• Bonanza Creek Energy Announces Third Quarter 2017 Financial Results and Operational Update

    Source: Nasdaq GlobeNewswire / 08 Nov 2017 16:30:33   America/New_York

    • Production from enhanced completions is outperforming offset wells by ~40%
    • Expecting ~15% reductions to annualized LOE and midstream operating expense
    • Improved drilling cycle times with record spud-to-total depth of 3.4 days for a 4,100' lateral
    • Third quarter production volumes averaged 15.8 MBoe per day

    DENVER, Nov. 08, 2017 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company" or "Bonanza Creek") today announces its third quarter 2017 financial results and operating outlook and has posted an updated investor presentation on its corporate website.

    Seth Bullock, Interim CEO commented, "Our third quarter operations program was very encouraging with great production results from our enhanced completions and record drill times on SRL wells drilled during the quarter. I am pleased to announce that initial results from our enhanced completion program are significantly out-pacing offset wells that used the previous completion design. These increased production results along with the significant structural cost reductions that have been identified and implemented this year are laying the ground work for a strong 2018. I am confident that this reorganized Company is successfully shaping a culture that pursues continuous improvement and maximizes returns for its shareholders."

    Operational Highlights

    Production Results from Enhanced Completions
    At the end of the second quarter, the Company completed its first pad of four drilled uncompleted ("DUC") wells which utilized enhanced completion design. These 4,100-foot standard reach lateral ("SRL") wells were completed using approximately 2,000 pounds of sand per lateral foot, approximately 100-foot stage spacing, and enhanced recovery flow back. Initial results from these first four wells are very encouraging, with an approximate 40% increase in overall average production and an approximate 60% increase in average oil production through the first 120 days when compared to offsetting wells. The offsetting wells utilized the Company's previous standard design of approximately 1,000 pounds of sand per lateral foot and stage spacing of approximately 225 feet.

    Drilling and Completion Activity
    During the third quarter the Company's operated program drilled six gross and net wells (4 SRL and 2 XRL), and completed zero wells. The Company's non-operated program had one net completion during the third quarter. Newly drilled wells for the quarter included three wells on the Company's central legacy acreage, one well on its French Lake acreage, and two wells of an eight-well pad on its western legacy acreage. The Company's non-operated program had four gross, one net completion during the third quarter. Subsequent to the quarter, the Company finished drilling its 8-well pad and completed five wells on its central acreage positions, and completed its one French Lake well. The results from these wells along with the remaining 2017 program, which exclusively utilized an enhanced completion design, are expected during the first half of 2018 and will help to inform the Company's drilling and completion program into 2019. Year-to-date, the Company's operated drilling program has exceeded expectations with faster drill times. Spud-to-rig release times have decreased by approximately 20% when compared to the 2016 program, and are currently averaging less than six days for an SRL.

    Wattenberg Gas Takeaway
    Due to increased line pressures on the gathering system operated by the Company's primary gas processor, Bonanza Creek entered into a 15-year gas purchase agreement with Sterling Energy Investments, LLC, a nearby third-party gas processor, on September 1, 2017. The agreement will allow the Company to deliver approximately 6.5 MMcf per day of wet gas, or approximately 20% of the Company's third quarter 2017 Rocky Mountain gas production, into Sterling's system. A new pipeline and interconnect, constructed by Sterling, will provide an additional gas processing outlet for gas production from the Company via its Rocky Mountain Infrastructure (RMI) gas gathering system. Gas will begin flowing to Sterling during the first half of November 2017.  The Company is currently evaluating additional alternatives to minimize the potential of production headwinds from regional infrastructure constraints.

    Third Quarter 2017 Results

    During the third quarter of 2017, the Company reported average daily production of 15.8 MBoe per day, at the low end of the Company's guidance range of 15.8 – 16.2 MBoe per day. Production during the quarter was negatively affected by the aforementioned increased line pressures on a third-party regional gas gathering and processing system in addition to extended downtime from offset completion operations. The Company's third quarter production decreased by 25% when compared to the third quarter of 2016 due to minimal drilling and completion activity throughout 2016 and the first half of 2017. Product mix for the third quarter of 2017 was 52% oil, 21% NGLs, and 27% natural gas. 

    Net revenue for the third quarter of 2017 was $45.2 million, compared to $49.3 million for the third quarter of 2016. Crude oil accounted for approximately 76% of total revenue. Differentials for the Company's Rocky Mountain oil production during the quarter averaged approximately $4.45 per Bbl off of NYMEX WTI. Corporate average realized prices for the third quarter of 2017 are presented below.

      
    Average Realized
    Prices
     
     Three Months Ended
    September 30, 2017
    Oil (per Bbl)44.72
    Gas (per Mcf)2.33
    NGL (per Bbl)17.79
    Boe (Per Boe)30.85
      

    Lease operating expense ("LOE") for the third quarter of 2017 was $9.6 million, or $6.63 per Boe, a 3% reduction in total LOE compared to $9.9 million or $5.13 per Boe in the third quarter of 2016. Per unit metrics increased year over year as a result of declining volumes. These metrics are expected to improve as cost reductions are implemented and production volumes stabilize and increase. Future expected LOE reductions from cost saving initiatives are discussed in the "Production, Capital, and Expense Outlook" section below.

    Below is a breakout of the Company's regional LOE and gas plant and midstream operating expense for the third quarter of 2017.

     
     
     Three Months Ended September 30, 2017
     Rocky Mountain Mid-Continent Total Company
     ($M) ($/Boe) ($M) ($/Boe) ($M) ($/Boe)
    Lease operating expense$6,638  $5.76  $3,005  $9.97  $9,643  $6.63 
    Gas plant and midstream operating expense$1,299  $1.13  $1,966  $6.52  3,265  $2.24 
    Total$7,937  $6.89  $4,971  $16.49  $12,908  $8.87 
                            

    The Company's general and administrative ("G&A") expense was $15.2 million for the third quarter of 2017, a 19% decrease from the third quarter of 2016. The decrease is primarily due to $5.9 million in advisory fees related to financial alternatives that were incurred in 2016.  The Company's recurring cash G&A for the third quarter was, $8.6 million, compared to $10.9 million in the third quarter of 2016. The 21% decrease in recurring cash G&A is due primarily to the cost reduction initiatives that were implemented since restructuring, including the previously announced reduction in force, which occurred in August of 2017.

    Recurring cash G&A is a non-GAAP measure. Please refer to the reconciliation to GAAP general and administrative expense in the financial exhibits to this press release.

    Production, Capital, and Expense Outlook

    The Company is providing updated production, capital, and expense guidance for the remainder of the year. The Company is reducing its full-year production guidance by 4%, to a mid-point of 16.0 MBoe per day as a result of increased line pressures in the basin, and significant processing downtime expected in the fourth quarter. To mitigate these line pressure issues, the Company has secured an agreement with another third party gas processor in the basin, and is actively exploring additional options to alleviate these basin level bottlenecks that negatively impact production. Due to changes in activity timing, CAPEX guidance for the year has been lowered to a midpoint of $112 million compared to previous guidance of $125 million. As a part of its ongoing cost structure review, the Company has identified further savings to its LOE, which will be implemented throughout 2018. The Company expects to reduce its run-rate LOE and gas plant/midstream operating expense by approximately $8.0 to $9.0 million in total, or approximately 15% of their annualized third quarter amounts, by the beginning of 2019. These LOE savings along with the previously announced G&A savings are concrete examples of the Company's commitment to reducing its cost structure and increasing full-cycle returns.

     Below is a table summarizing the Company's production, capital, and expense guidance for the remainder of 2017.

    Guidance Summary   
     Three Months Ended
    December 31, 2017
     Twelve Months Ended
    December 31, 2017
        
    Production (MBoe/d)13.8 – 14.2 15.7 – 15.9
    LOE ($/Boe)  $6.50 – $7.00
    Midstream expense ($/Boe)  $1.90 – $2.10
    Cash G&A* ($MM)  $41 – $43
    Production taxes (% of pre-derivative realization)  7% – 8%
    Total CAPEX ($MM)  $108 – $115
    * Cash G&A guidance assumes severance costs of $1.6 million in the third quarter of 2017 and non-recurring expenses of $5.4 million. 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 less certainty to the stock based compensation portion of GAAP G&A.
     

    Financial Highlights

    As of the end of the third quarter, the Company had liquidity of $223 million, which included cash on hand of $31 million and $192 million of borrowing capacity under its credit facility.  The Company has no outstanding term debt and its credit facility is undrawn. Based on the terms of the credit facility, the Company's next borrowing base redetermination will occur in April of 2018. The Company's balance sheet strength allows it to be flexible, patient and selective in its investment decisions, and the opportunity to participate in acquisition opportunities and the flexibility to objectively evaluate divestiture candidates.

    Commodity Derivative Position
    The Company's current hedge position is summarized in the table below and reflects additional hedges the Company entered into through October 27, 2017.


         
      Crude Oil
    (NYMEX WTI)
     Natural Gas
    (NYMEX Henry Hub)
      Bbls/day Weighted Avg.
    Price per Bbl
     MMBtu/day Weighted Avg.
    Price per MMBtu
    4Q17        
    Swap 2,000  $51.86 —   —
    Collar 2,000  $41.50/$51.00 2,600  $3.00/$3.30
    1Q18        
    Swap 2,000  $51.61 6,000  $3.36
    Collar 2,000  $42.00/$52.50 5,600  $2.75/$3.43
    2Q18        
    Swap 2,000  $51.61 —   —
    Collar 2,000  $42.00/$52.50 5,600  $2.75/$3.43
    3Q18        
    Swap 2,000  $51.96 —   —
    Collar 2,000  $43.00/$53.50 5,600  $2.75/$3.43
    4Q18        
    Swap 2,000  $51.96 —   —
    Collar 2,000  $43.00/$53.50 5,600  $2.75/$3.43
    1Q19        
    Swap —   — —   —
    Collar 2,000  $43.00/$54.53 2,600  $2.75/$3.40
     2Q19        
    Swap —   — —   —
    Collar 1,330  $44.01/$54.79 857  $2.75/$3.40
             


    Conference Call Information

    The Company will host a conference call to discuss these financial and operating results on November 9, 2017 at 8:00 a.m. Mountain Time (10:00 a.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 Participant877-793-43627577527
    Replay855-859-20567577527

    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 primarily in the Rocky Mountain region in the Wattenberg Field, focused on the Niobrara and Codell formations, and in southern Arkansas, focused on oily Cotton Valley sands. 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 2017 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, 2016, filed on March 16, 2017, 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:
    James R. Edwards
    Director - Investor Relations
    720-440-6136
    jedwards@bonanzacrk.com


    Schedule 1: Statement of Operations

    (in thousands, expect for per share amounts, unaudited)

     Successor  Predecessor
     Three Months Ended
    September 30, 2017
      Three Months Ended
    September 30, 2016
         
    Operating net revenues:    
    Oil and gas sales$45,232   $49,325 
    Operating expenses:    
    Lease operating expense9,643   9,893 
    Gas plant and midstream operating expense3,265   2,874 
    Severance and ad valorem taxes2,434   4,100 
    Depreciation, depletion and amortization7,350   27,296 
    Abandonment and impairment of unproved properties   7,682 
    Unused commitments   1,688 
    General and administrative (including $2,646 and $1,863, respectively, of stock-based compensation)15,181   18,671 
    Total operating expenses37,873   72,204 
    Income (loss) from operations7,359   (22,879)
    Other income (expense):    
    Derivative gain (loss)(2,762)  2,206 
    Interest expense(265)  (15,142)
    Other income (loss)(4)  913 
    Total other expense(3,031)  (12,023)
    Income (loss) from operations before taxes4,328   (34,902)
    Income tax benefit (expense)    
    Net income (loss)$4,328   $(34,902)
    Comprehensive income (loss)$4,328   $(34,902)
         
    Basic net income (loss) per common share$0.21   $(0.71)
         
    Diluted net income (loss) per common share$0.21   $(0.71)
         
    Basic weighted-average common shares outstanding20,439   49,324 
         
    Diluted weighted-average common shares outstanding20,447   49,324 
           
    • The Predecessor Company followed the two-class method when computing the basic and diluted 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.

     
     Successor  PredecessorPredecessor
     April 29, 2017 through
    September 30, 2017
      January 1, 2017
    through April 28, 2017
    Nine Months Ended
    September 30, 2016
    Operating net revenues:     
    Oil and gas sales$73,346   $68,589 $148,029 
    Operating expenses:     
    Lease operating expense15,796   13,128 33,928 
    Gas plant and midstream operating expense5,027   3,541 10,198 
    Severance and ad valorem taxes4,842   5,671 11,531 
    Exploration359   3,699 943 
    Depreciation, depletion and amortization12,186   28,065 84,602 
    Impairment of oil and gas properties    10,000 
    Abandonment and impairment of unproved properties    24,463 
    Unused commitments   993 3,460 
    General and administrative (including $10,595,        
     $2,116 and $7,249, respectively, of stock-based compensation)31,320   15,092 49,591 
    Total operating expenses69,530   70,189 228,716 
    Income (loss) from operations3,816   (1,600)(80,687)
    Other income (expense):     
    Derivative loss(2,762)   (11,724)
    Interest expense(460)  (5,656)(46,216)
    Reorganization items, net   8,808  
    Gain on termination fee    6,000 
    Other income154   1,108 1,011 
    Total other income (expense)(3,068)  4,260 (50,929)
    Income (loss) from operations before taxes748   2,660 (131,616)
    Income tax benefit (expense)     
    Net income (loss)$748   $2,660 $(131,616)
    Comprehensive income (loss)$748   $2,660 $(131,616)
          
    Basic net income (loss) per common share$0.04   $0.05 $(2.67)
          
    Diluted net income (loss) per common share$0.04   $0.05 $(2.67)
          
    Basic weighted-average common shares outstanding20,410   49,559 49,244 
          
    Diluted weighted-average common shares outstanding20,438   50,971 49,244 
             
    • The Predecessor Company followed the two-class method when computing the basic and diluted 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.

    Schedule 2: Statement of Cash Flows
    (in thousands, unaudited)

     Successor  Predecessor
     Three Months Ended
    September 30, 2017
      Three Months Ended
    September 30, 2016
         
    Cash flows from operating activities:    
    Net income (loss)$4,328   $(34,902)
    Adjustments to reconcile net income (loss) to net cash provided by operating activities:    
    Depreciation, depletion and amortization7,350   27,296 
    Abandonment and impairment of unproved properties   7,682 
    Well abandonment costs and dry hole expense10   (61)
    Stock-based compensation2,646   1,865 
    Amortization of deferred financing costs and debt premium   426 
    Derivative (gain) loss2,762   (2,206)
    Derivative cash settlements   4,348 
    Other2   1,923 
    Changes in current assets and liabilities:    
    Accounts receivable(8,447)  6,027 
    Prepaid expenses and other assets(350)  301 
    Accounts payable and accrued liabilities7,428   5,205 
    Settlement of asset retirement obligations(477)  (398)
    Net cash provided by operating activities15,252   17,506 
    Cash flows from investing activities:    
    Acquisition of oil and gas properties(92)  (103)
    Exploration and development of oil and gas properties(37,442)  (4,738)
    Increase in restricted cash(10)  (5,172)
    Additions to property and equipment - non oil and gas(506)  (145)
    Net cash used in investing activities(38,050)  (10,158)
    Cash flows from financing activities:    
    Payments to credit facility   (44,000)
    Payment of employee tax withholdings in exchange for the return of common stock(318)  (10)
    Deferred financing costs   (79)
    Net cash used in financing activities(318)  (44,089)
    Net change in cash and cash equivalents(23,116)  (36,741)
    Cash and cash equivalents:    
    Beginning of period54,212   170,171 
    End of period$31,096   $133,430 
             


          
     Successor  PredecessorPredecessor
     April 29, 2017 through
    September 30, 2017
      January 1, 2017
    through April 28, 2017
    Nine Months Ended
    September 30, 2016
          
    Cash flows from operating activities:     
    Net income (loss)$748   $2,660 $(131,616)
    Adjustments to reconcile net income (loss) to net cash provided by operating activities:     
    Depreciation, depletion and amortization12,186   28,065 84,602 
    Non-cash reorganization items   (44,160) 
    Impairment of oil and gas properties    10,000 
    Abandonment and impairment of unproved properties    24,463 
    Well abandonment costs and dry hole expense74   2,931 905 
    Stock-based compensation10,595   2,116 7,249 
    Amortization of deferred financing costs and debt premium   374 2,705 
    Derivative loss2,762    11,724 
    Derivative cash settlements    15,749 
    Other7   18 127 
    Changes in current assets and liabilities:     
    Accounts receivable(2,027)  (6,640)29,442 
    Prepaid expenses and other assets(80)  963 (1,047)
    Accounts payable and accrued liabilities(11,910)  (5,880)(23,252)
    Settlement of asset retirement obligations(936)  (331)(473)
    Net cash (used in) provided by operating activities11,419   (19,884)30,578 
    Cash flows from investing activities:     
    Acquisition of oil and gas properties(5,074)  (445)(919)
    Exploration and development of oil and gas properties(42,355)  (5,123)(47,491)
    Payments of contractual obligation    (12,000)
    (Increase) decrease in restricted cash(12)  118 (7,707)
    Additions to property and equipment - non oil and gas(667)  (454)(106)
    Net cash used in investing activities(48,108)  (5,904)(68,223)
    Cash flows from financing activities:     
    Proceeds from credit facility    209,000 
    Payments to credit facility   (191,667)(58,667)
    Proceeds from sale of common stock   207,500  
    Payment of employee tax withholdings in exchange for the return of common stock(2,398)  (427)(283)
    Deferred financing costs    (316)
    Net cash (used in) provided by financing activities(2,398)  15,406 149,734 
    Net change in cash and cash equivalents(39,087)  (10,382)112,089 
    Cash and cash equivalents:     
    Beginning of period70,183   80,565 21,341 
    End of period$31,096   $70,183 $133,430 
                


    Schedule 3: Condensed Consolidated Balance Sheets

    (in thousands, unaudited)Successor  Predecessor
     September 30,
    2017
      December 31,
    2016
    ASSETS    
    Current assets:    
    Cash and cash equivalents$31,096   $80,565 
    Accounts receivable:    
    Oil and gas sales25,443   14,479 
    Joint interest and other4,488   6,784 
    Prepaid expenses and other5,032   5,915 
    Inventory of oilfield equipment3,270   4,685 
    Derivative assets48    
    Total current assets69,377   112,428 
    Property and equipment (successful efforts method):    
    Proved properties508,955   2,525,587 
    Less: accumulated depreciation, depletion and amortization(10,771)  (1,694,483)
    Total proved properties, net498,184   831,104 
    Unproved properties183,534   163,369 
    Wells in progress44,049   18,250 
    Other property and equipment, net of accumulated depreciation of $560 in 2017 and $11,206 in 20166,163   6,245 
    Total property and equipment, net731,930   1,018,968 
    Long-term derivative assets6    
    Other noncurrent assets2,750   3,082 
    Total assets$804,063   $1,134,478 
    LIABILITIES AND STOCKHOLDERS’ EQUITY    
    Current liabilities:    
    Accounts payable and accrued expenses$50,848   $61,328 
    Oil and gas revenue distribution payable19,828   23,773 
    Derivative liability2,044    
    Revolving credit facility - current portion   191,667 
    Senior Notes - current portion   793,698 
    Total current liabilities72,720   1,070,466 
    Long-term liabilities:    
    Ad valorem taxes8,531   14,118 
    Derivative liability772    
    Asset retirement obligations for oil and gas properties28,973   30,833 
    Total liabilities110,996   1,115,417 
    Stockholders’ equity:    
    Predecessor preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding as of December 31, 2016    
    Predecessor common stock, $.001 par value, 225,000,000 shares authorized,  49,660,683 issued and outstanding as of December 31, 2016   49 
    Successor preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding as of September 30, 2017    
    Successor common stock, $.01 par value, 225,000,000 shares authorized, 20,453,444 issued and outstanding as of September 30, 20174,286    
    Additional paid-in capital688,033   814,990 
    Accumulated earnings (deficit)748   (795,978)
    Total stockholders’ equity693,067   19,061 
    Total liabilities and stockholders’ equity$804,063   $1,134,478 
             


    Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
    (unaudited)

     Three Months Ended
    September 30,
     Nine Months Ended
    September 30,
     2017 2016 2017 2016
    Wellhead Volumes and Prices       
            
    Crude Oil and Condensate Sales Volumes (Bbl/d)       
    Rocky Mountains6,447  8,845  6,632  10,403 
    Mid-Continent1,816  2,152  1,871  2,286 
    Total8,263  10,997  8,503  12,689 
            
    Crude Oil and Condensate Realized Prices ($/Bbl)       
    Rocky Mountains$43.90  $35.64  $45.27  $32.01 
    Mid-Continent$47.63  $44.33  $49.00  $41.64 
    Composite$44.72  $37.35  $46.09  $33.75 
    Composite (after derivatives)$44.72  $41.64  $46.09  $38.27 
            
    Natural Gas Liquids Sales Volumes (Bbl/d)       
    Rocky Mountains2,842  3,916  3,069  3,702 
    Mid-Continent463  607  470  667 
    Total3,305  4,523  3,539  4,369 
            
    Natural Gas Liquids Realized Prices ($/Bbl)       
    Rocky Mountains$16.31  $9.77  $16.03  $11.08 
    Mid-Continent$26.88  $17.44  $24.51  $15.38 
    Composite$17.79  $10.80  $17.16  $11.73 
    Composite (after derivatives)$17.79  $10.80  $17.16  $11.73 
            
    Natural Gas Sales Volumes (Mcf/d)       
    Rocky Mountains19,459  25,536  20,414  27,202 
    Mid-Continent5,982  7,141  6,182  7,478 
    Total25,441  32,677  26,596  34,680 
            
    Natural Gas Realized Prices ($/Mcf)       
    Rocky Mountains$2.12  $1.98  $2.24  $1.39 
    Mid-Continent$3.02  $2.93  $3.11  $2.33 
    Composite$2.33  $2.18  $2.44  $1.59 
    Composite (after derivatives)$2.33  $2.18  $2.44  $1.59 
            
    Crude Oil Equivalent Sales Volumes (Boe/d)       
    Rocky Mountains12,532  17,017  13,104  18,639 
    Mid-Continent3,276  3,949  3,372  4,199 
    Total15,808  20,966  16,476  22,838 
            
    Crude Oil Equivalent Sales Prices ($/Boe)       
    Rocky Mountains$29.58  $23.74  $30.15  $22.10 
    Mid-Continent$35.71  $32.13  $36.30  $29.26 
    Composite$30.85  $25.32  $31.41  $23.41 
    Composite (after derivatives)$30.85  $27.57  $31.41  $25.93 
            
    Total Sales Volumes (MBoe)1,454.4  1,928.9  4,481.3  6,257.5 
                


    Schedule 5: Per unit operating margins
    (unaudited)

     Three Months Ended September 30, Nine Months Ended September 30,
     2017 2016 Percent
    Change
     2017 2016 Percent
    Change
    Production           
    Oil (MBbl)760  1,012  (25)% 2,313  3,477  (33)%
    Gas (MMcf)2,341  3,006  (22)% 7,234  9,502  (24)%
    NGL (MBbl)304  416  (27)% 963  1,197  (20)%
    Equivalent (MBoe)1,454  1,929  (25)% 4,481  6,258  (28)%
                
    Realized pricing (before derivatives)           
    Oil ($/Bbl)$44.72  $37.35  20% $46.09  $33.75  37%
    Gas ($/Mcf)$2.33  $2.18  7% $2.44  $1.59  53%
    NGL ($/Bbl)$17.79  $10.80  65% $17.16  $11.73  46%
    Equivalent ($/Boe)$30.85  $25.32  22% $31.41  $23.41  34%
                
    Per Unit Costs ($/Boe)           
    Realized price (before derivatives)$30.85  $25.32  22% $31.41  $23.41  34%
    Lease operating expense6.63  5.13  29% 6.45  5.42  19%
    Gas plant and midstream operating expense2.24  1.49  50% 1.91  1.63  17%
    Severance and ad valorem1.67  2.13  (22)% 2.35  1.84  28%
    Cash general and administrative8.62  8.71  (1)% 7.52  6.77  11%
    Total cash operating costs$19.16  $17.46  10% $18.23  $15.66  16%
    Cash operating margin (before derivatives)$11.69  $7.86  49% $13.18  $7.75  70%
    Derivative cash settlements  2.25  (100)%   2.52  (100)%
    Cash operating margin (after derivatives)$11.69  $10.11  16% $13.18  $10.27  28%
                
    Non-cash items           
    Non-cash general and administrative$1.82  $0.97  88% $2.84  $1.16  145%
                          


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

    Adjusted net income (loss) is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines adjusted net loss as net loss 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 loss 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 (loss) to the non-GAAP financial measure of adjusted net loss.

         
      Three Months Ended
    September 30,
     Nine Months Ended
    September 30,
      2017 2016 2017 2016
    Net Income (Loss) $4,328  $(34,902) $3,408  $(131,616)
    Adjustments to Net Income (Loss):        
    Derivative loss 2,762  (2,206) 2,762  11,724 
    Derivative cash settlements   4,348    15,749 
    Gain on termination fee       (6,000)
    Impairment of proved properties       10,000 
    Abandonment and impairment of unproved properties   7,682    24,463 
    Exploratory dry hole expense 10  (61) 3,005  905 
    Stock-based compensation (1) 2,646  1,865  12,711  7,249 
    Advisor fees related to financial alternatives (1)   5,918    5,918 
    Severance costs (1) 1,605    1,605  2,162 
    Reorganization items  
     
     
     
    (8,808)  
    Pre-petition advisory fees (1)     683   
    Post-petition restructuring fees (1) 2,317    3,740   
    Total adjustments before taxes 9,340  17,546  15,698  72,170 
    Income tax effect        
    Total adjustments after taxes $9,340  $17,546  $15,698  $72,170 
             
    Adjusted net income (loss) $13,668  $(17,356) $19,106  $(59,446)
    Adjusted net income (loss) per diluted share (2) $0.67  $(0.35) $0.93  $(1.21)
             
    Diluted weighted-average common shares outstanding (2) 20,447  49,324  20,438  49,244 
             
    (1) Included as a portion of general and administrative expense on the consolidated statement of operations.
    (2) For the nine-month period ended September 30, 2017, the Company used the Successor's diluted weighted average share count to calculated 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 and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. 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 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
    September 30,
     Nine Months Ended
    September 30,
      2017 2016 2017 2016
    Net Income (loss) $4,328  $(34,902) $3,408  $(131,616)
    Exploration     4,058  943 
    Depreciation, depletion and amortization 7,350  27,296  40,251  84,602 
    Impairment of proved properties       10,000 
    Abandonment and impairment of unproved properties   7,682    24,463 
    Stock-based compensation 2,646  1,865  12,711  7,249 
    Severance costs (1) 1,605    1,605  2,162 
    Advisor fees related to financial alternatives (1)   5,918    5,918 
    Gain on termination fee       (6,000)
    Interest expense 265  15,142  6,116  46,216 
    Derivative (gain) loss 2,762  (2,206) 2,762  11,724 
    Derivative cash settlements   4,348    15,749 
    Pre-petition advisory fees (1)     683   
    Post-petition restructuring fees (1) 2,317    3,740   
    Reorganization items     (8,808)  
    Income tax benefit        
    Adjusted EBITDAX $21,273  $25,143  $66,526  $71,410 
             
    (1) Included as a portion of general and administrative expense on the consolidated statement of operations.
     


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

    Recurring cash G&A is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines recurring cash G&A as GAAP G&A after adjusting for the impact of non-cash stock compensation expense and non-recurring items.

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

       
      Three Months Ended September 30,
      2017 2016
    General and Administrative $15,181  $18,671 
    Stock-based compensation (2,646) (1,863)
    Cash G&A $12,535  $16,808 
    Advisor fees related to financial alternatives   (5,918)
    Post-petition restructuring fees (2,317)  
    Severance payments (1,605)  
    Recurring Cash G&A $8,613  $10,890 
             

     

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