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

Source Press Release
Company Bonanza Creek Energy Inc 
Tags Capital Spending, Guidance, Financial & Operating Data, Strategy - Corporate
Date November 08, 2018

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, 2018used 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     
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  —            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  —       
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     
                       
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     
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.

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd