information and reconciliation.]

Reconciliation of Consolidated GAAP Net Income to Adjusted Income from Continuing Operations
[See “Non-GAAP Financial Measures” beginning on pp 10 for more information]

 
        1Q17     1Q16
        $M     $/dil. sh.     $M     $/dil. sh.
Net Income/(Loss) All Operations (GAAP)       $ 33,403       $ 0.34       $ (203,116 )     $ (2.34 )
Less: Non-cash mark-to-market gains/(losses)         46,692         0.48         (166 )     nm  
Less: Asset impairments         (939 )       (0.01 )       (121,420 )       (1.40 )
Less: Pension settlement and other expenses         --         --         (4,801 )       (0.06 )
Less: Income/(loss) associated with asset sales         --         --         (23,132 )       (0.27 )
Adj. Income Continuing Operations (Non-GAAP)       $ (12,350 )     $ (0.13 )     $ (53,597 )     $ (0.62 )

Note: Per share amounts may not sum due to rounding


Energen’s adjusted 1Q17 per-share loss was less than internal expectations by $3.8 million, or $0.04 per diluted share, largely due to above-budget production and lower-than-expected net salaries and general and administrative expense (SG&A), partially offset by increased depreciation, depletion, and amortization expense (DD&A) largely due to increased volumes and to the timing of exploration expense.

Production in 1Q17 totaled 52.8 thousand barrels of oil equivalents per day (mboepd) and exceeded guidance of 50.2 mboepd by 5.2 percent mainly due to the impact of new wells completed with Generation 3 fracs. Total oil production was up 6 percent over guidance largely due to stronger-than-expected oil volumes in the Delaware Basin. Net SG&A expenses were lower due to a variety of cost reductions, including non-cash compensation and legal services.

Energen’s adjusted EBITDAX totaled $95.6 million in the 1st quarter of 2017 and exceeded internal expectations by approximately 15 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $44.0 million. [See “Non-GAAP Financial Measures” beginning on pp 10 for more information and reconciliation.]

Comments from the Chairman

“We are very encouraged by the performance of the wells we have completed with our Generation 3 frac design,” said James McManus, Energen’s chairman and chief executive officer. “For those Gen 3 wells with at least 75 days of production history, cumulative production by formation is outperforming the type curves associated with the highest potential EURs we have identified.

“Since our ranges of EUR outcomes are based on the performance of pre-Gen 3 wells, one of our major goals for Gen 3 fracs is to achieve well results that meet or surpass the high end of these ranges. We are very excited to see that early results are doing just that.”

1st Quarter 2017 Results

Production (excludes asset sales) (mboepd)

       
Commodity       1Q17 1Q16
      Actual     Guidance     % Change
Oil       33.3     31.4     6   33.6
NGL       8.9     9.1     (2 ) 8.3
Natural Gas       10.6     9.7     10   10.4
Total       52.8     50.2     5   52.3
       
Area       1Q17 1Q16
      Actual     Guidance     % Change
Midland Basin       31.8     30.6     4 33.0
Delaware Basin       12.8     11.3     13 10.3
Central Basin/Other       8.3     8.3     -- 9.0
Total       52.8     50.2     5 52.3

Note: Totals in production tables above may not sum due to rounding.



Average Realized Sales Prices (excludes asset sales)

 
Commodity       1Q17     1Q16     % Change
Oil (per barrel)       $ 46.95     $ 32.34     45
NGL (per gallon)       $ 0.42     $ 0.22     91
Natural Gas (per mcf)       $ 2.39     $ 1.66     44
             
 
 

Average Prices before Effects of Hedges (excludes asset sales)

 
Commodity       1Q17     1Q16     % Change
Oil (per barrel)       $ 48.96     $ 30.67     60
NGL (per gallon)       $ 0.46     $ 0.22     109
Natural Gas (per mcf)       $ 2.46     $ 1.55     59
             
 
 

Expenses (excludes asset sales)

       
Per BOE, except where noted       1Q17 1Q16
      Actual     Guidance Mdpt.
LOE*       $ 8.68       $ 9.25   $ 8.43  

Production & ad valorem taxes**

        7.3 %       7.5 %   8.8 %
DD&A       $ 20.71       $ 20.95   $ 23.15  
Net SG&A       $ 4.29       $ 5.10   $ 4.52  
Exploration††       $ 0.76       $ 0.35   $ 0.03  
Interest ($mm)       $ 9.0       $ $8.9   $ 9.8  

* Production costs, marketing & transportation
** % of revenues, excluding hedges
Excludes $1.56 per BOE in 1Q16 for pension settlement and other expenses
†† Includes seismic, delay rentals, etc.



Operations Update

During the first quarter, Energen turned to production 10 gross (9 net) wells drilled in Glasscock County in the central Midland Basin and 2 gross (2 net) wells in the Delaware Basin. All 12 of these wells were part of Energen’s DUC inventory at YE16. The company set casing on 19 gross (17 net) wells in the first quarter. The company operated an average of 6.5 horizontal drilling rigs in the first quarter and an average of 6 frac crews.

Drilling efficiencies continued in the first quarter, with two new “internal best times” for days to drill from spud to total depth. In only 15 days, Energen drilled a 9,856-foot lateral Wolfcamp B well in the northern Midland Basin; and in just under 15 days, the company drilled a 10,733-foot lateral Middle Spraberry well.

Positive Response to Early Generation 3 Completions

For those Gen 3 wells with at least 75 days of production history, the average cumulative production by formation outperformed the type curves associated with the highest potential EURs identified by the company. Because the ranges of EURs are based on the performance of pre-Gen 3 wells, the company hopes to achieve Gen 3 well results that meet or surpass the high end of these ranges.

Energen’s first two Midland Basin wells utilizing a Generation 3 frac design (the “Tiger Unit” wells) -- continued to respond very well. The average cumulative production of the two Wolfcamp B, stand-alone wells in Martin County exceeded the 1 mmboe type curve for a 7,500-lateral by an average of approximately 20 percent through 165 days. Oil comprised 82 percent of the product mix.

At 75 days of production, five new Glasscock County completions were approximately 15 percent above the 1.3 mmboe EUR type curve for a 10,000’ lateral. Oil comprised 77 percent of the product mix. The company considers this a particularly attractive result since four of the wells are producing from the Wolfcamp B; the fifth well is producing from the Wolfcamp A. The five wells had an average 24-hour IP of 1,684 boepd (74% oil) and peak 30-day average of 1,465 boepd (74% oil); their average completed lateral length was 9,541’.

Cumulative production from the Checkers St. 54-12-21 701H well in the Delaware Basin continued to outperform the 2.0 mmboe EUR type curve for a 10,000’ lateral length by 6 percent through 195 days. The Checkers St. well is producing from the Wolfcamp B interval in Reeves County. Oil comprised 55 percent of the product mix.

The two Delaware Basin wells placed on production in the first quarter were 4,600 foot laterals; normalized to 10,000 feet, these two wells averaged 80 percent above the 2.0 mmboe EUR type curve for a 10,000’ lateral through 80 days. Oil comprised 61 percent of the product mix. The two Delaware Basin wells had an average 24-hour IP of 2,033 boepd (62% oil) and peak 30-day average of 1,825 boepd (60% oil); their average completed lateral length was 4,654’.

2017 Capital and Operating Overview

Energen estimates that it will invest an additional $60-$65 million in 2017 for 4 more gross completions and to participate in an additional 2.8 net non-operated wells, for increased working interests, and for facilities. Since the end of 1Q17, Energen has seen rising pressure on the costs of a wide variety of completion services; without off-setting efficiencies or other savings, the company estimates that it could see capital spending for drilling and development increase another $45-$50 million.

The company’s revised capital budget of $850-$900 million for drilling and development activities supports completion of 128 gross/118 net operated wells, including 124 gross/115 net horizontal wells. All horizontal wells are scheduled to be completed with a Generation 3 frac design.

Horizontal completions include 61 gross/60 net wells drilled but not completed (DUC) at year-end 2016 and 63 gross/55 net horizontal wells that are scheduled to be drilled and completed in 2017 with the company’s 6- to 7-rig drilling program. Another 24 gross/22 net horizontal wells are set to be drilled and awaiting completion at year end. Energen also plans to drill 7 gross/6 net vertical wells in the Midland Basin and complete 4 gross/3 net of them.

Energen’s non-operated opportunities have increased, and the company has agreed to participate in a total of 4 net wells. Such opportunities are difficult to predict and, therefore, are not budgeted until the company has visibility on an operator’s plans.

 
2017 Operated Horizontal Program       Gross/Net Wells     Avg. Lateral Length     Average WI
Midland Basin                    
YE16 DUC Completions       44/43     9,600’     98%
New Drills       54/46     8,330’     84%
New Drill Completions       39/32            
YE17 DUCs       15/14            
                     
Delaware Basin                    
YE16 DUC Completions       17/17     8,765’     98%
New Drills       33/31     8,410’     95%
New Drill Completions       24/23            
YE17 DUCs       9/8            

Note: In addition to the above, Energen plans to drill 7 gross/6 net vertical wells in the Midland Basin and complete 4 gross/3 net of them.



Acquisitions/Unproved Leasehold

In the first four months of 2017, Energen acquired a total of 6,923 net lease acres, primarily in the Delaware Basin, for approximately $147 million; the company also has purchased 690 net mineral acres in the Delaware Basin for approximately $20 million. The company does not budget for acquisitions.

 
Capital Summary by Basin       2017e Capital ($MM)
Midland Basin       $ 470 - 500
Delaware Basin       $ 375 - 395
Central Basin, ARO, Other       $ 5
Drilling & Development Capital       $ 850 - 900
Acquisitions/Unproved Leasehold       $ 167
Total Capital Expenditures       $ 1,017 - 1,067



Liquidity Update

As of March 31, 2017, Energen had cash of $88.7 million and debt of $544.6 million; the company had nothing drawn on its $1.05 billion line of credit, and its borrowing base currently is $1.4 billion. Energen estimates that its total net debt-to-2017 adjusted EBITDAX will range from 1.2x - 1.3x.

CY17 Guidance

Production (mboepd)

       
Guidance by Basin     1Q17a     2Q17e     3Q17e     4Q17e CY17e
Midland Basin     31.8     34.2     38.6     42.3 36.8
Delaware Basin     12.8     19.8     24.6     28.4 21.4
Central Basin Platform/Other     8.3     8.2     8.1     7.9 8.1
Total     52.8     62.2     71.3     78.6 66.3
       
Guidance by Commodity     1Q17a     2Q17e     3Q17e     4Q17e CY17e
Oil     33.3     40.6     46.6     52.1 43.2
NGL     8.9     10.5     11.9     12.8 11.0
Gas     10.6     11.1     12.8     13.7 12.1
Total     52.8     62.2     71.3     78.6 66.3

Note: Totals in production tables above may not sum due to rounding.



Estimated 2017 production of 66.3 mboepd reflects a 1 percent increase over prior guidance as a result of 1Q17 actual results. Production guidance for the remainder of the year is unchanged and reflects estimated production with Generation 2 fracs. Given that all wells completed in 2017 will use the Generation 3 frac design, if the associated production response continues to be positive, year-over-year production growth could be higher than the current estimate of 21 percent. Oil is expected to comprise 65 percent of the company’s total production mix in 2017, with natural gas liquids (NGL) and natural gas production estimated to make up 17 percent and 18 percent, respectively.

Operating Expenses

       
Per BOE, except where noted       1Q17a     2Q17e     3Q17e     4Q17e CY17e
LOE*       $8.68     $8.10-$8.40     $7.35-$7.65     $6.90-$7.20 $7.60-$8.00
Production & ad valorem taxes**       7.3%     6.9%     6.6%     6.5% 6.8%
DD&A expense†       $20.71     $17.95-$18.35     $17.20-$17.60     $15.50-$15.90 $17.50-$17.90
SG&A, net       $4.29     $3.70-$4.00     $3.10-$3.40     $2.70-$3.00 $3.25-$3.65
Exploration††       $0.76     $0.20-$0.30     $0.30-$0.40     $0.05-$0.15 $0.30-$0.40
Interest ($mm)       $9.0     $9.0-$9.4     $9.3-$9.7     $9.5-$9.9 $37.0-$38.0
Effective tax rate       32%     37%-39%     36%-38%     35%-37% 36%-38%

* Production costs, marketing & transportation
** % of revenues, excluding hedges
4Q17 and CY17 does not include estimate of 4Q17 DD&A look-back adjustment
†† Includes seismic, delay rentals, etc.

LOE per boe in CY17 is estimated to range $5.65-$5.95 in the Delaware Basin, $6.25-$6.55 in the Midland Basin, and $19.50-$19.80 in the Central Basin Platform. Production and ad valorem taxes in CY17, as a percent of revenues excluding hedges, are estimated to be 6.1 percent in the Delaware Basin, 6.9 percent in the Midland Basin, and 7.8 percent in the Central Basin Platform.

Net SG&A per boe in CY17 is estimated to be comprised of cash compensation of $2.60-$2.80 per boe and non-cash, equity-based compensation of $0.65-$0.85 per boe.

Hedges

For the remaining 9 months of 2017, approximately 68 percent of the company’s estimated oil production of 12.8 MMBOE is hedged as well as 46 percent of its estimated NGL production and 59 percent of its natural gas production. Hedges also are in place that limit the company’s exposure to the Midland to Cushing oil differential. Energen has hedged the WTI Midland to WTI Cushing (sweet oil) differential for 7.6 million barrels at an average price of $(0.64) per barrel. Energen estimates that approximately 86 percent of its oil production for the remainder of the year will be sweet.

Energen’s total oil hedge position for the remainder of 2017 is as follows:

 
Oil     2017 Hedge Volumes     Avg. NYMEX Price
Swaps     5.0 mmbo     $ 50.13 per barrel

Three way Collars¹

    3.6 mmbo      
Call Price           $ 62.18 per barrel
Put Price           $ 45.00 per barrel
Short Put Price           $ 35.00 per barrel

¹ When the NYMEX price is above the call price, Energen receives the call price; when the NYMEX price is between the call price and the put price, Energen receives the NYMEX price; when the NYMEX price is between the put price and the short put price, Energen receives the put price; and when the NYMEX price is below the short put price, Energen receives the NYMEX price plus the difference between the put price and the short put price.




Energen’s total natural gas and NGL hedge positions for the remainder of 2017 are as follows:

 
Commodity     Hedge Volumes     Production Guidance     % Hedged     Avg. NYMEXe Price
NGL     62.4 mm gallons     135.6 mm gallons     46%     $ 0.57 per gallon
Natural gas     12.3 bcf     20.7 bcf     59%     $ 3.28 per Mcf

Note: Includes known actuals




2Q17 Hedges

Energen’s total oil hedge position for 2Q17 is as follows:

 
Oil     2Q17 Hedge Volumes     Avg. NYMEX Price
Swaps     1.0 mmbo     $ 47.97 per barrel
Three way Collars     1.2 mmbo      
Call Price           $ 62.18 per barrel
Put Price           $ 45.00 per barrel
Short Put Price           $ 35.00 per barrel
       
 

Energen’s total natural gas and NGL hedge positions for 2Q17 as follows:

                         
Commodity     Hedge Volumes     Production Guidance     Hedge %     NYMEXe Price
NGL     20.8 mm gallons     40.0 mm gallons     52%     $ 0.57 per gallon
Natural Gas     3.6 bcf     6.1 bcf     59%     $ 3.31 per mcf

Note: Includes known actuals


Energen also has hedged the Midland to Cushing differential on 2.0 million barrels (approximately 66 percent) of its estimated 2Q17 sweet oil production at an average price of $(0.58).


Basis Differentials and Sensitivities

The company’s average realized prices will reflect commodity and basis hedges; oil transportation charges of approximately $2.00 per barrel in the last nine months of CY17 ($2.03 per barrel in 2Q17), NGL transportation and fractionation fees of approximately $0.13 per gallon for the remainder of the year ($0.13 per gallon in 2Q17), and gas and oil basis differentials applicable to unhedged production. In addition, natural gas and NGL production is subject to a percent of proceeds contract of approximately 85%.

The assumed gas basis for all open contracts for the remainder of 2017 is $(0.40) per Mcf, and assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil are $(1.30) and $(1.85), respectively. Energen’s assumed commodity prices for unhedged production for the last nine months of 2017 are: $52.00 per barrel of oil, $0.60 per gallon of NGL, and $3.30 per Mcf of gas (May-December).

Estimated Price Realizations (pre-hedge):

 
      2Q17     ROY 2017
Crude oil (% of NYMEX/WTI)     93     93
NGL (after T&F) (% of NYMEX/WTI)     32     33
Natural gas (% of NYMEX/Henry Hub)     74     76
       
 

2018 Hedges

Energen’s total oil hedge position for 2018 is as follows:

             
Oil     2018 Hedge Volumes     Avg. NYMEX Price
Three way Collars     7.4 mmbo      
Call Price           $ 63.85 per barrel
Put Price           $ 50.00 per barrel
Short Put Price           $ 40.00 per barrel
       
 

Energen’s total natural gas and NGL hedge positions for 2018 as follows:

 
Commodity     Hedge Volumes     NYMEXe Price
NGL     105.8 mm gallons     $ 0.59 per gallon
Natural Gas     3.6 bcf     $ 3.06 per mcf
       
 
 

Supplemental Slides and Conference Call

1Q17 supplemental slides associated with Energen’s quarterly release and conference call are available at www.energen.com. Energen will hold its quarterly conference call Friday, May 5, at 11:00 a.m. EDT. Investment community members may participate by calling 1-877-407-8289 (reference Energen earnings call). A live audio Webcast of the program as well as a replay may be accessed via www.energen.com.

Energen Corporation is an oil-focused exploration and production company with operations in the Permian Basin in west Texas and New Mexico. For more information, go to www.energen.com.

FORWARD LOOKING STATEMENTS: All statements, other than statements of historical fact, appearing in this release constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to the timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, the nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, the timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. Forward-looking statements may include words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “foresee,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “seek,” “will” or other words or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this news release. Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. We base our forward-looking statements on information currently available to us, and we undertake no obligation to correct or update these statements whether as a result of new information, future events or otherwise. Additional information regarding our forward‐looking statements and related risks and uncertainties that could affect future results of Energen, can be found in the Company’s periodic reports filed with the Securities and Exchange Commission and available on the Company’s website - www.energen.com.

CAUTIONARY STATEMENTS: The SEC permits oil and gas companies to disclose in SEC filings only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. Outside of SEC filings, we use the terms “estimated ultimate recovery” or “EUR,” reserve or resource “potential,” “contingent resources” and other descriptions of volumes of non-proved reserves or resources potentially recoverable through additional drilling or recovery techniques. These estimates are inherently more speculative than estimates of proved reserves and are subject to substantially greater risk of actually being realized. We have not risked EUR estimates, potential drilling locations, and resource potential estimates. Actual locations drilled and quantities that may be ultimately recovered may differ substantially from estimates. We make no commitment to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of our on-going drilling program, which will be directly affected by the availability of capital, drilling, and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approvals, and geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per-well EURs, and resource potential may change significantly as development of our oil and gas assets provides additional data. Additionally, initial production rates contained in this news release are subject to decline over time and should not be regarded as reflective of sustained production levels.

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 the effects of certain non-cash mark-to-market derivative financial instruments. Adjusted income from continuing operations further excludes impairment losses, certain prior period pension settlement expenses and losses associated with a reduction in force, and income associated with divestitures. Energen believes that excluding the impact of these items is more useful to analysts and investors in comparing the results of operations and operational trends between reporting periods and relative to other oil and gas producing companies.

       
Three Months Ended 3/31/17
Energen Net Income ($ in millions except per share data)     Net Income  

Per Diluted

Share

Net Income (Loss) All Operations (GAAP) 33.4   0.34
Non-cash mark-to-market gains (net of $25.7 tax) (46.7 ) (0.48 )
Asset impairment, other (net of $0.5 tax)     0.9     0.01  
Adjusted Income from Continuing Operations (Non-GAAP)     (12.4 )   (0.13 )
 
   
Three Months Ended 3/31/16
Energen Net Income ($ in millions except per share data)     Net Income  

Per Diluted

Share

Net Income (Loss) All Operations (GAAP) (203.1 ) (2.34 )
Non-cash mark-to-market losses (net of $0.1 tax) 0.2 nm
Asset impairment, other (net of $67.2 tax) 121.4 1.40
Pension settlement and other expenses (net of $2.6 tax) 4.8 0.06
Loss associated with property sales (net of $13.1 tax)     23.1     0.27  
Adjusted Income from Continuing Operations (Non-GAAP)     (53.6 )   (0.62 )
 
 
Note: Amounts may not sum due to rounding
 
 
 
 
 
 

Non-GAAP Financial Measures

 

Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (EBITDAX) is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles).  Adjusted EBITDAX from continuing operations further excludes impairment losses, certain non-cash mark-to-market derivative financial instruments,  prior period pension settlement expenses and losses associated with a reduction in force, and losses associated with  divestitures.  Energen believes these measures allow analysts and investors to understand the financial performance of the company from core business operations, without including the effects of capital structure, tax rates and depreciation. Further, this measure is useful in comparing the company and other oil and gas producing companies.

     
Reconciliation To GAAP Information Three Months Ended 3/31
($ in millions)     2017   2016
 
Energen Net Income (Loss) (GAAP) 33.4 (203.1 )
Loss associated with property sales, net of tax     0.0     23.1  
Net Income (Loss) Excluding Property Sales (Non-GAAP)     33.4     (180.0 )
Interest expense 9.0 9.8
Income tax expense (benefit) * 19.4 (95.3 )
Depreciation, depletion and amortization * 99.7 111.5
Accretion expense * 1.4 1.5
Exploration expense * 3.6 0.2
Adjustment for asset impairment * 1.5 188.6
Adjustment for mark-to-market (gains)/ losses (72.4 ) 0.3
Adjustment for pension settlement and other expenses     0.0     7.4  
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)     95.6     44.0  
 
 
Note: Amounts may not sum due to rounding
 
* Amount adjusted to exclude property sales in prior period. See reconciliation to GAAP Information for the Three Months Ended 3/31/16.
 
 
 
 
 
 

Non-GAAP Financial Measures

 

The consolidated statement of income excluding certain divestments is a Non-GAAP financial measure (GAAP refers to generally accepted accounting principles).  Energen believes excluding information associated with divestitures provides analysts and investors useful information to understand the financial performance of the company from ongoing business operations.  Further, this information is useful in comparing the company and other oil and gas producing companies operating primarily in the Permian Basin.

 
Energen Net Income (Loss) Excluding Property Sales

Reconciliation to GAAP Information

   

Three Months Ended

March 31, 2016
(in thousands except per share and production data)  
GAAP   $/BOE   Property Sales   Non-GAAP   $/BOE
Revenues        
Oil, natural gas liquids and natural gas sales $ 122,764 $ 13,178 $ 109,586
Gain (loss) on derivative instruments       5,455           -       5,455      
Total Revenues       128,219           13,178       115,041      
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 47,727 $ 8.55 7,613 40,114 $ 8.43
Production and ad valorem taxes 11,170 $ 2.00 1,523 9,647 $ 2.03
O&G Depreciation, depletion and amortization 118,020 $ 21.15 7,783 110,237 $ 23.15
FF&E Depreciation, depletion and amortization 1,342 $ 0.24 82 1,260 $ 0.26
Asset impairment 220,025 31,407 188,618
Exploration 242 $ 0.04 79 163 $ 0.03
General and administrative † 29,525 $ 5.29 565 28,960 $ 6.08
Accretion of discount on asset retirement obligations 1,757 252 1,505
(Gain) loss on sale of assets and other       222           143       79      
Total costs and expenses       430,030           49,447       380,583      
Operating Income (Loss)       (301,811 )         (36,269 )     (265,542 )    
Other Income/(Expense)
Interest expense (9,833 ) - (9,833 )
Other income       95           38       57      
Total other expense       (9,738 )         38       (9,776 )    
 
Loss Before Income Taxes (311,549 ) (36,231 ) (275,318 )
Income tax expense (benefit)       (108,433 )         (13,099 )     (95,334 )    
Net Income (Loss)     $ (203,116 )       $ (23,132 )   $ (179,984 )    
                       
Diluted Earnings Per Average Common Share     $ (2.34 )       $ -     $ (2.34 )    
                       
Basic earning Per Average Common Share     $ (2.34 )       $ -     $ (2.34 )    
 
Oil 3,386 328 3,058
NGL 953 197 756
Natural Gas       1,241           294       947      
Total Production (mboe)       5,580           819       4,761      
Total Production (boepd)       61,319           9,000       52,319      
 
Note: Amounts may not sum due to rounding
 

† General and administrative includes $7,443 or $1.56 per BOE of pension settlement expense and expense related to a reduction in force.

 

 
 
 
 
 
 

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
For the 3 months ending March 31, 2017 and 2016

 
      1st Quarter    
   
(in thousands, except per share data)       2017     2016     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 176,375 $ 122,764 $ 53,611
Gain on derivative instruments, net         64,546         5,455         59,091  
 
Total revenues         240,921         128,219         112,702  
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 41,288 47,727 (6,439 )
Production and ad valorem taxes 12,820 11,170 1,650
Depreciation, depletion and amortization 99,652 119,362 (19,710 )
Asset impairment 1,460 220,025 (218,565 )
Exploration 3,636 242 3,394
General and administrative (including non-cash stock based compensation of $3,197 and $2,471 for the three months ended March 31, 2017, and 2016, respectively)

 

 

20,399

 

 

29,525

 

 

(9,126

 

 

)

Accretion of discount on asset retirement obligations 1,414 1,757 (343 )
(Gain) loss on sale of assets and other         (1,175 )       222         (1,397 )
 
Total operating costs and expenses         179,494         430,030         (250,536 )
 
Operating Income (Loss)         61,427         (301,811 )       363,238  
 
Other Income (Expense)
Interest expense (8,966 ) (9,833 ) 867
Other income         383         95         288  
 
Total other expense         (8,583 )       (9,738 )       1,155  
 
Income (Loss) Before Income Taxes 52,844 (311,549 ) 364,393
Income tax expense (benefit)         19,441         (108,433 )       127,874  
 
Net Income (Loss)       $ 33,403       $ (203,116 )     $ 236,519  
                           
Diluted Earnings Per Average Common Share       $ 0.34       $ (2.34 )     $ 2.68  
Basic Earnings Per Average Common Share       $ 0.34       $ (2.34 )     $ 2.68  
Diluted Average Common Shares Outstanding         97,607         86,632         10,975  
Basic Average Common Shares Outstanding         97,140         86,632         10,508  

 
 
 
 
 
 

CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of March 31, 2017 and December 31, 2016

 

(in thousands)       March 31, 2017     December 31, 2016
         
ASSETS
Current Assets
Cash and cash equivalents $ 88,658 $ 386,093
Accounts receivable, net 90,100 73,322
Inventories, net 15,365 14,222
Derivative instruments 7,594 50
Income tax receivable 26,246 27,153
Prepayments and other         5,024       5,071
 
Total current assets         232,987       505,911
 
Property, Plant and Equipment
Oil and natural gas properties, net 4,298,911 4,016,683
Other property and equipment, net         45,606       44,869
 
Total property, plant and equipment, net         4,344,517       4,061,552
 
Other postretirement assets 3,607 3,619
Noncurrent derivative instruments 9,293
Other assets         8,311       8,741
 
TOTAL ASSETS       $ 4,598,715     $ 4,579,823
 

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities
Long-term debt due within one year 17,000 24,000
Accounts payable 79,644 65,031
Accrued taxes 10,153 7,252
Accrued wages and benefits 14,047 25,089
Accrued capital costs 120,825 79,988
Revenue and royalty payable 44,314 51,217
Derivative instruments 8,324 65,467
Other         14,368       20,160
 
Total current liabilities         308,675       338,204
 
Long-term debt 527,557 527,443
Asset retirement obligations 83,256 81,544
Deferred income taxes 516,295 495,888
Noncurrent derivative instruments 3,006
Other long-term liabilities         8,381       13,136
 
Total liabilities         1,444,164       1,459,221
 
Total Shareholders’ Equity         3,154,551       3,120,602
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY       $ 4,598,715    

$

4,579,823

 
 
 
 
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending March 31, 2017 and 2016

 
      1st Quarter    
   
(in thousands, except sales price and per unit data)       2017     2016     Change
 
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil $ 146,670 $ 102,157 $ 44,513
Natural gas liquids 15,634 8,589 7,045
Natural gas         14,071         12,018         2,053  
Total       $ 176,375       $ 122,764       $ 53,611  
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ 58,058 $ (1,699 ) $ 59,757
Natural gas liquids 7,087 7,087
Natural gas         7,224         1,442         5,782  
Total       $ 72,369       $ (257 )     $ 72,626  
 
Closed gains (losses) on derivative instruments
Oil $ (6,010 ) $ 5,094 $ (11,104 )
Natural gas liquids (1,465 ) (1,465 )
Natural gas         (348 )       618         (966 )
Total       $ (7,823 )     $ 5,712       $ (13,535 )
Total revenues       $ 240,921       $ 128,219       $ 112,702  
 
Production volumes
Oil (MBbl) 2,996 3,386 (390 )
Natural gas liquids (MMgal) 33.7 40.0 (6.3 )
Natural gas (MMcf)         5,730         7,446         (1,716 )
Total production volumes (MBOE)         4,754         5,580         (826 )
 

Average daily production volumes Oil (MBbl/d)

33.3

37.2

(3.9

)

Natural gas liquids (MMgal/d) 0.4 0.4
Natural gas (MMcf/d)         63.7         81.8         (18.1 )
Total average daily production volumes (MBOE/d)         52.8         61.3         (8.5 )
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 46.95 $ 31.67 $ 15.28
Natural gas liquids (per gallon) $ 0.42 $ 0.21 $ 0.21
Natural gas (per Mcf) $ 2.39 $ 1.70 $ 0.69
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 48.96 $ 30.17 $ 18.79
Natural gas liquids (per gallon) $ 0.46 $ 0.21 $ 0.25
Natural gas (per Mcf) $ 2.46 $ 1.61 $ 0.85
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

8.68

$

8.56

$

0.12

Production and ad valorem taxes $ 2.70 $ 2.00 $ 0.70
Depreciation, depletion and amortization $ 20.96 $ 21.39 $ (0.43 )
Exploration expense $ 0.76 $ 0.04 $ 0.72
General and administrative $ 4.29 $ 5.29 $ (1.0 )
Capital expenditures (includes acquisitions)       $ 384,135       $ 124,088       $ 260,047  
 
 
 
 

Source: Energen Corporation

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



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