Energen’s New Gen 3 Wells Delivering Outstanding Results in All Key Areas of Permian Operations

2Q17 Production Beats June Revised Guidance On Continued Strength of Gen 3 Results

Per-Unit LOE and SG&A Decrease Substantially in 2Q17

Bolt-on Lease Acquisitions Expanding Footprint, Helping Increase Inventory in Midland and Delaware Basins

NOTE: 2Q17 conference call slides available at www.energen.com

BIRMINGHAM, Ala.--()--Energen Corporation (NYSE: EGN) (“Energen” or the “company”) today announced financial and operating results for the second quarter ended June 30, 2017.

“This includes some 9,700 net acres acquired in the first six months of this year that helped contribute to an increase in our inventory of identified locations.”

FINANCIAL AND OPERATING HIGHLIGHTS

2Q17

  • Production beats June revised guidance by 2% and May guidance by 17%
  • On track to generate 29% YOY growth in total production and 37% YOY growth in Midland and Delaware production
  • Adjusted EBITDAX grows 49% from 1Q17 and beats internal expectations
  • Per-unit LOE (including marketing and transportation) beats June revised guidance midpoint by 8.1%
  • Per unit SG&A beats June revised guidance midpoint by 10.4%
  • Lease acquisitions in first six months of 2017 total 9,732 net acres for ≈$215 mm
  • Energen adds 158 net locations to Wolfcamp/Spraberry/Cline inventory and identifies 413 net locations in other Delaware Basin formations for total identified inventory of 4,116 net locations

2Q17 WELL RESULTS

  • 45 gross and net wells in the Midland and Delaware basins were turned to production in 2Q17 and generated excellent initial production rates in all key areas of operational focus in 2017; 78% are multi-zone pattern wells completed in batches
  • 59 Gen 3 wells are outperforming the highest EUR type curve and significantly outperforming the midpoint EUR type curve; 76% are multi-zone pattern wells completed in batches
  • Public data shows Gen 3 wells in Midland and Delaware basins outperforming other operators’ wells

Comments from the CEO

“The success we are achieving with our Generation 3 frac design and multi-zone pattern wells completed in batches has set the stage for 2017 to be the break-out year we have been working toward, underscoring our top-tier assets and solid execution,” said Energen Chief Executive Officer James McManus. “We are delivering outstanding well performance in all our areas of operational focus in the Midland and Delaware basins; and we continue to drive down our operating costs and G&A and are competitive with the best in the Midland and Delaware basins.

“Importantly, our Gen 3 wells are outperforming wells completed by other operators. The public well data also supports our position that the best way to maximize the full development of our assets is to complete them in multi-zone batches at original reservoir pressure,” McManus said. “We expect our Gen 3 multi-zone pattern wells to continue driving production growth as we move forward.

“We have continued executing on our bolt-on acquisition program, which we believe has created significant value for Energen. Over the last 18 months, we have added approximately 19,000 net acres in prime Delaware and Midland basin locations for an average price of about $17,600 an acre,” McManus said. “This includes some 9,700 net acres acquired in the first six months of this year that helped contribute to an increase in our inventory of identified locations.

“We are pleased with our performance this quarter and excited about our future prospects as we successfully implement our 2017 drilling and development program. We plan to maintain our focus on the further optimization of well performance and returns, and we are confident that Energen is well-positioned to continue delivering strong results and creating shareholder value in 2017 and beyond.”

Operations Update

In the second quarter of 2017, Energen turned to production 27 gross (27 net) wells in the Midland Basin and 18 gross (18 net) wells in the Delaware Basin; 78 percent are multi-zone pattern wells completed in batches. The company operated an average of 6.5 horizontal drilling rigs and an average of 4 frac crews. In the first six months of 2017, Energen turned to production 49 net wells in its 60-net well DUC inventory at year-end 2016.

                   

2017 First Production/Flow back (Horizontal Wells – Gross/Net)

 
      1Q17a     2Q17a     3Q17e     4Q17e     CY17e
Midland Basin     10/9     27/27     20/19     19/14     76/69
Delaware Basin     2/2     18/18     3/3     12/12     35/35
 
               

2Q17 Wells Turned to Production

 
Area     # of Wells    

Average
Completed
Lateral Length

Avg. Peak 24-Hour IP     Avg. Peak 30-day IP
    Boepd     %Oil     Boepd     %Oil
Delaware Basin     18     Wolfcamp A (8)

Wolfcamp B (10)

    9,466’     2,338     59     1,8891    

60

Northern Midland Basin     11    

MSB (4), Jo Mill (3),
LSB (4)

    10,531’     1,250     88     1,2122     85
Northern Midland Basin     8     Wolfcamp A (3)

Wolfcamp B (5)

    10,510’     1,558     86     1,270 3     81
Central Midland Basin     8    

Wolfcamp A (3)

Wolfcamp B (5)

    7,502’     1,671     79     1,126     66

1 16 wells with 30-day data

2 4 wells with 30-day data

3 7 wells with 30-day data

 

For 59 of the Gen 3 wells drilled to date (76 percent of which were multi-zone pattern wells completed in batches), the average cumulative production uplift of wells in each formation group (normalized to 10,000’) is exceeding the highest EUR type curve – and significantly outperforming the midpoint EUR type curve – identified for wells in that group completed with pre-Gen 3 frac designs. These are key measures of success for Energen’s latest frac design.

Relative to the midpoint EUR type curve, the average cumulative production uplift of the Gen 3 wells normalized to 10,000’ is:

  • ≈31% over a 1.75 MMBOE type curve at 270 days for 20 Delaware Basin Wolfcamp A and B wells – 9 of 20 are multi-zone pattern wells completed in batches
  • ≈40% over a 1.2 MMBOE type curve at 90 days for 11 wells in the Spraberry package – all are multi-zone pattern wells completed in batches
  • ≈11% over a 1.2 MMBOE type curve at 240 days for 10 northern Midland Basin Wolfcamp A and B wells – 7 of 10 are multi-zone pattern wells completed in batches
  • ≈21% over a 1.2 MMBOE type curve at 170 days for 16 central Midland Basin Wolfcamp A and B wells – all are multi-zone pattern wells in batches
  • ≈47% over a 850 MBOE type curve at 160 days for 2 central Midland Basin Lower Spraberry wells – both are multi-zone pattern wells completed in batches

In another assessment of success, the average cumulative production of Energen’s Midland Basin Gen 3 multi-zone pattern wells completed in batches is outperforming other operators’ pattern wells; and the average cumulative production of Energen’s Gen 3 wells (pattern and stand-alone) in the Midland and Delaware basins is outperforming other operators’ wells with comparable proppant loads of 1,700-2,500 pounds per foot.

The company attributes this outperformance to completing the wells in multi-zone batches instead of completing them as offset pattern wells. Utilizing simultaneous, multi-zone pattern development allows all wells to be completed at the original reservoir pressure, which should maximize reservoir productivity. In offset pattern well development, the original stand-alone well causes the reservoir pressure to drop and reduces the productivity of all subsequent wells drilled.

Bolt-on Lease Acquisitions Continue, Inventory Grows

In the first six months of 2017, Energen has acquired more than 9,700 net acres for approximately $215 million, or an average price of some $22,000 per acre. These acquisitions helped contribute to the addition of 158 net locations in its Wolfcamp, Spraberry, and Cline inventory (after moving 32 net locations into the drilled category). The company also has identified 413 net locations in other Delaware Basin formations, giving the company a new identified inventory of 4,116 net locations.

The company also has purchased 690 net mineral acres in the Delaware Basin in the first six months of 2017 for approximately $20 million.

Over the last 18 months (CY16 and YTD17), the company’s bolt-on acquisition program has added approximately 19,000 net lease acres in prime Delaware and Midland basin locations for an average price of approximately $17,600 an acre.

2017 Capital Overview

Energen’s estimate of capital spending for drilling and development in 2017 remains unchanged at $850-$900 million.

   
Capital Summary by Basin     2017e Capital ($MM)
Midland Basin     $ 470 - 490
Delaware Basin     $ 375 - 405
Central Basin, ARO, Other     $ 5
Drilling & Development Capital     $ 850 - 900
Acquisitions/Unproved Leasehold     $ 235
Total Capital Expenditures     $ 1,085 - 1,135
 

Liquidity and Leverage Update

As of June 30, 2017, Energen had cash of $0.5 million, long-term debt of $544.7 million, and $131.5 million drawn on its $1.05 billion line of credit, and its borrowing base currently is $1.4 billion. Energen estimates that its year-end 2017 total net debt-to-2017 adjusted EBITDAX will range from 1.3x - 1.4x.

2Q17 Financial Results

For the 3 months ended June 30, 2017, Energen reported GAAP net income from all operations of $29.5 million, or $0.30 per diluted share. Adjusting for a non-cash gain on mark-to-market derivatives and a small, non-cash impairment loss, Energen had adjusted net income in 2Q17 of $5.4 million, or $0.06 per diluted share. This compares with an adjusted loss in 2Q16 of $(27.1 million), or $(0.28) per diluted share. [See “Non-GAAP Financial Measures” beginning on pp 8 for more information and reconciliation.]

Energen’s adjusted 2Q17 net income of $5.4 million exceeded internal expectations by $1.6 million largely due to:

  • Less-than-expected lease operating expense (LOE) largely due to lower power and chemical costs;
  • Higher production due to continued positive impact of Gen 3 completions;
  • Lower salaries and general and administrative expense (SG&A) primarily due to lower non-cash compensation; and
  • Decreased production and ad valorem taxes.

Partially offsetting these gains were lower realized sales prices and increased depreciation, depletion, and amortization expense (DD&A) largely due to increased production.

Energen’s adjusted EBITDAX totaled $142.4 million in the 2nd quarter of 2017, increased 49 percent from the first quarter, and exceeded internal expectations by 4 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $82.3 million. [See “Non-GAAP Financial Measures” beginning on pp 8 for more information and reconciliation.]

Commodity     2Q17         1Q17
    Actual    

June Rev.
Guidance

    % ∆        

May
Guidance

    % ∆
Oil     45.1     44.9     0         40.6     11 33.3
NGL     13.5     12.8     5         10.5     29 8.9
Natural Gas     13.9     13.5     3         11.1     25 10.6
Total     72.5     71.1     2         62.2     17 52.8
 
 
Area 2Q17 1Q17
    Actual    

June Rev.
Guidance

    % ∆        

May
Guidance

    % ∆
Midland Basin     41.3     40.5     2         34.2     21 31.8
Delaware Basin     23.4     22.9     2         19.8     18 12.8
Central Basin/Other     7.9     7.7     3         8.2     (4) 8.3
Total     72.5     71.1     2         62.2     17 52.8
                   

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

 
           

2Q17 Expenses

 
Per BOE, except where noted 2Q17 1Q17
    Actual    

June Guidance
Midpoint

LOE (production costs, marketing & transportation)     $ 6.66     $ 7.25 $ 8.68

Production & ad valorem taxes (% of revenues exc. hedges)

      6.0%       6.9%   7.3%
DD&A     $ 18.25     $ 18.30 $ 20.71
SG&A     $ 3.00     $ 3.35 $ 4.29
Exploration (includes seismic, delay rentals, etc.)     $ 0.30     $ 0.25 $ 0.76
Interest ($mm)     $ 9.1     $ 9.2 $ 9.0
   
       

2Q17 Average Realized Prices

 
Commodity     With Hedges     W/O Hedges
Oil (per barrel)     $ 44.58     $ 44.54
NGL (per gallon)     $ 0.36     $ 0.36
Natural Gas (per mcf)     $ 2.38     $ 2.29
 

CY17 Guidance

                       

Production (mboepd)

 
By Basin     1Q17a     2Q17a     3Q17e     4Q17e CY17e
Midland Basin     31.8     41.3     40.6     42.1 39.0
Delaware Basin     12.8     23.4     26.2     31.9 23.6
Central Basin Platform/Other     8.3     7.9     8.0     7.8 8.0
Total     52.8     72.5     74.8     81.9 70.6
 
 
By Commodity     1Q17a     2Q17a     3Q17e     4Q17e CY17e
Oil     33.3     45.1     47.9     53.4 45.0
NGL     8.9     13.5     12.9     13.7 12.3
Gas     10.6     13.9     13.9     14.7 13.3
Total     52.8     72.5     74.8     81.9 70.6
 

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

 
                   

Operating Expenses

 
Per BOE, except where noted     1Q17a     2Q17a     3Q17e     4Q17e     CY17e
LOE*     $ 8.68     $ 6.66     $7.00-$7.30     $6.85-$7.15     $7.05-$7.45
Production & ad valorem taxes**       7.3%       6.0%     6.4%     6.3%     6.5%
DD&A expense†     $ 20.71     $ 18.25     $17.05-$17.45     $15.25-$15.75     $17.45-$17.85
SG&A     $ 4.29     $ 3.00     $3.10-$3.40     $2.55-$2.85     $3.00-$3.40
Exploration††     $ 0.76     $ 0.30     $0.10-$0.15     $0.15-$0.20     $0.25-$0.35
Interest ($mm)     $ 9.0     $ 9.1     $9.5-$10.5     $10.0-$11.0     $38.5-$39.5
Effective tax rate       32%       35%     37%-39%     36%-38%     37%-39%
 

* 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 from $5.20-$5.50 in the Delaware Basin, $5.85-$6.15 in the Midland Basin, and $18.60-$18.90 in the Central Basin Platform. Production and ad valorem taxes in CY17, as a percent of revenues excluding hedges, are estimated to be 6.3 percent in the Delaware Basin, 6.4 percent in the Midland Basin, and 7.4 percent in the Central Basin Platform. SG&A per boe in CY17 is estimated to be comprised of cash and other of $2.50-$2.70 per boe and non-cash, equity-based compensation of $0.50-$0.70 per boe.

Hedges

For the last six months of 2017, 69 percent of the company’s estimated oil production of 9.3 mmbo is hedged. Swaps for 4.0 mmbo have an average NYMEX price of $50.68 per barrel, and 3-way collars for 2.4 mmbo have average call, put, and short put prices of $62.18, $45.00, and $35.00 per barrel, respectively. Approximately 40 percent of Energen’s estimated NGL production is hedged at an average price of $0.57 per gallon, and 55 percent of its estimated gas production is hedged at an average NYMEX-equivalent price of $3.31 per Mcf. Energen also has hedged the WTI Midland to WTI Cushing (sweet oil) differential for 5.6 million barrels at an average price of $(0.66) per barrel; approximately 87 percent of Energen’s oil production for the remainder of the year is estimated to be sweet.

In 3Q17, approximately 73 percent of the company’s estimated oil production of 4.4 mmbo is hedged. Swaps for 2.0 mmbo have an average NYMEX price of $50.68 per barrel, and 3-way collars for 1.2 mmbo have average call, put, and short put prices of $62.18, $45.00, and $35.00 per barrel, respectively. Approximately 42 percent of Energen’s estimated NGL production is hedged at an average price of $0.57 per gallon, and 57 percent of its estimated gas production is hedged at an average NYMEXe price of $3.30 per Mcf. Energen also has hedged the Midland to Cushing differential for 2.6 million barrels at an average price of $(0.64) per barrel; approximately 68 percent of Energen’s estimated oil production in 3Q17 is estimated to be sweet.

Basis Differentials

Energen’s average realized prices in the last six months of CY17 will reflect commodity and basis hedges, oil transportation charges of approximately $2.00 per barrel, NGL T&F fees of approximately $0.12 per gallon, and basis differentials applicable to unhedged production. Natural gas and NGL production also is subject to a percent of proceeds contract of approximately 85%.

The assumed gas basis for all open contracts for August-December 2017 is $(0.45) per Mcf, and assumed prices for unhedged Midland to Cushing basis differentials for sweet and sour oil (August-December) are $(1.45) and $(1.30), respectively. Energen’s assumed commodity prices for unhedged production are approximately $47.30 per barrel of oil (July-December), $0.60 per gallon of NGL (July-December), and $3.15 per Mcf of gas (August-December).

       

Estimated Price Realizations (pre-hedge):

 
      3Q17     ROY 2017
Crude oil (% of NYMEX/WTI)     93     93
NGL (after T&F) (% of NYMEX/WTI)     37     34
Natural gas (% of NYMEX/Henry Hub)     74     74
 
 

2018 Hedges

       
Oil     2018 Hedge Volumes     Avg. NYMEX Price
Three way Collars     13.5 mmbo      
Call Price          

$ 60.04 per barrel

Put Price          

$ 45.47 per barrel

Short Put Price          

$ 35.47 per barrel

 
Commodity     Hedge Volumes     NYMEXe Price
NGL     105.8 mm gallons     $ 0.59 per gallon
Natural Gas     3.6 bcf     $ 3.10 per mcf
       

Energen also has hedged the Midland to Cushing differential on 7.6 million barrels of its estimated 2018 sweet oil production at an average price of $(1.10).

Conference Call

2Q17 slides associated with Energen’s quarterly release and conference call are available at www.energen.com. Energen will hold its quarterly conference call Tuesday, August 8, at 8:30 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 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 6/30/17
Energen Net Income ($ in millions except per share data)     Net Income    

Per Diluted
Share

Net Income (Loss) All Operations (GAAP) 29.5     0.30
Non-cash mark-to-market gains (net of $13.2 tax) (24.1 ) (0.25 )
Asset impairment, other (net of tax)     nm       nm  
Adjusted Income from Continuing Operations (Non-GAAP)     5.4       0.06  
 
 
Three Months Ended 6/30/16
Energen Net Income ($ in millions except per share data)     Net Income    

Per Diluted
Share

Net Income (Loss) All Operations (GAAP) 36.8 0.38
Non-cash mark-to-market losses (net of $21.5 tax) 39.1 0.40
Reduction in force expenses (net of $0.3 tax) 0.6 0.01
Income associated with 2016 property sales (net of $58.2 tax)     (103.5 )     (1.06 )
Adjusted Income from Continuing Operations (Non-GAAP)     (27.1 )     (0.28 )
 
 
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 losses associated with a reduction in force, and income 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 6/30
($ in millions)     2017     2016
 
Energen Net Income (Loss) (GAAP) 29.5 36.8
Income associated with 2016 property sales, net of tax     0.0       (103.5 )
Net Income (Loss) Excluding 2016 Property Sales (Non-GAAP)     29.5       (66.8 )
Interest expense 9.1 9.0
Income tax expense (benefit) * 16.1 (35.1 )
Depreciation, depletion and amortization * 121.5 110.6
Accretion expense * 1.4 1.5
Exploration expense * 2.0 1.5
Adjustment for asset impairment nm 0.0
Adjustment for mark-to-market (gains)/ losses (37.3 ) 60.6
Adjustment for reduction in force expenses     0.0       0.9  
Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)     142.4       82.3  
 
 
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 6/30/16.
                   

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 2016 property sales 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 2016 Property Sales
Reconciliation to GAAP Information Three Months Ended
June 30, 2016
(in thousands except per share and production data)              
GAAP     2016 Property Sales     Non-GAAP
Revenues
Oil, natural gas liquids and natural gas sales $ 171,637 $ 14,426 $ 157,211
Gain (loss) on derivative instruments       (65,872 )     $ -         (65,872 )
Total Revenues       105,765         14,426         91,339  
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 42,840 5,660 37,180
Production and ad valorem taxes 11,265 1,236 10,029
O&G Depreciation, depletion and amortization 115,768 6,368 109,400
FF&E Depreciation, depletion and amortization 1,267 71 1,196
Asset impairment - - -
Exploration 1,520 32 1,488
General and administrative † 23,548 10 23,538
Accretion of discount on asset retirement obligations 1,779 248 1,531
(Gain) loss on sale of assets and other       (161,097 )       (160,944 )       (153 )
Total costs and expenses       36,890         (147,319 )       184,209  
Operating Income (Loss)       68,875         161,745         (92,870 )
Other Income/(Expense)
Interest expense (9,038 ) - (9,038 )
Other income       63         (1 )       64  

Total other expense

      (8,975 )       (1 )       (8,974 )
 
Income (Loss) Before Income Taxes 59,900 161,744 (101,844 )
Income tax expense (benefit)       23,141         58,204         (35,063 )
Net Income (Loss)     $ 36,759       $ 103,540       $ (66,781 )
                   
Diluted Earnings Per Average Common Share     $ 0.38       $ 1.06       $ (0.69 )
                   
Basic earning Per Average Common Share     $ 0.38       $ 1.06       $ (0.69 )
 
Oil 3,558 238 3,320
NGL 1,067 212 855
Natural Gas       1,216         292         924  
Total Production (mboe)       5,841         742         5,099  
Total Production (boepd)       64,187         8,154         56,033  
 
Note: Amounts may not sum due to rounding
 
† General and administrative includes $866 of expense related to the reductions in force
 
       

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

For the 3 months ending June 30, 2017 and 2016

 
2nd Quarter
   
(in thousands, except per share data)     2017     2016     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 218,723 $ 171,637 $ 47,086
Gain (loss) on derivative instruments, net       38,101         (65,872 )       103,973  
 
Total revenues       256,824         105,765         151,059  
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 43,909 42,840 1,069
Production and ad valorem taxes 13,218 11,265 1,953
Depreciation, depletion and amortization 121,549 117,035 4,514
Asset impairment 29 29
Exploration 1,998 1,520 478

General and administrative (including stock based compensation of $3,191 and $5,504 for the three months ended June 30, 2017, and 2016, respectively)

 

19,792

 

23,548

 

(3,756

)

Accretion of discount on asset retirement obligations 1,443 1,779 (336 )
(Gain) loss on sale of assets and other       172         (161,097 )       161,269  
 
Total operating costs and expenses       202,110         36,890         165,220  
 
Operating Income       54,714         68,875         (14,161 )
 
Other Income (Expense)
Interest expense (9,145 ) (9,038 ) (107 )
Other income       45         63         (18 )
 
Total other expense       (9,100 )       (8,975 )       (125 )
 
Income Before Income Taxes 45,614 59,900 (14,286 )
Income tax expense       16,133         23,141         (7,008 )
 
Net Income     $ 29,481       $ 36,759       $ (7,278 )
                   
Diluted Earnings Per Average Common Share     $ 0.30       $ 0.38       $ (0.08 )
Basic Earnings Per Average Common Share     $ 0.30       $ 0.38       $ (0.08 )
Diluted Average Common Shares Outstanding       97,693         97,389         304  
Basic Average Common Shares Outstanding       97,189         97,067         122  
 
       

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

For the 6 months ending June 30, 2017 and 2016

 
Year-to-date
   
(in thousands, except per share data)     2017     2016     Change
 
Revenues
Oil, natural gas liquids and natural gas sales $ 395,098 $ 294,401 $ 100,697
Gain (loss) on derivative instruments, net       102,647         (60,417 )       163,064  
 
Total revenues       497,745         233,984         263,761  
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 85,197 90,567 (5,370 )
Production and ad valorem taxes 26,038 22,435 3,603
Depreciation, depletion and amortization 221,201 236,397 (15,196 )
Asset impairment 1,489 220,025 (218,536 )
Exploration 5,634 1,762 3,872
General and administrative (including stock based compensation of $6,388 and $7,975 for the six months ended June 30, 2017, and 2016, respectively)

40,191

53,073

(12,882

)

Accretion of discount on asset retirement obligations 2,857 3,536 (679 )
Gain on sale of assets and other       (1,003 )       (160,875 )       159,872  
 
Total operating costs and expenses       381,604         466,920         (85,316 )
 
Operating Income (Loss)       116,141         (232,936 )       349,077  
 
Other Income (Expense)
Interest expense (18,111 ) (18,871 ) 760
Other income       428         159         269  
 
Total other expense       (17,683 )       (18,712 )       1,029  
 
Income (Loss) Before Income Taxes 98,458 (251,648 ) 350,106
Income tax expense (benefit)       35,574         (85,291 )       120,865  
 
Net Income (Loss)     $ 62,884       $ (166,357 )     $ 229,241  
                   
Diluted Earnings Per Average Common Share     $ 0.64       $ (1.81 )     $ 2.45  
Basic Earnings Per Average Common Share     $ 0.65       $ (1.81 )     $ 2.46  
Diluted Average Common Shares Outstanding       97,648         91,850         5,798  
Basic Average Common Shares Outstanding       97,165         91,850         5,315  
 
 

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

As of June 30, 2017 and December 31, 2016

 

       
(in thousands)     June 30, 2017     December 31, 2016
 
 
ASSETS
Current Assets
Cash and cash equivalents $ 498 $ 386,093
Accounts receivable, net 104,359 73,322
Inventories, net 18,263 14,222
Derivative instruments 39,063 50
Income tax receivable 301 27,153
Prepayments and other       4,410       5,071
 
Total current assets       166,894       505,911
 
Property, Plant and Equipment
Oil and natural gas properties, net 4,513,743 4,016,683
Other property and equipment, net       45,241       44,869
 
Total property, plant and equipment, net       4,558,984       4,061,552
 
Other postretirement assets 3,595 3,619
Noncurrent derivative instruments 9,534
Other assets       7,725       8,741
 
TOTAL ASSETS     $ 4,746,732     $ 4,579,823
 

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities
Long-term debt due within one year 17,000 24,000
Accounts payable 65,770 65,031
Accrued taxes 12,734 7,252
Accrued wages and benefits 15,709 25,089
Accrued capital costs 95,509 79,988
Revenue and royalty payable 48,332 51,217
Derivative instruments 481 65,467
Other       17,778       20,160
 
Total current liabilities       273,313       338,204
 
Long-term debt 659,158 527,443
Asset retirement obligations 84,867 81,544
Deferred income taxes 532,605 495,888
Noncurrent derivative instruments 502 3,006
Other long-term liabilities 8,545 13,136
 
Total liabilities       1,558,990       1,459,221
 
Total Shareholders’ Equity       3,187,742       3,120,602
 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY     $ 4,746,732     $ 4,579,823
 
       

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending June 30, 2017 and 2016

 
2nd 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 $ 182,701 $ 146,360 $ 36,341
Natural gas liquids 18,634 13,928 4,706
Natural gas       17,388         11,349         6,039  
Total     $ 218,723       $ 171,637       $ 47,086  
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ 31,067 $ (54,729 ) $ 85,796
Natural gas liquids 4,530 4,530
Natural gas       1,737         (5,896 )       7,633  
Total     $ 37,334       $ (60,625 )     $ 97,959  
 
Closed gains (losses) on derivative instruments
Oil $ 152 $ (6,297 ) $ 6,449
Natural gas liquids (80 ) (80 )
Natural gas       695         1,050         (355 )
Total     $ 767       $ (5,247 )     $ 6,014  
Total revenues     $ 256,824       $ 105,765       $ 151,059  
 
Production volumes
Oil (MBbl) 4,102 3,558 544
Natural gas liquids (MMgal) 51.6 44.8 6.8
Natural gas (MMcf)       7,596         7,296         300  

Total production volumes (MBOE)

 

6,596

        5,841         755  
 

Average daily production volumes

Oil (MBbl/d)

45.1

39.1

6.0

Natural gas liquids (MMgal/d) 0.6 0.5 0.1
Natural gas (MMcf/d)       83.5         80.2         3.3  
Total average daily production volumes (MBOE/d)       72.5         64.2         8.3  
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 44.58 $ 39.37 $ 5.21
Natural gas liquids (per gallon) $ 0.36 $ 0.31 $ 0.05
Natural gas (per Mcf) $ 2.38 $ 1.70 $ 0.68
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 44.54 $ 41.14 $ 3.40
Natural gas liquids (per gallon) $ 0.36 $ 0.31 $ 0.05
Natural gas (per Mcf) $ 2.29 $ 1.56 $ 0.73
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

6.66

$

7.34

$

(0.68

)

Production and ad valorem taxes $ 2.00 $ 1.93 $ 0.07
Depreciation, depletion and amortization $ 18.43 $ 20.04 $ (1.61 )
Exploration expense $ 0.30 $ 0.26 $ 0.04
General and administrative $ 3.00 $ 4.03 $ (1.03 )
Capital expenditures (including acquisitions)     $ 336,111       $ 92,962       $ 243,149  
 
   

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 6 months ending June 30, 2017 and 2016

   
Year-to-date
(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 $ 329,371 $ 248,517 $ 80,854
Natural gas liquids 34,268 22,517 11,751
Natural gas       31,459         23,367         8,092  
Total     $ 395,098       $ 294,401       $ 100,697  
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ 89,125 $ (56,428 ) $ 145,553
Natural gas liquids 11,617 11,617
Natural gas       8,961         (4,454 )       13,415  
Total     $ 109,703       $ (60,882 )     $ 170,585  
 
Closed gains (losses) on derivative instruments
Oil $ (5,858 ) $ (1,203 ) $ (4,655 )
Natural gas liquids (1,545 ) (1,545 )
Natural gas       347         1,668         (1,321 )
Total     $ (7,056 )     $ 465       $ (7,521 )
Total revenues     $ 497,745       $ 233,984       $ 263,761  
 
Production volumes
Oil (MBbl) 7,098 6,944 154
Natural gas liquids (MMgal) 85.3 84.8 0.5
Natural gas (MMcf)       13,326         14,742         (1,416 )

Total production volumes (MBOE)

   

11,350

        11,421         (71 )
 

Average daily production volumes

Oil (MBbl/d)

39.2

38.2

1.0

Natural gas liquids (MMgal/d) 0.5 0.5
Natural gas (MMcf/d)       73.6         81.0         (7.4 )
Total average daily production volumes (MBOE/d)       62.7         62.8         (0.1 )
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 45.58 $ 35.62 $ 9.96
Natural gas liquids (per gallon) $ 0.38 $ 0.27 $ 0.11
Natural gas (per Mcf) $ 2.39 $ 1.70 $ 0.69
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 46.40 $ 35.79 $ 10.61
Natural gas liquids (per gallon) $ 0.40 $ 0.27 $ 0.13
Natural gas (per Mcf) $ 2.36 $ 1.59 $ 0.77
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

7.51

$

7.93

$

(0.42

)

Production and ad valorem taxes $ 2.29 $ 1.96 $ 0.33
Depreciation, depletion and amortization $ 19.49 $ 20.70 $ (1.21 )
Exploration expense $ 0.50 $ 0.15 $ 0.35
General and administrative $ 3.54 $ 4.65 $ (1.11 )
Capital expenditures (includes acquisitions)     $ 720,246       $ 217,050       $ 503,196  
 

Contacts

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

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