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Production Beats 1Q18 Guidance Midpoint by 4%

BIRMINGHAM, Ala.--(BUSINESS WIRE)--

Energen Corporation (EGN) (“Energen” or the “company”) today announced financial and operating results for the first quarter ended March 31, 2018.

FINANCIAL AND OPERATING HIGHLIGHTS

CY18 OFF TO EXCELLENT START IN 1Q

  • Total production of 92.9 mboepd surpasses guidance midpoint by 4% primarily due to well outperformance
  • Oil production of 55.4 mbopd exceeds top end of 1Q18 guidance range – up 5% from midpoint
  • Per-unit net SG&A expense of $2.66/boe beats guidance midpoint by 11%
  • Adjusted EBITDAX totaled $240.6 million, exceeding internal expectations by ≈10%
  • >70% of estimated oil production (at guidance mdpt) for ROY hedged as well as ≈58% of the basis differential
  • Bolt-on acquisitions in 1Q18 add ≈1,100 net leasehold acres for ≈$18 million

STRONG EXECUTION SHOWCASED IN 1Q18

  • 25 gross (23 net) wells turned to production in 1Q18 as efficiencies help drive above-budget pace
  • 8 new Gen 3 Wolfcamp wells in Delaware Basin deliver average peak 24-hour IP rates of >440 boepd/1,000’
  • Performance of new Gen 3 Wolfcamp wells in central Midland Basin in line with type curve
  • First Gen 3 Cline tests generate excellent results in north and central Midland Basin

Comments from the CEO

“In the first quarter of 2018, Energen built on the strong execution, growth, and financial strength it demonstrated in 2017,” said James McManus, Energen’s chairman and chief executive officer. “Our Generation 3 completions continued to drive production outperformance and, in combination with execution excellence, resulted in wells being placed on production earlier than planned. Additionally, our first Gen 3 completions on two Cline wells in different areas of the Midland Basin are delivering exciting results.

“We are pleased to report that we have all of the rigs and services lined up to execute on our 2018 drilling and development plans. We have strong arrangements in place to provide flow assurance for our oil and gas production. And we have high-quality, oil-focused assets with attractive rates of return and an outstanding balance sheet,” McManus added. “In short, we are extremely pleased with our performance in the quarter and confident that Energen is well-positioned to continue delivering strong results and creating shareholder value.”

1Q18 Operations Update

Energen’s production in 1Q18 totaled 92.9 mboepd, or 4 percent higher than the guidance midpoint of 89.5 mboepd; this primarily was due to the outperformance of wells. A secondary contributor was wells being placed on production ahead of schedule but generally late in the quarter. Energen turned to production 15 gross (13 net) wells in the Midland Basin and 10 gross (10 net) wells in the Delaware Basin as compared to guidance of 9 gross (8 net) wells and 4 gross (4 net) wells, respectively. Energen’s oil production in 1Q18 totaled 55.4 mbopd, or 5 percent higher than the guidance midpoint of 53.0 mbopd.

1Q18 Production (mboepd)

  Commodity         1Q18  
      Actual         Guidance Mdpt         % ∆  
  Oil     55.4    

53.0

    5  
  NGL     18.2     17.5     4  
  Natural Gas     19.3     19.0     2  
  Total         92.9         89.5         4  

Note: Totals above may not sum due to rounding.

 

1Q18 Wells Turned to Production

  Area         # Wells        

Avg.
Completed
Lateral
Length

       

Avg. Peak 24-Hr IP

       

Avg. Peak 30-Day IP

 
              Boepd        

Boepd/
1,000’

        % Oil     Boepd        

Boepd/
1,000’

        % Oil  
  Delaware Basin1     8      

Wolfcamp A (3)
Wolfcamp B (4)
Wolfcamp BC (1)

    5,529     2,440     441     53 %     1,669*     392*    

58

%*

 
  N. Midland Basin2     1     Wolfcamp B     11,053     1,930     175     88 %                    
  N. Midland Basin     1     Cline     7,531     1,593     212     87 %                    
  C. Midland Basin     11     Wolfcamp A/B     8,736     1,600     188     81 %     1,186     136     75 %  
  C. Midland Basin3         1       Cline         6,572         2,318         353         69 %         1,233         188         65 %  

1

 

Excludes 1 well for which there is insufficient production history and 1 test well

* 30-day peak data for 5 wells with sufficient production history

2

Excludes 2 wells (a Lower Spraberry and a Jo Mill) for which there is insufficient production history

3

Turned to production in late 4Q17 but not previously disclosed due to timing of first production

 

Of the wells placed on production in 1Q18, 40 percent (all of which are in the Midland Basin) are multi-zone pattern wells completed in batches at original reservoir pressure. During 1Q18, Energen utilized an average of 6-7 horizontal drilling rigs and an average of 4 frac crews. The company currently is running 10 drilling rigs and 4 frac crews, with a 5th frac crew scheduled to begin work in the Midland Basin this summer.

Among the operating highlights in the quarter was a 9,350’ lateral Wolfcamp A in the Delaware Basin that was drilled in a record 22 days from spud to total depth. The company also placed on production its longest completed lateral length wells to date: 11,574’ in the Delaware Basin and 11,053’ in the Midland Basin. In addition, drilling and completion down time continued to decline.

1Q18 Financial Results

For the 3 months ended March 31, 2018, Energen reported GAAP net income from all operations of $118.9 million, or $1.22 per diluted share. Adjusting for non-cash items, including a $14.6 million gain on mark-to-market derivatives, a $26.0 million gain associated with a property trade, and $1.1 million miscellaneous loss, Energen had adjusted income in 1Q18 of $79.4 million, or $0.81 per diluted share. This compares with an adjusted loss in 1Q17 of $(12.4 million), or $(0.13) per diluted share. [See “Non-GAAP Financial Measures” beginning on p. 8 for more information and reconciliation.]

Energen’s adjusted 1Q18 earnings exceeded internal expectations by $0.16 per diluted share largely due to substantially higher production and realized commodity prices. The company’s adjusted EBITDAX totaled $240.6 million in 1Q18 and exceeded internal expectations by approximately 10 percent. In the same period a year ago, Energen’s adjusted EBITDAX totaled $95.6 million. [See “Non-GAAP Financial Measures” beginning on p. 8 for more information and reconciliation.]

Drilling and development capital invested in 1Q18 totaled $236 million. Energen also invested some $18 million for approximately 1,100 net acres of unproved leasehold, primarily in the Delaware Basin. Including lease renewals, FF&E, and other miscellaneous items, total capital spending in 1Q18 totaled approximately $260 million.

1Q18 Expenses

  Per BOE, except where noted         1Q18  
      Actual        

Guidance
Midpoint

        % ∆  
  LOE (production costs, marketing & transportation)     $ 6.30       $ 6.30       --    
 

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

      6.3 %       6.4 %     NM    
  DD&A     $ 14.72       $ 14.95       (2 )  
  SG&A     $ 2.66       $ 3.00       (11 )  
  Exploration (incudes seismic, delay rentals, etc.)     $ 0.14       $ 0.18       (22 )  
  Effective tax rate (%)           23 %           23 %         --    
         

1Q18 Average Realized Prices

  Commodity         With Hedges         W/O Hedges  
  Oil (per barrel)     $ 57.65     $ 60.99  
  NGL (per gallon)     $ 0.44     $ 0.50  
  Natural Gas (per mcf)         $ 1.92         $ 1.89  
         

NOTE: Average prices for oil are net of transportation costs. Average prices for NGLs and natural gas in 1Q18 were impacted by the adoption of Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), which requires certain transportation, gathering, processing, and compression fees paid to be recorded as a deduction to revenues. Prior to 2018, certain of these fees were recorded as gathering and transportation, which are included in lease operating expenses. Additional information can be found in the Company’s Form 10-Q filing with the SEC for the three months ending March 31, 2018, expected to be filed May 9, 2018.

Liquidity and Leverage Update

As of March 31, 2018, Energen had cash of $0.6 million, long-term debt of $528.0 million, and line of credit borrowings of $228.0 million. The company estimates that its total net debt-to-adjusted EBITDAX at year end will range from 0.9x - 1.1x.

Effective April 30, 2018, as part of the spring redetermination process for its secured credit facility, the aggregate commitments for the line of credit increased from $1.05 billion to $1.25 billion and the borrowing base was raised from the $1.7 billion to $2.15 billion. Along with the renewal, the term of the line of credit was extended to April 2023. No changes were made to the financial covenants of the credit facility.

2018 Overview

Estimated total capital spending for drilling and development activities in 2018 remains unchanged from prior guidance of $1.1 billion to $1.3 billion. Drilling and development capital in 2Q18 is estimated to range from $300 million to $330 million. The company’s 2018 drilling and completion plans have been adjusted to reflect increased working interests and longer lateral lengths. The company expects to drill approximately 128 gross/117 net horizontal wells in 2018 and complete approximately 123 gross/114 net horizontal wells, including 30 gross/28 net year-end 2017 drilled but uncompleted wells (DUCs). The average lateral length of wells scheduled for completion in 2018 (including known completed lateral lengths) is 8,000’; and the working interest of completed wells in 2018 has increased to approximately 92 percent.

The company estimates its YE18 DUCs will total approximately 35 gross/32 net. Energen also plans to drill 7 gross/7 net vertical wells in the Midland Basin and complete 6 gross/6 net of them.

2018 Production Guidance

Estimated 2018 production guidance of 92.0 – 99.0 mboepd reflects the impact of 1Q18 actual results, while guidance ranges for the rest of the year remain unchanged.

                                                       
            1Q18a         2Q18e         3Q18e         4Q18e     CY18e  
  Oil     55.4     51.5 - 54.5     54.0 - 57.0     65.0 - 68.0     56.0 - 59.0  
  NGL     18.2     17.0 - 19.0     16.5 - 18.5     18.0 - 20.0     17.0 - 19.0  
  Gas     19.3     19.0 - 21.0     19.0 - 21.0     20.0 - 22.0     19.0 - 21.0  
  Total         92.9         87.5 - 94.5         89.5 - 96.5         103.5 - 110.5     92.0 - 99.0  

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

 

2018 First Production/Flow back (Operated Horizontal Wells – Gross/Net)

            1Q18a         2Q18e         3Q18e         4Q18e         CY18e  
  Midland Basin     15/13     10/9     20/20     20/17     65/59  
  Delaware Basin         10/10         8/6         9/8         22/21         49/46  

NOTE: Totals may not sum due to rounding

 

CY18 Operating Expenses

         
  Per BOE, except where noted         1Q18a         2Q18e         3Q18e         4Q18e     CY18e  
  LOE     $ 6.30     $6.80 - $7.00     $6.50 - $6.70     $6.10 -$6.30     $6.40 - $6.60  
  Prod. & ad valorem taxes*     6.3%     6.2%     6.2%     6.2%     6.2%  
  DD&A expense     $ 14.72     $14.75 - $15.25     $14.15 - $14.65     $13.40 - $13.90     $14.15 - $14.65  
  SG&A, net     $ 2.66     $2.50 - $2.90     $2.30 - $2.70     $1.80 - $2.20     $2.30 - $2.70  
  Exploration expense     $ 0.14     $0.15 - $0.20     $0.15 - $0.20     $0.15 - $0.20     $0.15 - $0.20  
  Effective tax rate (%)         23%         22% - 24%         22% - 24%         22% - 24%     22% - 24%  

* % of revenues, excluding hedges

 

LOE per boe in CY18 is estimated to range from $5.20-$5.40 in the Midland Basin, $5.25-$5.45 in the Delaware Basin, and $21.00-$21.20 in the Central Basin Platform/Northeast Shelf areas (“Platform”). Net SG&A per boe in CY18 is estimated to be comprised of cash of $1.90-$2.10 per boe and non-cash, equity-based compensation of $0.40-$0.60 per boe.

Hedges

Since reporting year-end 2018 results, Energen has continued to increase its hedge position in 2018 and 2019 to further mitigate commodity price and basis differential risks. For the last 9 months of 2018, approximately 72 percent of the company’s estimated oil production of 16.0 mmbo (at guidance midpoint) is hedged as well as approximately 49 percent of its estimated NGL production and approximately 24 percent of its estimated natural gas production. Energen also has hedged the Midland to Cushing differential on 9.2 mmbo, or approximately 58 percent of its estimated oil production, at an average price of $(1.37) per barrel. The company’s natural gas hedges cover both the commodity and the basis.

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

  Oil         Hedge Volumes         Avg. NYMEX Price  
  Swaps     1.4 mmbo     $ 60.24 per barrel  
  Three way Collars¹     10.1 mmbo        
  Call Price           $ 60.04 per barrel  
  Put Price           $ 45.47 per barrel  
  Short Put Price                   $ 35.47 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 2018 are as follows:

  Commodity         Hedge Volumes         Production Guidance         % Hedged         Avg. Price  
  NGL     102.1 mm gallons     209.8 mm gallons     49%     $ 0.61 per gallon  
  Natural gas        

8.1 bcf

        33.6 bcf         24%         $ 1.98 per Mcf  

Note: The average price reflected for natural gas represents a basin-specific net Permian price

 

2Q18 Hedges

For the three months ended June 30, 2018, approximately 77 percent of the company’s estimated oil production of 4.8 mmbo (at guidance midpoint) is hedged as well as approximately 49 percent of its estimated NGL production and approximately 25 percent of its estimated natural gas production. Energen has hedged the Midland to Cushing differential on 2.9 mmbo, or approximately 60 percent of its estimated oil production, at an average price of $(1.19) per barrel. The company’s natural gas hedges cover both the commodity and the basis.

                         
  Oil         Hedge Volumes         Avg. NYMEX Price  
  Swaps     0.4 mmbo     $ 60.17 per barrel  
  Three way Collars     3.4 mmbo        
  Call Price           $ 60.04 per barrel  
  Put Price           $ 45.47 per barrel  
  Short Put Price                   $ 35.47 per barrel  
         

Energen’s total natural gas and NGL hedge positions for 2Q18 are as follows:

  Commodity         Hedge Volumes         Production Guidance         Hedge %         Avg. Price  
  NGL     34.0 mm gallons     68.8 mm gallons     49%     $ 0.61 per gallon  
  Natural Gas         2.7 bcf         10.9 bcf         25%         $ 1.98 per mcf  

Note: The average price reflected for natural gas represents a basin-specific net Permian price

 

The company’s average realized prices in the last nine months of 2018 (and in 2Q18) will reflect commodity and basis hedges, oil transportation charges of approximately $1.95 per barrel, NGL transportation and fractionation fees of approximately $0.14 per gallon, and basis differentials applicable to unhedged production. Natural gas and NGL production are also subject to percent of proceeds contracts of approximately 85%.

The assumed gas basis is $(1.40) per Mcf for the rest of 2018 and $(1.33) per Mcf for 2Q18. The assumed per-unit Midland to Cushing basis differentials for unhedged sweet and sour production for the rest of the year are $(4.60) and $(6.17), respectively, and $(2.91) and $(3.39), respectively, for 2Q18. Energen’s assumed commodity prices for unhedged volumes for the last nine months of 2018 are: $65.00 per barrel of oil, $0.70 per gallon of NGL, and $2.85 per Mcf of gas (May-December).

Estimated Price Realizations (pre-hedge):

            2Q18         ROY 2018  
  Crude oil (% of NYMEX/WTI)     93     91  
  NGL (after T&F) (% of NYMEX/WTI)     31     31  
  Natural gas (% of NYMEX/Henry Hub)         38         36  
         

2019 Hedges

Energen’s total oil hedge position for 2019 is as follows:

  Oil         2019 Hedge Volumes         Avg. NYMEX Price  
  Swaps     3.6 mmbo     $ 57.28 per barrel  
  Three-way Collars     5.8 mmbo        
  Call Price           $ 61.65 per barrel  
  Put Price           $ 45.94 per barrel  
  Short Put Price                   $ 35.94 per barrel  
         

Energen’s NGL hedge position for 2019 is as follows:

  Commodity         Hedge Volumes         Avg. Price  
  NGL         85.7 mm gallons         $ 0.64 per gallon  
         

Energen also has hedged the Midland to Cushing differential on 6.8 million barrels of its estimated 2019 oil production at an average price of $(1.11) per barrel.

Supplemental Slides and Conference Call

1Q18 supplemental slides associated with Energen’s quarterly release and conference call are available at www.energen.com. Energen will hold its quarterly conference call Tuesday, May 8, at 8:30 a.m. ET. 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, income associated with acreage swaps, and losses associated with the Tax Cuts and Jobs Act. 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 3/31/18  
  Energen Net Income ($ in millions except per share data)     Net Income     Per Diluted Share  
Net Income (Loss) All Operations (GAAP) 118.9 1.22
Non-cash mark-to-market gains (net of $4.1 tax) (14.6 ) (0.15 )
Asset impairment, other (net of $0.1 tax) * 0.3

nm

Income associated with 2018 acreage swaps (net of $7.4 tax) (26.0 ) (0.27 )
  Expense associated with Tax Cuts and Jobs Act     0.8       0.01    
  Adjusted Income from Continuing Operations (Non-GAAP)     79.4       0.81    
 
                 
  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 )  
 
Note: Amounts may not sum due to rounding
 
* This may include impairments, lease expirations, and dry hole expense.
 
                         
 

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, income associated with acreage swaps, and losses associated with the Tax Cuts and Jobs Act .  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)     2018     2017  
 
Energen Net Income (Loss) (GAAP) 118.9 33.4
Interest expense 10.2 9.0
Income tax expense 35.4 19.4
Depreciation, depletion and amortization 124.2 99.7
Accretion expense 1.5 1.4
Exploration expense 1.2 3.6
Adjustment for asset impairment, other * 0.4 1.5
Adjustment for mark-to-market gains (18.7 ) (72.4 )
Expense associated with Tax Cuts and Jobs Act 0.8 0.0
  Income associated with 2018 acreage swaps     (33.4 )     0.0    
  Energen Adjusted EBITDAX from Continuing Operations (Non-GAAP)     240.6       95.6    
 
Note: Amounts may not sum due to rounding
 
* This may include impairments, lease expirations, and dry hole expense.
 
 

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
For the 3 months ending March 31, 2018 and 2017

     
    1st Quarter    
   
  (in thousands, except per share data)     2018     2017     Change  
 
Revenues
Oil, natural gas liquids and natural gas sales $ 357,866 $ 176,375 $ 181,491
  Gain (loss) on derivative instruments, net       (1,695 )       64,546         (66,241 )  
 
  Total revenues       356,171         240,921         115,250    
 
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production 52,635 41,288 11,347
Production and ad valorem taxes 22,568 12,820 9,748
Depreciation, depletion and amortization 124,210 99,652 24,558
Asset impairment 177 1,460 (1,283 )
Exploration 1,398 3,636 (2,238 )

General and administrative (including stock-based compensation of $4,145 and $3,197 for the three months ended March 31, 2018 and 2017, respectively)

22,257

20,516

1,741

Accretion of discount on asset retirement obligations

1,533 1,414 119
  Gain on sale of assets and other, net       (33,723 )       (1,175 )       (32,548 )  
 
  Total operating costs and expenses       191,055         179,611         11,444    
 
  Operating Income       165,116         61,310         103,806    
 
Other Income (Expense)
Interest expense (10,248 ) (9,023 ) (1,225 )
  Other income       227         557         (330 )  
 
  Total other expense       (10,021 )       (8,466 )       (1,555 )  
 
Income Before Income Taxes 155,095 52,844 102,251
  Income tax expense       36,180         19,441         16,739    
 
  Net Income     $ 118,915       $ 33,403       $ 85,512    
                       
  Diluted Earnings Per Average Common Share     $ 1.22       $ 0.34       $ 0.88    
  Basic Earnings Per Average Common Share     $ 1.22       $ 0.34       $ 0.88    
  Diluted Average Common Shares Outstanding       97,818         97,607         211    
  Basic Average Common Shares Outstanding       97,321         97,140         181    
 
 

CONSOLIDATED BALANCE SHEETS (UNAUDITED)
As of March 31, 2018 and December 31, 2017

 

 

 
  (in thousands)     March 31, 2018     December 31, 2017  
       
ASSETS
Current Assets
Cash and cash equivalents $ 600 $ 439
Accounts receivable, net 150,813 158,787
Inventories, net 19,586 13,177
Derivative instruments 4,984
Income tax receivable 6,899 6,905
  Prepayments and other       9,773       12,085  
 
  Total current assets       192,655       191,393  
 
Property, Plant and Equipment
Oil and natural gas properties, net 4,887,737 4,718,939
  Other property and equipment, net       44,427       44,581  
 
  Total property, plant and equipment, net       4,932,164       4,763,520  
 
Other postretirement assets 2,627 2,646
Noncurrent derivative instruments 3,261
Noncurrent income tax receivable, net 70,716 70,716
  Other assets       4,341       5,620  
 
  TOTAL ASSETS     $ 5,205,764     $ 5,033,895  
 

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current Liabilities
Accounts payable $ 104,430 $ 75,167
Accrued taxes 6,411 2,631
Accrued wages and benefits 8,936 26,170
Accrued capital costs 111,887 74,909
Revenue and royalty payable 62,517 54,072
Derivative instruments 57,478 71,379
  Other       12,239       17,916  
 
  Total current liabilities       363,898       322,244  
 
Long-term debt 755,964 782,861
Asset retirement obligations 90,295 88,378
Noncurrent derivative instruments 11,563 8,886
Deferred income taxes 423,228 387,807
  Other long-term liabilities       5,969       5,262  
 
  Total liabilities       1,650,917       1,595,438  
 
  Total Shareholders’ Equity       3,554,847       3,438,457  
 
  TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY     $ 5,205,764     $ 5,033,895  
 
 

SELECTED BUSINESS SEGMENT DATA (UNAUDITED)

For the 3 months ending March 31, 2018 and 2017

     
    1st Quarter    
   
 

(in thousands, except sales price and per unit data)

   

2018

   

2017

   

Change

 
 
Operating and production data
Oil, natural gas liquids and natural gas sales
Oil $ 303,995 $ 146,670 $ 157,325
Natural gas liquids 34,133 15,634 18,499
  Natural gas       19,738         14,071         5,667    
  Total     $ 357,866       $ 176,375       $ 181,491    
 
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil $ 11,202 $ 58,058 $ (46,856 )
Natural gas liquids 5,766 7,087 (1,321 )
  Natural gas       1,712         7,224         (5,512 )  
  Total     $ 18,680       $ 72,369       $ (53,689 )  
 
Closed gains (losses) on derivative instruments
Oil $ (16,667 ) $ (6,010 ) $ (10,657 )
Natural gas liquids (3,981 ) (1,465 ) (2,516 )
  Natural gas       273         (348 )       621    
  Total     $ (20,375 )     $ (7,823 )     $ (12,552 )  
  Total revenues     $ 356,171       $ 240,921       $ 115,250    
 
Production volumes
Oil (MBbl) 4,984 2,996 1,988
Natural gas liquids (MMgal) 68.8 33.7 35.1
  Natural gas (MMcf)       10,422         5,730         4,692    
  Total production volumes (MBOE)       8,358         4,754         3,604    
 
Average daily production volumes

Oil (MBbl/d)

55.4

33.3

22.1

Natural gas liquids (MMgal/d) 0.8 0.4 0.4
  Natural gas (MMcf/d)       115.8         63.7         52.1    
  Total average daily production volumes (MBOE/d)       92.9         52.8         40.1    
 
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel) $ 57.65 $ 46.95 $ 10.7
Natural gas liquids (per gallon) $ 0.44 $ 0.42 $ 0.02
Natural gas (per Mcf) $ 1.92 $ 2.39 $ (0.47 )
 
Average realized prices excluding effects of all derivative instruments
Oil (per barrel) $ 60.99 $ 48.96 $ 12.03
Natural gas liquids (per gallon) $ 0.50 $ 0.46 $ 0.04
Natural gas (per Mcf) $ 1.89 $ 2.46 $ (0.57 )
 
Costs per BOE
Oil, natural gas liquids and natural gas production expenses

$

6.30

$

8.68

$

(2.38

)

Production and ad valorem taxes $ 2.70 $ 2.70 $ -
Depreciation, depletion and amortization $ 14.86 $ 20.96 $ (6.10 )
Exploration expense $ 0.17 $ 0.76 $ (0.59 )
General and administrative $ 2.66 $ 4.32 $ (1.66 )
  Capital expenditures (including acquisitions)     $ 260,533       $ 384,135       $ (123,602 )  

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