• Bonanza Creek Energy Announces Fourth Quarter and Full Year 2017 Financial and Operating Results

    Source: Nasdaq GlobeNewswire / 14 Mar 2018 17:00:27   America/New_York

    • Quarterly GAAP cash flow from operating activities of $16.2 million; adjusted EBITDAX(1) of $21.6 million; GAAP net loss of $0.28 per diluted share; adjusted net income(1) of $0.40 per diluted share

    • 2017 all-in finding and development costs of $7.46 per Boe

    • Slick-water completion test is outperforming offset wells and expectations

    (1) Non-GAAP measure, see attached Reconciliation Schedules.

    DENVER, March 14, 2018 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today announces its fourth quarter and full year 2017 financial and operating results.

    Fourth Quarter 2017 Results
    For the fourth quarter of 2017, the Company reported quarterly and annual production volumes of 14.8 MBoe per day and 16.0 MBoe per day, respectively.  As previously announced, these production figures exceeded the high end of the Company's guidance range. As the Company brought online new wells in the back half of the year, the product mix became increasingly oil-weighted as new wells with enhanced completions and choke management increased oil cuts. The oil-weighted growth from these wells along with increased commodity prices resulted in a 6% increase in quarterly revenues, despite the 19% decrease in production volumes from the prior year. The table below provides production data for the quarter and year ended December 31, 2017.

         
      Three Months Ended Twelve Months Ended
    Avg. Daily Sales Volumes: 12/31/2017 12/31/2016 % Change 12/31/2017 12/31/2016 % Change
    Crude oil (Bbls/d) 8,350  9,058  (8)%  8,442  11,776  (28)% 
    Natural gas (Mcf/d) 22,176  29,664  (25)%  25,408  33,419  (24)% 
    Natural gas liquids (Bbls/d) 2,705  4,237  (36)%  3,319  4,336  (23)% 
    Crude oil equivalent (Boe/d) 14,750  18,239  (19)%  15,995  21,682  (26)% 
                 
    Product Mix            
    Crude oil 57% 50%   53% 54%  
    Natural gas 25% 27%   26% 26%  
    Natural gas liquids 18% 23%   21% 20%  
                 
    Average Sales Prices (before derivatives):            
    Crude oil (per Bbl) $52.00  $41.86  24%  $47.56  $35.31  35% 
    Natural gas (per Mcf) $2.23  $2.32  (4)%  $2.39  $1.76  36% 
    Natural gas liquids (per Bbl) $21.56  $14.40  50%  $18.06  $12.39  46% 
    Crude oil equivalent (per Boe) $36.73  $27.90  32%  $32.65  $24.36  34% 
                 
    Product Revenue (in thousands) $49,850  $46,823  6%  $190,617  $193,335  (1)% 
                           

    Upon emerging from bankruptcy, the Company focused on reducing operating expenses to right-size its cost structure with the current environment. The table below provides selected cash operating expenses comparatively on a quarterly and annual year-over-year basis.

                 
      Three Months Ended Twelve Months Ended
    Operating Expenses 12/31/2017 12/31/2016 % Change 12/31/2017 12/31/2016 % Change
    Lease operating expense $10,066  $9,743  3%  $38,990  $43,671  (11)% 
    Gas plant and midstream operating expense $3,314  $2,628  26%  $11,882  $12,826  (7)% 
    Severance and ad valorem taxes $4,748  $3,773  26%  $15,261  $15,304  —% 
    General and Administrative $11,356  $27,474  (59)%  $57,768  $77,065  (25)% 
                           

    On an annual basis, the Company reduced its cash operating costs substantially as a result of various cost-saving measures that were implemented during 2017. While annual costs were reduced year over year, fourth quarter expenses increased compared to 2016. These increased costs resulted from increased well servicing expenses in the Mid-Continent region and implementation costs of compressor swaps that occurred in the Company's Rocky Mountain region. During the fourth quarter, the Company began a program to swap out existing compressors in the Wattenberg field to reduce its future rental fees. Compressor exchanges will continue into 2018 and the associated costs are reflected in the Company's lease operating expense guidance, provided on January 29, 2018. The Company expects its operating expenses to be reduced on a per-unit basis in 2018 as production volumes grow and field-level infrastructure capacity is optimally utilized.

    The table below provides a regional breakout of the Company's lease operating expense and gas plant and midstream operating expenses.

     
    Regional Breakout
     Three Months Ended December 31, 2017
     Rocky Mountain Mid-Continent Total Company
     ($M) ($/Boe) ($M) ($/Boe) ($M) ($/Boe)
    Lease operating expense$6,728  $6.11  $3,338  $13.04  $10,066  $7.42 
    Gas plant and midstream operating expense1,802  1.64  1,512  5.90  3,314  2.44 
    Total$8,530  $7.75  $4,850  $18.94  $13,380  $9.86 
                            

    Reported net loss for the fourth quarter of 2017 was $5.8 million, or $0.28 per diluted share, compared to a net loss of $67.3 million, or $1.37 per diluted share, for the fourth quarter of 2016.  Adjusted net income for the fourth quarter of 2017 was $8.3 million, or $0.40 per diluted share, compared to adjusted net loss of $27.9 million, or $0.57 per diluted share, for the fourth quarter of 2016. The increase in GAAP and adjusted net income over the prior year was driven by improved cost structure, greater oil-weighted production and an increase in commodity prices over the prior period.

    Adjusted EBITDAX for the fourth quarter of 2017 was $21.6 million, a 49% increase compared to $14.5 million for the fourth quarter of 2016.

    Adjusted net income (loss) 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   
     Twelve Months Ended December 31, 2017
     Guidance Actual
    Production (MBoe/d)15.7 – 15.9 16.0 
    Lease operating expense ($/Boe)$6.50 – $7.00 $6.68 
    Midstream ($/Boe)$1.90 – $2.10 $2.04 
    Cash G&A ($MM)*$41 – $43 $44 
    Production taxes (% of pre-derivative realization)7% – 8% 8.0%
    CAPEX ($MM)$108 – $115 $110 
        
    * Cash G&A guidance is a non-GAAP measure that is exclusive of 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.
     

    The Company reported annual production above the high-end of guidance. With the exception of cash G&A, costs and capital were reported within the guided range. The Company's cash G&A expense for the year was above the high end of the Company's 2017 guidance range as a result of higher than expected advisory fees in the fourth quarter related to the previously proposed merger with SandRidge Energy, Inc.

    2017 Proved Reserves, Costs Incurred, and Finding and Development Costs

    As previously reported, Bonanza Creek's year-end 2017 proved reserves were 102.0 MMBoe, which represented a 13% increase from 2016. The Company's year-end 2017 proved reserves were comprised of 52.9 MMBbls of oil, 22.8 MMBbls of NGLs, and 157.7 Bcf of natural gas and were 53% proved developed.  At year end the Company's proved reserves PV-10 utilizing SEC pricing was $598 million. If SEC pricing for oil and gas increased by 10% to $56.47 per barrel WTI and $3.28 per Mcf Henry Hub, the Company's proved reserves PV-10 would increase by 27% to $760 million. If, rather than flat pricing, 2017 year-end strip pricing is used, the Company's PV-10 value for its proved reserves would be $656 million. Please see Schedule 9 at the end of this release for information on SEC pricing and a reconciliation from PV-10 to the GAAP figure "Standardized Measure of Oil and Gas." All-in finding and development costs for 2017 were $7.46 per Boe, based on the Company's 2017 costs incurred of $127.5 million and all-in additions of 17,090 MBoe. A breakout of the Company's costs incurred are provided in the table below.

    Costs Incurred

    (in thousands)For the Year Ended
    December 31, 2017
       
    Acquisition(1) $5,828 
    Development(2)  117,229 
    Exploration  4,440 
    Total(3) $127,497 

    (1) Acquisition costs for unproved properties were $5.8 million. There were no acquisition costs for proved properties in 2017.
    (2) Development costs include workover costs of $6.1 million.
    (3) Includes amounts relating to asset retirement obligations of $8.3 million.


    Proved Reserve Roll-Forward

     MBoe
    Balance as of December 31, 201690,651 
    Extensions, discoveries and infills15,547 
    Revisions to previous estimates1,543 
    Production(5,719)
    Balance as of December 31, 2017102,022 
       

    2018 Production, Capital, and Expense Guidance
    The table below reiterates the Company's previously provided 2018 guidance:

         
    Guidance Summary    
     Three Months Ended
    March 31, 2018
      Twelve Months Ended
    December 31, 2018
         
    Production (MBoe/d)16.0 - 16.6  17.7 - 18.7
    LOE ($/Boe)   $5.00 - $6.00
    Midstream expense ($/Boe)   $1.40 - $1.80
    Recurring cash G&A ($MM)(1)   $1.40 - $1.80
    Production taxes (% of pre-derivative realization)   7% - 8%
    Total CAPEX ($MM)   $280 - $320
    Rockies Oil Differential (2)   $5.85 off WTI
         
    (1) Recurring cash G&A guidance is a non-GAAP measure that is defined as GAAP G&A expense less stock based compensation and anticipated costs for permanent CEO 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 Recurring cash G&A.
    (2) Assumes strip pricing as of January 23, 2018.
     

    Operational Update

    During the fourth quarter, the Company turned online two adjacent pads in its central legacy acreage, the J21 and T21, which now have approximately 120 days of production data. These two pads consisted of a total of five wells, two SRL and three XRL, and tested an average of approximately 1,700 pounds of proppant per lateral foot. One of the SRL wells on the T21 pad utilized a slick-water completion design, which increased the fluid intensity by over 100%. While the wells on both of the pads are generally 5 performing in line with expectations, the one slick-water well on the T21 pad stands out with significant outperformance when compared to the other wells on these adjacent pads. The slick-water SRL that was tested in the central acreage is tracking the performance of the 500 MBoe per well average of the North Platte 44-13 pad on the Company's west acreage. The Company is very encouraged by the slick-water results and plans to test additional slick-water designs in the first half of the year in various portions of the Company's Wattenberg acreage.

    At the beginning of 2018, the Company turned online its 8-SRL F26 pad, which utilized an average of approximately 2,000 pounds of proppant per lateral foot and has also recently turned online its first French Lake well. The Company is currently drilling its four XRL B-28 pad on its eastern acreage and is completing its remaining seven French Lake wells. These remaining French Lake wells are expected to be turned online by the end of the second quarter.

    The Company has provided an updated investor presentation to its website, under the "For Investors" section of its corporate website at www.bonanzacrk.com. Included in this presentation are updated production results and corresponding type curves.

    Fourth Quarter Earnings Release and Conference Call

    The Company announces that in conjunction with this release of it fourth quarter 2017 operating and financial results, it will host a conference call to discuss these results on March 15, 2018 at 9:00 a.m. Mountain Time. A live webcast and replay of this event will be available on the Investor Relations section of the Company’s website at www.bonanzacrk.com. A dial-in replay of the event will be available through March 29, 2018. Dial-in information for the conference call is included below.

    TypePhone NumberPasscode
    Live participant877-793-43621899728
    Replay855-859-20561899728

    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 Mountains 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; and decreasing operating and capital costs. 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 14, 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:
    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 December
    31, 2017
      Three Months
    Ended December
    31, 2016
    Operating net revenues:    
    Oil and gas sales$50,189   $47,266 
    Operating expenses:    
    Lease operating expense10,066   9,743 
    Gas plant and midstream operating expense3,314   2,628 
    Severance and ad valorem taxes4,748   3,773 
    Exploration3,386   3 
    Depreciation, depletion and amortization9,126   26,613 
    Abandonment and impairment of unproved properties   229 
    Unused commitments   4,226 
    Contract settlement expense   21,000 
    General and administrative (including $1,035 and $1,643, respectively, of stock compensation)11,356   27,474 
    Total operating expenses41,996   95,689 
    Income (loss) from operations8,193   (48,423)
    Other income (expense):    
    Derivative gain (loss)(12,603)  490 
    Interest expense(313)  (15,842)
    Other income (loss)(1,421)  (3,559)
    Total other income (expense)(14,337)  (18,911)
    Loss from operations before taxes(6,144)  (67,334)
    Income tax benefit (expense)376    
    Net loss$(5,768)  $(67,334)
         
    Net loss per basic common share$(0.28)  $(1.37)
         
    Net loss per diluted common share$(0.28)  $(1.37)
         
    Basic weighted-average common shares outstanding20,454   49,388 
    Diluted weighted-average common shares outstanding20,454   49,388 
    • 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 loss per share. Please refer to Note 14 – Earnings per Share in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, for a detailed calculation.
     
      Successor  Predecessor
      April 29, 2017
    through
    December 31,
    2017
      January 1,
    2017 through
    April 28, 2017
     Twelve
    Months Ended
    December 31,
    2016
    Operating net revenues:       
    Oil and gas sales $123,535   $68,589  $195,295 
    Operating expenses:       
    Lease operating expense 25,862   13,128  43,671 
    Gas plant and midstream operating expense 8,341   3,541  12,826 
    Severance and ad valorem taxes 9,590   5,671  15,304 
    Exploration 3,745   3,699  946 
    Depreciation, depletion and amortization 21,312   28,065  111,215 
    Impairment of oil and gas properties      10,000 
    Abandonment and impairment of unproved properties      24,692 
    Unused commitments    993  7,686 
    Contract settlement expense      21,000 
    General and administrative (including $11,630, $2,116, and $8,892, respectively, of stock compensation) 42,676   15,092  77,065 
    Total operating expenses 111,526   70,189  324,405 
    Income (loss) from operations 12,009   (1,600) (129,110)
    Other income (expense):       
    Derivative gain (loss) (15,365)    (11,234)
    Interest expense (773)  (5,656) (62,058)
    Reorganization items, net    8,808   
    Gain on termination fee      6,000 
    Other income (loss) (1,267)  1,108  (2,548)
    Total other income (expense) (17,405)  4,260  (69,840)
    Income (loss) from operations before taxes (5,396)  2,660  (198,950)
    Income tax benefit (expense) 376      
    Net income (loss) $(5,020)  $2,660  $(198,950)
            
    Net income (loss) per basic common share $(0.25)  $0.05  $(4.04)
            
    Net income (loss) per diluted common share $(0.25)  $0.05  $(4.04)
            
    Basic weighted-average common shares outstanding 20,427   49,559  49,268 
    Diluted weighted-average common shares outstanding 20,427   50,971  49,268 
    • 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 loss per share. Please refer to Note 14 – Earnings per Share in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, for a detailed calculation.


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

     Successor  Predecessor
     Three Months
    Ended December
    31, 2017
      Three Months
    Ended December
    31, 2016
    Cash flows from operating activities:    
    Net loss$(5,768)  $(67,334)
    Adjustments to reconcile net loss to net cash provided by (used in) operating activities:    
    Depreciation, depletion and amortization9,126   26,613 
    Abandonment and impairment of unproved properties   229 
    Well abandonment costs and dry hole expense   (33)
    Stock-based compensation1,035   1,643 
    Amortization of deferred financing costs and debt premium   475 
    Derivative (gain) loss12,603   (490)
    Derivative cash settlements(1,464)  2,584 
    Inventory write-off1,758   4,390 
    Other4   (450)
    Changes in current assets and liabilities:    
    Accounts receivable(2,450)  5,840 
    Prepaid expenses and other assets(1,899)  (791)
    Accounts payable and accrued liabilities3,441   11,636 
    Settlement of asset retirement obligations(231)  (327)
        Net cash provided by (used in) operating activities16,155   (16,015)
    Cash flows from investing activities:    
    Acquisition of oil and gas properties(309)  821 
    Exploration and development of oil and gas properties(34,020)  (4,853)
    (Increase) decrease in restricted cash(4)  5,094 
    Additions to property and equipment - non oil and gas(207)  (240)
        Net cash provided by (used in) investing activities(34,540)  822 
    Cash flows from financing activities:    
    Payments to predecessor credit facility   (37,666)
    Payment of employee tax withholdings in exchange for the return of common stock   (6)
        Net cash provided by (used in) financing activities   (37,672)
    Net change in cash and cash equivalents(18,385)  (52,865)
    Cash and cash equivalents:    
    Beginning of period31,096   133,430 
    End of period$12,711   $80,565 
             


          
      Successor  Predecessor
      April 29,
    2017
    through
    December
    31, 2017
      January 1,
    2017
    through
    April 28,
    2017
     Twelve
    Months
    Ended
    December
    31, 2016
    Cash flows from operating activities:       
    Net income (loss) $(5,020)  $2,660  $(198,950)
    Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:       
    Depreciation, depletion and amortization 21,312   28,065  111,215 
    Non-cash reorganization items    (44,160)  
    Impairment of oil and gas properties      10,000 
    Abandonment and impairment of unproved properties      24,692 
    Well abandonment costs dry hole expense 75   2,931  872 
    Stock-based compensation 11,630   2,116  8,892 
    Amortization of deferred financing costs and debt premium    374  3,180 
    Derivative (gain) loss 15,365     11,234 
    Derivative cash settlements (1,464)    18,333 
    Inventory write-off 1,758     4,390 
    Other 11   18  (323)
    Changes in current assets and liabilities:       
    Accounts receivable (4,477)  (6,640) 35,282 
    Prepaid expenses and other assets (1,979)  963  (1,838)
    Accounts payable and accrued liabilities (8,470)  (5,880) (11,616)
    Settlement of asset retirement obligations (1,167)  (331) (800)
        Net cash provided by (used in) operating activities 27,574   (19,884) 14,563 
    Cash flows from investing activities:       
    Acquisition of oil and gas properties (5,383)  (445) (98)
    Payments of contractual obligation      (12,000)
    Exploration and development of oil and gas properties (76,375)  (5,123) (52,344)
    (Increase) decrease in restricted cash (16)  118  (2,613)
    Additions to property and equipment - non oil and gas (874)  (454) (346)
        Net cash used in investing activities (82,648)  (5,904) (67,401)
    Cash flows from financing activities:       
    Proceeds from predecessor credit facility      209,000 
    Payments to predecessor credit facility    (191,667) (96,333)
    Proceeds from sale of common stock    207,500   
    Payment of employee tax withholdings in exchange for the return of common stock (2,398)  (427) (289)
    Deferred financing costs      (316)
        Net cash provided by (used in) financing activities (2,398)  15,406  112,062 
    Net change in cash and cash equivalents (57,472)  (10,382) 59,224 
    Cash and cash equivalents:       
    Beginning of period 70,183   80,565  21,341 
    End of period $12,711   $70,183  $80,565 
                  

    Schedule 3: Balance Sheets
    (in thousands, unaudited)            

     Successor  Predecessor
     As of
    December 31, 2017
      As of
    December 31, 2016
    ASSETS    
    Current assets:    
    Cash and cash equivalents$12,711   $80,565 
    Accounts receivable:    
    Oil and gas sales28,549   14,479 
    Joint interest and other3,831   6,784 
    Prepaid expenses and other6,555   5,915 
    Inventory of oilfield equipment1,019   4,685 
    Derivative asset488    
       Total current assets53,153   112,428 
    Property and equipment (successful efforts method):    
    Proved properties555,341   2,525,587 
    Less: accumulated depreciation, depletion and amortization(17,032)  (1,694,483)
    Total proved properties, net538,309   831,104 
    Unproved properties183,843   163,369 
    Wells in progress47,224   18,250 
    Other property and equipment, net of accumulated depreciation of $2,224 in 2017 and $11,206 in 20164,706   6,245 
    Total property and equipment, net774,082   1,018,968 
    Long-term derivative asset6    
    Other noncurrent assets3,130   3,082 
    Total assets$830,371   $1,134,478 
    LIABILITIES AND STOCKHOLDERS’ EQUITY    
    Current liabilities:    
    Accounts payable and accrued expenses$62,129   $61,328 
    Oil and gas revenue distribution payable15,667   23,773 
    Derivative liability11,423    
    Predecessor credit facility - current portion   191,667 
    Senior Notes - current portion   793,698 
    Total current liabilities89,219   1,070,466 
    Long-term liabilities:    
    Ad valorem taxes11,584   14,118 
    Long-term derivative liability2,972    
    Asset retirement obligations for oil and gas properties38,262   30,833 
    Total liabilities142,037   1,115,417 
    Commitments and contingencies    
    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 December 31, 2017    
    Successor common stock, $.01 par value, 225,000,000 shares authorized, 20,453,549 issued and outstanding as of December 31, 20174,286    
    Additional paid-in capital689,068   814,990 
    Retained deficit(5,020)  (795,978)
    Total stockholders’ equity688,334   19,061 
    Total liabilities and stockholders’ equity$830,371   $1,134,478 
             

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

     Three Months Ended
     December 31,
     2017 2016
    Wellhead Volumes and Prices   
        
    Crude Oil and Condensate Sales Volumes (Bbl/d)   
    Rocky Mountains6,762 7,042
    Mid-Continent1,588 2,016
    Total8,350 9,058
        
    Crude Oil and Condensate Realized Prices ($/Bbl)   
    Rocky Mountains$51.30 $39.98
    Mid-Continent54.95 48.44
    Composite (before derivatives)52.00 41.86
    Composite (after derivatives)50.06 44.96
        
    Natural Gas Liquids Sales Volumes (Bbl/d)   
    Rocky Mountains2,311 3,695
    Mid-Continent394 542
    Total2,705 4,237
        
    Natural Gas Liquids Realized Prices ($/Bbl)   
    Rocky Mountains$19.66 $13.19
    Mid-Continent32.72 22.65
    Composite (before derivatives)21.56 14.40
    Composite (after derivatives)21.56 14.40
        
    Natural Gas Sales Volumes (Mcf/d)   
    Rocky Mountains17,397 23,061
    Mid-Continent4,779 6,603
    Total22,176 29,664
        
    Natural Gas Realized Prices ($/Mcf)   
    Rocky Mountains$2.08 $2.12
    Mid-Continent2.77 3.01
    Composite (before derivatives)2.23 2.32
    Composite (after derivatives)2.24 2.32
        
    Crude Oil Equivalent Sales Volumes (Boe/d)   
    Rocky Mountains11,972 14,581
    Mid-Continent2,778 3,658
    Total14,750 18,239
        
    Crude Oil Equivalent Sales Prices ($/Boe)   
    Rocky Mountains$35.79 $26.01
    Mid-Continent40.81 35.47
    Composite (before derivatives)36.73 27.90
    Composite (after derivatives)35.66 29.44
        
    Total Sales Volumes (MBoe)1,357.0 1,678.0
        

    Schedule 5: Per unit operating margins
    (unaudited)

     For the Three Months
    Ended December 31,
     For the Twelve Months
    Ended December 31,
     2017 2016
     Percent
    Change
     2017 2016 Percent
    Change
    Per Unit Costs ($/Boe)           
    Realized price (before derivatives)$36.73  $27.90  32%  $32.65  $24.36  34% 
    Lease operating expense$7.42  $5.81  28%  $6.68  $5.50  21% 
    Midstream expense$2.44  $1.57  55%  $2.04  $1.62  26% 
    Severance and Ad Valorem$3.50  $2.25  56%  $2.61  $1.93  35% 
    Cash General and Administrative (1)$7.61  $15.39  (51)%  $7.54  $8.59  (12)% 
    Total cash operating costs$20.97  $25.02  (16)%  $18.87  $17.64  7% 
    Cash operating margin (before derivatives)$15.76  $2.88  447%  $13.78  $6.72  105% 
    Derivative Cash Settlements$(1.07)  $1.54  (169)%  $(0.25)  $2.31  (111)% 
    Cash operating margin (after derivatives)$14.69  $4.42  232%  $13.53  $9.03  50% 
                
    Non-cash items           
    Depreciation Depletion and Amortization$6.72  $15.86  (58)%  $8.46  $14.01  (40)% 
    Non-cash General and Administrative$0.76  $0.98  (22)%  $2.35  $1.12  110% 
                
    (1) Cash general and administrative expense excludes stock based compensation of $1.0 million and $1.6 million for the three-month periods ended December 31, 2017 and 2016, respectively, and $13.7 million and $8.9 million for the twelve-month periods ended December 31, 2017 and 2016, respectively.
     

    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 income (loss) as net income (loss) after adjusting first for (1) the impact of certain non-cash items, including unrealized gains and losses on unsettled derivative instruments, impairment of oil and gas properties, other similar non-cash charges (2) one-time transactions and then (3) the non-cash and one time items’ impact on taxes based on an applicable rate that approximates the Company's effective tax rate in each period. Adjusted net income (loss) is not a measure of net income (loss) as determined by GAAP.

    The following table provides a reconciliation of net loss (GAAP) to adjusted net income (loss) (non-GAAP):

     Three Months Ended Twelve Months Ended
     December 31, December 31,
     2017 2016 2017 2016
    Net loss$(5,768) $(67,334) $(2,360) $(198,950)
            
    Adjustments to net loss:       
    Derivative (gain) loss12,603  (490) 15,365  11,234 
    Derivative cash settlements(1,464) 2,584  (1,464) 18,333 
    Impairment of proved properties      10,000 
    Abandonment and impairment of unproved properties  229    24,692 
    Exploratory dry hole expense  (33) 3,006  872 
    Stock-based compensation (1)1,035  1,643  13,746  8,892 
    Advisor fees related to CEO transition and strategic alternatives (1)2,774  14,457  2,774  20,375 
    Cash severance costs (1)    1,605  2,162 
    Pre-petition advisory fees(1)    683   
    Post-petition restructuring fees(1)    3,740   
    Reorganization items    (8,808)  
    Gain on termination fee      6,000 
    Contract settlement expense  21,000    21,000 
    Total adjustments before taxes14,948  39,390  30,647  123,560 
    Income tax effect(912)   (4,199)  
    Total adjustments after taxes$14,036  $39,390  $26,448  $123,560 
            
    Adjusted net income (loss)$8,268  $(27,944) $24,088  $(75,390)
    Adjusted net income (loss) per diluted share (2)$0.40  $(0.57) $1.18  $(1.53)
            
    Diluted weighted-average common shares outstanding (2)20,454  49,388  20,427  49,268 
            
    (1) Included as a portion of general and administrative expense on the consolidated statement of operations.
    (2) For the twelve-month period ended December 31, 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, except per share amounts, 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 GAAP financial measures of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.

     Three Months Ended Twelve Months Ended
     December 31, December 31,
     2017 2016 2017 2016
    Net Income (loss)$(5,768) $(67,334) $(2,360) $(198,950)
    Exploration3,386  3  7,444  946 
    Depreciation, depletion and amortization9,126  26,613  49,377  111,215 
    Impairment of proved properties      10,000 
    Abandonment and impairment of unproved properties  229    24,692 
    Stock-based Compensation (1)1,035  1,643  13,746  8,892 
    Cash severance costs (1)    1,605  2,162 
    Advisor fees related to CEO search and strategic alternatives(1)2,774  14,457  2,774  20,375 
    Gain on termination fee      (6,000)
    Contract settlement expense  21,000    21,000 
    Pre-petition advisory fees(1)    683   
    Post-petition restructuring fees(1)    3,740   
    Reorganization items    (8,808)  
    Interest expense313  15,842  6,429  62,058 
    Derivative (gain) loss12,603  (490) 15,365  11,234 
    Derivative cash settlements(1,464) 2,584  (1,464) 18,333 
    Income tax (benefit) expense(376)   (376)  
    Adjusted EBITDAX$21,629  $14,547  $88,155  $85,957 
            
    (1) Included as a portion of general and administrative expense on the consolidated statement of operations.
     

    Schedule 9: PV-10 of Estimated Proved Reserves

    PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our proved oil and natural gas reserves.

    The following table presents a reconciliation of GAAP Standardized Measure to the non-GAAP financial measure of PV-10.

      December 31,
    (in thousands) 2017
       
    PV-10 (1) 598,498 
    Present value of future income taxes discounted at 10% (2)  
    Standardized Measure $598,498 
       
    (1) The 12-month average benchmark pricing used to estimate SEC proved reserves and PV-10 value for crude oil and natural gas was $51.34 per Bbl of WTI crude oil and $2.98 per MMBtu of natural gas at Henry Hub before differential adjustments. Year-end 2017 benchmark prices for oil, and natural gas were both 20% higher from year-end 2016 SEC pricing. After differential adjustments, the Company's SEC pricing realizations for year-end 2017 were $46.76 per Bbl of oil, $19.57 per Bbl of NGLs, and $2.45 per Mcf of natural gas. Please refer to the Non-GAAP Disclosure at the end of this release for information regarding PV-10
    (2) The tax basis of the Company's oil and gas properties as of December 31, 2017 provides more tax deduction than income generation when reserve estimates were prepared using 2017 SEC pricing.
     

    Schedule 10: Cash G&A
    (in thousands, unaudited)

    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 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 GAAP financial measures of G&A expense to the non-GAAP financial measure of cash G&A.

      Three Months Ended Twelve Months Ended
      12/31/2017 9/30/2017 12/31/2017 12/31/2016
    General and Administrative Expense $11,356  $15,181  $57,768  $77,065 
    Stock Compensation (1,035) (2,646) (13,746) (8,892)
    Cash G&A 10,321  12,535  44,022  68,173 

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