Questions? +1 (202) 335-3939 Login
Trusted News Since 1995
A service for energy industry professionals · Saturday, November 17, 2018 · 468,644,438 Articles · 3+ Million Readers

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

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

Bonanza Creek delivered strong performance in the third quarter driven by solid production growth, lower operating expenses, and higher realized pricing. Wattenberg daily production for the third quarter of 2018 has increased 40% compared to the fourth quarter of 2017 and the Company expects annualized production growth in excess of 50% in 2019.

  • Third quarter sales volumes averaged 17.7 MBoe per day ("MBoe/d"), at midpoint of guidance
  • Wattenberg lease operating expenses ("LOE") of $4.26 per Boe decreased 29% sequentially and compared favorably to guidance midpoint of $4.60 per Boe
  • Wattenberg gathering and midstream expenses of $1.00 per Boe compared to guidance midpoint of $1.35 per Boe
  • Company growth not impacted by basin-wide gas processing constraints
  • Rocky Mountain Infrastructure (“RMI”) providing low gathering system pressures at the wellhead and access to four gas processors through eleven interconnects
  • Third quarter GAAP net income of $43.4 million, or $2.10 per diluted share; Adjusted net income(1) of $26.8 million, or $1.30 per diluted share
  • Adjusted EBITDAX(1) of $38.4 million, 10% growth over second quarter 2018, despite Mid-Con sale
  • Proved reserves of $749 million (PV-10) as of September 30, 2018(2), 56% growth in Wattenberg PV-10 compared to year-end 2017
  • Executed French Lake joint development agreement

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

(2) PV-10 is a non-GAAP measure. As prepared by the Company's Independent Qualified Reserves Evaluator, Netherland Sewell & Associates. Please see Schedule 9 at end of this release for additional disclosures related to PV-10.

"Our third quarter results continue to demonstrate our growing operational capability as we delivered on sales volumes while lowering our cost structure.  Operational performance translated into strong financial performance, with Adjusted EBITDAX increasing 10% compared to second quarter 2018 despite the sale of Mid-Con in August,” said Eric Greager, President and CEO.

“We continue to increase the pace and efficiency of our Wattenberg-focused development program, which calls for greater than 50% production growth in 2019. Our rural acreage position, combined with nearly 80% high-value liquids production, rapidly improving well performance, unconstrained gathering and processing, and a clean balance sheet put us in a unique position to generate favorable returns, growth and value for our shareholders.”

Third Quarter 2018 Results

During the third quarter of 2018, the Company reported average daily sales of 17.7 MBoe/d, which was at the mid-point of the Company's guidance range of 17.4 - 18.0 MBoe/d. The Company's Wattenberg average daily sales of 16.8 MBoe/d increased 11% sequentially, driven by recent completion designs and consistent low gathering system pressures at the wellhead on the Company's RMI system. Product mix for the third quarter of 2018 was 60% oil, 18% NGLs, and 22% residue natural gas.

Net revenue for the third quarter of 2018 was $74.4 million, compared to $45.2 million for the third quarter of 2017. The increase in third quarter 2018 net revenue compared to 2017 was primarily a result of increased production and improved commodity pricing, partially offset by the loss of production associated with the Mid-Continent divestiture. Crude oil accounted for approximately 84% of total revenue. Differentials for the Company's Wattenberg oil production during the quarter averaged approximately $6.52 per barrel off of NYMEX WTI. Corporate average realized prices for the third quarter of 2018 are presented below.

Average Realized Prices (Before Derivatives)  
  Three Months Ended September 30, 2018
Oil (per Bbl) $63.50
Gas (per Mcf) $2.22
NGL (per Bbl) $24.32
Boe (Per Boe) $45.31

Wattenberg LOE for the third quarter of 2018 on a unit basis decreased by 26% to $4.26 per Boe from $5.76 per Boe in the third quarter of 2017 and compared favorably to guidance of $4.40 to $4.80 per Boe. Additionally, Wattenberg midstream expenses for the third quarter were $1.00 per Boe compared to $1.13 per Boe in the same period a year ago and guidance of $1.25 to $1.45 per Boe.

Unit operating expenses in the third quarter were favorably impacted by lower regulatory, compliance, and labor costs. The Company completed its accelerated compressor replacement program early in the third quarter, resulting in a significant reduction in maintenance and connection costs, as well as go-forward rental rates. Unit operating expenses have also benefited from new well production and high return well servicing activities, which have helped improve base production performance.

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

 
  Three Months Ended September 30, 2018
  Wattenberg   Mid-Continent   Total Company
  ($M)   ($/Boe)   ($M)   ($/Boe)   ($M)   ($/Boe)
Lease operating expense $ 6,571     $ 4.26     $ 1,380     $ 15.43     $ 7,951     $ 4.87  
Gas plant and midstream operating expense $ 1,546     $ 1.00     $ 703     $ 7.86     $ 2,249     $ 1.38  
Total $ 8,117     $ 5.26     $ 2,083     $ 23.29     $ 10,200     $ 6.25  

The Company's general and administrative ("G&A") expense was $10.9 million for the third quarter of 2018, which includes $1.7 million in stock compensation. G&A expense in the third quarter was impacted by severance expenses related to the Mid-Continent divestiture in August 2018. Cash G&A expense, which excludes stock compensation, was $9.2 million for the third quarter and is tracking in-line with the Company's full year 2018 guidance.

Reported net income for the third quarter of 2018 was $43.4 million, or $2.10 per diluted share. Adjusted net income for the third quarter of 2018 was $26.8 million, or $1.30 per diluted share.

Adjusted EBITDAX for the third quarter of 2018 was $38.4 million.

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

Production, Capital, and Expense Outlook

The table below summarizes the Company's production, capital, and expense guidance for the fourth quarter and full year 2018.

Guidance Summary        
  Three Months
Ended December
31, 2018
Twelve Months
Ended December 31, 2018
(Pro-forma)(1) 
  Twelve Months
Ended December
31, 2018
         
Production (MBoe/d) 17.6 - 18.2 15.8 - 16.0   17.5 - 17.7
LOE ($/Boe) $3.90 - $4.30 $4.95 - $5.05   $5.65 - $5.75
Midstream expense ($/Boe) $1.20 - $1.40 $1.37 - $1.47   $1.70 - $1.80
Recurring cash G&A* ($MM)       $32.5 - $33.5
Production taxes (% of pre-derivative realization)       7% - 8%
Total CAPEX ($MM)       $275 - $295
* Recurring Cash G&A is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock-based compensation portion of GAAP G&A.
(1) The Company's estimate for the full year of 2018 excluding results from the Mid-Continent operations.

Operational Highlights

During the third quarter of 2018, the Company spud 19 gross (13.2 net) operated wells, five of which were extended reach lateral ("XRL") wells, and completed five gross (4.1 net) operated wells, five of which were XRL wells.

The Company continues to be encouraged by the results at French Lake. Six of the eight XRL wells are tracking above the Company’s expectations and, we believe, best reflect the reservoir quality in the area. Additionally, Bonanza Creek recently executed a joint development agreement with a major operator in the basin. This agreement moves the Company significantly closer to realizing the value of the French Lake asset.

The Company’s five-well K-22 pad on its Legacy West acreage, which has wells completed in the Niobrara B, C, and Codell, is currently tracking above the Company's type curve for this area with average cumulative production of 13.1 MBoe (68% oil) per 1,000 feet of lateral after 136 days of production. This production performance further validates the Company’s high-intensity stimulation designs and the value of its Legacy Western acreage. Additionally, this five-well pad was drilled on approximately 40-acre spacing (16 wells/section) compared to approximately 60-acre spacing (11 wells/section) on pads completed in this area last year and earlier this year. The Company will continue to optimize spacing, stacking and high-intensity stimulation designs to maximize resource recoveries and value.

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

The Company continued to benefit from multiple delivery points on the RMI system in the third quarter. This delivery point flexibility, combined with consistently low line pressures on RMI, have helped ensure minimal production impacts. Line pressure on the Company’s RMI system has remained consistent between 50 and 100 psi and is well below typical field-wide operating pressures outside of RMI. The Company's 2018 drilling plan has not experienced constraints or delays due to access to third-party gas processing. We will continue to maintain delivery point flexibility via RMI and do not anticipate gathering or processing issues to constrain our growth in 2019.

Financial Highlights

As of the end of the third quarter, the Company had liquidity of $215.7 million, which included cash on hand of $24.0 million and $191.7 million of borrowing capacity under its credit facility.

The Company reported a PV-10 value (non-GAAP measure) of its proved reserves of $749 million as of September 30, 2018. This represents an increase of 56% compared to year-end 2017 Wattenberg proved reserves value. The SEC 12-month average benchmark pricing as of September 30, 2018 used for reporting the Company’s reserves, which have been adjusted for basis and quality differentials, were $2.91/MMbtu for residue natural gas, $31.84/Bbl for natural gas liquids and $63.43/Bbl for crude oil. Bonanza Creek’s reserves at September 30, 2018 were prepared by the Company's Independent Qualified Reserves Evaluator, Netherland Sewell & Associates. Please see Schedule 9 at the end of this release for additional disclosures related to PV-10.

Conference Call Information

The Company will host a conference call to discuss these financial and operating results on November 9, 2018 at 9:00 a.m. Mountain Time (11:00 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 2465519
Replay 855-859-2056 2465519

About Bonanza Creek Energy, Inc.

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

Forward-Looking Statements

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

For further information, please contact:
Doug Atkinson
Senior Manager, Investor Relations
720-225-6690
datkinson@bonanzacrk.com

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

  Successor
  Three Months Ended
September 30, 2018
  Three Months Ended
September 30, 2017
Operating net revenues:      
Oil and gas sales $ 74,380     $ 45,232  
Operating expenses:      
Lease operating expense 7,951     9,643  
Gas plant and midstream operating expense 2,249     3,265  
Gathering, transportation, and processing 2,749      
Severance and ad valorem taxes 6,485     2,434  
Exploration (6 )    
Depreciation, depletion, and amortization 10,987     7,350  
Abandonment and impairment of unproved properties(1) 430      
General and administrative (including $1,741 and $2,646, respectively, of stock-based compensation) 10,899     15,181  
Total operating expenses 41,744     37,873  
Income from operations 32,636     7,359  
Other income (expense):      
Derivative loss (16,078 )   (2,762 )
Interest expense (608 )   (265 )
Gain on sale of properties 26,720      
Other income (expense) 693     (4 )
Total other income (expense) 10,727     (3,031 )
Income from operations before taxes 43,363     4,328  
Income tax benefit (expense)      
Net income $ 43,363     $ 4,328  
       
Comprehensive income $ 43,363     $ 4,328  
       
Basic net income per common share $ 2.11     $ 0.21  
       
Diluted net income per common share $ 2.10     $ 0.21  
       
Basic weighted-average common shares outstanding 20,541     20,439  
       
Diluted weighted-average common shares outstanding 20,631     20,447  

The Successor Company follows the treasury stock method to compute basic and diluted net income per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.
(1) The Company incurred impairment charges relating to the standard amortization of unproved properties within the Wattenberg Field during the Current Successor quarter.   

  Successor     Predecessor
  Nine Months Ended
September 30, 2018
  April 29, 2017 through
September 30, 2017
    January 1, 2017
through April 28, 2017
Operating net revenues:            
Oil and gas sales $ 210,444     $ 73,346       $ 68,589  
Operating expenses:            
Lease operating expense 29,726     15,796       13,128  
Gas plant and midstream operating expense 9,109     5,027       3,541  
Gathering, transportation, and processing 6,747            
Severance and ad valorem taxes 17,788     4,842       5,671  
Exploration 244     359       3,699  
Depreciation, depletion, and amortization 28,059     12,186       28,065  
Abandonment and impairment of unproved properties(1) 5,409            
Unused commitments 21           993  
General and administrative (including $4,933, $10,595 and $2,116, respectively, of stock-based compensation) 30,350     31,320       15,092  
Total operating expenses 127,453     69,530       70,189  
Income (loss) from operations 82,991     3,816       (1,600 )
Other income (expense):            
Derivative loss (46,832 )   (2,762 )      
Interest expense (1,770 )   (460 )     (5,656 )
Gain on sale of properties 26,720            
Reorganization items, net (note 2)           8,808  
Other income 983     154       1,108  
Total other income (expense) (20,899 )   (3,068 )     4,260  
Income from operations before taxes 62,092     748       2,660  
Income tax benefit (expense)            
Net income $ 62,092     $ 748       $ 2,660  
             
Comprehensive income $ 62,092     $ 748       $ 2,660  
             
Basic net income per common share $ 3.03     $ 0.04       $ 0.05  
             
Diluted net income per common share $ 3.02     $ 0.04       $ 0.05  
             
Basic weighted-average common shares outstanding 20,495     20,410       49,559  
             
Diluted weighted-average common shares outstanding 20,587     20,438       50,971  

Note: The Predecessor Company followed the two-class method when computing the basic and diluted net income 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 per share. Please refer to Note 12 – Earnings Per Share in the Form 10-Q, for a detailed calculation.
(1) Represents incurred impairment charges relating to non-core leases expiring and the standard amortization of unproved properties within the Wattenberg Field.

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

  Successor
  Three Months Ended
September 30, 2018
  Three Months Ended
September 30, 2017
Cash flows from operating activities:      
Net income $ 43,363     $ 4,328  
Adjustments to reconcile net income to net cash provided by operating activities:      
Depreciation, depletion, and amortization 10,987     7,350  
Abandonment and impairment of unproved properties 430      
Well abandonment costs and dry hole expense     10  
Stock-based compensation 1,741     2,646  
Derivative loss 16,078     2,762  
Derivative cash settlements (8,322 )    
Gain on sale of oil and gas properties (26,720 )    
Other (172 )   2  
Changes in current assets and liabilities:      
Accounts receivable (22,447 )   (8,447 )
Prepaid expenses and other assets 48     (350 )
Accounts payable and accrued liabilities 10,587     7,428  
Settlement of asset retirement obligations (700 )   (477 )
Net cash provided by operating activities 24,873     15,252  
Cash flows from investing activities:      
Acquisition of oil and gas properties (634 )   (92 )
Exploration and development of oil and gas properties (65,338 )   (37,442 )
Proceeds from sale of oil and gas properties 103,114      
Additions to property and equipment - non oil and gas (60 )   (506 )
Net cash used in investing activities 37,082     (38,040 )
Cash flows from financing activities:      
Payments to credit facility (60,000 )    
Proceeds from exercise of stock options 132      
Payment of employee tax withholdings in exchange for the return of common stock (69 )   (318 )
Net cash provided by (used in) financing activities (59,937 )   (318 )
Net change in cash, cash equivalents and restricted cash 2,018     (23,106 )
Cash, cash equivalents and restricted cash:      
Beginning of period 22,068     54,275  
End of period $ 24,086     $ 31,169  


  Successor     Predecessor
  Nine Months Ended
September 30, 2018
  April 29, 2017 through
September 30, 2017
    January 1, 2017 through
April 28, 2017
Cash flows from operating activities:            
Net income $ 62,092     $ 748       $ 2,660  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:            
Depreciation, depletion, and amortization 28,059     12,186       28,065  
Non-cash reorganization items           (44,160 )
Abandonment and impairment of unproved properties 5,409            
Well abandonment costs and dry hole expense     74       2,931  
Stock-based compensation 4,933     10,595       2,116  
Amortization of deferred financing costs and debt premium           374  
Derivative loss 46,832     2,762        
Derivative cash settlements (19,944 )          
Gain on sale of oil and gas properties (26,720 )          
Other     7       18  
Changes in current assets and liabilities:            
Accounts receivable (42,823 )   (2,027 )     (6,640 )
Prepaid expenses and other assets 983     (80 )     963  
Accounts payable and accrued liabilities 9,698     (11,910 )     (5,880 )
Settlement of asset retirement obligations (1,497 )   (936 )     (331 )
Net cash provided by (used in) operating activities 67,022     11,419       (19,884 )
Cash flows from investing activities:            
Acquisition of oil and gas properties (1,929 )   (5,074 )     (445 )
Exploration and development of oil and gas properties (156,820 )   (42,355 )     (5,123 )
Proceeds from sale of oil and gas properties 103,134            
Additions to property and equipment - non oil and gas (340 )   (667 )     (454 )
Net cash used in investing activities (55,955 )   (48,096 )     (6,022 )
Cash flows from financing activities:            
Proceeds from credit facility 60,000            
Payments to credit facility (60,000 )         (191,667 )
Proceeds from sale of common stock           207,500  
Proceeds from exercise of stock options 1,100            
Payment of employee tax withholdings in exchange for the return of common stock (863 )   (2,398 )     (427 )
Net cash provided by (used in) financing activities 237     (2,398 )     15,406  
Net change in cash, cash equivalents and restricted cash 11,304     (39,075 )     (10,500 )
Cash, cash equivalents and restricted cash:            
Beginning of period 12,782     70,246       80,746  
End of period $ 24,086     $ 31,171       $ 70,246  

Schedule 3: Condensed Consolidated Balance Sheets

  Successor
  September 30, 2018   December 31, 2017
ASSETS      
Current assets:      
Cash and cash equivalents $ 24,007     $ 12,711  
Accounts receivable:      
Oil and gas sales 36,085     28,549  
Joint interest and other 39,118     3,831  
Prepaid expenses and other 5,365     6,555  
Inventory of oilfield equipment 1,759     1,019  
Derivative assets 134     488  
Total current assets 106,468     53,153  
Property and equipment (successful efforts method):      
Proved properties 584,672     555,341  
Less: accumulated depreciation, depletion and amortization (39,644 )   (17,032 )
Total proved properties, net 545,028     538,309  
Unproved properties 177,552     183,843  
Wells in progress 102,462     47,224  
Other property and equipment, net of accumulated depreciation of $2,382 in 2018 and $2,224 in 2017 3,766     4,706  
Total property and equipment, net 828,808     774,082  
Long-term derivative assets     6  
Other noncurrent assets 3,159     3,130  
Total assets $ 938,435     $ 830,371  
LIABILITIES AND STOCKHOLDERS’ EQUITY      
Current liabilities:      
Accounts payable and accrued expenses $ 72,720     $ 62,129  
Oil and gas revenue distribution payable 16,119     15,667  
Derivative liability 34,419     11,423  
Total current liabilities 123,258     89,219  
       
Long-term liabilities:      
Credit facility      
Ad valorem taxes 25,174     11,584  
Long-term derivative liability 6,504     2,972  
Asset retirement obligations for oil and gas properties 27,903     38,262  
Total liabilities 182,839     142,037  
       
Commitments and contingencies      
       
Stockholders’ equity:      
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding      
Common stock, $.01 par value, 225,000,000 shares authorized, 20,543,940 and 20,453,549 issued and outstanding in 2018 and 2017, respectively 4,286     4,286  
Additional paid-in capital 694,238     689,068  
Retained earnings (deficit) 57,072     (5,020 )
Total stockholders’ equity 755,596     688,334  
Total liabilities and stockholders’ equity $ 938,435     $ 830,371  

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

  Three Months Ended September 30,   Nine Months Ended September 30,
  2018   2017   2018   2017
Wellhead Volumes and Prices              
               
Crude Oil and Condensate Sales Volumes (Bbl/d)              
Rocky Mountains 10,135     6,447     9,101     6,632  
Mid-Continent 484     1,816     1,246     1,871  
Total 10,619     8,263     10,347     8,503  
               
Crude Oil and Condensate Realized Prices ($/Bbl)              
Rocky Mountains $ 63.26     $ 43.90     $ 61.31     $ 45.27  
Mid-Continent $ 68.64     $ 47.63     $ 65.21     $ 49.00  
Composite $ 63.50     $ 44.72     $ 61.78     $ 46.09  
Composite (after derivatives) $ 55.02     $ 44.72     $ 54.66     $ 46.09  
               
Natural Gas Liquids Sales Volumes (Bbl/d)              
Rocky Mountains 3,013     2,842     2,853     3,069  
Mid-Continent 136     463     340     470  
Total 3,149     3,305     3,193     3,539  
               
Natural Gas Liquids Realized Prices ($/Bbl)              
Rocky Mountains $ 23.74     $ 16.31     $ 20.91     $ 16.03  
Mid-Continent $ 37.14     $ 26.88     $ 31.76     $ 24.51  
Composite $ 24.32     $ 17.79     $ 22.06     $ 17.16  
Composite (after derivatives) $ 24.32     $ 17.79     $ 22.06     $ 17.16  
               
Natural Gas Sales Volumes (Mcf/d)              
Rocky Mountains 21,728     19,459     19,512     20,414  
Mid-Continent 2,114     5,982     4,322     6,182  
Total 23,842     25,441     23,834     26,596  
               
Natural Gas Realized Prices ($/Mcf)              
Rocky Mountains $ 2.15     $ 2.12     $ 2.24     $ 2.24  
Mid-Continent $ 2.93     $ 3.02     $ 2.97     $ 3.11  
Composite $ 2.22     $ 2.33     $ 2.37     $ 2.44  
Composite (after derivatives) $ 2.20     $ 2.33     $ 2.40     $ 2.44  
               
Crude Oil Equivalent Sales Volumes (Boe/d)              
Rocky Mountains 16,769     12,532     15,206     13,104  
Mid-Continent 972     3,276     2,306     3,372  
Total 17,741     15,808     17,512     16,476  
               
Crude Oil Equivalent Sales Prices ($/Boe)              
Rocky Mountains $ 45.28     $ 29.58     $ 43.49     $ 30.15  
Mid-Continent $ 45.74     $ 35.71     $ 45.47     $ 36.30  
Composite $ 45.31     $ 30.85     $ 43.75     $ 31.41  
Composite (after derivatives) $ 40.21     $ 30.85     $ 39.58     $ 31.41  
               
Total Sales Volumes (MBoe) 1,632.2     1,454.4     4,781.0     4,481.3  

Schedule 5: Per unit operating margins
(unaudited)

  Three Months Ended September 30,   Nine Months Ended September 30,
  2018   2017   Percent Change   2018   2017   Percent Change
Sales volume                      
Oil (MBbl) 977     760     29 %   2,825     2,313     22 %
Gas (MMcf) 2,193     2,341     (6 )%   6,506     7,234     (10 )%
NGL (MBbl) 290     304     (5 )%   872     963     (9 )%
Equivalent (MBoe) 1,632     1,454     12 %   4,781     4,481     7 %
                       
Realized pricing (before derivatives)                      
Oil ($/Bbl) $ 63.50     $ 44.72     42 %   $ 61.78     $ 46.09     34 %
Gas ($/Mcf) $ 2.22     $ 2.33     (5 )%   $ 2.37     $ 2.44     (3 )%
NGL ($/Bbl) $ 24.32     $ 17.79     37 %   $ 22.06     $ 17.16     29 %
Equivalent ($/Boe) $ 45.31     $ 30.85     47 %   $ 43.75     $ 31.41     39 %
                       
Per Unit Costs ($/Boe)                      
Realized price equivalent (before derivatives) $ 45.31     $ 30.85     47 %   $ 43.75     $ 31.41     39 %
Lease operating expense 4.87     6.63     (27 )%   6.22     6.45     (4 )%
Gathering, transportation and processing 1.68         %   1.41         %
Gas plant and midstream operating expense 1.38     2.24     (38 )%   1.91     1.91     %
Severance and ad valorem 3.97     1.67     138 %   3.72     2.35     58 %
Cash general and administrative 5.61     8.62     (35 )%   5.32     7.52     (29 )%
Total cash operating costs $ 17.51     $ 19.16     (9 )%   $ 18.58     $ 18.23     2 %
Cash operating margin (before derivatives) $ 27.80     $ 11.69     138 %   $ 25.17     $ 13.18     91 %
Derivative cash settlements (5.10 )       %   (4.17 )       %
Cash operating margin (after derivatives) $ 22.70     $ 11.69     94 %   $ 21.00     $ 13.18     59 %
                       
Non-cash items                      
Non-cash general and administrative $ 1.07     $ 1.82     (41 )%   $ 1.03     $ 2.84     (64 )%

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

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

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

    Three Months Ended September 30,   Nine Months Ended September 30,
    2018   2017   2018   2017
Net income   $ 43,363     $ 4,328     $ 62,092     $ 3,408  
Adjustments to net income:                
Derivative loss   16,078     2,762     46,832     2,762  
Derivative cash settlements   (8,322 )       (19,944 )    
Gain on sale of oil and gas properties   (26,720 )       (26,720 )    
Abandonment and impairment of unproved properties   430         5,409      
Exploratory dry hole expense       10         3,005  
Unused commitments           21      
Stock-based compensation (1)   1,741     2,646     4,933     12,711  
Severance costs (1)   279     1,605     279     1,605  
Reorganization items, net               (8,808 )
Pre-petition advisory fees (1)               683  
Post-petition restructuring fees (1)       2,317         3,740  
Total adjustments before taxes   (16,514 )   9,340     10,810     15,698  
Income tax effect                
Total adjustments after taxes   $ (16,514 )   $ 9,340     $ 10,810     $ 15,698  
                 
Adjusted net income   $ 26,849     $ 13,668     $ 72,902     $ 19,106  
Adjusted net income per diluted share (2)   $ 1.30     $ 0.67     $ 3.54     $ 0.93  
                 
Diluted weighted-average common shares outstanding (2)   20,631     20,447     20,587     20,438  
                 
(1) Included as a portion of general and administrative expense in the consolidated statements of operations.
(2) For the three and nine month periods ended September 30, 2017, the Company used the Successor's diluted weighted average share count to calculate adjusted net income per diluted share.

Schedule 7: Adjusted EBITDAX
(in thousands, unaudited)

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

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

    Three Months Ended September 30,   Nine Months Ended September 30,
    2018   2017   2018   2017
Net income   $ 43,363     $ 4,328     $ 62,092     $ 3,408  
Exploration   (6 )       244     4,058  
Depreciation, depletion and amortization   10,987     7,350     28,059     40,251  
Abandonment and impairment of unproved properties   430         5,409      
Unused commitments           21      
Stock-based compensation (1)   1,741     2,646     4,933     12,711  
Severance costs (1)   279     1,605     279     1,605  
Interest expense   608     265     1,770     6,116  
Derivative loss   16,078     2,762     46,832     2,762  
Derivative cash settlements   (8,322 )       (19,944 )    
Gain on sale of oil and gas properties   (26,720 )       (26,720 )    
Pre-petition advisory fees (1)               683  
Post-petition restructuring fees (1)       2,317         3,740  
Reorganization items, net               (8,808 )
Adjusted EBITDAX   $ 38,438     $ 21,273     $ 102,975     $ 66,526  
                 
(1) Included as a portion of general and administrative expense in the consolidated statements 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 to provide only the cash portion of its G&A expense, which can be used to evaluate cost management and operating efficiency on a comparable basis from period to period. Management believes Recurring cash G&A provides external users of the Company’s consolidated financial statements such as industry analysts, investors, lenders, and rating agencies with additional information to assist in their analysis of the Company. The Company defines recurring 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 recurring cash G&A to provide typical cash G&A costs that are planned for in a given period. Recurring cash G&A is not a fully inclusive measure of general and administrative expense as determined by GAAP.

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

    Three Months Ended September 30,   Nine Months Ended September 30,
    2018   2017   2018   2017
General and administrative   $ 10,899     $ 15,181     $ 30,350     $ 46,412  
Stock-based compensation   (1,741 )   (2,646 )   (4,933 )   (12,711 )
Cash G&A   $ 9,158     $ 12,535     $ 25,417     $ 33,701  
Pre-petition restructuring fees               (683 )
Post-petition restructuring fees       (2,317 )       (2,317 )
Other non-recurring expense   (279 )   (1,605 )   (279 )   (1,606 )
Recurring Cash G&A   $ 8,879     $ 8,613     $ 25,138     $ 29,095  

Schedule 9: PV10 Value
PV-10 values are non-GAAP financial measures as defined by the SEC. The Company believes that the presentation of PV-10 value is relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies.

The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). With respect to PV-10 calculated as of an interim date, GAAP does not provide for disclosure of standardized measure on an interim basis. It is not practical to calculate the taxes for the related interim period.

blue-logo-200x-web.jpg

Powered by EIN News