Bonanza Creek Energy Announces Fourth Quarter and Full-year 2018 Results

Company Bonanza Creek Energy Inc 
Tags Production/Development, Exploration, Strategy - Upstream, Financial & Operating Data, Strategy - Corporate
Date February 27, 2019

Bonanza Creek Energy, Inc. (NYSE: BCEI) (the "Company" or "Bonanza Creek") today announced its fourth quarter and full-year 2018 financial results and has posted an updated investor presentation on its corporate website.

Highlights of the fourth quarter and full-year 2018 include:

  • Net oil and gas revenue of $66.2 million and $276.7 million for the three and twelve months ended December 31, 2018, respectively
  • Wattenberg lease operating expenses of $3.27 per Boe and $4.76 per Boe for the three and twelve months ended December 31, 2018, respectively
  • Rocky Mountain Infrastructure ("RMI") operating expenses of $1.06 per Boe and $1.35 per Boe for the three and twelve months ended December 31, 2018, respectively
  • GAAP net income of $106.1 million, or $5.15 per diluted share, and $168.2 million, or $8.16 per diluted share, for the three and twelve months ended December 31, 2018, respectively
  • Adjusted EBITDAX(1) of $41.9 million and $144.8 million for the three and twelve months ended December 31, 2018, respectively
  • Year-end 2018 Wattenberg reserves of 116.8 MMBoe, up 29% from prior year-end reserves with PV-10 growth of 60% to $955.0 million(2)
    (1)   Adjusted EBITDAX is a non-GAAP measure. Please see Schedule 5 at the end of this release for additional disclosures related to Adjusted EBITDAX and a reconciliation to net income (loss) (GAAP).
    (2)   PV-10 is a non-GAAP measure. Please see Schedule 6 at end of this release for additional disclosures related to PV-10 and a reconciliation to Standardized Measure (GAAP).

Eric Greager, Chief Executive Officer of Bonanza Creek, commented, "We exited 2018 with significant momentum as adjusted EBITDAX increased to $41.9 million in the fourth quarter of 2018, up 9% sequentially from third quarter of 2018.  Our results continue to demonstrate the quality of our assets and our technical and operational capabilities. Our returns focused capital program, combined with an improved cost structure, provide a disciplined path to achieving greater than 30% Wattenberg production growth while maintaining leverage of approximately 0.5x in 2019.”

Fourth Quarter 2018 Results

During the fourth quarter of 2018, the Company reported Wattenberg average daily sales of 17.7 Mboe per day, which increased 5% from the third quarter 2018, driven by high-intensity completion designs and consistently low gathering system pressures on the Company's RMI system. Product mix for the fourth quarter of 2018 was 62% oil, 17% NGLs, and 21% residue natural gas. During the fourth quarter of 2018, the Company drilled 28 gross (21.8 net) operated wells, 8 of which were extended reach lateral ("XRL") wells, and turned to sales 17 gross (12.8 net) operated wells, 9 of which were XRL wells.

The table below provides operating statistics for our Wattenberg assets.

    Three Months Ended(1)    Twelve Months Ended(1) 
    12/31/2018    12/31/2017    % Change    12/31/2018    12/31/2017    % Change 
Avg. Daily Sales Volumes:                                     
Crude oil (Bbls/d)    11,039      6,762        63          9,589        6,646        44   
Natural gas (Mcf/d)    22,627      17,397        30          20,297        19,597         
Natural gas liquids (Bbls/d)    2,928      2,311        27          2,872        2,869          --     
Crude oil equivalent (Boe/d)    17,738      11,972        48          15,844        12,782        23   
                         
Product Mix                         
  Crude oil      62      56        61      52       
  Natural gas      21      25        21      26       
  Natural gas liquids      17      19        18      22       
                         
Average Sales Prices (before derivatives)(2):                         
  Crude oil (per Bbl)      52.70        51.30        3        58.82          46.81        25   
  Natural gas (per Mcf)      2.68        2.08        29        2.36          2.20         
  Natural gas liquids (per Bbl)      23.74        19.66        21        21.63          16.77        29   
  Crude oil equivalent (per Boe)      40.14        35.79        12        42.55          31.48        35   
                         

(1) Results for three and twelve months ended are for Wattenberg only. Please see tables in the back of this press release and the Annual Report on Form 10-K filed on February 27, 2019 for total Company operating statistics.
(2) 2017 does not include the impacts of adoption ASC 606. Please refer to Note 2 - Revenue Recognition in Annual Report on Form 10-K filed on February 27, 2019 for more information.

Net oil and gas revenue for the fourth quarter of 2018 was $66.2 million compared to $74.4 millionfor the third quarter of 2018. The decrease in fourth quarter 2018 net revenue compared to third quarter was primarily a result of the sale of production associated with the Mid-Continent divestiture in August of 2018. Crude oil accounted for approximately 83% of total revenue in the fourth quarter. Differentials for the Company's Wattenberg oil production during the quarter averaged approximately $5.53 per barrel off of NYMEX WTI.

Wattenberg LOE for the fourth quarter of 2018 on a unit basis decreased by 23% to $3.27 per Boe from $4.26 per Boe in the third quarter of 2018 and compared favorably to fourth quarter guidance of $3.90 per Boe to $4.30 per Boe. Additionally, RMI operating expenses for the fourth quarter were $1.06 per Boe compared to $1.00 per Boe in the third quarter of 2018 and fourth quarter guidance of $1.20 per Boe to $1.40 per Boe.

Unit operating expenses continue to benefit from lower regulatory, compliance, and labor costs. Additionally, the Company’s completed compressor replacement program resulted in significant reductions in maintenance and rental costs. Unit operating expenses have also benefited from new well production, re-use of centralized facilities and well maintenance activities, which have helped improve base production performance.

Production taxes in the fourth quarter of 2018 were positively impacted by a $5.1 million net ad valorem tax settlement. The $5.1 ad valorem settlement is net of $2.3 million due to the Company's associated interest owners and is presented as a reimbursement in the severance and ad valorem taxes line items in the 2018 financial statements in the back of this press release. Please see the Company's Form 10-K filed on February 27, 2019 for more information regarding this settlement.

The Company continued to benefit from multiple delivery points on the RMI system in the fourth quarter. The Company’s fourth gas processor (Cureton Midstream) brought online a 60 MMcf per day cryogenic gas processing plant in the fourth quarter, further enhancing the Company’s downstream optionality. This delivery point flexibility, combined with consistently low line pressures on RMI, have helped ensure minimal production constraints. Line pressure on the Company’s RMI system has remained consistent between 50 and 100 psi, well below typical field-wide operating pressures outside of RMI. The Company's 2018 development program did not experience constraints or delays due to access to third-party gas processing, nor does the Company anticipate any constraints in 2019.

The Company's general and administrative ("G&A") expense was $12.1 million for the fourth quarter of 2018, which includes $2.2 million in stock compensation. Cash G&A expense, which excludes stock compensation, was $9.9 million for the fourth quarter and totaled $35.3 million for the full-year. Cash G&A is a non-GAAP measure. Please see Schedule 7 at the end of this release for a reconciliation from GAAP figure of general and administrative expense to cash G&A.

2018 Proved Reserves, Costs Incurred, and Finding and Development Costs

As previously reported, Bonanza Creek’s year-end 2018 proved reserves were 116.8 MMBoe, a 29% increase from year-end 2017 Wattenberg reserves.  The Company's year-end 2018 proved reserves were comprised of 64.4 MMbbls of oil, 24.9 MMbbls of NGLs, and 165.0 Bcf of natural gas and were 42% proved developed producing. At year-end the Company’s proved reserves PV-10 utilizing Securities and Exchange Commission ("SEC") pricing was $955.0 million. Bonanza Creek’s independent reserve engineering firm, Netherland, Sewell & Associates, Inc., completed its estimate of the Company’s year-end 2018 proved reserves in accordance with SEC guidelines using pricing of $65.56 per barrel for crude oil and $3.10 per million British Thermal Units (MMBtu) for natural gas. Please see Schedule 6 at the end of this release for information on SEC pricing and a reconciliation of PV-10 to the GAAP figure “Standardized Measure of Oil and Gas.”

A breakout of the Company’s costs incurred are provided in the table below.

(in thousands)  For the Year Ended
December 31, 2018 
     
Acquisition(1)    2,861   
Development(2)      304,197   
Exploration      294   
Total(3)    307,352   
  1. Acquisition costs for unproved properties were $2.5 million in 2018.  Acquisition costs for proved properties were $0.4 million in 2018.
  2. Development costs include workover costs of $4.3 million.
  3. Includes amounts relating to asset retirement obligations of ($9.0) million.

Proved Reserve Roll-Forward

  MBoe 
Balance as of December 31, 2017  102,022   
Divestitures  (11,157 
Extensions, discoveries, and infills  28,832 
Revisions to previous estimates  6,024 
Locations Removal  (2,527 
Production  (6,409 
Balance as of December 31, 2018  116,785   

Conference Call Information

The Company will host a conference call to discuss these financial and operating results on February 28, 2019 at 10:00 a.m. Mountain Time (12:00 p.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 . Dial-in information for the conference call is included below.

Type  Phone Number  Passcode 
Live participant  877-793-4362  3582918 
Replay  855-859-2056  3582918 

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

  Successor 
  Three Months Ended December 31, 
  2018    2017 
Operating net revenues:       
Oil and gas sales  66,213      50,189   
Operating expenses:       
Lease operating expense  5,099      10,066   
Gas plant and midstream operating expense  1,679      3,314   
Gathering, transportation, and processing  2,985      —   
Severance and ad valorem taxes(1)  1,211      4,748   
Exploration  47      3,386   
Depreciation, depletion and amortization  13,824      9,126   
Abandonment and impairment of unproved properties  (138    —   
General and administrative (including $2,224 and $1,035, respectively, of stock compensation)  12,103      11,356   
Total operating expenses  36,810      41,996   
Income from operations  29,403      8,193   
Other income (expense):       
Derivative gain (loss)  77,103      (12,603 
Interest expense  (833    (313 
Gain on sale of properties  604      —   
Other income (loss)  (183    (1,421 
Total other income (expense)  76,691      (14,337 
Income (loss) from operations before taxes  106,094      (6,144 
Income tax benefit  —      376   
Net Income (loss)  106,094      (5,768 
       
Net Income (loss) per basic common share*  5.16      (0.28 
       
Net Income (loss) per diluted common share*  5.15      (0.28 
       
Basic weighted-average common shares outstanding  20,544      20,454   
Diluted weighted-average common shares outstanding  20,588      20,454   
  • The Successor Company follows the treasury stock method to compute basic and diluted net income (loss) per share. Please refer to Note 14 – Earnings per Share in the Form 10-K, for a detailed calculation.
    (1) Includes $5.1 million reimbursement related to an ad valorem tax settlement. Please refer to Note 8 - Commitment and Contingencies in the Form 10-K for additional information.
    Successor      Predecessor 
    Twelve
Months
Ended
December
31, 2018 
  April 29,
2017
through
December
31, 2017 
    January 1,
2017 through
April 28, 2017 
Operating net revenues:               
Oil and gas sales    276,657      123,535        68,589   
Operating expenses:               
Lease operating expense    34,825      25,862        13,128   
Gas plant and midstream operating expense    10,788      8,341        3,541   
Gathering, transportation, and processing    9,732      —        —   
Severance and ad valorem taxes(1)    18,999      9,590        5,671   
Exploration    291      3,745        3,699   
Depreciation, depletion and amortization    41,883      21,312        28,065   
Abandonment and impairment of unproved properties    5,271      —        —   
Unused commitments    21      —        993   
General and administrative expense (including $7,156, $11,630, and $2,116 respectively, of stock-based compensation)    42,453      42,676        15,092   
Total operating expenses    164,263      111,526        70,189   
Income (loss) from operations    112,394      12,009        (1,600 
Other income (expense):               
Derivative gain (loss)    30,271      (15,365      —   
Interest expense    (2,603    (773      (5,656 
Gain on sale of properties    27,324      —        —   
Reorganization items, net    —      —        8,808   
Other income (loss)    800      (1,267      1,108   
Total other income (expense)    55,792      (17,405      4,260   
Income (loss) from operations before taxes    168,186      (5,396      2,660   
Income tax benefit    —      376        —   
Net income (loss)    168,186      (5,020      2,660   
               
Net income (loss) per basic common share*    8.20      (0.25      0.05   
               
Net income (loss) per diluted common share*    8.16      (0.25      0.05   
               
Basic weighted-average common shares outstanding    20,507      20,427        49,559   
Diluted weighted-average common shares outstanding    20,603      20,427        50,971   
  • The Predecessor Company followed the two-class method when computing the basic and diluted income (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 14 – Earnings per Share in the Form 10-K, for a detailed calculation.

(1) Includes $5.1 million reimbursement related to an ad valorem tax settlement. Please refer to Note 8 - Commitment and Contingencies in the Form 10-K for additional information.

Schedule 2: Statement of Cash Flows

(in thousands, unaudited)

  Successor 
  Three Months Ended December 31, 
  2018    2017 
Cash flows from operating activities:       
Net income (loss)  106,094      (5,768 
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:       
Depreciation, depletion and amortization  13,824      9,126   
Abandonment and impairment of unproved properties  (138    —   
Well abandonment costs and dry hole expense  —      —   
Stock-based compensation  2,223      1,035   
Amortization of deferred financing costs and debt premium  30      —   
Gain on sale of properties  (604    —   
Derivative (gain) loss  (77,103    12,603   
Derivative cash settlements  1,784      (1,464 
Inventory write-off  248      1,758   
Other  (3,559     
Changes in current assets and liabilities:       
     Accounts receivable  (4,165    (2,450 
     Prepaid expenses and other assets  1,231      (1,899 
     Accounts payable and accrued liabilities  10,255      3,441   
     Settlement of asset retirement obligations  (544    (231 
         Net cash provided by (used in) operating activities  49,576      16,155   
Cash flows from investing activities:       
Acquisition of oil and gas properties  (963    (309 
Exploration and development of oil and gas properties  (107,411    (34,020 
Additions to property and equipment - non oil and gas  (47    (210 
         Net cash provided by (used in) investing activities  (108,421    (34,539 
Cash flows from financing activities:       
Proceeds from Current Credit Facility  50,000      —   
Proceeds from Prior Credit Facility  30,000      —   
Payments to Prior Credit Facility  (30,000    —   
Deferred financing costs  (2,239    —   
         Net cash provided by (used in) financing activities  47,761      —   
Net change in cash, cash equivalents, and restricted cash:  (11,084    (18,384 
Cash, cash equivalents, and restricted cash:       
Beginning of period  24,086      31,166   
End of period  13,002      12,782   
    Successor      Predecessor 
    Twelve
Months
Ended
December
31, 2018 
  April 29,
2017
through
December
31, 2017 
    January 1,
2017 through
April 28,
2017 
Cash flows from operating activities:               
Net income (loss)    168,186      (5,020      2,660   
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:               
Depreciation, depletion and amortization    41,883      21,312        28,065   
Non-cash reorganization items    —      —        (44,160 
Abandonment and impairment of unproved properties    5,271      —        —   
Well abandonment costs and dry hole expense    —      75        2,931   
Stock-based compensation    7,156      11,630        2,116   
Amortization of deferred financing costs and debt premium    30      —        374   
Derivative (gain) loss    (30,271    15,365        —   
Derivative cash settlements    (18,160    (1,464      —   
Gain on sale of oil and gas properties    (27,324    —        —   
Inventory write-offs    248      1,758        —   
Other    (3,559    11        18   
Changes in current assets and liabilities:               
     Accounts receivable    (46,988    (4,477      (6,640 
     Prepaid expenses and other assets    2,214      (1,979      963   
     Accounts payable and accrued liabilities    19,953      (8,470      (5,880 
     Settlement of asset retirement obligations    (2,041    (1,167      (331 
         Net cash provided by (used in) operating activities    116,598      27,574        (19,884 
Cash flows from investing activities:               
Acquisition of oil and gas properties    (2,892    (5,383      (445 
Exploration and development of oil and gas properties    (264,231    (76,384      (5,123 
Proceeds from sale of oil and gas properties    103,134      —        —   
Additions to property and equipment - non oil and gas    (387    (874      (454 
         Net cash used in investing activities    (164,376    (82,641      (6,022 
Cash flows from financing activities:               
Proceeds from Current Credit Facility    50,000             
Proceeds from Prior Credit Facility    90,000             
Payments to Prior Credit Facility    (90,000           
Payments to predecessor credit facility    —      —        (191,667 
Proceeds from sale of common stock    —      —        207,500   
Payment of employee tax withholdings in exchange for the return of common stock    (863    (2,398      (427 
Deferred financing costs    (2,239    —        —   
Proceeds from exercise of stock options    1,100      —        —   
         Net cash provided by (used in) financing activities    47,998      (2,398      15,406   
Net change in cash, cash equivalents, and restricted cash    220      (57,465      (10,500 
Cash, cash equivalents, and restricted cash:               
Beginning of period    12,782      70,247        80,747   
End of period    13,002      12,782        70,247   

Schedule 3: Balance Sheets

(in thousands, unaudited)

  Successor 
  As of December 31, 
  2018    2017 
ASSETS       
Current assets:       
Cash and cash equivalents  12,916      12,711   
Accounts receivable:       
Oil and gas sales  31,799      28,549   
Joint interest and other  47,577      3,831   
Prepaid expenses and other  4,633      6,555   
Inventory of oilfield equipment  3,478      1,019   
Derivative asset  34,408      488   
     Total current assets  134,811      53,153   
Property and equipment (successful efforts method):       
Proved properties  719,198      555,341   
Less: accumulated depreciation, depletion and amortization  (52,842    (17,032 
Total proved properties, net  666,356      538,309   
Unproved properties  154,352      183,843   
Wells in progress  93,617      47,224   
Other property and equipment, net of accumulated depreciation of $2,546 in 2018 and $2,224 in 2017  3,649      4,706   
Total property and equipment, net  917,974      774,082   
Long-term derivative asset  3,864       
Other noncurrent assets  4,885      3,130   
Total assets  1,061,534      830,371   
LIABILITIES AND STOCKHOLDERS’ EQUITY       
Current liabilities:       
Accounts payable and accrued expenses  79,390      62,129   
Oil and gas revenue distribution payable  19,903      15,667   
Derivative liability  183      11,423   
Total current liabilities  99,476      89,219   
Long-term liabilities:       
Credit facility  50,000      —   
Ad valorem taxes  18,740      11,584   
Long-term derivative liability  —      2,972   
Asset retirement obligations for oil and gas properties  29,405      38,262   
Total liabilities  197,621      142,037   
Commitments and contingencies       
Stockholders’ equity:       
Successor preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding as of December 31, 2018 and 2017  —      —   
Successor common stock, $.01 par value, 225,000,000 shares authorized, 20,543,940 and 20,453,549 issued and outstanding as of December 31, 2018 and 2017, respectively  4,286      4,286   
Additional paid-in capital  696,461      689,068   
Retained earnings (deficit)  163,166      (5,020 
Total stockholders’ equity  863,913      688,334   
Total liabilities and stockholders’ equity  1,061,534      830,371   

Schedule 4: Per unit operating margins

(unaudited)

    For the Three Months Ended
December 31, 
  For the Twelve Months Ended
December 31, 
    2018    2017    Percent
Change 
  2018    2017    Percent
Change 
Crude Oil Equivalent Sales Volumes (Boe)    1,632,776      1,357,028      20    6,413,777      5,838,306      10 
                         
Per Unit Costs ($/Boe)                         
Realized price (before derivatives)(1)    40.14      36.73      10    42.83      32.65      31 
LOE    3.12      7.42      (58  )%    5.43      6.68      (19  )% 
Midstream expense    1.03      2.44      (58  )%    1.68      2.04      (17  )% 
Severance and Ad Valorem    0.74      3.50      (79  )%    2.96      2.61      13 
Cash General and Administrative (2)    6.05      7.61      (20  )%    5.50      7.54      (27  )% 
Total cash operating costs    10.94      20.97      (48  )%    15.57      18.87      (17  )% 
Cash operating margin (before derivatives)    29.20      15.76      85    27.26      13.78      98 
Derivative Cash Settlements    1.09      (1.07    —    (2.83    (0.25    — 
Cash operating margin (after derivatives)    30.29      14.69      106    24.43      13.53      81 
                         
Non-cash items                         
Depreciation Depletion and Amortization    8.47      6.72      26    6.53      8.46      (23  )% 
Non-cash General and Administrative    1.36      0.76      79    1.12      2.35      (53  )% 
                         
(1)Crude oil and natural gas sales excludes $0.7 million, $0.3 million, $1.9, and $1.0 million of oil transportation revenues from third parties, which do not have associated sales volumes for three months ended December 31 2018 and 2017 and for the year ended December 31, 2018 and 2017, respectively. 
(2) Cash general and administrative expense excludes stock based compensation of $2.2 million and $1.0 million for the three-month periods ended December 31, 2018 and 2017, respectively, and $7.2 million and $13.7 million for the twelve-month periods ended December 31, 2018 and 2017, respectively. 
Three Months Ended    Twelve Months Ended 
  December 31,    December 31, 
  2018    2017    2018    2017 
Net Income (loss)  106,094      (5,768    168,186      (2,360 
Exploration  47      3,386      291      7,444   
Depreciation, depletion and amortization  13,824      9,126      41,883      49,377   
Abandonment and impairment of unproved properties  (138    —      5,271      —   
Stock-based Compensation (1)  2,224      1,035      7,156      13,746   
Cash severance costs (1)  —      —      279      1,605   
Unused commitments  —      —      21      —   
Gain on sale of oil and gas properties  (604    —      (27,324    —   
Ad valorem reimbursement(2)  (5,134        (5,134     
Advisor fees related to CEO search and strategic alternatives(1)  —      2,774      —      2,774   
Deferred financing costs amortization  30      —      30      374   
Pre-petition advisory fees(1)  —      —      —      683   
Post-petition restructuring fees(1)  —      —      —      3,740   
Reorganization items  —      —      —      (8,808 
Interest expense  833      313      2,603      6,429   
Derivative (gain) loss  (77,103    12,603      (30,271    15,365   
Derivative cash settlements  1,784      (1,464    (18,160    (1,464 
Income tax (benefit)  —      (376    —      (376 
Adjusted EBITDAX  41,857      21,629      144,831      88,529   
               
(1) Included as a portion of general and administrative expense on the consolidated statement of operations. 
(2) $5.1 million reimbursement related to an ad valorem tax settlement. Please refer to the Form 10-K for additional information. 

Schedule 6: PV-10 of Estimated Proved Reserves

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

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

    December 31, 
(in thousands)    2018 
     
PV-10 (1)    954,980   
Present value of future income taxes discounted at 10% (2)    —   
Standardized Measure    954,980   
     
(1) The 12-month average benchmark pricing used to estimate SEC proved reserves and PV-10 value for crude oil and natural gas was $65.56 per Bbl of WTI crude oil and $3.10 per MMBtu of natural gas at Henry Hub before differential adjustments. After differential adjustments, the Company's SEC pricing realizations for year-end 2018 were $59.29 per Bbl of oil, $22.06 per Bbl of NGLs, and $2.28 per Mcf of natural gas. 
(2) The tax basis of the Company's oil and gas properties as of December 31, 2018 provides more tax deduction than income generation when reserve estimates were prepared using 2018 SEC pricing. 

Schedule 7: Cash G&A

(in thousands, unaudited)

Cash G&A is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines cash G&A as GAAP general and administrative expense exclusive of the Company's stock based compensation. The Company refers to cash G&A to provide typical cash G&A costs that are planned for in a given period. Cash G&A is not a fully inclusive measure of general and administrative expense as determined by GAAP.

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

    Three Months Ended    Twelve Months Ended 
    12/31/2018    12/31/2017    12/31/2018    12/31/2017 
General and Administrative Expense    12,103      11,356      42,453      57,768   
Stock Compensation    (2,224    (1,035    (7,156    (13,746 
Cash G&A    9,879      10,321      35,297      44,022 

 
Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd