August 8, 2018 - 5:34 PM EDT
Print Email Article Font Down Font Up Charts

Bonanza Creek Energy Announces Second Quarter 2018 Financial Results and Operational Update

DENVER, Aug. 08, 2018 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE: BCEI) (the "Company" or "Bonanza Creek") today announced its second quarter 2018 financial results and operating outlook and has posted an updated investor presentation on its corporate website.

Bonanza Creek delivered solid performance in the second quarter driven by strong production growth and lower capital spend. The Company is on track to grow Wattenberg production by approximately 25% year-over-year and 50% when comparing the fourth quarter of 2018 to the fourth quarter of 2017.

  • Second quarter sales volumes averaged 18.0 MBoe per day including the negative effects of a prior-period adjustment of 0.6 Mboe per day related to non-operated wells

  • Rapidly improving well performance yields over 1,000 economic drilling locations in Wattenberg

  • Full year 2018 Wattenberg production guidance raised while lowering full year capex guidance

  • Accretive Mid-Continent divestiture of $117 million(1) bolsters balance sheet, improves unit operating costs and focuses operations on highest returning opportunities

  • Well head pressures effectively managed via Rocky Mountain Infrastructure's ("RMI") multiple third-party gas processing optionality

  • Second quarter GAAP net income of $4.9 million, or $0.24 per diluted share; Adjusted net income(1) of $24.2 million, or $1.18 per diluted share

  •  Adjusted EBITDAX(2) of $34.8 million, 17% growth over first quarter 2018

(1) Effective date of February 1, 2018

(2) Non-GAAP measures, see attached reconciliation schedules at the end of this release.

"Bonanza Creek delivered a solid quarter, marked by consistently improving operational and financial performance. We continue to be encouraged by the strong well performance across our Wattenberg position. Through a combination of improving well productivity from more recent completion designs, and attention to our base, we are able to raise our full year 2018 production guidance while lowering our full-year capex," said Eric Greager, President and CEO.

"As we look further into this year and next, we expect to see strong production growth, improving unit costs and increased operating cash flow as we accelerate our pace of development. Our balance sheet remains strong. We are well-funded to execute on our capital plan which provides for approximately 25% Rockies production growth in 2018 and greater than 50% growth in 2019."

Second Quarter 2018 Results

During the second quarter of 2018, the Company reported average daily sales of 18.0 MBoe per day, which was at the low end of the Company's guidance range of 18.0 – 18.6 MBoe per day. Otherwise strong production during the quarter was impacted by a negative adjustment of 0.6 MBoe per day related to our interest in several months of production from two outside-operated pads. If not for this adjustment, second quarter production would have been at the high-end of guidance. The Company's second quarter reported sales increased 7% sequentially as we continue to see strong well performance from the recent completion designs and consistently low wellhead gathering pressures on the Company's RMI system. As a result of these factors, we are raising our full-year production guidance, pro-forma for the Mid-Continent divestiture, as detailed below. Product mix for the second quarter of 2018 was 58% oil, 20% NGLs, and 22% residue natural gas.

Net revenue for the second quarter of 2018 was $71.9 million, compared to $44.1 million for the second quarter of 2017. The increase in second quarter 2018 net revenue compared to 2017 was primarily a result of increased production and improved commodity pricing.  Crude oil accounted for approximately 85% of total revenue. Differentials for the Company's Wattenberg oil production during the quarter averaged approximately $6.39 per barrel off of NYMEX WTI. Corporate average realized prices for the second quarter of 2018 are presented below.

  
Average Realized Prices
(Before Derivatives)
 
 Three Months Ended
June 30, 2018
Oil (per Bbl)$63.67
Gas (per Mcf)$2.13
NGL (per Bbl)$19.05
Boe (Per Boe)$43.57
   

Lease operating expenses ("LOE") for the second quarter of 2018 were $11.3 million, compared to $9.4 million in the second quarter of 2017.  LOE on a unit basis for the second quarter of 2018 increased by 6.6% to $6.90 per Boe from $6.47 per Boe in the second quarter of 2017. Gas plant and midstream expenses for the second quarter of 2018 were $3.2 million, compared to $2.6 million in the second quarter of 2017. On a unit basis, gas plant and midstream expenses increased 10% to $1.98 per Boe for the second quarter of 2018 from $1.80 per Boe in the second quarter of 2017. Unit operating costs were impacted by decisions to pull forward certain planned activities and to pursue high-returning maintenance opportunities. They were also impacted by some cost inflation and environmental compliance costs required by the air emissions consent order in the Wattenberg Field. The Company’s accelerated compressor replacement program is now largely complete and will continue to ensure Bonanza Creek’s product flows while helping to reduce future operating costs. Additional spending on the company’s base optimization efforts (e.g. pipeline pigging and well servicing) have helped improve base production volumes. Cost pressures due to a busier operating environment and air emissions compliance costs are expected to continue through 2018 and are reflected in our revised LOE, gas plant and midstream expense guidance.

Below is a breakout of the Company's regional operating expenses for the second quarter of 2018.

 
 Three Months Ended June 30, 2018
 Wattenberg Mid-Continent Total Company
 ($M) ($/Boe) ($M) ($/Boe) ($M) ($/Boe)
Lease operating expense$8,247  $6.01  $3,069  $11.45  $11,316  $6.90 
Gas plant and midstream operating expense$2,181  $1.59  $1,066  $3.98  $3,247  $1.98 
Total$10,428  $7.60  $4,135  $15.43  $14,563  $8.88 
                        

The Company's general and administrative ("G&A") expense was $9.9 million for the second quarter of 2018, which includes $2.2 million in stock compensation. This represents a 48% decrease from the second quarter of 2017. Cash G&A expense, which excludes stock compensation, was $7.7 million for the quarter and is tracking at the low-end of the Company's full year 2018 guidance.

Reported net income for the second quarter of 2018 was $4.9 million, or $0.24 per diluted share. Adjusted net income for the second quarter of 2018 was $24.2 million, or $1.18 per diluted share.

Adjusted EBITDAX for the second quarter of 2018 was $34.8 million.

Cash G&A, Adjusted net income, and Adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the schedules at the end of this release for additional information about these measures.

The table below summarizes the Company's annual results as compared to previously provided guidance.

    
Guidance vs Actual Summary   
 2Q18 Guidance 2Q18 Actual
Production (MBoe/d)18.0 - 18.6  18.0 
    
 Annual Guidance YTD Actual
Lease operating expense ($/Boe)$5.00 - $6.00 $6.92 
Gas plant and midstream operating expense ($/Boe)$1.40 - $1.80 $2.18 
Cash G&A ($MM)*$33 - $35 $16 
Production taxes (% of pre-derivative realization)7% - 8%  8%
CAPEX ($MM)$280 - $320 $95 
    
* Cash G&A guidance is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A. Please refer to the non-GAAP disclosure at the end of this release for information regarding cash G&A.
 

Production, Capital, and Expense Outlook

The Company is updating its 2018 annual guidance to account for strong well performance in the Wattenberg and the sale of the Mid-Continent operations on August 6, 2018.  Third quarter 2018 production and operating expense guidance is also being provided for the full company and pro-forma for the sale of the Mid-Continent operations. Below is a table summarizing the Company's production, capital, and expense guidance for the remainder of 2018.

      
Guidance Summary     
 Three Months Ended
September 30, 2018
(Pro-forma)(1)
Three Months Ended
September 30, 2018
 Twelve Months Ended
December 31, 2018
 
      
Production (MBoe/d)16.6 - 17.217.4 - 18.0 17.4 - 18.0  
LOE ($/Boe)$4.40 - $4.80$4.75 - $5.15 $5.50 - $5.90  
Midstream expense ($/Boe)$1.25 - $1.45$1.45 - $1.65 $1.70 - $1.90  
Recurring cash G&A* ($MM)   $32.5 - $33.5  
Production taxes (% of pre-derivative realization)   7% - 8% 
Total CAPEX ($MM)   $275 - $295 
      
* Recurring Cash G&A is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A. 
(1) Pro-forma is the Company estimate for the third quarter of 2018 excluding results from the Mid-Continent operations.  
   

Operational Highlights

During the second quarter of 2018, the Company spud 12 gross (8.1 net) operated wells, ten of which were extended reach lateral ("XRL") wells, and completed 11 gross (11.0 net) operated wells, six of which were XRL wells.

The Company continues to be encouraged by its eight-well F26 pad on its western legacy acreage. These eight standard reach lateral ("SRL") wells have average cumulative production of 18.3 MBoe per 1,000 feet of lateral after 178 days of production. Additionally, the Company has finished completing and turned to production all eight XRL wells in the French Lake area. While two of the wells are currently hindered by mechanical issues, the Company is very pleased with the early results of the remaining six XRLs with results meeting or exceeding expectations.

The Company has provided updated production results for these wells in its August Investor Presentation, which is available on the Company's website.

The Company continued to benefit from multiple delivery points on the RMI system in the second quarter, including the Sterling interconnect which came online in the fourth quarter 2017. This delivery point flexibility, combined with consistent low line pressures on RMI, helped ensure minimal production curtailments. The Company entered into a new agreement with Cureton Front Range LLC (“Cureton”) whereby Cureton will gather and process gas from the Company’s northern acreage.  In addition to gathering and processing services, the new agreement provides flow assurance by adding 15 MMcf per day of firm gas processing capacity for up to twenty-five years. The Company also secured three years of downstream residue transportation from Cureton in order to support upcoming production needs. This improves the Company’s flexibility to manage system pressures across its Wattenberg position and provides the backbone infrastructure system to allow development of the northern acreage.

Upon completing the 2018 resource assessment and as a result of rapidly improving well performance, the Company has identified over 1,000 economic SRL equivalent locations in its Wattenberg position.

Financial Highlights

As of the end of the second quarter, the Company had liquidity of $153.7 million, which included cash on hand of $22.0 million and $131.7 million of borrowing capacity under its credit facility.  Pro forma for the Mid-Continent divestiture which closed on August 6, 2018, the Company had $256.6 million in liquidity.  The balance sheet strength and Wattenberg inventory provide the company with a strong position from which to deliver disciplined, return-oriented growth.

Commodity Derivative Position

The Company's current hedge position is summarized in the table below and reflects additional hedges the Company entered into through August 8, 2018. Subsequent to quarter-end, the Company entered into natural gas basis swaps between NYMEX Henry Hub price and the Colorado Interstate Gas (CIG) Rockies Natural Gas price, the index on which the majority of the Company's natural gas is sold.

      
  Crude Oil
(NYMEX WTI)
 Natural Gas
(NYMEX Henry Hub)
Natural Gas
(NYMEX Henry Hub)
  Bbls/day Weighted
Avg. Price
per Bbl
 MMBtu/day Weighted
Avg. Price
per MMBTU
MMBtu/day Weighted Avg.
Basis Differential
to NYMEX Henry
Hub Price
per MMBtu
3Q18           
Cashless Collar 2,000 $43.00/$53.50 13,600 $2.75/$3.32  —
Swap 5,000 $57.87    —
  Basis Swap   —  8,354 $0.67
4Q18           
Cashless Collar 2,000 $43.00/$53.50 12,600 $2.75/$3.35  —
Swap 5,000 $58.07    —
  Basis Swap   —  12,600 $0.67
1Q19           
Cashless Collar 2,000 $43.00/$54.53 7,600 $2.75/$3.22  —
Swap 5,000 $59.33    —
  Basis Swap   —  7,600 $0.67
2Q19           
Cashless Collar 3,330 $51.81/$64.23 2,505 $2.75/$3.22  —
Swap 4,500 $58.32    —
3Q19           
Swap 3,000 $55.00    —
4Q19           
Swap 3,000 $55.00    —
            

Conference Call Information

The Company will host a conference call to discuss these financial and operating results on August 9, 2018 at 10:00 a.m. Mountain Time (12:00 p.m. Eastern Time). A webcast of the live event, as well as a replay, will be available on the Investor Relations section of the Company’s website at www.bonanzacrk.com. Dial-in information for the conference call is included below.

   
TypePhone NumberPasscode
Live Participant877-793-43623289067
Replay855-859-20563289067
   

About Bonanza Creek Energy, Inc.

Bonanza Creek Energy, Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. The Company’s assets and operations are concentrated in the Rocky Mountain region in the Wattenberg Field, focused on the Niobrara and Codell formations. The Company’s common shares are listed for trading on the NYSE under the symbol: “BCEI.” For more information about the Company, please visit www.bonanzacrk.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These statements include statements regarding development and completion expectations and strategy; decreasing operating and capital costs; impact of the Company's reorganization; and updated 2018 guidance. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, that may cause actual results to differ materially from those implied or expressed by the forward-looking statements, including the following: changes in natural gas, oil and NGL prices; general economic conditions, including the performance of financial markets and interest rates; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; ability to acquire adequate supplies of water; risks related to derivative instruments; access to adequate gathering systems and pipeline take-away capacity; and pipeline and refining capacity constraints. Further information on such assumptions, risks and uncertainties is available in the Company’s SEC filings. We refer you to the discussion of risk factors in our Annual Report on Form 10-K for the year ended December 31, 2017, filed on March 15, 2018, and other filings submitted by us to the Securities Exchange Commission. The Company’s SEC filings are available on the Company’s website at www.bonanzacrk.com and on the SEC’s website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

For further information, please contact:
Doug Atkinson
Senior Manager, Investor Relations
720-225-6690
[email protected]

 
Schedule 1: Statements of Operations
(in thousands, expect for per share amounts, unaudited)
 
 Successor  Predecessor
 Three Months Ended
June 30, 2018
 April 29, 2017 through
June 30, 2017
  April 1, 2017 through
April 28, 2017
Operating net revenues:      
Oil and gas sales$71,872  $28,114   $16,030 
Operating expenses:      
Lease operating expense11,316  6,153   3,203 
Gas plant and midstream operating expense3,247  1,762   836 
Gathering, transportation and processing1,660      
Severance and ad valorem taxes6,071  2,408   1,352 
Exploration221  359   292 
Depreciation, depletion and amortization9,564  4,836   6,853 
Abandonment and impairment of unproved properties(1)2,477      
General and administrative (including $2,184, $7,949 and
$391, respectively, of stock-based compensation)
9,917  16,139   2,998 
Total operating expenses44,473  31,657   15,534 
Income (loss) from operations27,399  (3,543)  496 
Other income (expense):      
Derivative loss(22,012)     
Interest expense(805) (195)  (1,088)
Reorganization items, net     97,811 
Other income (expense)277  158   (283)
Total other income (expense)(22,540) (37)  96,440 
Income (loss) from operations before taxes4,859  (3,580)  96,936 
Income tax benefit (expense)      
Net income (loss)$4,859  $(3,580)  $96,936 
       
Comprehensive income (loss)$4,859  $(3,580)  $96,936 
       
Basic net income (loss) per common share$0.24  $(0.18)  $1.88 
       
Diluted net income (loss) per common share$0.24  $(0.18)  $1.85 
       
Basic weighted-average common shares outstanding20,488  20,369   49,902 
       
Diluted weighted-average common shares outstanding20,603  20,369   50,486 
          

Note: The Predecessor Company followed the two-class method when computing the basic and diluted net income (loss) per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.
(1) The Company incurred impairment charges relating to the standard amortization of unproved properties within the Wattenberg Field during the Current Successor quarter.   

     
 Successor  Predecessor
 Six Months Ended
June 30, 2018
 April 29, 2017 through
June 30, 2017
  January 1, 2017 through
April 28, 2017
Operating net revenues:      
Oil and gas sales$136,064  $28,114   $68,589 
Operating expenses:      
Lease operating expense21,775  6,153   13,128 
Gas plant and midstream operating expense6,860  1,762   3,541 
Gathering, transportation and processing3,998      
Severance and ad valorem taxes11,303  2,408   5,671 
Exploration250  359   3,699 
Depreciation, depletion and amortization17,072  4,836   28,065 
Abandonment and impairment of unproved properties(1)4,979      
Unused commitments21     993 
General and administrative (including $3,192, $7,949 and
$2,116, respectively, of stock-based compensation)
19,451  16,139   15,092 
Total operating expenses85,709  31,657   70,189 
Income (loss) from operations50,355  (3,543)  (1,600)
Other income (expense):      
Derivative loss(30,754)     
Interest expense(1,162) (195)  (5,656)
Reorganization items, net     8,808 
Other income290  158   1,108 
Total other income (expense)(31,626) (37)  4,260 
Income (loss) from operations before taxes18,729  (3,580)  2,660 
Income tax benefit (expense)      
Net income (loss)$18,729  $(3,580)  $2,660 
       
Comprehensive income (loss)$18,729  $(3,580)  $2,660 
       
Basic net income (loss) per common share$0.91  $(0.18)  $0.05 
       
Diluted net income (loss) per common share$0.91  $(0.18)  $0.05 
       
Basic weighted-average common shares outstanding20,471  20,369   49,559 
       
Diluted weighted-average common shares outstanding20,538  20,369   50,971 
          

Note: The Predecessor Company followed the two-class method when computing the basic and diluted net income (loss) per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.
(1) The Company incurred impairment charges relating to non-core leases expiring and the standard amortization of unproved properties within the Wattenberg Field during the Current Successor Period.

 
Schedule 2: Statements of Cash Flows
(in thousands, unaudited)
 
 Successor Successor  Predecessor
 Three Months Ended
June 30, 2018
 April 29, 2017 through
June 30, 2017
  April 1, 2017 through
April 28, 2017
Cash flows from operating activities:      
Net income (loss)$4,859  $(3,580)  $96,936 
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities:
      
Depreciation, depletion and amortization9,564  4,836   6,853 
Non-cash reorganization items     (101,501)
Abandonment and impairment of unproved properties2,477      
Well abandonment costs and dry hole expense  64   230 
Stock-based compensation2,184  7,949   391 
Amortization of deferred financing costs and debt premium     374 
Derivative loss22,012      
Derivative cash settlements(7,310)     
Other  5   (365)
Changes in current assets and liabilities:      
Accounts receivable(4,618) 6,420   (2,826)
Prepaid expenses and other assets(2,467) 270   1,499 
Accounts payable and accrued liabilities(323) (19,338)  (36,972)
Settlement of asset retirement obligations(132) (459)  (155)
Net cash provided by (used in) operating activities26,246  (3,833)  (35,536)
Cash flows from investing activities:      
Acquisition of oil and gas properties(1,197) (4,982)  (6)
Exploration and development of oil and gas properties(53,818) (4,913)  (1,698)
Proceeds from sale of oil and gas properties      
Additions to property and equipment - non oil and gas(177) (161)  (253)
Net cash used in investing activities(55,192) (10,056)  (1,957)
Cash flows from financing activities:      
Proceeds from credit facility45,000      
Payments to credit facility     (191,667)
Proceeds from sale of common stock     207,500 
Proceeds from exercise of stock options968      
Payment of employee tax withholdings in exchange for the return of common stock(794) (2,080)  (92)
Net cash provided by (used in) financing activities45,174  (2,080)  15,741 
Net change in cash, cash equivalents and restricted cash16,228  (15,969)  (21,752)
Cash, cash equivalents and restricted cash:      
Beginning of period5,840  68,406   90,158 
End of period$22,068  $52,437   $68,406 
             


 
 Successor  Predecessor
 Six Months Ended
June 30, 2018
 April 29, 2017 through
June 30, 2017
  January 1, 2017 through
April 28, 2017
Cash flows from operating activities:      
Net income (loss)$18,729  $(3,580)  $2,660 
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities:
      
Depreciation, depletion and amortization17,072  4,836   28,065 
Non-cash reorganization items     (44,160)
Abandonment and impairment of unproved properties4,979      
Well abandonment costs and dry hole expense  64   2,931 
Stock-based compensation3,192  7,949   2,116 
Amortization of deferred financing costs and debt premium     374 
Derivative loss30,754      
Derivative cash settlements(11,622)     
Other172  5   18 
Changes in current assets and liabilities:      
Accounts receivable(20,376) 6,420   (6,640)
Prepaid expenses and other assets935  270   963 
Accounts payable and accrued liabilities(889) (19,338)  (5,880)
Settlement of asset retirement obligations(797) (459)  (331)
Net cash provided by (used in) operating activities42,149  (3,833)  (19,884)
Cash flows from investing activities:      
Acquisition of oil and gas properties(1,295) (4,982)  (445)
Exploration and development of oil and gas properties(91,482) (4,913)  (5,123)
Proceeds from sale of oil and gas properties20      
Additions to property and equipment - non oil and gas(280) (161)  (454)
Net cash used in investing activities(93,037) (10,056)  (6,022)
Cash flows from financing activities:      
Proceeds from credit facility60,000      
Payments to credit facility     (191,667)
Proceeds from sale of common stock     207,500 
Proceeds from exercise of stock options968      
Payment of employee tax withholdings in exchange for the return of common stock(794) (2,080)  (427)
Net cash provided by (used in) financing activities60,174  (2,080)  15,406 
Net change in cash, cash equivalents and restricted cash9,286  (15,969)  (10,500)
Cash, cash equivalents and restricted cash:      
Beginning of period12,782  68,406   78,906 
End of period$22,068  $52,437   $68,406 
             


 
Schedule 3: Condensed Consolidated Balance Sheets
 
 Successor
 June 30, 2018 December 31, 2017
ASSETS   
Current assets:   
Cash and cash equivalents$  21,989  $12,711 
Accounts receivable:   
Oil and gas sales38,830  28,549 
Joint interest and other13,926  3,831 
Prepaid expenses and other5,620  6,555 
Inventory of oilfield equipment1,434  1,019 
Derivative assets39  488 
Total current assets81,838  53,153 
Property and equipment (successful efforts method):   
Proved properties552,858  555,341 
Less: accumulated depreciation, depletion and amortization(29,703) (17,032)
Total proved properties, net523,155  538,309 
Unproved properties179,735  183,843 
Wells in progress52,747  47,224 
Oil and gas properties held for sale, net of accumulated depreciation,
depletion and amortization of $2,583 in 2018
82,328   
Other property and equipment, net of accumulated depreciation
of $2,722 in 2018 and $2,224 in 2017
4,488  4,706 
Total property and equipment, net842,453  774,082 
Long-term derivative assets  6 
Other noncurrent assets3,151  3,130 
Total assets$  927,442  $830,371 
LIABILITIES AND STOCKHOLDERS’ EQUITY   
Current liabilities:   
Accounts payable and accrued expenses$50,242  $62,129 
Oil and gas revenue distribution payable20,355  15,667 
Derivative liability28,416  11,423 
Total current liabilities99,013  89,219 
    
Long-term liabilities:   
Credit facility60,000   
Ad valorem taxes19,803  11,584 
Long-term derivative liability4,657  2,972 
Asset retirement obligations for oil and gas properties28,154  38,262 
Asset retirement obligations for oil and gas properties held for sale5,386   
Total liabilities217,013  142,037 
    
Commitments and contingencies   
    
Stockholders’ equity:   
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding   
Common stock, $.01 par value, 225,000,000 shares authorized, 20,534,799 and
20,453,549 issued and outstanding in 2018 and 2017, respectively
4,286  4,286 
Additional paid-in capital692,434  689,068 
Retained earnings (deficit)13,709  (5,020)
Total stockholders’ equity710,429  688,334 
Total liabilities and stockholders’ equity$927,442  $830,371 
        


 
Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
(unaudited)
 
 Three Months Ended
June 30,
 Six Months Ended
June 30,
 2018 2017 2018 2017
Wellhead Volumes and Prices       
        
Crude Oil and Condensate Sales Volumes (Bbl/d)       
Rocky Mountains8,866  6,189  8,575  6,690 
Mid-Continent1,600  1,845  1,633  1,889 
Total10,466  8,034  10,208  8,579 
        
Crude Oil and Condensate Realized Prices ($/Bbl)       
Rocky Mountains$63.05  $43.94  $60.15  $45.94 
Mid-Continent$67.12  $47.69  $64.69  $49.65 
Composite$63.67  $44.80  $60.87  $46.76 
Composite (after derivatives)$55.99  $44.80  $54.47  $46.76 
        
Natural Gas Liquids Sales Volumes (Bbl/d)       
Rocky Mountains3,126  3,046  2,772  3,167 
Mid-Continent441  452  444  471 
Total3,567  3,498  3,216  3,638 
        
Natural Gas Liquids Realized Prices ($/Bbl)       
Rocky Mountains$17.06  $16.10  $19.34  $15.90 
Mid-Continent$33.13  $20.84  $30.92  $23.32 
Composite$19.05  $16.71  $20.94  $16.86 
Composite (after derivatives)$19.05  $16.71  $20.94  $16.86 
        
Natural Gas Sales Volumes (Mcf/d)       
Rocky Mountains18,511  20,144  18,385  20,786 
Mid-Continent5,421  6,067  5,444  6,249 
Total23,932  26,211  23,829  27,035 
        
Natural Gas Realized Prices ($/Mcf)       
Rocky Mountains$1.96  $2.18  $2.29  $2.29 
Mid-Continent$2.70  $3.06  $2.98  $3.15 
Composite$2.13  $2.38  $2.45  $2.49 
Composite (after derivatives)$2.13  $2.38  $2.50  $2.49 
        
Crude Oil Equivalent Sales Volumes (Boe/d)       
Rocky Mountains15,077  12,592  14,412  13,322 
Mid-Continent2,945  3,308  2,985  3,402 
Total18,022  15,900  17,397  16,724 
        
Crude Oil Equivalent Sales Prices ($/Boe)       
Rocky Mountains$43.02  $28.98  $42.43  $30.43 
Mid-Continent$46.40  $35.05  $45.43  $36.60 
Composite$43.57  $30.24  $42.95  $31.68 
Composite (after derivatives)$39.11  $30.24  $39.26  $31.68 
        
Total Sales Volumes (MBoe)1,640.0  1,446.9  3,148.8  3,026.9 
            


 
Schedule 5: Per unit operating margins
(unaudited)
 
 Three Months Ended June 30, Six Months Ended June 30,
 2018 2017 Percent
Change
 2018 2017 Percent
Change
Production           
Oil (MBbl)952  731  30% 1,848  1,553  19%
Gas (MMcf)2,178  2,385  (9)% 4,313  4,893  (12)%
NGL (MBbl)325  318  2% 582  659  (12)%
Equivalent (MBoe)1,640  1,447  13% 3,149  3,027  4%
            
Realized pricing (before derivatives)           
Oil ($/Bbl)$63.67  $44.80  42% $60.87  $46.76  30%
Gas ($/Mcf)$2.13  $2.38  (11)% $2.45  $2.49  (2)%
NGL ($/Bbl)$19.05  $16.71  14% $20.94  $16.86  24%
Equivalent ($/Boe)$43.57  $30.24  44% $42.95  $31.68  36%
            
Per Unit Costs ($/Boe)           
Realized price equivalent (before derivatives)$43.57  $30.24  44% $42.95  $31.68  36%
Lease operating expense6.90  6.47  7% 6.92  6.37  9%
Gathering, transportation and processing1.01    % 1.27    %
Gas plant and midstream operating expense1.98  1.80  10% 2.18  1.75  25%
Severance and ad valorem3.70  2.60  42% 3.59  2.67  34%
Cash general and administrative4.72  7.46  (37)% 5.16  6.99  (26)%
Total cash operating costs$18.31  $18.33  % $19.12  $17.78  8%
Cash operating margin (before derivatives)$25.26  $11.91  112% $23.83  $13.90  71%
Derivative cash settlements(4.46)   % (3.69)   %
Cash operating margin (after derivatives)$20.80  $11.91  75% $20.14  $13.90  45%
            
Non-cash items           
Non-cash general and administrative$1.33  $5.76  (77)% $1.01  $3.33  (70)%
                      

Schedule 6: Adjusted Net Income
(in thousands, except per share amounts, unaudited)

Adjusted net income is a supplemental non-GAAP financial measure that is used by management to present recurring profitability that is more comparable between periods by excluding items that are non-recurring in nature or items which are not easily estimable. Management believes adjusted net income provides external users of the Company's consolidated financial statements such as industry analysts, investors, creditors, and rating agencies with additional information to assist in their analysis of the Company. The Company defines adjusted net income as net income after adjusting first for (1) the impact of certain non-cash items and one-time transactions and then (2) the non-cash and one time items’ impact on taxes based on a tax rate that approximates the Company's effective tax rate in each period. Adjusted net income is not a measure of net income as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of adjusted net income.

     
  Three Months Ended
June 30,
 Six Months Ended
June 30,
  2018 2017 2018 2017
Net income (loss) $4,859  $93,356  $18,729  $(920)
Adjustments to net income:        
Derivative loss 22,012    30,754   
Derivative cash settlements (7,310)   (11,622)  
Abandonment and impairment of unproved properties 2,477    4,979   
Exploratory dry hole expense   294    2,995 
Unused commitments     21  993 
Stock-based compensation (1) 2,184  8,340  3,192  10,065 
Reorganization items, net   (97,811)   (8,808)
Pre-petition advisory fees (1)       683 
Post-petition restructuring fees (1)   1,422    1,422 
Total adjustments before taxes 19,363  (87,755) 27,324  7,350 
Income tax effect        
Total adjustments after taxes $19,363  $(87,755) $27,324  $7,350 
         
Adjusted net income $24,222  $5,601  $46,053  $6,430 
Adjusted net income per diluted share (2) $1.18  $0.27  $2.24  $0.32 
         
Diluted weighted-average common shares outstanding (2) 20,603  20,369  20,538  20,369 
         
(1) Included as a portion of general and administrative expense in the consolidated statements of operations.
(2) For the three- and six-month periods ended June 30, 2017, the Company used the Successor's diluted weighted average share count to calculate adjusted net income per diluted share.
 

Schedule 7: Adjusted EBITDAX
(in thousands, unaudited)

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management to provide a metric of the Company's ability to internally generate funds for exploration and development of oil and gas properties. The metric excludes items which are non-recurring in nature and/or items which are not reasonably estimable. Management believes adjusted EBITDAX provides external users of the Company’s consolidated financial statements such as industry analysts, investors, lenders, and rating agencies with additional information to assist in their analysis of the Company. The Company defines Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment, exploration expenses and other similar non-cash and non-recurring charges. Adjusted EBITDAX is not a measure of net income (loss) or cash flows as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.

     
  Three Months Ended June 30, Six Months Ended June 30,
  2018 2017 2018 2017
Net income (loss) $4,859  $93,356  $18,729  $(920)
Exploration 221  651  250  4,058 
Depreciation, depletion and amortization 9,564  11,689  17,072  32,901 
Abandonment and impairment of unproved properties 2,477    4,979   
Unused commitments     21  993 
Stock-based compensation (1) 2,184  8,340  3,192  10,065 
Interest expense 805  1,283  1,162  5,851 
Derivative loss 22,012    30,754   
Derivative cash settlements (7,310)   (11,622)  
Pre-petition advisory fees (1)       683 
Post-petition restructuring fees (1)   1,422    1,422 
Reorganization items, net   (97,811)   (8,808)
Adjusted EBITDAX $34,812  $18,930  $64,537  $46,245 
         
(1) Included as a portion of general and administrative expense in the consolidated statements of operations.
 

Schedule 8: Cash G&A
(in thousands, unaudited)

Cash G&A is a supplemental non-GAAP financial measure that is used by management to provide only the cash portion of its G&A expense, which can be used to evaluate cost management and operating efficiency on a comparable basis from period to period. Management believes cash G&A provides external users of the Company’s consolidated financial statements such as industry analysts, investors, lenders, and rating agencies with additional information to assist in their analysis of the Company. The Company defines cash G&A as GAAP general and administrative expense exclusive of the Company's stock based compensation and one-time charges, such as severance costs and advisor fees. The Company refers to cash G&A to provide typical cash G&A costs that are planned for in a given period. Cash G&A is not a fully inclusive measure of general and administrative expense as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of general and administrative expense to the non-GAAP financial measure of cash G&A.

     
  Three Months Ended June 30, Six Months Ended June 30,
  2018 2017 2018 2017
General and administrative $9,917  $19,137  $19,451  $31,231 
Stock-based compensation (2,184) (8,340) (3,192) (10,065)
Cash G&A $7,733  $10,797  $16,259  $21,166 
Post-petition restructuring fees   (1,422)   (1,422)
Other non-recurring expense   (184)   (184)
Recurring Cash G&A $7,733  $9,191  $16,259  $19,560 

Primary Logo


Source: GlobeNewswire (August 8, 2018 - 5:34 PM EDT)

News by QuoteMedia
www.quotemedia.com

Legal Notice