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


  • First quarter production volumes averaged 16.8 MBoe per day, above high end of guidance
  • Enhanced completion wells continue to outperform type curve
  • First quarter GAAP net income of $13.9 million, or $0.68 per diluted share; adjusted net income (1) of $21.8 million, or $1.07 per diluted share; adjusted EBITDAX(1) of $29.7 million

(1)  Non-GAAP measures, see attached Reconciliation Schedules

DENVER, May 08, 2018 (GLOBE NEWSWIRE) — Bonanza Creek Energy, Inc. (NYSE:BCEI) (the “Company” or “Bonanza Creek”) today announces its first quarter 2018 financial results and operating outlook and has posted an updated investor presentation on its corporate website.

Eric Greager, President and Chief Executive Officer, commented, “I am excited to be part of the Bonanza Creek team and believe that the first quarter marked a solid start to the year. Our team has made great progress in driving better well results through the application of higher-intensity completions. I look forward to continuing our innovation in this area and applying these techniques across our acreage position. I am also pleased with Bonanza’s differentiated midstream capabilities and the demonstrated value that they provide to our operations. I believe that 2018 will be a pivotal year for our company and shareholders.”

First Quarter 2018 Results

During the first quarter of 2018, the Company reported average daily production of 16.8 MBoe per day, which exceeded the high end of the Company’s guidance range of 16.0 – 16.6 MBoe per day. Production outperformance for the quarter was a result of strong new well completions and consistently low line pressures on the Company’s Rocky Mountain Infrastructure system (“RMI”).The Company’s first quarter production decreased by 5% when compared to the first quarter of 2017 due to minimal drilling and completion activity throughout the first half of 2017. Product mix for the first quarter of 2018 was 59% oil, 17% NGLs, and 24% natural gas.

Net revenue for the first quarter of 2018 was $64.2 million, compared to $52.6 million for the first quarter of 2017. The increase in first quarter 2018 net revenue compared to 2017 was a result of increased commodity pricing, greater oil-weighted production, and the adoption of ASC 606, which requires revenues to be reported on a gross basis and no longer net of certain gathering, transportation, and processing charges. The net effect of these changes in presentation increased revenues and related gathering, transportation, and processing line items for the quarter ended March 31, 2018, by $2.3 million, and had no effect on net income. Please see additional disclosure on the adoption of this revenue recognition standard in note 3 of the Company’s 10-Q filed on May 8, 2018.  Crude oil accounted for approximately 81% of total revenue. Differentials for the Company’s Rocky Mountain oil production during the quarter averaged approximately $5.68 per Bbl off of NYMEX WTI. Corporate average realized prices for the first quarter of 2018 are presented below.

Average Realized Prices
Three Months Ended March 31, 2018
Oil (per Bbl) 57.89
Gas (per Mcf) 2.78
NGL (per Bbl) 23.33
Boe (Per Boe) 42.27

Lease operating expense (“LOE”) for the first quarter of 2018 was $10.5 million, or $6.93 per Boe, a 5% increase in total LOE compared to $9.9 million, or $6.28 per Boe, in the first quarter of 2017. Gas plant and midstream operating expense for the first quarter of 2018 was $3.6 million, or $2.39 per Boe, a 34% increase in total gas plant and midstream operating expense compared to $2.7 million, or $1.71 per Boe, in the first quarter of 2017. Absolute and per-unit LOE and gas plant and midstream operating expenses increased during the first quarter of 2018 primarily as a result of implementation costs from compressor swaps that occurred during the quarter. The Company accelerated its transition to an efficient fleet, which is expected to reduce compressor costs and help ensure low gathering system pressures going forward. These reduced costs, along with increased production, are expected to drive down per-unit LOE metrics each quarter for the remainder of 2018.

Below is a breakout of the Company’s regional LOE and gas plant and midstream operating expense for the first quarter of 2018.

Three Months Ended March 31, 2018
Rocky Mountain Mid-Continent Total Company
($M) ($/Boe) ($M) ($/Boe) ($M) ($/Boe)
Lease operating expense $ 7,424 $ 6.00 $ 3,035 $ 11.15 $ 10,459 $ 6.93
Gas plant and midstream operating expense $ 2,368 $ 1.92 $ 1,245 $ 4.57 3,613 $ 2.39
Total $ 9,792 $ 7.92 $ 4,280 $ 15.72 $ 14,072 $ 9.32

The Company’s general and administrative (“G&A”) expense was $9.5 million for the first quarter of 2018, a 21% decrease from the first quarter of 2017. The decrease is primarily due to reduced advisory fees and cost reduction initiatives that were implemented since the Company’s restructuring, including the previously announced reduction in force, which occurred in August of 2017.

Reported net income for the first quarter of 2018 was $13.9 million, or $0.68 per diluted share, compared to a net loss of $94.3 million, or $1.91 per diluted share, for the first quarter of 2017.  The net loss in 2017 was driven by reorganization items of $89.0 million. Adjusted net income for the first quarter of 2018 was $21.8 million, or $1.07 per diluted share, compared to adjusted net income of $0.8 million, or $0.02 per diluted share, for the first quarter of 2017. The increase in adjusted net income over the prior year was driven by improved cost structure, greater oil-weighted production, and an increase in commodity prices over the prior period.

Adjusted EBITDAX for the first quarter of 2018 was $29.7 million, a 9% increase compared to $27.3 million for the first quarter of 2017.

Adjusted net income (loss) 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.

The table below summarizes the Company’s annual results as compared to previously provided guidance.

Guidance vs Actual Summary
1Q18 Guidance 1Q18 Actual
Production (MBoe/d) 16.0 – 16.6 16.8
Annual Guidance YTD Actual
Lease operating expense ($/Boe) $5.00 – $6.00 $ 6.93
Gas plant and midstream operating expense ($/Boe) $1.40 – $1.80 $ 2.39
Cash G&A ($MM)* $32 – $34 $ 9
Production taxes (% of pre-derivative realization) 7% – 8% 8 %
CAPEX ($MM) $280 – $320 $ 52
* Cash G&A guidance is a non-GAAP measure that is exclusive of 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. Please refer to the non-GAAP disclosure at the end of this release for information regarding cash G&A.

The Company reported quarterly production above the high end of guidance in the first quarter. The Company’s lease operating expense and gas plant and midstream operating expense for the first quarter were above the Company’s expectation due to the aforementioned accelerated compressor swap program, which resulted in moderately higher per Boe metrics. The Company expects its per-unit operating costs to reduce throughout the year as production volumes increase and system efficiencies are utilized.

Production, Capital, and Expense Outlook

The Company is updating its 2018 annual guidance and providing second quarter 2018 production guidance. Annual operating cost and CAPEX guidance ranges remain unchanged from the previously provided guidance ranges with the exception of recurring cash G&A, which has been updated to reflect compensation for the Company’s newly-appointed CEO. Below is a table summarizing the Company’s production, capital, and expense guidance for the remainder of 2018.

Guidance Summary
Three Months Ended
June 30, 2018
Twelve Months Ended
December 31, 2018
Production (MBoe/d) 18.0 – 18.6 17.7 – 18.7
LOE ($/Boe) $5.00 – $6.00
Midstream expense ($/Boe) $1.40 – $1.80
Recurring cash G&A* ($MM) $33 – $35
Production taxes (% of pre-derivative realization) 7% – 8%
Total CAPEX ($MM) $280 – $320
* 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.

Operational Highlights

During the first quarter of 2018, the Company spud 18 gross (12.6 net) operated wells, seven of which were extended reach lateral (“XRL”) wells, and completed 8 gross (6.5 net) operated wells, all of which were standard reach lateral (“SRL”) wells.

The Company is providing initial well results for the three XRL wells on its J21 and T21 pads, which were completed in the second half of 2017 on the Company’s central acreage. These two pads had a combined well count of five wells, two SRLs and three XRLs. The three XRL wells have average cumulative production of 8.6 MBoe per 1,000 feet of lateral after 156 days of production and are outperforming the Company’s legacy central XRL type curve by approximately 35%. The average projected three-stream EUR for these XRL wells is approximately 680 MBoe. The Company is encouraged by these results, as they are the first XRL results the Company has obtained using the enhanced stimulation and controlled flow-back programs.

At the beginning of 2018, the Company turned online its eight-SRL F26 pad on its western legacy acreage. Results from these wells have been encouraging and are exceeding the Company’s legacy west SRL type curve by 40%. These eight SRL wells have average cumulative production of 6.5 MBoe per 1,000 feet of lateral after 78 days of production. The wells on this pad still have increasing daily production rates, and as such the Company is waiting for the rates to peak before determining an EUR.

The Company has provided updated production results for these wells along with updated production data from its other enhanced completion wells in its May Investor Presentation, which is available on the Company’s website.

Financial Highlights

As of the end of the first quarter, the Company had liquidity of $182.5 million, which included cash on hand of $5.8 million and $176.7 million of borrowing capacity under its credit facility.  The Company has no outstanding term debt and had $15.0 million outstanding on its credit facility. The Company’s balance sheet strength allows it to be flexible, patient and selective in its investment decisions, and the opportunity to participate in growth opportunities.

Commodity Derivative Position
The Company’s current hedge position is summarized in the table below and reflects additional hedges the Company entered into through May 8, 2018.

Crude Oil
(NYMEX WTI)
Natural Gas
(NYMEX Henry Hub)
Bbls/day Weighted Avg.
Price per Bbl
MMBtu/day Weighted Avg.
Price per MMBTU
2Q18
Cashless Collar 2,000 $42.00/$52.50 6,259 $2.75/$3.38
Swap 3,835 55.03
3Q18
Cashless Collar 2,000 $43.00/$53.50 7,600 $2.75/$3.31
Swap 5,000 57.87
4Q18
Cashless Collar 2,000 $43.00/$53.50 6,600 $2.75/$3.37
Swap 5,000 58.07
1Q19
Cashless Collar 2,000 $43.00/$54.53 7,600 $2.75/$3.22
Swap 4,000 58.16
2Q19
Cashless Collar 1,330 $44.01/$54.79 2,505 $2.75/$3.22
Swap 4,500 58.32
3Q19
Swap 3,000 55.00
4Q19
Swap 3,000 55.00

Conference Call Information

The Company will host a conference call to discuss these financial and operating results on May 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 6175978
Replay 855-859-2056 6175978

About Bonanza Creek Energy, Inc.

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

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These statements include statements regarding development and completion expectations and strategy; decreasing operating and capital costs; impact of the Company’s reorganization; and updated 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:
Scott Fenoglio
SVP – Finance and Planning
720-225-6667
[email protected]

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

Successor Predecessor
Three Months Ended March 31, 2018 Three Months Ended March 31, 2017
Operating net revenues:
Oil and gas sales $ 64,193 $ 52,559
Operating expenses:
Lease operating expense 10,459 9,925
Gas plant and midstream operating expense 3,613 2,705
Gathering, transportation and processing 2,338
Severance and ad valorem taxes 5,233 4,319
Exploration 29 3,407
Depreciation, depletion and amortization 7,508 21,212
Abandonment and impairment of unproved properties 2,502
Unused commitments 21 993
General and administrative (including $1,008 and $1,725, respectively, of stock-based compensation) 9,533 12,094
Total operating expenses 41,236 54,655
Income (loss) from operations 22,957 (2,096 )
Other income (expense):
Derivative loss (8,742 )
Interest expense (357 ) (4,568 )
Reorganization items, net (89,003 )
Other income 12 1,391
Total other expense (9,087 ) (92,180 )
Income (loss) from operations before taxes 13,870 (94,276 )
Income tax benefit (expense)
Net income (loss) $ 13,870 $ (94,276 )
Comprehensive income (loss) $ 13,870 $ (94,276 )
Basic net income (loss) per common share $ 0.68 $ (1.91 )
Diluted net income (loss) per common share $ 0.68 $ (1.91 )
Basic weighted-average common shares outstanding 20,454 49,452
Diluted weighted-average common shares outstanding 20,470 49,452
  • The Predecessor Company followed the two-class method when computing the basic and diluted net 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 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.

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

Successor Predecessor
Three Months Ended March 31, 2018 Three Months Ended March 31, 2017
Cash flows from operating activities:
Net income (loss) $ 13,870 $ (94,276 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 7,508 21,212
Non-cash reorganization items 57,341
Abandonment and impairment of unproved properties 2,502
Well abandonment costs and dry hole expense 2,701
Stock-based compensation 1,008 1,725
Derivative loss 8,742
Derivative cash settlements (4,312 )
Other 172 383
Changes in current assets and liabilities:
  Accounts receivable (15,758 ) (3,814 )
  Prepaid expenses and other assets 3,402 (536 )
  Accounts payable and accrued liabilities (566 ) 31,092
  Settlement of asset retirement obligations (665 ) (176 )
    Net cash provided by operating activities 15,903 15,652
Cash flows from investing activities:
Acquisition of oil and gas properties (98 ) (439 )
Exploration and development of oil and gas properties (37,664 ) (3,425 )
Proceeds from sale of oil and gas properties 20
Additions to property and equipment – non oil and gas (103 ) (201 )
    Net cash used in investing activities (37,845 ) (4,065 )
Cash flows from financing activities:
Proceeds from credit facility 15,000
Payment of employee tax withholdings in exchange for the return of common stock (335 )
    Net cash provided by (used in) financing activities 15,000 (335 )
Net change in cash, cash equivalents and restricted cash (6,942 ) 11,252
Cash, cash equivalents and restricted cash:
Beginning of period $ 12,782 80,747
End of period $ 5,840 $ 91,999

Schedule 3: Condensed Consolidated Balance Sheets

(in thousands, unaudited) Successor
March 31, 2018 December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents $ 5,761 $ 12,711
Accounts receivable:
Oil and gas sales 37,781 28,549
Joint interest and other 10,357 3,831
Prepaid expenses and other 3,153 6,555
Inventory of oilfield equipment 1,308 1,019
Derivative assets 126 488
Total current assets 58,486 53,153
Property and equipment (successful efforts method):
Proved properties 495,141 555,341
Less: accumulated depreciation, depletion and amortization (21,401 ) (17,032 )
Total proved properties, net 473,740 538,309
Unproved properties 181,193 183,843
Wells in progress 68,735 47,224
Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $2,583 in 2018 82,504
Other property and equipment, net of accumulated depreciation of $2,482 in 2018 and $2,224 in 2017 4,551 4,706
Total property and equipment, net 810,723 774,082
Long-term derivative assets 56 6
Other noncurrent assets 3,142 3,130
Total assets $    872,407 $ 830,371
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 69,148 $ 62,129
Oil and gas revenue distribution payable 18,481 15,667
Derivative liability 15,427 11,423
Total current liabilities 103,056 89,219
Long-term liabilities:
Credit facility 15,000
Ad valorem taxes 15,435 11,584
Long-term derivative liability 3,086 2,972
Asset retirement obligations for oil and gas properties 26,939 38,262
Asset retirement obligations for oil and gas properties held for sale 5,679
Total liabilities 169,195 142,037
Stockholders’ equity:
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding
Common stock, $.01 par value, 225,000,000 shares authorized, 20,453,619 and 20,453,549 issued and outstanding in 2018 and 2017, respectively 4,286 4,286
Additional paid-in capital 690,076 689,068
Retained earnings (deficit) 8,850 (5,020 )
Total stockholders’ equity 703,212 688,334
Total liabilities and stockholders’ equity $ 872,407 $ 830,371

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

Three Months Ended March 31,
2018 2017
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains 8,281 7,197
Mid-Continent 1,667 1,934
Total 9,948 9,131
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains $ 57.01 $ 47.80
Mid-Continent $ 62.34 $ 51.55
Composite $ 57.89 $ 48.59
Composite (after derivatives) $ 52.86 $ 48.59
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains 2,415 3,290
Mid-Continent 447 490
Total 2,862 3,780
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains $ 22.33 $ 15.72
Mid-Continent $ 28.73 $ 25.65
Composite $ 23.33 $ 17.01
Composite (after derivatives) $ 23.33 $ 17.01
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains 18,257 21,435
Mid-Continent 5,467 6,433
Total 23,724 27,868
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains $ 2.64 $ 2.57
Mid-Continent $ 3.25 $ 3.24
Composite $ 2.78 $ 2.73
Composite (after derivatives) $ 2.87 $ 2.73
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains 13,739 14,060
Mid-Continent 3,025 3,496
Total 16,764 17,556
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains $ 41.79 $ 32.07
Mid-Continent $ 44.48 $ 38.07
Composite $ 42.27 $ 33.26
Composite (after derivatives) $ 39.42 $ 33.26
Total Sales Volumes (MBoe) 1,508.8 1,580.0

Schedule 5: Per unit operating margins
(unaudited)

Three Months Ended March 31,
2018 2017 Percent Change
Production
Oil (MBbl) 895 822 9 %
Gas (MMcf) 2,135 2,508 (15 )%
NGL (MBbl) 258 340 (24 )%
Equivalent (MBoe) 1,509 1,580 (5 )%
Realized pricing (before derivatives)
Oil ($/Bbl) $ 57.89 $ 48.59 19 %
Gas ($/Mcf) $ 2.78 $ 2.73 2 %
NGL ($/Bbl) $ 23.33 $ 17.01 37 %
Equivalent ($/Boe) $ 42.27 $ 33.26 27 %
Per Unit Costs ($/Boe)
Realized price (before derivatives) $ 42.27 $ 33.26 27 %
Lease operating expense 6.93 6.28 10 %
Gathering, transportation and processing 1.55 %
Gas plant and midstream operating expense 2.39 1.71 40 %
Severance and ad valorem 3.47 2.73 27 %
Cash general and administrative 5.65 6.56 (14 )%
Total cash operating costs $ 19.99 $ 17.28 16 %
Cash operating margin (before derivatives) $ 22.28 $ 15.98 39 %
Derivative cash settlements (2.85 ) %
Cash operating margin (after derivatives) $ 19.43 $ 15.98 22 %
Non-cash items
Non-cash general and administrative $ 0.67 $ 1.09 (39 )%

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

Adjusted net income (loss) is a supplemental non-GAAP financial measure that is used by management 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 (loss) 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 (loss) as net income (loss) after adjusting first for (1) the impact of certain non-cash items and one-time transactions and then (2) the non-cash and one time items’ impact on taxes based on a tax rate that approximates the Company’s effective tax rate in each period. Adjusted net income (loss) is not a measure of net income (loss) as determined by GAAP.

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

Three Months Ended March 31,
2018 2017
Net income (loss) $ 13,870 $ (94,276 )
Adjustments to net income (loss):
Derivative loss 8,742
Derivative cash settlements (4,312 )
Abandonment and impairment of unproved properties 2,502
Exploratory dry hole expense 2,701
Unused commitments 21 993
Stock-based compensation (1) 1,008 1,725
Reorganization items, net 89,003
Pre-petition advisory fees (1) 683
Total adjustments before taxes 7,961 95,105
Income tax effect
Total adjustments after taxes $ 7,961 $ 95,105
Adjusted net income (loss) $ 21,831 $ 829
Adjusted net income (loss) per diluted share (2) $ 1.07 $ 0.02
Diluted weighted-average common shares outstanding (2) 20,470 49,452
(1) Included as a portion of general and administrative expense in the consolidated statements of operations.
(2) For the three-month period ended March 31, 2018, 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 (loss) or cash flows as determined by GAAP.

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

Three Months Ended March 31,
2018 2017
Net income (loss) $ 13,870 $ (94,276 )
Exploration 29 3,407
Depreciation, depletion and amortization 7,508 21,212
Abandonment and impairment of unproved properties 2,502
Unused commitments 21 993
Stock-based compensation (1) 1,008 1,725
Interest expense 357 4,568
Derivative loss 8,742
Derivative cash settlements (4,312 )
Pre-petition advisory fees (1) 683
Reorganization items, net 89,003
Income tax effect
Adjusted EBITDAX $ 29,725 $ 27,315
(1) Included as a portion of general and administrative expense on the consolidated statements of operations.

Schedule 8: Cash G&A
(in thousands, unaudited)

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 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 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 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 the GAAP financial measure of general and administrative expense to the non-GAAP financial measure of cash G&A.

Three Months Ended March 31,
2018 2017
General and administrative $ 9,533 $ 12,094
Stock-based compensation (1,008 ) (1,725 )
Cash G&A $ 8,525 $ 10,369


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