Bonanza Creek Energy Announces Second Quarter 2017 Financial Results and Operational Update

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| Source: Bonanza Creek Energy, Inc.
  • Aggressively applying enhanced drilling and completion techniques throughout capital program
  • Completed first pad of DUC wells, early data out-pacing expectations
  • Commenced drilling program at the end of July; first pad expected to complete in fourth quarter
  • Continuing cost reduction program; reduced annualized cash G&A
  • Second quarter production volumes averaged 15.9 MBoe per day

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

Jack Vaughn, Chairman of the Board of Directors commented, "On behalf of the Board of Directors, we are very pleased with our team's swift progress in commencing the Company's 2017 drilling and completion program. Three key objectives of this program are to maximize well performance through completion design enhancements, reduce the cost structure at the field and corporate level, commence operations in the French Lake area, and allocate capital at a pace that preserves the Company's balance sheet. As the team executes the 2017 capital program, the Board of Directors has engaged an executive search firm to identify and review CEO candidates and is simultaneously assessing strategic opportunities. With strong leadership, we believe that Bonanza Creek can become a premier DJ Basin producer."

Second Quarter 2017 Results

For the second quarter of 2017, the Company reported average daily production of 15.9 MBoe per day, in line with the Company's guidance of 15.8 – 16.2 Mboe per day, and a 32% decrease from the second quarter of 2016. The reduction in production volumes from the prior year is a result of having no drilling and completion activity during the previous five quarters. Product mix for the second quarter of 2017 was 51% oil, 22% NGLs, and 27% natural gas. 

Net revenue for the second quarter of 2017 was $44.1 million, compared to $54.5 million for the second quarter of 2016. Crude oil accounted for approximately 74% of total revenue. Differentials for the Company's Rocky Mountain oil production during the quarter averaged approximately $4.45 per Bbl, a 50% decrease from the second quarter of 2016. The significant reduction in the Company's oil differentials is a result of its recently restructured oil purchasing contracts in the Wattenberg. Corporate average realized prices for the second quarter of 2017 are presented below.

Average Realized Prices  
 Three Months Ended
June 30, 2017
 
Oil (per Bbl)44.89 
Gas (per Mcf)2.52 
NGL (per Bbl)16.71 
Boe (Per Boe)30.51 

Lease operating expense ("LOE") for the second quarter of 2017 was $9.4 million, or $6.47 per Boe, a 13% reduction in total LOE compared to $10.7 million or $5.08 per Boe in the second quarter of 2016. Per unit metrics have increased from year to year as a result of declining volumes. These metrics are expected to improve as activity is restarted and production volumes stabilize and increase.

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

 
 Three Months Ended June 30, 2017
 Rocky Mountain Mid-Continent Total Company
 ($M) ($/Boe) ($M) ($/Boe) ($M) ($/Boe)
Lease operating expense$6,808  $5.94  $2,548  $8.46  $9,356  $6.47 
Gas plant and midstream operating expense$1,535  $1.34  $1,063  $3.53  2,598  $1.80 
Total$8,343  $7.28  $3,611  $11.99  $11,954  $8.27 

The Company's general and administrative ("G&A") expense was $19.1 million for the second quarter of 2017, a 45% increase from the second quarter of 2016. The increase is primarily due to approximately $7.1 million in non-cash stock compensation, which was accelerated in connection with the departure of the Company's former CEO on June 11, 2017, and $1.1 million of post-petition restructuring fees. The Company's recurring cash G&A expense for the second quarter of 2017 was $9.2 million and is exclusive of the aforementioned post-petition restructuring fees. This compares to prior year recurring cash G&A expense of $10.9 million. The benefits of the Company's ongoing G&A cost reduction program are discussed below. 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.

Operational Highlights

Testing and Assessing Enhanced Completions
During the second quarter of 2017, the Company completed its first pad of 4 drilled uncompleted ("DUC") wells. These 4,100-foot standard reach lateral ("SRL") wells were completed using approximately 2,000 pounds of sand per lateral foot and utilized approximately 100-foot stage spacing. This enhanced completion design compares to the Company's previous standard design of approximately 1,000 pounds per lateral foot of sand and stage spacing of approximately 160 feet. Flow-back of these wells has utilized the Company's enhanced recovery flow-back protocol, which provides choke management to increase oil cuts and overall recoveries by maintaining down-hole pressures higher for longer and decreasing medium-term decline rates. The DUCs started flowing back on July 2, 2017 and while early, the initial results are encouraging.

The Company commenced its 2017 drilling program at the end of July by spudding a three-well pad, consisting of one, 9,600 foot extended reach lateral ("XRL") well and two SRL wells. The Company expects the first pad to be turned into sales during the fourth quarter.

All of the Company's 2017 drilling and completion activity will utilize various forms of enhanced completion design to maximize well productivity, recovery, and project economics.

In addition to its operated program, the Company plans to participate in approximately 18 gross non-operated wells. These 18 wells will also test enhanced completions and provide informative and useful well data over a broader areal extent of the Company's acreage with lower capital commitments. The operated and non-operated programs will together provide a significant data set of 43 well results. These results will provide key information regarding the potential uplift from various leading-edge completion designs, which will inform the Company's development plans.

French Lake Opportunity
During 2017 and into the beginning of 2018, the Company plans to drill and complete eight XRL wells in its French Lake area. The Company acquired this acreage in the fall of 2014 and, with its financial restructuring and recapitalization complete, the Company is eager to confirm the geology and reservoir performance of the area. Bonanza Creek is pursuing its plans under an agreement with an offset operator, and upon completion of these eight wells, will essentially eliminate all of the Company's near-term lease expiry risk in its Wattenberg acreage. The Company plans to pursue a comprehensive agreement to develop this acreage with the offset operator.

Production, Capital, and Expense Outlook

The Company is reiterating its production and capital guidance for the remainder of the year and providing initial cost guidance for 2017. As a part of its ongoing cost structure review, the Company executed a reduction in force subsequent to the second quarter, which resulted in a reduction of 25% of its employee base. Based on these changes, the Company now expects its annualized recurring cash G&A expense to be within the range of $30 – $32 million, which compares to $45.6 million of recurring cash G&A in 2016. Recurring G&A expense excludes non-recurring items associated with advisor fees and severance charges. These announced G&A savings, along with continued efforts to reduce LOE and further reduce non-payroll G&A, will help drive Bonanza Creek towards its goal of 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
September 30, 2017
 Twelve Months Ended
December 31, 2017
    
Production (MBoe/d)15.8 – 16.2 16.3 – 16.7
LOE ($/Boe)  $6.50 – $7.00
Midstream expense ($/Boe)  $1.90 – $2.10
Cash G&A* ($MM)  $38 – $40
Production taxes (% of pre-derivative realization)  7% – 8%
Total CAPEX ($MM)  $120 – $130
* Cash G&A guidance assumes expected severance costs of $2.0 million in the third quarter of 2017 and nonrecurring expenses of $3.2 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 second quarter, the Company had liquidity of $246 million, which included cash on hand of $54 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
Subsequent to the second quarter, the Company began to implement hedges for oil and gas for the remainder of 2017 through the first half of 2019. As the new wells are turned into sales, the Company plans to add incremental hedges to lock in cash flows and project returns. The Company's current hedge position is summarized in the table below.

  Crude Oil
(NYMEX WTI)
 Natural Gas
(NYMEX Henry Hub)
  Bbls/day Weighted Avg.
Price per Bbl
 MMBtu/day Weighted Avg.
Price per MMBTU
4Q17        
Cashless Collar 2,000  $41.50/$51.00 2,600  $3.00/$3.30
1Q18        
Swap     3,000  3.35
Cashless Collar 2,000  $42.00/$52.50 2,600  $2.75/$3.35
2Q18        
Cashless Collar 2,000  $42.00/$52.50 2,600  $2.75/$3.35
3Q18        
Cashless Collar 1,000  $41.00/$52.00 2,600  $2.75/$3.35
4Q18        
Cashless Collar 1,000  $41.00/$52.00 2,600  $2.75/$3.35
1Q19        
Cashless Collar 1,000  $41.00/$54.00    
April 2019        
Cashless Collar 1,000  $41.00/$54.00    

Fresh Start Accounting

The Company adopted fresh-start accounting as of April 28, 2017, the effective date of its emergence from Chapter 11 bankruptcy proceedings, resulting in a new corporate entity for financial reporting purposes. Upon the adoption of fresh-start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh-start reporting date. As a result, the Company’s unaudited condensed consolidated financial statements subsequent to April 28, 2017 are not comparable to its financial statements prior to April 28, 2017. References to "Predecessor" refer to the Company prior to the adoption of fresh-start accounting while references to "Successor" refer to the Company subsequent to the adoptions of fresh-start accounting. Please review the Company’s second quarter 2017 Form 10-Q for further details regarding fresh-start accounting and the financial information presented at the end of this release.

Conference Call Information

The Company will host a conference call to discuss these financial and operating results on August 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 Participant877-793-436263290457
Replay855-859-205663290457

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.

Schedule 1: Statement of Operations
(in thousands, expect for per share amounts, unaudited)

 Successor  PredecessorPredecessor
 April 29, 2017
through June 30,
2017
  April 1, 2017
through April 28,
2017
Three Months
Ended June 30,
2016
Operating net revenues:     
Oil and gas sales$28,114   $16,030 $54,530 
Operating expenses:     
Lease operating expense6,153   3,203 10,737 
Gas plant and midstream operating expense1,762   836 3,535 
Severance and ad valorem taxes2,408   1,352 4,277 
Exploration359   292 677 
Depreciation, depletion and amortization4,836   6,853 30,927 
Abandonment and impairment of unproved properties    9,875 
General and administrative (including $7,949, $391 and $2,380, respectively, of stock-based compensation)16,139   2,998 13,235 
Total operating expenses31,657   15,534 73,263 
Income (loss) from operations(3,543)  496 (18,733)
Other income (expense):     
Derivative loss    (12,923)
Interest expense(195)  (1,088)(16,527)
Reorganization items, net   97,811  
Other income (loss)158   (283)(1,294)
Total other income (expense)(37)  96,440 (30,744)
Income (loss) from operations before taxes(3,580)  96,936 (49,477)
Income tax benefit (expense)     
Net income (loss)$(3,580)  $96,936 $(49,477)
Comprehensive income (loss)$(3,580)  $96,936 $(49,477)
      
Basic net income (loss) per common share$(0.18)  $1.88 $(1.00)
        
Diluted net income (loss) per common share$(0.18)  $1.85 $(1.00)
      
Basic weighted-average common shares outstanding20,369   49,902 49,277 
      
Diluted weighted-average common shares outstanding20,369   50,486 49,277 
         
  • 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 June 30,
2017
  January 1, 2017
through April 28,
2017
Six Months Ended
June 30, 2016
Operating net revenues:     
Oil and gas sales$28,114   $68,589 $98,704 
Operating expenses:     
Lease operating expense6,153   13,128 24,035 
Gas plant and midstream operating expense1,762   3,541 7,324 
Severance and ad valorem taxes2,408   5,671 7,431 
Exploration359   3,699 943 
Depreciation, depletion and amortization4,836   28,065 57,306 
Impairment of oil and gas properties    10,000 
Abandonment and impairment of unproved properties    16,781 
Unused commitments   993  
General and administrative (including $7,949, $2,116, $5,384, respectively, of stock-based compensation)16,139   15,092 30,920 
Total operating expenses31,657   70,189 154,740 
Loss from operations(3,543)  (1,600)(56,036)
Other income (expense):     
Derivative loss    (13,930)
Interest expense(195)  (5,656)(31,074)
Reorganization items, net   8,808  
Gain on termination fee    6,000 
Other income (loss)158   1,108 (1,674)
Total other income (expense)(37)  4,260 (40,678)
Income (loss) from operations before taxes(3,580)  2,660 (96,714)
Income tax benefit (expense)     
Net income (loss)$(3,580)  $2,660 $(96,714)
Comprehensive income (loss)$(3,580)  $2,660 $(96,714)
      
Basic net income (loss) per common share$(0.18)  $0.05 $(1.97)
      
Diluted net income (loss) per common share$(0.18)  $0.05 $(1.97)
      
Basic weighted-average common shares outstanding20,369   49,559 49,204 
      
Diluted weighted-average common shares outstanding20,369   50,971 49,204 
         
  • 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  PredecessorPredecessor
 April 29, 2017
through June
30, 2017
  April 1, 2017
through April
28, 2017
Three Months
Ended June
30, 2016
      
Cash flows from operating activities:     
Net income (loss)$(3,580)  $96,936 $(49,477)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:     
Depreciation, depletion and amortization4,836   6,853 30,927 
Non-cash reorganization items   (101,501) 
Abandonment and impairment of unproved properties    9,875 
Well abandonment costs and dry hole expense64   230 734 
Stock-based compensation7,949   391 2,380 
Amortization of deferred financing costs and debt premium   374 1,671 
Derivative loss    12,923 
Derivative cash settlements    3,893 
Other5   (365)4 
Changes in current assets and liabilities:     
Accounts receivable6,420   (2,826)371 
Prepaid expenses and other assets270   1,499 274 
Accounts payable and accrued liabilities(19,338)  (36,972)(25,316)
Settlement of asset retirement obligations(459)  (155)(34)
Net cash used in operating activities(3,833)  (35,536)(11,775)
Cash flows from investing activities:     
Acquisition of oil and gas properties(4,982)  (6)(284)
Exploration and development of oil and gas properties(4,913)  (1,698)(7,881)
Payments of contractual obligation    (12,000)
Increase in restricted cash(2)   (2)
Additions to property and equipment - non oil and gas(161)  (253)(8)
Net cash used in investing activities(10,058)  (1,957)(20,175)
Cash flows from financing activities:     
Payments to credit facility   (191,667)(14,667)
Proceeds from sale of common stock   207,500  
Deferred restructuring charges    (1,684)
Payment of employee tax withholdings in exchange for the return of common stock(2,080)  (92)(44)
Deferred financing costs    (83)
Net cash (used in) provided by financing activities(2,080)  15,741 (16,478)
Net change in cash and cash equivalents(15,971)  (21,752)(48,428)
Cash and cash equivalents:     
Beginning of period70,183   91,935 218,599 
End of period$54,212   $70,183 $170,171 
            


 Successor  PredecessorPredecessor
 April 29, 2017
through June
30, 2017
  January 1,
2017 through
April 28, 2017
Six Months
Ended June
30, 2016
      
Cash flows from operating activities:     
Net income (loss)$(3,580)  $2,660 $(96,714)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:     
Depreciation, depletion and amortization4,836   28,065 57,306 
Non-cash reorganization items   (44,160) 
Impairment of oil and gas properties    10,000 
Abandonment and impairment of unproved properties    16,781 
Well abandonment costs and dry hole expense64   2,931 966 
Stock-based compensation7,949   2,116 5,384 
Amortization of deferred financing costs and debt premium   374 2,279 
Derivative loss    13,930 
Derivative cash settlements    11,401 
Other5   18 (112)
Changes in current assets and liabilities:     
Accounts receivable6,420   (6,640)23,415 
Prepaid expenses and other assets270   963 (1,348)
Accounts payable and accrued liabilities(19,338)  (5,880)(28,457)
Settlement of asset retirement obligations(459)  (331)(75)
Net cash  (used in) provided by operating activities(3,833)  (19,884)14,756 
Cash flows from investing activities:     
Acquisition of oil and gas properties(4,982)  (445)(816)
Exploration and development of oil and gas properties(4,913)  (5,123)(42,753)
Payments of contractual obligation    (12,000)
(Increase) decrease in restricted cash(2)  118 (2,535)
(Additions) deletions to property and equipment - non oil and gas(161)  (454)39 
Net cash used in investing activities(10,058)  (5,904)(58,065)
Cash flows from financing activities:     
Proceeds from credit facility    209,000 
Payments to credit facility   (191,667)(14,667)
Proceeds from sale of common stock   207,500  
Deferred restructuring charges    (1,684)
Payment of employee tax withholdings in exchange for the return of common stock(2,080)  (427)(273)
Deferred financing costs    (237)
Net cash (used in) provided by financing activities(2,080)  15,406 192,139 
Net change in cash and cash equivalents(15,971)  (10,382)148,830 
Cash and cash equivalents:     
Beginning of period70,183   80,565 21,341 
End of period$54,212   $70,183 $170,171 
            
            

Schedule 3: Condensed Consolidated Balance Sheets
(in thousands, unaudited)

 Successor  Predecessor
 June 30, 2017  December 31,
2016
ASSETS    
Current assets:    
Cash and cash equivalents$54,212   $80,565 
Accounts receivable:    
Oil and gas sales18,410   14,479 
Joint interest and other3,073   6,784 
Prepaid expenses and other4,682   5,915 
Inventory of oilfield equipment3,942   4,685 
Total current assets84,319   112,428 
Property and equipment (successful efforts method):    
Proved properties498,229   2,525,587 
Less: accumulated depreciation, depletion and amortization(4,266)  (1,694,483)
Total proved properties, net493,963   831,104 
Unproved properties183,443   163,369 
Wells in progress16,100   18,250 
Other property and equipment, net of accumulated depreciation of $238 in 2017 and $11,206 in 20165,980   6,245 
Total property and equipment, net699,486   1,018,968 
Other noncurrent assets2,739   3,082 
Total assets$786,544   $1,134,478 
LIABILITIES AND STOCKHOLDERS’ EQUITY    
Current liabilities:    
Accounts payable and accrued expenses$28,586   $61,328 
Oil and gas revenue distribution payable22,321   23,773 
Revolving credit facility - current portion   191,667 
Senior Notes - current portion   793,698 
Total current liabilities50,907   1,070,466 
     
Long-term liabilities:    
Ad valorem taxes20,288   14,118 
Asset retirement obligations for oil and gas properties28,938   30,833 
Total liabilities100,133   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 June 30, 2017    
Successor common stock, $.01 par value, 225,000,000 shares authorized, 20,429,691 issued and outstanding as of June 30, 20174,286    
Additional paid-in capital685,705   814,990 
Accumulated deficit(3,580)  (795,978)
Total stockholders’ equity686,411   19,061 
Total liabilities and stockholders’ equity$786,544   $1,134,478 
         
         

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,
 2017 2016 2017 2016
Wellhead Volumes and Prices       
        
Crude Oil and Condensate Sales Volumes (Bbl/d)       
Rocky Mountains6,189  10,715  6,690  11,190 
Mid-Continent1,845  2,270  1,889  2,353 
Total8,034  12,985  8,579  13,543 
        
Crude Oil and Condensate Realized Prices ($/Bbl)       
Rocky Mountains$44.06  $36.74  $46.32  $30.70 
Mid-Continent$47.69  $45.18  $49.94  $40.41 
Composite$44.89  $38.21  $47.11  $32.39 
Composite (after derivatives)$44.89  $41.51  $47.11  $37.01 
        
Natural Gas Liquids Sales Volumes (Bbl/d)       
Rocky Mountains3,046  3,772  3,167  3,594 
Mid-Continent452  675  471  697 
Total3,498  4,447  3,638  4,291 
        
Natural Gas Liquids Realized Prices ($/Bbl)       
Rocky Mountains$16.10  $10.59  $15.99  $11.80 
Mid-Continent$20.84  $16.75  $23.45  $14.48 
Composite$16.71  $11.53  $16.96  $12.23 
Composite (after derivatives)$16.71  $11.53  $16.96  $12.23 
        
Natural Gas Sales Volumes (Mcf/d)       
Rocky Mountains20,144  27,450  20,786  28,044 
Mid-Continent6,067  7,444  6,249  7,648 
Total26,211  34,894  27,035  35,692 
        
Natural Gas Realized Prices ($/Mcf)       
Rocky Mountains$2.36  $1.34  $2.48  $1.27 
Mid-Continent$3.06  $2.01  $3.17  $2.05 
Composite$2.52  $1.48  $2.64  $1.44 
Composite (after derivatives)$2.52  $1.48  $2.64  $1.44 
        
Crude Oil Equivalent Sales Volumes (Boe/d)       
Rocky Mountains12,592  19,062  13,322  19,458 
Mid-Continent3,308  4,186  3,402  4,325 
Total15,900  23,248  16,724  23,783 
        
Crude Oil Equivalent Sales Prices ($/Boe)       
Rocky Mountains$29.31  $24.68  $30.93  $21.66 
Mid-Continent$35.05  $30.78  $36.79  $27.94 
Composite$30.51  $25.78  $32.12  $22.80 
Composite (after derivatives)$30.51  $27.62  $32.12  $25.44 
        
Total Sales Volumes (MBoe)1,446.9  2,115.5  3,026.9  4,328.7 
            
            

Schedule 5: Per unit operating margins
(unaudited)

 Three Months Ended June 30, Six Months Ended June 30,
 2017 2016 Percent
Change
 2017 2016 Percent
Change
Production           
Oil (MBbl)731  1,182  (38)% 1,553  2,465  (37)%
Gas (MMcf)2,385  3,175  (25)% 4,893  6,496  (25)%
NGL (MBbl)318  405  (21)% 659  781  (16)%
Equivalent (MBoe)1,447  2,116  (32)% 3,027  4,329  (30)%
                  
Realized pricing (before derivatives)                
Oil ($/Bbl)$44.89  $38.21  17% $46.85  $32.38  45%
Gas ($/Mcf)$2.52  $1.48  70% $2.63  $1.44  83%
NGL ($/Bbl)$16.71  $11.53  45% $16.86  $12.23  38%
Equivalent ($/Boe)$30.51  $25.78  18% $31.95  $22.80  40%
                  
Per Unit Costs ($/Boe)                 
Realized price (before derivatives)$30.51  $25.78  18% $31.95  $22.80  40%
Lease operating expense6.47  5.08  27%  6.37   5.55  15%
Gas plant and midstream operating expense1.80  1.67  8%  1.75   1.69  4%
Severance and ad valorem2.60  2.02  29%  2.67   1.72  55%
Cash general and administrative7.46  5.13  45%  6.99   5.90  18%
Total cash operating costs$18.33  $13.90  32% $17.78  $14.86  20%
Cash operating margin (before derivatives)$12.18  $11.88  3% $14.17  $7.94  78%
Derivative cash settlements  1.84  (100)%   2.64  (100)%
Cash operating margin (after derivatives)$12.18  $13.72  (11)% $14.17  $10.58  34%
                  
Non-cash items                 
Non-cash general and administrative$5.76  $1.13  410% $3.33  $1.24  169%
                      
                      

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
June 30,
 Six Months Ended
June 30,
  2017 2016 2017 2016
Net Income (Loss) $93,356  $(49,477) $(920) $(96,714)
Adjustments to Net Income (Loss):        
Derivative loss   12,923    13,930 
Derivative cash settlements   3,893    11,401 
Gain on termination fee       (6,000)
Impairment of proved properties       10,000 
Abandonment and impairment of unproved properties   9,875    16,781 
Exploratory dry hole expense 294  734  2,995  966 
Stock-based compensation (1) 8,340  2,380  10,065  5,384 
Severance costs (1)       2,162 
Reorganization items (97,811)   (8,808)  
Pre-petition advisory fees (1)     683   
Post-petition restructuring fees (1) 1,422    1,422   
Total adjustments before taxes (87,755) 29,805  6,357  54,624 
Income tax effect        
Total adjustments after taxes $(87,755) $29,805  $6,357  $54,624 
         
Adjusted net income (loss) $5,601  $(19,672) $5,437  $(42,090)
Adjusted net loss per diluted share (2) $0.27  $(0.40) $0.27  $(0.86)
         
Diluted weighted-average common shares outstanding (2) 20,369  49,277  20,369  49,204 
         
(1) Included as a portion of general and administrative expense on the consolidated statement 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 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 June 30, Six Months Ended June 30,
  2017 2016 2017 2016
Net Income (loss) $93,356  $(49,477) $(920) $(96,714)
Exploration 651  677  4,058  943 
Depreciation, depletion and amortization 11,689  30,927  32,901  57,306 
Impairment of proved properties       10,000 
Abandonment and impairment of unproved properties   9,875    16,781 
Stock-based compensation 8,340  2,380  10,065  5,384 
Severance costs (1)       2,162 
Gain on termination fee       (6,000)
Interest expense 1,283  16,527  5,851  31,074 
Derivative loss   12,923    13,930 
Derivative cash settlements   3,893    11,401 
Pre-petition advisory fees (1)     683   
Post-petition restructuring fees (1) 1,422    1,422   
Reorganization items (97,811)   (8,808)   
Income tax benefit        
Adjusted EBITDAX $18,930  $27,725  $45,252  $46,267 
         
(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 June 30,
  2017 2016
General and Administrative $19,137  $13,235 
Stock-based compensation (8,340) (2,380)
Cash G&A $10,797  $10,855 
Post-petition restructuring fees (1,422)  
Other non-recurring expense (184)  
Recurring Cash G&A $9,191  $10,855 


For further information, please contact:
James R. Edwards
Director - Investor Relations
720-440-6136
jedwards@bonanzacrk.com