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

Type Phone Number Passcode
Live Participant 877-793-4362 63290457
Replay 855-859-2056 63290457

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     Predecessor Predecessor
  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 expense 6,153       3,203   10,737  
Gas plant and midstream operating expense 1,762       836   3,535  
Severance and ad valorem taxes 2,408       1,352   4,277  
Exploration 359       292   677  
Depreciation, depletion and amortization 4,836       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 expenses 31,657       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 outstanding 20,369       49,902   49,277  
           
Diluted weighted-average common shares outstanding 20,369       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     Predecessor Predecessor
  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 expense 6,153       13,128   24,035  
Gas plant and midstream operating expense 1,762       3,541   7,324  
Severance and ad valorem taxes 2,408       5,671   7,431  
Exploration 359       3,699   943  
Depreciation, depletion and amortization 4,836       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 expenses 31,657       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 outstanding 20,369       49,559   49,204  
           
Diluted weighted-average common shares outstanding 20,369       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     Predecessor Predecessor
  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 amortization 4,836       6,853   30,927  
Non-cash reorganization items       (101,501 )  
Abandonment and impairment of unproved properties         9,875  
Well abandonment costs and dry hole expense 64       230   734  
Stock-based compensation 7,949       391   2,380  
Amortization of deferred financing costs and debt premium       374   1,671  
Derivative loss         12,923  
Derivative cash settlements         3,893  
Other 5       (365 ) 4  
Changes in current assets and liabilities:          
Accounts receivable 6,420       (2,826 ) 371  
Prepaid expenses and other assets 270       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 period 70,183       91,935   218,599  
End of period $ 54,212       $ 70,183   $ 170,171  
                       


  Successor     Predecessor Predecessor
  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 amortization 4,836       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 expense 64       2,931   966  
Stock-based compensation 7,949       2,116   5,384  
Amortization of deferred financing costs and debt premium       374   2,279  
Derivative loss         13,930  
Derivative cash settlements         11,401  
Other 5       18   (112 )
Changes in current assets and liabilities:          
Accounts receivable 6,420       (6,640 ) 23,415  
Prepaid expenses and other assets 270       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 period 70,183       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 sales 18,410       14,479  
Joint interest and other 3,073       6,784  
Prepaid expenses and other 4,682       5,915  
Inventory of oilfield equipment 3,942       4,685  
Total current assets 84,319       112,428  
Property and equipment (successful efforts method):        
Proved properties 498,229       2,525,587  
Less: accumulated depreciation, depletion and amortization (4,266 )     (1,694,483 )
Total proved properties, net 493,963       831,104  
Unproved properties 183,443       163,369  
Wells in progress 16,100       18,250  
Other property and equipment, net of accumulated depreciation of $238 in 2017 and $11,206 in 2016 5,980       6,245  
Total property and equipment, net 699,486       1,018,968  
Other noncurrent assets 2,739       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 payable 22,321       23,773  
Revolving credit facility - current portion       191,667  
Senior Notes - current portion       793,698  
Total current liabilities 50,907       1,070,466  
         
Long-term liabilities:        
Ad valorem taxes 20,288       14,118  
Asset retirement obligations for oil and gas properties 28,938       30,833  
Total liabilities 100,133       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, 2017 4,286        
Additional paid-in capital 685,705       814,990  
Accumulated deficit (3,580 )     (795,978 )
Total stockholders’ equity 686,411       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 Mountains 6,189     10,715     6,690     11,190  
Mid-Continent 1,845     2,270     1,889     2,353  
Total 8,034     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 Mountains 3,046     3,772     3,167     3,594  
Mid-Continent 452     675     471     697  
Total 3,498     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 Mountains 20,144     27,450     20,786     28,044  
Mid-Continent 6,067     7,444     6,249     7,648  
Total 26,211     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 Mountains 12,592     19,062     13,322     19,458  
Mid-Continent 3,308     4,186     3,402     4,325  
Total 15,900     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 expense 6.47     5.08     27 %     6.37       5.55     15 %
Gas plant and midstream operating expense 1.80     1.67     8 %     1.75       1.69     4 %
Severance and ad valorem 2.60     2.02     29 %     2.67       1.72     55 %
Cash general and administrative 7.46     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

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