Civitas Resources (CIVI) 10-K 28 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Feb. 24, 2020	Jun. 30, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-35371
Entity Registrant Name	Bonanza Creek Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	61-1630631
Entity Address, Address Line One	410 17th Street,
Entity Address, Address Line Two	Suite 1400
Entity Address, City or Town	Denver,
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80202
City Area Code	(720)
Local Phone Number	440-6100
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	BCEI
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Bankruptcy Proceedings, Reporting Current	true
Entity Public Float			$ 429.9
Entity Common Stock, Shares Outstanding (in shares)		20,648,266
Entity Central Index Key	0001509589
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 11,008	$ 12,916
Accounts receivable:
Oil and gas sales	43,714	31,799
Joint interest and other	38,136	47,577
Prepaid expenses and other	7,048	4,633
Inventory of oilfield equipment	7,726	3,478
Derivative Asset, Current	2,884	34,408
Total current assets	110,516	134,811
Property and equipment (successful efforts method):
Proved properties	935,025	719,198
Less: accumulated depreciation, depletion and amortization	(126,614)	(52,842)
Total proved properties, net	808,411	666,356
Unproved properties	143,020	154,352
Wells in progress	98,750	93,617
Other property and equipment, net of accumulated depreciation of $3,142 in 2019 and $2,546 in 2018	3,394	3,649
Total property and equipment, net	1,053,575	917,974
Long-term derivative assets (note 12)	121	3,864
Right-of-use assets (note 2)	38,562
Other noncurrent assets (note 4)	3,544	4,885
Total assets	1,206,318	1,061,534
Current liabilities:
Accounts payable and accrued expenses (note 5)	57,638	79,390
Oil and gas revenue distribution payable	29,021	19,903
Lease liability (note 2)	11,690
Derivative liability (note 12)	6,390	183
Total current liabilities	104,739	99,476
Long-term liabilities:
Credit facility (note 6)	80,000	50,000
Lease liability (note 2)	27,540
Ad valorem taxes	28,520	18,740
Derivative liability (note (12)	921	0
Asset retirement obligations for oil and gas properties (note 10)	27,908	29,405
Total liabilities	269,628	197,621
Commitments and contingencies (note 7)
Stockholders’ equity:
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding	0	0
Common Stock, Value, Issued	4,284	4,286
Additional paid-in capital	702,173	696,461
Retained earnings	230,233	163,166
Total stockholders’ equity	936,690	863,913
Total liabilities and stockholders’ equity	$ 1,206,318	$ 1,061,534

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$ 3,142	$ 2,546
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (in shares)	25,000,000	25,000,000
Preferred stock, shares outstanding (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	225,000,000	225,000,000
Common stock, shares issued (in shares)	20,643,738	20,643,738
Common stock, shares outstanding (in shares)	20,543,940	20,543,940

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) shares in Thousands, $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Operating net revenues:
Oil and gas sales	$ 68,589	$ 123,535	$ 313,220	$ 276,657
Operating expenses:
Lease operating expense	13,128	25,862	25,249	34,825
Severance and ad valorem taxes	5,671	9,590	25,598	18,999
Exploration	3,699	3,745	797	291
Depreciation, depletion and amortization	28,065	21,312	76,453	41,883
Abandonment and impairment of unproved properties	0	0	11,201	5,271
Unused commitments	993	0	0	21
General and administrative expense (including $6,886, $7,156, $11,630, and $2,116, respectively, of stock-based compensation)	15,092	42,676	39,668	42,453
Total operating expenses	70,189	111,526	207,662	164,263
Other income (expense):
Derivative gain (loss)	0	(15,365)	(37,145)	30,271
Interest expense, net	(5,656)	(773)	(2,650)	(2,603)
Gain on sale of properties, net	0	0	1,177	27,324
Reorganization items, net (note 15)	8,808	0	0	0
Other income (expense)	1,108	(1,267)	127	800
Total other income (expense)	4,260	(17,405)	(38,491)	55,792
Income (loss) from operations before taxes	2,660	(5,396)	67,067	168,186
Current income tax benefit (expense) (note 9)	0	376	0	0
Net income (loss)	2,660	(5,020)	67,067	168,186
Comprehensive income (loss)	$ 2,660	$ (5,020)	$ 67,067	$ 168,186
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.05	$ (0.25)	$ 3.25	$ 8.20
Diluted (in dollars per share)	$ 0.05	$ (0.25)	$ 3.24	$ 8.16
Weighted Average Number Of Shares Outstanding, Basic And Diluted [Abstract]
Basic (in shares)	49,559	20,427	20,612	20,507
Diluted (in shares)	50,971	20,427	20,681	20,603
Gas plant and midstream operating expense
Operating expenses:
Operating expenses	$ 3,541	$ 8,341	$ 12,014	$ 10,788
Gathering, transportation, and processing
Operating expenses:
Operating expenses	$ 0	$ 0	$ 16,682	$ 9,732

CONSOLIDATED STATEMENTS OF OP_2

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Income Statement [Abstract]
General and administrative, stock compensation	$ 2,116	$ 11,630	$ 6,886	$ 7,156

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-In Capital	Accumulated Earnings Deficit
Shares outstanding, beginning of period (in shares) at Dec. 31, 2016		49,660,683
Balance at beginning of period at Dec. 31, 2016	$ 19,061	$ 49	$ 814,990	$ (795,978)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock issued (in shares)		767,848
Restricted common stock issued	1	$ 1
Restricted common stock forfeited (in shares)		(5,134)
Restricted stock used for tax withholdings (in shares)		(318,180)
Restricted stock used for tax withholdings	(428)	$ (1)	(427)
Fair value of equity issued to existing common stockholders	(23,410)		(23,410)
Stock-based compensation	2,116		2,116
Net income (loss)	2,660			2,660
Shares outstanding, end of period (in shares) at Apr. 28, 2017		50,105,217
Balance at end of period at Apr. 28, 2017	684,121	$ 49	793,269	(793,318)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cancellation of Predecessor equity (in shares)		(50,105,217)
Cancellation of Predecessor equity		$ (49)	(793,269)	793,318
Issuance of Successor equity (in shares)		20,356,071
Issuance of Successor equity	684,121	$ 4,285	679,836
Stockholders' equity, adjusted balance (in shares)		20,356,071
Stockholders' equity, adjusted balance	684,121	$ 4,285	679,836	0
Restricted common stock issued (in shares)		173,200
Restricted common stock issued	2	$ 2
Restricted stock used for tax withholdings (in shares)		(75,722)
Restricted stock used for tax withholdings	(2,399)	$ (1)	(2,398)
Stock-based compensation	11,630		11,630
Net income (loss)	(5,020)			(5,020)
Shares outstanding, end of period (in shares) at Dec. 31, 2017		20,453,549
Balance at end of period at Dec. 31, 2017	688,334	$ 4,286	689,068	(5,020)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock issued (in shares)		84,345
Restricted stock used for tax withholdings (in shares)		(25,991)
Restricted stock used for tax withholdings	(863)		(863)
Exercise of stock options (in shares)		32,037
Exercise of stock options	1,100		1,100
Stock-based compensation	7,156		7,156
Net income (loss)	168,186			168,186
Shares outstanding, end of period (in shares) at Dec. 31, 2018		20,543,940
Balance at end of period at Dec. 31, 2018	863,913	$ 4,286	696,461	163,166
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock issued (in shares)		146,359
Restricted stock used for tax withholdings (in shares)		(46,561)
Restricted stock used for tax withholdings	(1,176)	$ (2)	(1,174)
Stock-based compensation	6,886		6,886
Net income (loss)	67,067			67,067
Shares outstanding, end of period (in shares) at Dec. 31, 2019		20,643,738
Balance at end of period at Dec. 31, 2019	$ 936,690	$ 4,284	$ 702,173	$ 230,233

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ 2,660	$ (5,020)	$ 67,067	$ 168,186
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	28,065	21,312	76,453	41,883
Non-cash reorganization items	(44,160)	0	0	0
Abandonment and impairment of unproved properties	0	0	11,201	5,271
Well abandonment costs and dry hole expense	2,931	75	172	0
Stock-based compensation	2,116	11,630	6,886	7,156
Non-cash lease expense			668
Amortization of deferred financing costs and debt premium	374	0	487	30
Derivative (gain) loss	0	15,365	37,145	(30,271)
Derivative cash settlements	0	(1,464)	1,691	(18,160)
Gain on sale of oil and gas properties	0	0	(1,177)	(27,324)
Inventory write-offs	0	1,758	0	248
Other	18	11	3,559	(3,559)
Changes in current assets and liabilities:
Accounts receivable	(6,640)	(4,477)	(2,688)	(46,988)
Prepaid expenses and other assets	963	(1,979)	(2,415)	2,214
Accounts payable and accrued liabilities	(5,880)	(8,470)	28,320	19,953
Settlement of asset retirement obligations	(331)	(1,167)	(2,722)	(2,041)
Net cash provided by (used in) operating activities	(19,884)	27,574	224,647	116,598
Cash flows from investing activities:
Acquisition of oil and gas properties	(445)	(5,383)	(14,087)	(2,892)
Exploration and development of oil and gas properties	(5,123)	(76,384)	(242,487)	(264,231)
Proceeds from sale of oil and gas properties	0	0	1,757	103,134
Additions to property and equipment - non oil and gas	(454)	(874)	(341)	(387)
Net cash used in investing activities	(6,022)	(82,641)	(255,158)	(164,376)
Cash flows from financing activities:
Proceeds from credit facility	0	0	55,000	140,000
Payments to credit facility	(191,667)	0	(25,000)	(90,000)
Proceeds from sale of common stock	207,500	0	0	0
Proceeds from exercise of stock options	0	0	0	1,100
Payment of employee tax withholdings in exchange for the return of common stock	(427)	(2,398)	(1,176)	(863)
Deferred financing costs	0	0	(220)	(2,239)
Net cash provided by (used in) financing activities	15,406	(2,398)	28,604	47,998
Net change in cash, cash equivalents, and restricted cash	(10,500)	(57,465)	(1,907)	220
Cash, cash equivalents, and restricted cash:
Beginning of period	80,747	70,247	13,002	12,782
End of period	70,247	12,782	11,095	13,002
Supplemental cash flow disclosure:
Cash paid for interest, net of capitalization	3,509	523	4,110	2,582
Severance and ad valorem tax refund	0	0	352	0
Cash paid for reorganization items	52,968	0	0	0
Changes in working capital related to drilling expenditures	3,360	16,057	30,354	11,769
Cash paid for amounts included in the measurement of lease liabilities	$ 0	$ 0	$ 10,993	$ 0

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Operations Bonanza Creek Energy, Inc. (“BCEI” or, together with its consolidated subsidiaries, the “Company”) is engaged primarily in acquiring, developing, extracting, and producing oil and gas properties. The Company’s assets and operations are concentrated in the rural portions of the Wattenberg Field in Weld County, Colorado. Basis of Presentation As of December 31, 2019, the consolidated balance sheets (“balance sheets”) include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All intercompany accounts and transactions have been eliminated. Certain prior period amounts have been reclassified to conform to the current period presentation. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2019, through the filing date of this report. On August 6, 2018, the Company sold its equity interests in Bonanza Creek Energy Resources, LLC, which owns all of the outstanding equity interest in Bonanza Creek Energy Upstream LLC and Bonanza Creek Energy Midstream, LLC. These subsidiaries comprised the Company's Mid-Continent region and assets. Please refer to Note 3 - Divestitures for additional discussion. On January 4, 2017, the Company and certain of its subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions,” and the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) to pursue the Debtors’ Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as proposed, the “Plan”). The Bankruptcy Court granted the Debtors' motion seeking to administer all of the Debtors' Chapter 11 Cases jointly under the caption “In re Bonanza Creek Energy, Inc., et al” (Case No. 17-10015). The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017 (the “Effective Date”). Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession during a portion of the year ended December 31, 2017. As such, certain aspects of the bankruptcy proceedings of the Company and related matters are described below in order to provide context and explain part of our financial condition and results of operations for the period presented. Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements after April 28, 2017 are not comparable with the financial statements on or prior to April 28, 2017. The Company's condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after April 28, 2017 and dates prior thereto. Please refer to Note 15 - Fresh-Start Accounting for additional discussion. Subsequent to January 4, 2017 and through the date of emergence, all expenses, gains, and losses directly associated with the reorganization are reported as reorganization items, net in the accompanying consolidated statements of operations and comprehensive income (loss) (“statements of operations”). References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or prior to April 28, 2017. Throughout these financial statements, the Company refers to the 2017 annual period which is comprised of both Successor and Predecessor periods. References to “2017 Successor Period” relate to the period of April 29, 2017 through December 31, 2017. References to the “2017 Predecessor Period” relate to the period of January 1, 2017 through April 28, 2017. Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Going Concern Presumption Our consolidated financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets, and the satisfaction of liabilities and other commitments in the normal course of business. Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. Accounts Receivable The Company’s accounts receivables are generated from oil and gas sales and from joint interest owners on properties that the Company operates. These receivables are generally unsecured. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated. For receivables from joint interest owners, the Company usually has the ability to withhold future revenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables are typically collected within one two Inventory of Oilfield Equipment Inventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or net realizable value, which approximates fair value. Oil and Gas Producing Activities The Company follows the successful efforts method of accounting for its oil and gas exploration and development costs. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether economically recoverable reserves have been found. If an exploratory well does not find economically recoverable reserves, the costs of drilling the well and other associated costs are charged to dry hole expense. The costs of development wells are capitalized whether the well is productive or nonproductive. Costs incurred to maintain wells and their related equipment and leases as well as operating costs are charged to expense as incurred. Geological and geophysical costs are expensed as incurred. Depletion, depreciation, and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs and anticipated proceeds from salvaging equipment. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets' net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. The factors used to determine fair value are subject to the Company’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows on all developed proved reserves and risk adjusted probable and possible reserves, net of estimated operating and development costs, future commodity pricing based on the Company's internal budgeting model originating from the NYMEX strip price adjusted for basis differential, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. As of December 31, 2019, the Company's gathering assets comprised $146.4 million, $1.3 million, and $0.1 million of proved properties, wells in progress, and unproved properties, respectively, on the accompanying balance sheets. Depreciation on the Company's gathering assets is calculated using the straight-line method over the estimated useful lives of the assets and the assets it is servicing, which is approximately 30 years. Unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis once proved reserves have been assigned. The unproved property balance at emergence from bankruptcy represents probable and possible well locations that are reassessed at least annually. The assessment of probable and possible locations incorporates key factors such as economic viability, surface constraints, wells per section, limitations on operatorship due to working interest changes, and any relevant components at such time. Changes in probable and possible locations that result in entire areas no longer being represented in the reserve run are impaired. Leases acquired post-emergence are assessed for impairment applying the following factors: • the remaining amount of unexpired term under leases; • the Company's ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration; • its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; • its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; • its evaluation of the continuing successful results from the application of completion technology by the Company or by other operators in areas adjacent to or near its unproved properties; and • strategic shifts in development areas. The Company records the fair value of an asset retirement obligation as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. The increase in carrying value is included in proved properties in the accompanying balance sheets. For additional discussion, please refer to Note 10 - Asset Retirement Obligations. Gains and losses arising from sales of oil and gas properties will be included in income. However, a partial sale of proved properties within an existing field that does not significantly affect the unit-of-production depletion rate will be accounted for as a normal retirement with no gain or loss recognized. The sale of a partial interest within a proved property is accounted for as a recovery of cost. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained. Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three Assets Held for Sale Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent decreases to the estimated fair value less the costs to sell impact the measurement of assets held for sale. Any properties deemed held for sale as of the balance sheet date are presented separately on the accompanying balance sheets at the lower of net book value or fair value less cost to sell. Please refer to Note 3 - Divestitures for more information. Revenue Recognition On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606 (“ASC 606”), Revenue from Contracts with Customers, using the modified retrospective approach . Sales of oil, natural gas, and NGLs are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. The Company's contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies. As further described in Note 7 - Commitments and Contingencies , one contract with NGL Crude has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL Crude agreement based on approved production plans to determine if liquidated damages to NGL Crude are probable. As of December 31, 2019, the Company believes that the volumes delivered to NGL Crude will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL Crude agreement. Under the oil sales contracts, the Company sells oil production at the wellhead, or other contractually agreed-upon delivery points, and collect an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received. Under the natural gas processing contracts, the Company delivers natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the outlet of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the Company's accompanying statements of operations. Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis. Under the product sales contracts, the Company invoices customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under this guidance. At December 31, 2019 and 2018, the Company's receivables from contracts with customers were $43.7 million and $31.8 million, respectively. Payment is generally received within 30 to 60 days after the date of production. The Company records revenue in the month production is delivered to the purchaser. However, as stated above, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between our estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the period from January 1, 2019 through December 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands) for the periods following the adoption of ASC 606: For the years ended December 31, 2019 2018 Operating Revenues: Crude oil sales $ 268,865 $ 228,661 Natural gas sales 28,296 22,369 Natural gas liquids sales 16,059 25,627 Oil and gas sales $ 313,220 $ 276,657 Income Taxes The Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Uncertain Tax Positions The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax returns for 2018, 2017, and 2016 are still subject to audit by the Internal Revenue Service. There were no uncertain tax positions during any period presented. Concentrations of Credit Risk The Company maintains cash balances in excess of the Federal Deposit Insurance Corporation (FDIC) insured limit. The Company is exposed to credit risk in the event of nonpayment by counterparties whose creditworthiness is continuously evaluated. For the years ended December 31, 2019, 2018, and 2017, NGL Crude Logistics accounted for 82%, 66%, and 44% of sales, respectively; Lion Oil Trading & Transportation, Inc. accounted for 0%, 8%, and 18% of sales, respectively; and Duke Energy Field Services accounted for 6%, 8%, and 16% of sales, respectively. Oil and Gas Derivative Activities The Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forward contracts. The contracts are placed with major financial institutions and take the form of swaps, collars, or puts. The oil contracts are indexed to NYMEX WTI prices, and natural gas contracts are indexed to NYMEX HH and CIG prices, which have a high degree of historical correlation with actual prices received by the Company, before differentials. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities at fair value. For additional discussion, please refer to Note 12 - Derivatives . Earnings Per Share Earnings per basic and diluted share within the Successor Company are calculated under the treasury stock method. Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. Diluted net income (loss) per common share is calculated by dividing net income (loss) by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested restricted stock units (“RSUs”), in-the-money outstanding stock options, unvested performance stock units (“PSUs”), and exercisable warrants. When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. Earnings per basic and diluted share within the Predecessor Company were calculated under the two-class method. Pursuant to the two-class method, the Company’s unvested restricted stock awards with non-forfeitable rights to dividends are considered participating securities. Under the two-class method, earnings per basic share is calculated by dividing net income available to shareholders by the weighted-average number of common shares outstanding during the period. The two-class method includes an earnings allocation formula that determines earnings per share for each participating security according to undistributed earnings for the period. Net income available to shareholders is reduced by the amount allocated to participating restricted shares to arrive at the earnings allocated to common stock shareholders for purposes of calculating earnings per share. Participating shares are not contractually obligated to share in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding shares. Earnings per diluted share is computed on the basis of the weighted-average number of common shares outstanding during the period plus the dilutive effect of any potential common shares outstanding during the period using the more dilutive of the treasury method or two-class method. For additional discussion, please refer to Note 13 - Earnings Per Share . Stock-Based Compensation The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. For additional discussion, please refer to Note 8 - Stock-Based Compensation . Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, credit facilities, and derivative instruments. Cash and cash equivalents, trade receivables, trade payables, and accrued liabilities are carried at cost and approximate fair value due to the short-term nature of these instruments. Our credit facilities have variable interest rates, so they approximate fair value. Derivative instruments are recorded at fair value. Restricted Cash The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which sums to the total of such amounts shown in the accompanying consolidated statements of cash flows (in thousands): As of December 31, As of 2019 2018 2017 April 28, 2017 Cash and cash equivalents $ 11,008 $ 12,916 $ 12,711 $ 70,183 Restricted cash included in other noncurrent assets (1) 87 86 71 64 Total cash, cash equivalents and restricted cash as shown in the statements of cash flows $ 11,095 $ 13,002 $ 12,782 $ 70,247 ____________________________ (1) Consists of funds for road maintenance and repairs Recently Issued and Adopted Accounting Standards In February 2016, the FASB issued Update No. 2016-02 - Leases (ASC 842) to increase transparency and comparability among organizations by recognizing right-of-use assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Each lease that is recognized in the balance sheet will be classified as either finance or operating requiring certain quantitative and qualitative disclosures. Leases acquired to explore the development of oil and natural gas resources are not within the scope of this guidance. The new standard was adopted using the optional transition approach at the date of initial application on January 1, 2019. Please refer to Note 2 - Leases for additional disclosure. In June 2016, the FASB issued Update No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . The update changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amended standard is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. Historically, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the Company does not believe the adoption of this standard will have a material impact on its consolidated financial statements. In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement . The objective of this update is to improve the effectiveness of fair value measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the form of the Company's disclosures.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
LEASES	LEASES On January 1, 2019, the Company adopted ASC 842 using the optional transition approach prescribed in Updated No 2018-11 - Lease (Topic 842), Targeted Improvements . Under this approach, results for reporting periods beginning January 1, 2019 are presented in accordance with ASC 842, while prior period amounts are reported in accordance with ASC 840 - Leases . The Company recognized $32.8 million and $33.6 million in right-of-use assets and lease liabilities, respectively, on January 1, 2019, representing lease payment obligations associated with compressors, vehicles, office space, and other field and corporate equipment with contractual durations in excess of one year. The difference between the right-of-use assets and the total lease liability was related to a deferred rent balance of $0.8 million, which were required to be netted against the right-of-use assets as of the implementation date of January 1, 2019. There was no cumulative-effect adjustment to retained earnings upon adoption of the new standard. ASC 842 provided certain practical expedients, of which the Company elected (i) to account for lease and non-lease components in its contracts as a single lease component for all asset classes, (ii) to adopt the land easement practical expedient, which allows the Company to apply ASC 842 prospectively to new or modified land easements beginning January 1, 2019, and (iii) to not apply the recognition requirements of ASC 842 to leases with a lease term of twelve months or less. The Company's leasing activities as a lessor are negligible. During the year ended December 31, 2019, the Company incurred $16.6 million in new right-of-use assets and lease liabilities. The Company’s right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet at $38.6 million and $39.2 million as of December 31, 2019, respectively. All leases recognized on the Company's balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below (in thousands): Right-of-use Asset Lease Liability Field equipment (1) $ 35,057 $ 35,075 Corporate leases 2,462 3,129 Vehicles 1,043 1,026 Total $ 38,562 $ 39,230 ____________________________ (1) Includes compressors, certain gas processing equipment, and other field equipment. The lease amounts disclosed are presented on a gross basis. A portion of these costs may have been or will be billed to other working interest owners, and the Company's net share of these costs, once paid, are included in proved properties, other property and equipment, lease operating expenses, or general and administrative expenses, as applicable. The Company recognizes lease expense on a straight-line basis excluding short-term and variable lease payments, which are recognized as incurred. Short-term lease cost represents payments for leases with a lease term of one year or less, excluding leases with a term of one month or less. Short-term leases include drilling rigs and other equipment. Drilling rig contracts are structured based on an allotted number of wells to be drilled consecutively at a daily operating rate. Short-term drilling rig costs include a non-lease labor component, which is treated as a single lease component. The following table summarizes the components of the Company's gross operating lease costs incurred during the year ended December 31, 2019 (in thousands): Twelve Months Ended December 31, 2019 Operating lease cost (1) $ 11,330 Short-term lease cost 8,169 Variable lease cost (2) 259 Sublease income (3) (348) Total lease cost $ 19,410 ____________________________ (1) Includes office rent expense of $1.1 million for the year ended December 31, 2019. (2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs. (3) The Company subleased a portion of its office space for the remainder of the office lease term. The Company does not have any leases with an implicit interest rate that can be readily determined. As a result, the Company used the incremental borrowing rate, based on the Credit Facility benchmark rate, adjusted for facility utilization and lease term, to calculate the respective discount rates. Please refer to Note 6 - Long-term Debt for additional information. The Company has certain lease agreements that provide for the option to extend or terminate early, which was evaluated on each lease to arrive at the proper lease term. There were some leases that the option to extend was factored into the resulting lease term. There were no leases where early termination was factored into the resulting lease term. The Company's weighted-average remaining lease term and discount rate used during the year ended December 31, 2019 are as follows: Twelve Months Ended December, 2019 Weighted-average lease term (years) 3.5 Weighted-average discount rate 4.33% Future commitments by year for the Company's operating leases with a lease term of one year or more as of December 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows (in thousands): Amount 2020 $ 13,113 2021 11,823 2022 10,028 2023 5,721 2024 1,559 Thereafter — Total lease payments 42,244 Less: imputed interest (3,014) Total lease liability $ 39,230 Future minimum lease payments related to the Company’s operating leases as of December 31, 2018 are presented below (in thousands): Amount (1) 2019 1,256 2020 1,351 2021 1,401 2022 234 2023 — Thereafter — Total $ 4,242 ____________________________ (1) Consists of future minimum lease payments not reported on the balance sheet in accordance with ASC 840 - Leases .

DIVESTITURES

DIVESTITURES	12 Months Ended
	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
DIVESTITURES	DIVESTITURES During the first quarter of 2018, the Company established a plan to sell all of the Company's assets within its Mid-Continent region and North Park Basin in order to focus on and partially fund the development of its core assets in the Wattenberg Field in Colorado, at which point they were deemed held for sale. The Company sold its North Park Basin assets on March 9, 2018 for minimal net proceeds and full release of all current and future obligations resulting in a minimal net loss.

OTHER NONCURRENT ASSETS

OTHER NONCURRENT ASSETS	12 Months Ended
	Dec. 31, 2019
Other Assets [Abstract]
OTHER NONCURRENT ASSETS	OTHER NONCURRENT ASSETS Other noncurrent assets contain the following (in thousands): As of December 31, 2019 2018 Operating bonds $ 1,638 $ 2,713 Deferred financing costs 1,443 1,710 AMT credit refund (1) 376 376 Restricted cash 87 86 Other noncurrent assets $ 3,544 $ 4,885 ______________________________________ (1) Represents the alternative minimum tax credit refund due to the Company upon application of the newly enacted comprehensive tax legislation that took effect on December 22, 2017.

ACCOUNTS PAYABLE AND ACCRUED EX

ACCOUNTS PAYABLE AND ACCRUED EXPENSES	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND ACCRUED EXPENSES	ACCOUNTS PAYABLE AND ACCRUED EXPENSES Accounts payable and accrued expenses contain the following (in thousands): As of December 31, 2019 2018 Drilling and completion costs $ 3,248 $ 33,602 Accounts payable trade 17,117 11,532 Accrued general and administrative cost 5,620 12,728 Lease operating expense 2,187 2,183 Accrued interest 692 241 Accrued oil and gas hedging 453 — Production and ad valorem taxes and other 28,321 19,104 Total accounts payable and accrued expenses $ 57,638 $ 79,390

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Successor Debt Credit Facility On December 7, 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions, as lenders (the “Credit Facility”). The Credit Facility has an aggregate original commitment amount of $750.0 million, an initial borrowing base of $350.0 million, and a maturity date of December 7, 2023. The Credit Facility borrowing base is redetermined on a semi-annual basis. The most recent redetermination was concluded on November 26, 2019, resulting in a reaffirmation of the borrowing base at $375.0 million; however, the Company chose to hold the aggregate elected commitments at $350.0 million. The next scheduled redetermination is set to occur in May 2020. Borrowings under the Credit Facility bear interest at a per annum rate equal to, at the option of the Company, either (i) a London InterBank Offered Rate (“LIBOR”), subject to a 0% LIBOR floor plus a margin of 1.75% to 2.75%, based on the utilization of the Credit Facility (the “Eurodollar Rate”) or (ii) a fluctuating interest rate per annum equal to the greatest of (a) the rate of interest publicly announced by JPMorgan Chase Bank, N.A. as its prime rate, (b) the rate of interest published by the Federal Reserve Bank of New York as the federal funds effective rate, (c) the rate of interest published by the Federal Reserve Bank of New York as the overnight bank funding rate, or (d) a LIBOR offered rate for a one month interest period, subject to a 0% LIBOR floor plus a margin of 0.75% to 1.75%, based on the utilization of the Credit Facility (the “Reference Rate”). Interest on borrowings that bear interest at the Eurodollar Rate shall be payable on the last day of the applicable interest period selected by the Company, which shall be one, two, three, or six months, and interest on borrowings that bear interest at the Reference Rate shall be payable quarterly in arrears. The Company's Credit Facility approximates fair value as the applicable interest rates are floating. The Credit Facility is guaranteed by all wholly owned subsidiaries of the Company (each, a “Guarantor” and, together with the Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions. The Credit Facility contains customary representations and affirmative covenants. The Credit Facility also contains customary negative covenants, which, among other things, and subject to certain exceptions, include restrictions on (i) liens, (ii) indebtedness, guarantees and other obligations, (iii) restrictions in agreements on liens and distributions, (iv) mergers or consolidations, (v) asset sales, (vi) restricted payments, (vii) investments, (viii) affiliate transactions, (ix) change of business, (x) foreign operations or subsidiaries, (xi) name changes, (xii) use of proceeds, letters of credit, (xiii) gas imbalances, (xiv) hedging transactions, (xv) additional subsidiaries, (xvi) changes in fiscal year or fiscal quarter, (xvii) operating leases, (xviii) prepayments of certain debt and other obligations, (xix) sales or discounts of receivables, and (xx) dividend payments. The Credit Parties are subject to certain financial covenants under the Credit Facility, including, without limitation, tested on the last day of each fiscal quarter, (i) a maximum ratio of the Company’s consolidated indebtedness (subject to certain exclusions) to earnings before interest, income taxes, depreciation, depletion, and amortization, exploration expense, and other non-cash charges (“EBITDAX”) of 4.00 to 1.00 and (ii) a current ratio, as defined in the agreement, inclusive of the unused Commitments then available to be borrowed, to not be less than 1.00 to 1.00. The Company was in compliance with all covenants as of December 31, 2019 and through the filing date of this report. The Company had $80.0 million and $50.0 million outstanding on the Credit Facility as of December 31, 2019 and 2018, respectively. As of the date of filing, the Company had $80.0 million outstanding on its Credit Facility. In connection with the Credit Facility, the Company capitalized a total of $2.5 million in deferred financing costs. Of the total post-amortization net capitalized amounts, $1.4 million and $1.7 million as of December 31, 2019 and 2018, respectively, are presented within other noncurrent assets, and $0.5 million as of December 31, 2019 and 2018, respectively, are presented within prepaid expenses and other line items in the accompanying balance sheets. Prior Credit Facility On the Effective Date, the Company entered into a revolving credit facility, as the borrower, with KeyBank National Association, as the administrative agent, and certain lenders party thereto (the “Prior Credit Facility”). The borrowing base was $191.7 million and had a maturity date of March 31, 2021. The Prior Credit Facility stated the Company's leverage ratio of indebtedness to EBITDAX was not to exceed 3.50 to 1.00, the minimum current ratio had to be 1.00 to 1.00, and the minimum interest coverage ratio of trailing twelve-month EBITDAX to trailing twelve-month interest expense had to be 2.50 to 1.00 as of the end of the respective fiscal quarter. During the period the Prior Credit Facility was outstanding, the Company was in compliance with all covenants. The Prior Credit Facility provided for interest rates plus an applicable margin to be determined based on LIBOR or a base rate, at the Company’s election. LIBOR borrowings bore interest at LIBOR, plus a margin of 3.00% to 4.00% depending on the utilization level, and the base rate borrowings bore interest at the Reference Rate, as defined in the Prior Credit Facility, plus a margin of 2.00% to 3.00% depending on the utilization level. This Prior Credit Facility was terminated and settled in full as of December 7, 2018. Predecessor Debt Please refer to Note 14 - Chapter 11 Proceedings and Emergence for discussion regarding the predecessor credit facility and predecessor senior unsecured notes. Interest Expense For the years ended December 31, 2019, 2018, the 2017 Successor Period, and the 2017 Predecessor Period, the Company incurred interest expense of $5.1 million, $2.6 million, $0.8 million, and $5.7 million respectively. The Company capitalized $2.4 million of interest expense during the year ended December 31, 2019. No interest was capitalized for the year ended December 31, 2018, the 2017 Successor Period, or the 2017 Predecessor Period.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES Legal Proceedings From time to time, the Company is involved in various commercial and regulatory claims, litigation, and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with authoritative accounting guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the most likely anticipated outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration, or the violation of any rules or regulations. As of the filing date of this report, there were no probable, material pending, or overtly threatened legal actions against the Company of which it is aware. The Company and the Colorado Department of Public Health and Environment (“CDPHE”) agreed to a Compliance Order on Consent (the “COC”) resolving the matters addressed by a compliance advisory issued to the Company for certain storage tank facilities located in the Wattenberg Field with respect to applicable air quality regulations. The COC further set forth compliance requirements and criteria for continued operations. The Company adopted procedures and processes to address the monitoring, reporting, and control of air emissions. In order to be in compliance, the Company has incurred approximately $2.1 million from 2017 through December 31, 2019 and expects to incur an immaterial amount of maintenance during 2020 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHE approval. In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), an environmental non-governmental organization, alleging failure to obtain required permits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the Denver Metropolitan and North Front Range of Colorado, among other things. The Company is one of seven operators in the Wattenberg Field to receive such an NOI letter from WEG, and these letters appear to challenge long-established federal and state regulations and policies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Act and state counterpart statutes. On May 3, 2019, WEG filed a lawsuit against the Company and the other six operators who received the NOI, alleging claims consistent with those contained in the NOI letters. Because the allegations made in the lawsuit are based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit, but the Company will vigorously defend against such allegations and will coordinate as much as possible with state and federal permitting authorities to maintain the validity of its current and future air permits for such facilities. In September 2018, the Company reached a settlement in a case in which it was one of several plaintiffs seeking reimbursement of ad valorem taxes that were assessed by a special metropolitan district in Colorado. Pursuant to that settlement, the Company received a gross reimbursement of ad valorem taxes paid in the amount of $7.4 million. The settlement amount of $5.1 million, net of the Company’s associated interest owners' portion, is presented as a reimbursement in the accompanying statements of operations within the severance and ad valorem taxes line item. This net settlement amount will be further reduced to reflect the reimbursement to the State of Colorado of a certain amount of severance tax credits received in connection with ad valorem taxes historically paid by the Company. Commitments The purchase agreement to deliver fixed determinable quantities of crude oil to NGL Crude became effective on April 28, 2017. The NGL Crude agreement includes defined volume commitments over an initial seven six twelve three The annual minimum commitment payments under the NGL Crude agreement for the next five years as of December 31, 2019 are presented below (in thousands): NGL Crude Commitments (1) 2020 $ 22,474 2021 23,316 2022 24,009 2023 11,200 2024 and thereafter — Total $ 80,999 ____________________ (1) The above calculation is based on the minimum volume commitment schedule (as defined in the NGL Crude agreement) and applicable differential fees. Since the commencement of the NGL Crude agreement and through the remainder of the term of the agreement, the Company has not and does not expect to incur any deficiency payments. Refer to Note 2 - Leases

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION 2017 Long Term Incentive Plan Upon emergence from bankruptcy, the Company adopted a new Long Term Incentive Plan (the “2017 LTIP”), as established by the pre-emergence Board, which allows for the issuance of RSU's, PSU's, and options. On the Effective Date, the Company reserved 2,467,430 shares of the new common stock for issuance under the 2017 LTIP. See below for further discussion of awards granted under the 2017 LTIP. The Company recorded compensation expense related to the awards granted under the 2017 LTIP as follows (in thousands): For the Years Ended December 31, 2017 Successor Period 2019 2018 Restricted stock units $ 5,518 $ 5,140 $ 7,913 Performance stock units 764 621 — Stock options 604 1,395 3,717 $ 6,886 $ 7,156 $ 11,630 As of December 31, 2019, unrecognized compensation expense will be amortized through the relevant periods as follows (in thousands): Unrecognized Compensation Expense Final Year of Recognition Restricted stock units $ 9,589 2023 Performance stock units 1,714 2021 Stock options 174 2020 $ 11,477 Inducement Awards During the year ended December 31, 2018, the Company granted inducement awards in the form of RSUs separate and distinct from the 2017 LTIP. The total number of inducement awards granted to employees during the year ended December 31, 2018 was 170,613, representing a total fair value of $4.6 million. Restricted Stock Units The 2017 LTIP allows for the issuance of RSUs to members of the Board and employees of the Company at the discretion of the Board. Each RSU represents one share of the Company's common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three In 2017, the Company granted 63,894 RSUs to non-executive members of the Board, with a fair value of $2.3 million. This grant is intended to cover a three The fair value of the RSUs granted from the 2017 LTIP during the years ended December 31, 2019, 2018, and the 2017 Successor Period was $5.9 million, $6.2 million, and $13.4 million, respectively. A summary of the status and activity of non-vested restricted stock units for the year ended December 31, 2019 is presented below: Restricted Stock Units Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 480,835 $ 30.83 Granted 258,785 $ 22.70 Vested (143,761) $ 23.12 Forfeited (38,042) $ 25.92 Non-vested, end of year 557,817 $ 26.95 Cash flows resulting from excess tax benefits are to be classified as part of cash flows from operating activities. Excess tax benefits are realized tax benefits from tax deductions for vested restricted stock in excess of the deferred tax asset attributable to stock compensation costs for such restricted stock. The Company recorded no excess tax benefits for the years ended December 31, 2019 and 2018, and 2017 Successor Period. Performance Stock Units The 2017 LTIP allows for the issuance of PSUs to employees at the sole discretion of the Board. The number of shares of the Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded. The PSUs vest in their entirety at the end of the three The fair value of the PSUs was measured at the grant date. The portion of the PSUs tied to the TSR required a stochastic process method using a Brownian Motion simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s TSRs, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company’s peers. The following table presents the assumptions used to determine the fair value of the TSR portion of the PSUs: For the Years Ended December 31, 2019 2018 Expected term (in years) 3 3 Risk-free interest rate 2.26 % 2.76 % Expected daily volatility 2.6 % 2.6 % The fair value of the PSUs granted during 2019 and 2018 was $2.3 million and $1.8 million, respectively. A summary of the status and activity of performance stock units for the year ended December 31, 2019 is presented below: Performance Stock Units (1) Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 53,689 $ 29.92 Granted 102,379 $ 22.15 Vested (2,598) $ 23.55 Forfeited — $ — Non-vested, end of year 153,470 $ 24.74 ______________________________ (1) The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition. Stock Options The 2017 LTIP allows for the issuance of stock options to the Company's employees at the sole discretion of the Board. Options expire ten years from the grant date unless otherwise determined by the Board. Compensation expense on the stock options is recognized as general and administrative expense over the vesting period of the award. There were no stock options granted during 2019 and 2018. The fair value of the stock options granted during the 2017 Successor Period was $6.8 million. Stock options were valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards. For the Year Ended December 31, 2017 Expected term (years) 6.0 Risk-free interest rate 1.96 % Expected volatility 52.1 % Expected dividends — % A summary of the status and activity of non-vested stock options for the year ended December 31, 2019 is presented below: Stock Options Weighted- Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding, beginning of year 132,809 $ 34.36 Granted — $ — Exercised — $ — Forfeited (32,095) $ 34.36 Outstanding, end of year 100,714 $ 34.36 6.7 $ — Options outstanding and exercisable 70,077 $ 34.36 6.4 $ — Predecessor Long Term Incentive Plan The Company’s Predecessor Long Term Incentive Plan (the “Predecessor Plan”) had different forms of equity issuances allowed under it, including restricted stock, performance stock units, and long term incentive plan units (“predecessor awards”). Upon emergence from bankruptcy, the Company's predecessor awards were canceled. The Company recorded compensation expense related to the awards granted under the Predecessor Plan as follows (in thousands): 2017 Predecessor Period Restricted stock units $ 1,267 Performance stock units 451 Plan units 398 $ 2,116

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the Company’s balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes. The provision for income taxes consists of the following (in thousands): Successor Predecessor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Current tax benefit Federal $ — $ — $ 376 $ — State — — — — Deferred tax benefit — — — — Total income tax benefit $ — $ — $ 376 $ — Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax asset (liability) result from the following components (in thousands): As of December 31, 2019 2018 Deferred tax liabilities: Oil and gas properties $ 79,187 $ 52,006 Derivative instruments — 8,527 Right-of-use assets 9,508 — Total deferred tax liabilities 88,695 60,533 Deferred tax assets: Federal and state tax net operating loss carryforward 139,546 137,567 Derivative instruments 1,062 — Reclamation costs 6,881 7,251 Stock compensation 2,209 1,635 Accrued compensation — 1,308 Inventory 1,577 1,577 Lease liability 9,673 — Other long-term assets 300 271 Total deferred tax assets 161,248 149,609 Less: Valuation allowance 72,553 89,076 Total deferred tax assets after valuation allowance 88,695 60,533 Total non-current net deferred tax asset (liability) $ — $ — The Company has $582.8 million and $577.6 million of net operating loss carryovers for federal income tax purposes as of December 31, 2019 and 2018, respectively. Federal net operating loss carryforwards incurred prior to January 1, 2018 of $470.3 million will begin to expire in 2036. Federal net operating loss carryforwards incurred after December 31, 2017 of $112.5 million have no expiration and can only be used to offset 80% of taxable income when utilized. The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will be realized. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. As a result of the Company's analysis, it was concluded that as of December 31, 2019 and 2018 a valuation allowance should be established against the Company's deferred tax asset. The Company recorded a valuation allowance as of December 31, 2019 and 2018 of $72.6 million and $89.1 million, respectively, on its deferred tax assets. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that the deferred tax assets will be realized. Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, rate changes, and other permanent differences, as follows (in thousands): Successor Predecessor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Federal statutory tax (expense) benefit by applying the statutory rate $ 14,084 $ 35,319 $ 1,889 $ (931) Decrease (increase) in tax resulting from: State tax expense net of federal benefit 2,537 6,556 172 (85) Prior year true-up (579) (458) — (7,572) Stock compensation 197 854 — (1,773) Permanent differences 128 61 (715) (35,273) Rate change — (421) (73,956) — NOL Adjustment — 5,973 — — Other 156 — (642) — Valuation allowance (16,523) (47,884) 73,628 45,634 Total income tax benefit $ — $ — $ 376 $ — There was no deferred income tax benefit or expense in the accompanying statements of operations. The valuation allowance decreased by $16.5 million to $72.6 million in 2019 when compared to the same period in 2018. The Company's net income decreased between the comparable periods causing the federal tax benefit to decrease. During the year ended December 31, 2018, the decrease in tax rate was primarily due to placing a valuation allowance against net deferred tax assets. There was no deferred income tax benefit or expense in the accompanying statements of operations. The valuation allowance decreased to $89.1 million in 2018 due to improvement of operational results. Net operating losses are inherently subject to changes in ownership. The net operating loss adjustment was derived from the write-off of the Company's Mid-Continent tax attributes upon the sale of those assets. During the year ended December 31, 2017, the decrease in tax rate was primarily due to the enactment of the Tax Cuts and Jobs Act (“Tax Act”). There was $0.4 million of current income tax benefits in the accompanying statements of operations due to the AMT payments being refunded as prescribed in the Tax Act. The valuation allowance decreased to $137.0 million in 2017 due to decreased tax rate as mandated by the Tax Act. The Company had no unrecognized tax benefits as of December 31, 2019, 2018, and 2017. The tax returns for 2018, 2017, and 2016 are still subject to audit by the Internal Revenue Service.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS The Company recognizes an estimated liability for future costs to abandon its oil and gas properties. The fair value of the asset retirement obligation is recorded as a liability when incurred, which is typically at the time the asset is acquired or placed in service. There is a corresponding increase to the carrying value of the asset, which is included in the proved properties line item in the accompanying balance sheets. The Company depletes the amount added to proved properties and recognizes expense in connection with accretion of the discounted liability over the remaining estimated economic lives of the properties. The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimated costs to abandon the wells, and regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred. A roll-forward of the Company's asset retirement obligation is as follows (in thousands): For the Years Ended December 31, 2019 2018 Balance, beginning of year $ 29,405 $ 38,262 Additional liabilities incurred 228 373 Accretion expense 1,467 1,831 Liabilities settled (2,443) (1,627) Revisions to estimate (749) 1,490 Sold properties — (10,924) Balance, end of year $ 27,908 $ 29,405

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS The Company follows fair value measurement authoritative guidance, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The authoritative accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices are available in active markets for identical assets or liabilities Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable Level 3: Significant inputs to the valuation model are unobservable Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of December 31, 2019 and 2018 and their classification within the fair value hierarchy (in thousands): As of December 31, 2019 Level 1 Level 2 Level 3 Derivative assets (1) $ — $ 3,005 $ — Derivative liabilities (1) $ — $ 7,311 $ — Asset retirement obligations (2) $ — $ — $ (749) As of December 31, 2018 Level 1 Level 2 Level 3 Derivative assets (1) $ — $ 38,272 $ — Derivative liabilities (1) $ — $ 183 $ — Asset retirement obligations (2) $ — $ — $ 1,490 _______________________________ (1) Represents a financial asset or liability that is measured at fair value on a recurring basis. (2) Represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion. Derivatives Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps and collars were validated by observable transactions for the same or similar commodity options using the NYMEX futures index and were designated as Level 2 within the valuation hierarchy. Proved Oil and Gas Properties Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. Depending on the availability of data, the Company uses Level 3 inputs and either the income valuation technique, which converts future amounts to a single present value amount to measure the fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management, or the market valuation approach. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the Company's internal budgeting model derived from the NYMEX strip pricing, adjusted for management estimates and basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no oil and gas property impairments during the years ended December 31, 2019 and 2018. Unproved Oil and Gas Properties Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be fully recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, remaining lease life, and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company uses the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. During 2019, the Company incurred $11.2 million in abandonment and impairment of unproved properties due to reassessment of estimated probable and possible reserve values and the expiration of non-core leases. During 2018, the Company incurred $5.3 million in abandonment and impairment of unproved properties due to the expiration of non-core leases. Asset Retirement Obligation

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVES	DERIVATIVES The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps, collars, and puts for oil and natural gas, and none of the derivative instruments qualify as having hedging relationships. In a typical commodity swap agreement, if the agreed upon published third-party index price is lower than the swap strike price, the Company receives the difference between the index price and the agreed upon swap strike price. If the index price is higher than the swap strike price, the Company pays the difference. A put gives the owner the right to sell the underlying commodity at a set price over the term of the contract. If the index settlement price is higher than the put fixed price, the put will expire worthless. If the settlement price is lower than the put fixed price, the Company will exercise the put and receive the difference between the settlement price and the put fixed price. A cashless collar arrangement establishes a floor and ceiling price on future oil and gas production. When the settlement price is above the ceiling price, the Company pays the difference between the settlement price and the ceiling price. When the settlement price is below the floor price, the Company receives the difference between the settlement price and floor price. In the event that the settlement price is between the ceiling and the floor, no payment or receipt occurs. A basis swap arrangement guarantees a price differential from a specified delivery point to an agreed upon reference point. The Company receives the difference between the price differential and the stated terms, if the price differential is greater than the stated terms. The Company pays the difference between the price differential and the stated terms, if the stated terms are greater than the price differential. As of December 31, 2019, the Company had entered into the following commodity derivative contracts: Crude Oil Natural Gas Natural Gas Natural Gas Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu 1Q20 Cashless Collar 5,000 $55.00/$62.88 — — — — — — Swap 4,500 $60.69 20,000 $2.63 20,000 $0.56 2,500 $2.40 2Q20 Cashless Collar 7,500 $54.00/$61.01 — — — — — — Swap 1,500 $54.98 10,000 $2.61 20,000 $0.56 — — 3Q20 Cashless Collar 6,000 $52.67/$58.40 — — — — — — Swap 3,000 $53.60 — — 20,000 $0.56 — — 4Q20 Cashless Collar 6,000 $52.67/$58.40 — — — — — — Swap 3,000 $53.60 — — 20,000 $0.56 — — 1Q21 Cashless Collar 2,000 $50.50/$55.19 — — — — — — Swap 3,500 $53.89 — — — — — — 2Q21 Cashless Collar 500 $52.00/$55.00 — — — — — — Swap 2,000 $53.35 — — — — — — 3Q21 Swap 1,000 $54.87 — — — — — — As of the filing date of this report, the Company had entered into the following commodity derivative contracts: Crude Oil Natural Gas Natural Gas Natural Gas Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu 1Q20 Cashless Collar 5,000 $55.00/$62.88 — — — — — — Swap 4,500 $60.69 20,000 $2.63 26,593 $0.55 2,500 $2.40 2Q20 Cashless Collar 7,500 $54.00/$61.01 — — — — — — Swap 1,500 $54.98 10,000 $2.61 30,000 $0.54 — — 3Q20 Cashless Collar 6,000 $52.67/$58.40 — — — — — — Swap 3,500 $54.12 — — 30,000 $0.54 — — 4Q20 Cashless Collar 6,000 $52.67/$58.40 — — — — — — Swap 3,500 $54.12 — — 30,000 $0.54 — — 1Q21 Cashless Collar 2,000 $50.50/$55.19 — — — — — — Swap 5,000 $54.48 — — — — — — 2Q21 Cashless Collar 500 $52.00/$55.00 — — — — — — Swap 4,000 $54.13 — — — — — — 3Q21 Swap 2,500 $54.45 — — — — — — 4Q21 Swap 1,000 $55.20 — — — — — — Derivative Assets and Liabilities Fair Value The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of December 31, 2019 and 2018 (in thousands): As of December 31, 2019 2018 Derivative Assets: Commodity contracts - current $ 2,884 $ 34,408 Commodity contracts - noncurrent 121 3,864 Derivative Liabilities: Commodity contracts - current (6,390) (183) Commodity contracts - long-term (921) — Total derivative assets (liabilities), net $ (4,306) $ 38,089 The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands): Successor Predecessor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Derivative cash settlement gain (loss): Oil contracts $ 1,185 $ (17,700) $ (1,486) $ — Gas contracts 506 (460) 22 — Total derivative cash settlement gain (loss) (1) 1,691 (18,160) (1,464) — Change in fair value gain (loss) (38,836) 48,431 (13,901) — Total derivative gain (loss) (1) $ (37,145) $ 30,271 $ (15,365) $ — ___________________________ (1) Total derivative gain (loss) and total derivative cash settlement gain (loss) for each of the periods presented above is reported in the derivative (gain) loss line item and derivative cash settlements line item in the accompanying statements of cash flows, within the cash flows from operating activities.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE The Company issues RSUs, which represent the right to receive, upon vesting, one share of the Company's common stock. The number of potentially dilutive shares related to RSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified price. The number of potentially dilutive shares related to the stock options is based on the number of shares, if any, that would be exercised at the end of the respective reporting period, assuming that date was the end of such stock options' term. The number of potentially dilutive shares related to the warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period. Please refer to Note 8 - Stock-Based Compensation for additional discussion. The Company uses the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts): Successor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 Net income (loss) $ 67,067 $ 168,186 $ (5,020) Basic net income (loss) per common share $ 3.25 $ 8.20 $ (0.25) Diluted net income (loss) per common share $ 3.24 $ 8.16 $ (0.25) Weighted-average shares outstanding - basic 20,612 20,507 20,427 Add: dilutive effect of contingent stock awards 69 96 — Weighted-average shares outstanding - diluted 20,681 20,603 20,427 There were 269,208 and 170,755 shares that were anti-dilutive for the years ended December 31, 2019 and 2018, respectively. The exercise price of the Company's warrants was in excess of the Company's stock price; therefore, they were excluded from the earnings per share calculation. The Company was in a net loss position for the 2017 Successor Period, which made the 375,123 potentially dilutive shares anti-dilutive. The Predecessor Company issued shares of restricted stock, which entitled the holders to receive non-forfeitable dividends if and when the Predecessor Company was to declare a dividend before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two-class method. The two-class method allocates earnings for the period between common shareholders and unvested participating shareholders and losses to common shareholders only. The Predecessor Company issued units, which represented the right to receive, upon vesting, shares of the Predecessor Company's common stock on a one-to-one basis up to a share price of $26. In the event the price of the Company's common stock were to exceed $26, the number of shares distributed would be adjusted downward so that the shares distributed would represent a value equivalent to $26 per share. The Predecessor Company issued PSUs, which represented the right to receive, upon settlement of the PSUs, a number of shares of the Predecessor Company’s common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the measurement period applicable to such PSUs. Please refer to Note 8 - Stock-Based Compensation for additional discussion. The following table sets forth the calculation of income per basic and diluted shares from net income for the Predecessor Period ended April 28, 2017 (in thousands, except per share amounts): Predecessor January 1, 2017 through April 28, 2017 Net income $ 2,660 Less: undistributed income to unvested restricted stock 120 Undistributed income to common shareholders $ 2,540 Basic net income per common share $ 0.05 Diluted net income per common share $ 0.05 Weighted-average shares outstanding - basic 49,559 Add: dilutive effect of contingent PSUs 1,412 Weighted-average shares outstanding - diluted 50,971

CHAPTER 11 PROCEEDINGS AND EMER

CHAPTER 11 PROCEEDINGS AND EMERGENCE	12 Months Ended
	Dec. 31, 2019
Reorganizations [Abstract]
CHAPTER 11 PROCEEDINGS AND EMERGENCE	CHAPTER 11 PROCEEDINGS AND EMERGENCE On December 23, 2016, Bonanza Creek Energy, Inc. and its subsidiaries entered into a Restructuring Support Agreement with (i) holders of approximately 51% in aggregate principal amount of the Company's 5.75% Senior Notes due 2023 (“5.75% Senior Notes”) and 6.75% Senior Notes due 2021 (“6.75% Senior Notes”), collectively (the “Senior Notes”) and (ii) NGL Energy Partners, LP and NGL Crude Logistics, LLC. On January 4, 2017, the Company filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code. The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017. Reorganization On the Effective Date, the Senior Notes and existing common shares of the Company (“existing common shares”) were canceled, and the reorganized Company issued: (i) new common stock; (ii) three • the Senior Notes aggregate principal amount of $800.0 million, plus $14.9 million of accrued and unpaid pre-petition interest and $51.2 million of prepayment premiums was settled for 46.6% or 9,481,610 shares of the Company's new common stock; • the Company issued 803,083 or 3.9% of the new common stock to holders of our existing common stock, of which 1.75% was for the ad hoc equity committee settlement in exchange for $7.5 million, on terms equivalent to the rights offering; • the Company issued 10,071,378 shares of new common stock in exchange for $200.0 million relating to the rights offering; • the Company issued 1,650,510 of warrants entitling their holders upon exercise thereof, on a pro rata basis, to 7.5% of the total outstanding new common shares at a per share price of $71.23 per warrant; and • the Company reserved 2,467,430 shares of the new common stock for issuance under its 2017 Long Term Incentive Plan (“LTIP”). Pursuant to the terms of the approved Plan the following transactions were completed on the Effective Date; • the Company paid Silo Energy, LLC (“Silo”) the contract settlement amount of $7.2 million in full; • with respect to the predecessor credit facility, dated March 29, 2011 (the “predecessor credit facility”), principal, accrued interest, and fees of $193.7 million were paid in full; • the Company paid $1.6 million for the 2016 Short Term Incentive Plan (“2016 STIP”) to various employees; • the Company funded an escrow account in the amount of $17.2 million for professional service fees attributable to its advisers; • the Company paid $13.8 million for professional services attributable to advisers of third parties involved in the bankruptcy proceedings; • the Company emerged with cash on hand of $70.2 million for operations; and • the Company amended its articles of incorporation and bylaws for the authorization of the new common stock. As confirmed in the Plan, the Company terminated its purchase agreement with Silo on February 1, 2017, and entered into a settlement agreement that allowed Silo to: (i) retain the $5.0 million adequate assurance deposit maintained, (ii) retain the Company's $8.7 million crude oil revenue receivable due to the Company for December 2016 production, and (iii) receive additional cash payment of $7.2 million, which was paid on the Effective Date. Upon the Company's emergence from Chapter 11 bankruptcy, the Company adopted fresh-start accounting, pursuant to FASB ASC 852, Reorganizations , and applied the provisions thereof to its financial statements. The Company qualified for fresh-start accounting because: (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company; and (ii) the reorganization value of the Company's assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh-start accounting as of April 28, 2017, when it emerged from bankruptcy protection. Adopting fresh-start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit as of the fresh-start reporting date. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares of the Successor Company caused a related change of control of the Company under ASC 852. Reorganization Value Under fresh-start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Under application of fresh-start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values. The Company's reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt, other interest bearing liabilities, and shareholders’ equity, less total cash and cash equivalents. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $570.0 million to $680.0 million. Based on the estimates and assumptions used in determining the enterprise value, as further discussed below, the Company estimated the enterprise value to be approximately $643.0 million. This valuation analysis was prepared with the assistance of an independent third-party consultant utilizing reserve information prepared by the Company's internal reserve engineers, internal development plans and schedules, other internal financial information and projections and the application of standard valuation techniques including risked net asset value analysis and comparable public company metrics. The Company's principal assets are its oil and gas properties. The Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets segregated into geographic regions. The computations were based on market conditions and reserves in place as of the Effective Date. Discounted cash flow models were generated using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising our proved reserves. The proved locations were limited to wells expected to be drilled in the Company's five year plan. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange five year forward prices for West Texas Intermediate oil and Henry Hub natural gas with inflation adjustments applied to periods beyond five years. The prices were further adjusted for typical differentials realized by the Company for the location and product quality. Wattenberg Field oil differential estimates were based on the new NGL Crude purchase agreement that was confirmed as part of the Plan. Development costs were based on recent bids received by the Company and the operating costs were based on actual costs, and both were adjusted by the same inflation rate used for revenues. The discounted cash flow models also included estimates not typically included in proved reserves, such as an industry standard general and administrative expense and income tax expense. Due to the limited drilling plans that we had in place, proved undeveloped locations were risked within industry standards. The risk-adjusted after-tax cash flows were discounted at a rate of 11.0%. This rate was determined from a weighted-average cost of capital computation, which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. From this analysis the Company concluded the fair value of its proved, probable, and possible reserves was $397.3 million, $146.8 million, and $31.7 million, respectively, as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and determined that the fair value of its probable and possible reserves appropriately capture the fair value of its undeveloped leasehold acreage. The Company performed an analysis of its RMI assets using a replacement cost method which estimated the assets' replacement cost (for new assets), less any depreciation, physical deterioration, or obsolescence, resulting in a fair value of $103.1 million. The Company follows the lower of cost or net realizable value when valuing inventory of oilfield equipment. The valuation of the inventory of oilfield equipment as of the Effective Date did not yield a material difference from the Company's carrying value immediately prior to emergence from bankruptcy; as such, there was no valuation adjustment recorded. The valuation of the Company's other property and equipment as of the Effective Date did not yield a material difference from the Predecessor Company's net book value; as such there was no valuation adjustment recorded. Our liabilities on the Effective Date include working capital liabilities and asset retirement obligations. Our working capital liabilities are ordinary course obligations, and their carrying amounts approximate their fair values. The asset retirement obligation was reset using a revised credit-adjusted risk-free rate and known attributes as of the Effective Date, resulting in a $29.1 million obligation. In conjunction with the Company's emergence from bankruptcy, the Company issued 1,650,510 warrants to existing equity holders. The fair value of $4.1 million was estimated using a Black-Scholes pricing model. The model used the following assumptions; an expected volatility of 40%, a risk-free interest rate of 1.44%, a stock price of $34.36, a strike price of $71.23, and an expiration date of 3 years. The following table reconciles the enterprise value to the estimated fair value of Successor Company's common stock as of the Effective Date (in thousands, except per share amounts): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Less: Interest bearing liabilities (29,061) Less: Fair value of warrants (4,081) Fair value of Successor common stock $ 680,040 Shares outstanding at April 28, 2017 20,356 Per share value $ 33.41 The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Plus: Working capital liabilities 63,871 Plus: Other long-term liabilities 17,919 Reorganization value of Successor assets $ 794,972 Successor Condensed Consolidated Balance Sheet The adjustments set forth in the following condensed consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as estimated fair value adjustments as a result of the adoption of fresh-start accounting (reflected in the column “Fresh-Start Adjustments”). The explanatory notes highlight methods used to determine estimated fair values or other amounts of assets and liabilities, as well as significant assumptions. Predecessor Company Reorganization Adjustments Fresh-Start Adjustments Successor Company ASSETS (in thousands, except share amounts) Current Assets: Cash and cash equivalents $ 96,286 $ (26,103) (1) $ — 70,183 Accounts receivable: Oil and gas sales 24,876 — — 24,876 Joint interest and other 3,028 — — 3,028 Prepaid expenses and other 4,952 — — 4,952 Inventory of oilfield equipment 4,218 — — 4,218 Total current assets 133,360 (26,103) — 107,257 Property and equipment (successful efforts method): Proved properties 2,531,834 — (2,031,373) (6) 500,461 Less: accumulated depreciation, depletion and amortization (1,720,736) — 1,720,736 (6) — Total proved properties, net 811,098 — (310,637) 500,461 Unproved properties 163,781 — 14,679 (6) 178,460 Wells in progress 18,002 — (18,002) (7) — Other property and equipment, net 6,056 — — 6,056 Total property and equipment, net 998,937 — (313,960) 684,977 Other noncurrent assets 2,738 — — 2,738 Total assets $ 1,135,035 $ (26,103) $ (313,960) $ 794,972 LIABILITIES AND STOCKHOLDERS'S EQUITY Current liabilities: Accounts payable and accrued expenses $ 72,635 $ (33,701) (2) $ — $ 38,934 Oil and gas revenue distribution payable 24,937 — — 24,937 Predecessor credit facility - current portion 191,667 (191,667) (3) — — Total current liabilities 289,239 (225,368) — 63,871 Long-term liabilities: Ad valorem taxes 17,919 — — 17,919 Asset retirement obligations for oil and gas properties 31,660 — (2,599) (8) 29,061 Liabilities subject to compromise 873,292 (873,292) (4) — — Total liabilities 1,212,110 (1,098,660) (2,599) 110,851 Stockholders' equity: Predecessor preferred stock — — — — Predecessor common stock 49 — (49) (9) — Additional paid in capital 816,679 — (816,679) (9) — Successor common stock — 204 (5) — 204 Successor warrants — 4,081 (5) — 4,081 Additional paid-in capital — 679,836 (5) — 679,836 Retained deficit (893,803) 388,436 (4) 505,367 (10) — Total stockholders' equity (77,075) 1,072,557 (311,361) 684,121 Total liabilities and stockholders' equity $ 1,135,035 $ (26,103) $ (313,960) $ 794,972 Reorganization Adjustments (1) The following table reflects the net cash payments made upon emergence on the Effective Date (in thousands): Sources: Proceeds from rights offering $ 200,000 Proceeds from ad hoc equity committee 7,500 Total sources $ 207,500 Uses and transfers: Payment on predecessor credit facility (principal, interest and fees) $ (193,729) Payment and funding of escrow account related to professional fees (17,193) Payment of professional fees and other (13,831) Payment of Silo contract settlement and other (7,228) Payment of remaining 2016 STIP (1,622) Total uses and transfers $ (233,603) Total net sources, uses and transfers $ (26,103) (2) The following table shows the decrease of accounts payable and accrued liabilities attributable to reorganization items settled or paid upon emergence (in thousands): Accounts payable and accrued expenses: Accrued 2016 STIP payment $ (1,574) Escrow account funding (17,193) Professional fees and other (13,831) Accrued unpaid interest on predecessor credit facility (1,103) Total accounts payable and accrued expenses settled $ (33,701) (3) Represents the payment in full of the predecessor credit facility on the Effective Date. (4) On the Effective Date, the obligations of the Company with respect to the Senior Notes were canceled. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands): Senior Notes $ 800,000 Accrued interest on Senior Notes (pre-petition) 14,879 Make-whole payment on Senior Notes 51,185 Silo contract settlement accrual 7,228 Total liabilities subject to compromise of the predecessor 873,292 Rights offering 200,000 Fair value of equity issued to creditors, excluding equity issued to existing equity holders (653,212) Payment of Silo contract settlement (7,228) Gain on settlement of liabilities subject to compromise 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007) Total reorganization items at emergence 411,845 Issuance of warrants to existing shareholders (4,081) Proceeds from ad hoc equity committee 7,500 Issuance of shares to existing shareholders (26,828) Total reorganization adjustments to retained deficit $ 388,436 (5) Represents the fair value of 20,356,071 shares of new common stock and 1,650,510 warrants issued upon emergence from bankruptcy on the Effective Date. Fresh-Start Adjustments (6) Fair value adjustments to proved and unproved oil and natural gas properties. A combination of the market and income approach were utilized to perform valuations. Included in this line items were adjustments to the fully-owned subsidiary, Rocky Mountain Infrastructure, LLC. Lastly, the accumulated depreciation was reset to zero in accordance with fresh-start accounting. (7) Represents the reset of wells in progress with fair valuation of the associated reserves in proved property. (8) Upon application of fresh-start accounting and due to the Company’s emergence with no debt, the Company revalued its asset retirement obligations based upon comparable companies’ credit-adjusted risk-free rates in accordance with ASC 410 - Asset Retirement and Environmental Obligations. (9) Cancellation of Predecessor Company’s common stock and additional paid-in capital. (10) Adjustment to reset retained deficit to zero. Reorganization Items, Net Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan, and are classified as Reorganization items, net in our statement of operations. The following table summarizes reorganization items recorded in the Current Predecessor Period (in thousands): Gain on settlement of liabilities subject to compromise $ 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007) Fresh-start valuation adjustments (311,361) Legal and professional fees and expenses (34,335) Write-off of debt issuance and premium costs (6,156) Make-whole payment on Senior Notes (51,185) Total reorganization items, net $ 8,808

FRESH-START ACCOUNTING

FRESH-START ACCOUNTING	12 Months Ended
	Dec. 31, 2019
Reorganizations [Abstract]
FRESH-START ACCOUNTING	CHAPTER 11 PROCEEDINGS AND EMERGENCE On December 23, 2016, Bonanza Creek Energy, Inc. and its subsidiaries entered into a Restructuring Support Agreement with (i) holders of approximately 51% in aggregate principal amount of the Company's 5.75% Senior Notes due 2023 (“5.75% Senior Notes”) and 6.75% Senior Notes due 2021 (“6.75% Senior Notes”), collectively (the “Senior Notes”) and (ii) NGL Energy Partners, LP and NGL Crude Logistics, LLC. On January 4, 2017, the Company filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code. The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017. Reorganization On the Effective Date, the Senior Notes and existing common shares of the Company (“existing common shares”) were canceled, and the reorganized Company issued: (i) new common stock; (ii) three • the Senior Notes aggregate principal amount of $800.0 million, plus $14.9 million of accrued and unpaid pre-petition interest and $51.2 million of prepayment premiums was settled for 46.6% or 9,481,610 shares of the Company's new common stock; • the Company issued 803,083 or 3.9% of the new common stock to holders of our existing common stock, of which 1.75% was for the ad hoc equity committee settlement in exchange for $7.5 million, on terms equivalent to the rights offering; • the Company issued 10,071,378 shares of new common stock in exchange for $200.0 million relating to the rights offering; • the Company issued 1,650,510 of warrants entitling their holders upon exercise thereof, on a pro rata basis, to 7.5% of the total outstanding new common shares at a per share price of $71.23 per warrant; and • the Company reserved 2,467,430 shares of the new common stock for issuance under its 2017 Long Term Incentive Plan (“LTIP”). Pursuant to the terms of the approved Plan the following transactions were completed on the Effective Date; • the Company paid Silo Energy, LLC (“Silo”) the contract settlement amount of $7.2 million in full; • with respect to the predecessor credit facility, dated March 29, 2011 (the “predecessor credit facility”), principal, accrued interest, and fees of $193.7 million were paid in full; • the Company paid $1.6 million for the 2016 Short Term Incentive Plan (“2016 STIP”) to various employees; • the Company funded an escrow account in the amount of $17.2 million for professional service fees attributable to its advisers; • the Company paid $13.8 million for professional services attributable to advisers of third parties involved in the bankruptcy proceedings; • the Company emerged with cash on hand of $70.2 million for operations; and • the Company amended its articles of incorporation and bylaws for the authorization of the new common stock. As confirmed in the Plan, the Company terminated its purchase agreement with Silo on February 1, 2017, and entered into a settlement agreement that allowed Silo to: (i) retain the $5.0 million adequate assurance deposit maintained, (ii) retain the Company's $8.7 million crude oil revenue receivable due to the Company for December 2016 production, and (iii) receive additional cash payment of $7.2 million, which was paid on the Effective Date. Upon the Company's emergence from Chapter 11 bankruptcy, the Company adopted fresh-start accounting, pursuant to FASB ASC 852, Reorganizations , and applied the provisions thereof to its financial statements. The Company qualified for fresh-start accounting because: (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company; and (ii) the reorganization value of the Company's assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh-start accounting as of April 28, 2017, when it emerged from bankruptcy protection. Adopting fresh-start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit as of the fresh-start reporting date. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares of the Successor Company caused a related change of control of the Company under ASC 852. Reorganization Value Under fresh-start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Under application of fresh-start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values. The Company's reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt, other interest bearing liabilities, and shareholders’ equity, less total cash and cash equivalents. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $570.0 million to $680.0 million. Based on the estimates and assumptions used in determining the enterprise value, as further discussed below, the Company estimated the enterprise value to be approximately $643.0 million. This valuation analysis was prepared with the assistance of an independent third-party consultant utilizing reserve information prepared by the Company's internal reserve engineers, internal development plans and schedules, other internal financial information and projections and the application of standard valuation techniques including risked net asset value analysis and comparable public company metrics. The Company's principal assets are its oil and gas properties. The Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets segregated into geographic regions. The computations were based on market conditions and reserves in place as of the Effective Date. Discounted cash flow models were generated using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising our proved reserves. The proved locations were limited to wells expected to be drilled in the Company's five year plan. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange five year forward prices for West Texas Intermediate oil and Henry Hub natural gas with inflation adjustments applied to periods beyond five years. The prices were further adjusted for typical differentials realized by the Company for the location and product quality. Wattenberg Field oil differential estimates were based on the new NGL Crude purchase agreement that was confirmed as part of the Plan. Development costs were based on recent bids received by the Company and the operating costs were based on actual costs, and both were adjusted by the same inflation rate used for revenues. The discounted cash flow models also included estimates not typically included in proved reserves, such as an industry standard general and administrative expense and income tax expense. Due to the limited drilling plans that we had in place, proved undeveloped locations were risked within industry standards. The risk-adjusted after-tax cash flows were discounted at a rate of 11.0%. This rate was determined from a weighted-average cost of capital computation, which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. From this analysis the Company concluded the fair value of its proved, probable, and possible reserves was $397.3 million, $146.8 million, and $31.7 million, respectively, as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and determined that the fair value of its probable and possible reserves appropriately capture the fair value of its undeveloped leasehold acreage. The Company performed an analysis of its RMI assets using a replacement cost method which estimated the assets' replacement cost (for new assets), less any depreciation, physical deterioration, or obsolescence, resulting in a fair value of $103.1 million. The Company follows the lower of cost or net realizable value when valuing inventory of oilfield equipment. The valuation of the inventory of oilfield equipment as of the Effective Date did not yield a material difference from the Company's carrying value immediately prior to emergence from bankruptcy; as such, there was no valuation adjustment recorded. The valuation of the Company's other property and equipment as of the Effective Date did not yield a material difference from the Predecessor Company's net book value; as such there was no valuation adjustment recorded. Our liabilities on the Effective Date include working capital liabilities and asset retirement obligations. Our working capital liabilities are ordinary course obligations, and their carrying amounts approximate their fair values. The asset retirement obligation was reset using a revised credit-adjusted risk-free rate and known attributes as of the Effective Date, resulting in a $29.1 million obligation. In conjunction with the Company's emergence from bankruptcy, the Company issued 1,650,510 warrants to existing equity holders. The fair value of $4.1 million was estimated using a Black-Scholes pricing model. The model used the following assumptions; an expected volatility of 40%, a risk-free interest rate of 1.44%, a stock price of $34.36, a strike price of $71.23, and an expiration date of 3 years. The following table reconciles the enterprise value to the estimated fair value of Successor Company's common stock as of the Effective Date (in thousands, except per share amounts): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Less: Interest bearing liabilities (29,061) Less: Fair value of warrants (4,081) Fair value of Successor common stock $ 680,040 Shares outstanding at April 28, 2017 20,356 Per share value $ 33.41 The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Plus: Working capital liabilities 63,871 Plus: Other long-term liabilities 17,919 Reorganization value of Successor assets $ 794,972 Successor Condensed Consolidated Balance Sheet The adjustments set forth in the following condensed consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as estimated fair value adjustments as a result of the adoption of fresh-start accounting (reflected in the column “Fresh-Start Adjustments”). The explanatory notes highlight methods used to determine estimated fair values or other amounts of assets and liabilities, as well as significant assumptions. Predecessor Company Reorganization Adjustments Fresh-Start Adjustments Successor Company ASSETS (in thousands, except share amounts) Current Assets: Cash and cash equivalents $ 96,286 $ (26,103) (1) $ — 70,183 Accounts receivable: Oil and gas sales 24,876 — — 24,876 Joint interest and other 3,028 — — 3,028 Prepaid expenses and other 4,952 — — 4,952 Inventory of oilfield equipment 4,218 — — 4,218 Total current assets 133,360 (26,103) — 107,257 Property and equipment (successful efforts method): Proved properties 2,531,834 — (2,031,373) (6) 500,461 Less: accumulated depreciation, depletion and amortization (1,720,736) — 1,720,736 (6) — Total proved properties, net 811,098 — (310,637) 500,461 Unproved properties 163,781 — 14,679 (6) 178,460 Wells in progress 18,002 — (18,002) (7) — Other property and equipment, net 6,056 — — 6,056 Total property and equipment, net 998,937 — (313,960) 684,977 Other noncurrent assets 2,738 — — 2,738 Total assets $ 1,135,035 $ (26,103) $ (313,960) $ 794,972 LIABILITIES AND STOCKHOLDERS'S EQUITY Current liabilities: Accounts payable and accrued expenses $ 72,635 $ (33,701) (2) $ — $ 38,934 Oil and gas revenue distribution payable 24,937 — — 24,937 Predecessor credit facility - current portion 191,667 (191,667) (3) — — Total current liabilities 289,239 (225,368) — 63,871 Long-term liabilities: Ad valorem taxes 17,919 — — 17,919 Asset retirement obligations for oil and gas properties 31,660 — (2,599) (8) 29,061 Liabilities subject to compromise 873,292 (873,292) (4) — — Total liabilities 1,212,110 (1,098,660) (2,599) 110,851 Stockholders' equity: Predecessor preferred stock — — — — Predecessor common stock 49 — (49) (9) — Additional paid in capital 816,679 — (816,679) (9) — Successor common stock — 204 (5) — 204 Successor warrants — 4,081 (5) — 4,081 Additional paid-in capital — 679,836 (5) — 679,836 Retained deficit (893,803) 388,436 (4) 505,367 (10) — Total stockholders' equity (77,075) 1,072,557 (311,361) 684,121 Total liabilities and stockholders' equity $ 1,135,035 $ (26,103) $ (313,960) $ 794,972 Reorganization Adjustments (1) The following table reflects the net cash payments made upon emergence on the Effective Date (in thousands): Sources: Proceeds from rights offering $ 200,000 Proceeds from ad hoc equity committee 7,500 Total sources $ 207,500 Uses and transfers: Payment on predecessor credit facility (principal, interest and fees) $ (193,729) Payment and funding of escrow account related to professional fees (17,193) Payment of professional fees and other (13,831) Payment of Silo contract settlement and other (7,228) Payment of remaining 2016 STIP (1,622) Total uses and transfers $ (233,603) Total net sources, uses and transfers $ (26,103) (2) The following table shows the decrease of accounts payable and accrued liabilities attributable to reorganization items settled or paid upon emergence (in thousands): Accounts payable and accrued expenses: Accrued 2016 STIP payment $ (1,574) Escrow account funding (17,193) Professional fees and other (13,831) Accrued unpaid interest on predecessor credit facility (1,103) Total accounts payable and accrued expenses settled $ (33,701) (3) Represents the payment in full of the predecessor credit facility on the Effective Date. (4) On the Effective Date, the obligations of the Company with respect to the Senior Notes were canceled. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands): Senior Notes $ 800,000 Accrued interest on Senior Notes (pre-petition) 14,879 Make-whole payment on Senior Notes 51,185 Silo contract settlement accrual 7,228 Total liabilities subject to compromise of the predecessor 873,292 Rights offering 200,000 Fair value of equity issued to creditors, excluding equity issued to existing equity holders (653,212) Payment of Silo contract settlement (7,228) Gain on settlement of liabilities subject to compromise 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007) Total reorganization items at emergence 411,845 Issuance of warrants to existing shareholders (4,081) Proceeds from ad hoc equity committee 7,500 Issuance of shares to existing shareholders (26,828) Total reorganization adjustments to retained deficit $ 388,436 (5) Represents the fair value of 20,356,071 shares of new common stock and 1,650,510 warrants issued upon emergence from bankruptcy on the Effective Date. Fresh-Start Adjustments (6) Fair value adjustments to proved and unproved oil and natural gas properties. A combination of the market and income approach were utilized to perform valuations. Included in this line items were adjustments to the fully-owned subsidiary, Rocky Mountain Infrastructure, LLC. Lastly, the accumulated depreciation was reset to zero in accordance with fresh-start accounting. (7) Represents the reset of wells in progress with fair valuation of the associated reserves in proved property. (8) Upon application of fresh-start accounting and due to the Company’s emergence with no debt, the Company revalued its asset retirement obligations based upon comparable companies’ credit-adjusted risk-free rates in accordance with ASC 410 - Asset Retirement and Environmental Obligations. (9) Cancellation of Predecessor Company’s common stock and additional paid-in capital. (10) Adjustment to reset retained deficit to zero. Reorganization Items, Net Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan, and are classified as Reorganization items, net in our statement of operations. The following table summarizes reorganization items recorded in the Current Predecessor Period (in thousands): Gain on settlement of liabilities subject to compromise $ 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007) Fresh-start valuation adjustments (311,361) Legal and professional fees and expenses (34,335) Write-off of debt issuance and premium costs (6,156) Make-whole payment on Senior Notes (51,185) Total reorganization items, net $ 8,808

DISCLOSURES ABOUT OIL AND GAS P

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2019
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The Company’s oil and natural gas activities are located entirely within the United States. Costs incurred in oil and natural gas producing activities are as follows (in thousands): Successor Predecessor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Acquisition (1) $ 12,901 $ 2,861 $ 5,383 $ 445 Development (2)(3) 209,535 304,197 106,449 10,780 Exploration 796 294 3,671 769 Total $ 223,232 $ 307,352 $ 115,503 $ 11,994 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2019 and 2018, the 2017 Successor Period, and the 2017 Predecessor Period were $4.2 million, $2.5 million, $5.4 million, and $0.4 million, respectively. There were $8.7 million and $0.4 million in acquisition costs for proved properties for the years ended December 31, 2019 and 2018, respectively, and no acquisition costs for proved properties for the 2017 Successor Period and the 2017 Predecessor Period. (2) Development costs include workover costs of $1.4 million, $5.6 million, $4.3 million, and $1.8 million charged to lease operating expense for the years ended December 31, 2019 and 2018, the 2017 Successor Period, and the 2017 Predecessor Period, respectively. (3) Includes amounts relating to asset retirement obligations of $(0.9) million, $(9.0) million, $8.3 million, and $3.1 million, for the years ended December 31, 2019 and 2018, the 2017 Successor Period, and the 2017 Predecessor Period, respectively. Suspended Well Costs The Company did not incur any exploratory well costs during the years ended December 31, 2019 and 2018, the 2017 Successor Period, and the 2017 Predecessor Period. Reserves The proved reserve estimates at December 31, 2019, 2018, and 2017 were prepared by NSAI, our third party independent reserve engineers. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes, and other factors. All of the Company’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of the Company's changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2019, 2018, and 2017 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (MMcf) (MBbl) Balance-December 31, 2016 50,096 138,045 17,547 Extensions, discoveries and infills (1) 8,470 22,212 3,376 Production (3,081) (9,010) (1,136) Revisions to previous estimates (3) (2,557) 6,422 3,028 Balance-December 31, 2017 52,928 157,669 22,815 Extensions, discoveries and infills (1) 18,390 31,471 5,197 Production (3,841) (8,567) (1,140) Sales of minerals in place (6,236) (20,534) (1,499) Removed from capital program (2) (1,442) (3,246) (544) Revisions to previous estimates (3) 4,555 8,219 101 Balance-December 31, 2018 64,354 165,012 24,930 Extensions, discoveries and infills (1) 8,825 20,604 3,123 Production (5,136) (11,967) (1,431) Sales of minerals in place (52) (110) (18) Removed from capital program (2) (4,926) (11,508) (1,862) Purchases of minerals in place 303 627 102 Revisions to previous estimates (3) 1,045 49,542 (2,683) Balance-December 31, 2019 64,413 212,200 22,161 Proved developed reserves: December 31, 2017 25,785 92,718 12,702 December 31, 2018 23,725 79,630 11,703 December 31, 2019 25,397 105,840 11,566 Proved undeveloped reserves: December 31, 2017 27,143 64,951 10,113 December 31, 2018 40,629 85,382 13,227 December 31, 2019 39,016 106,360 10,595 ________________________ (1) During the years ended December 31, 2019, 2018, and 2017, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of 15.4 MMBoe, 28.8 MMBoe, and 15.5 MMBoe, respectively. (2) During the years ended December 31, 2019 2018, and 2017, proved undeveloped reserves were reduced by 8.7 MMBoe, 2.5 MMBoe, and 7.6 MMBoe respectively, due to the removal of proved undeveloped locations from our five-year drilling program. (3) As of December 31, 2019, the Company revised its proved reserves upward by 6.6 MMboe. The commodity prices at December 31, 2019 decreased to $55.85 per Bbl WTI and $2.58 per MMBtu HH from $65.56 per Bbl WTI and $3.10 per MMBtu HH at December 31, 2018, resulting in a negative revision of 1.4 MMBoe, offset by 8.1 MMBoe in positive engineering revision. As of December 31, 2018, the Company revised its proved reserves upward by 6.0 MMBoe. The commodity prices at December 31, 2018 increased to $65.56 per Bbl WTI and $3.10 per MMBtu HH from $51.34 per Bbl WTI and $2.98 per MMBtu HH at December 31, 2017, resulting in positive revisions of 2.3 MMBoe. In addition, lower operating cost estimates resulted in positive reserve adjustments of 1.5 MMBoe. There were net positive engineering revisions of 2.2 MMBoe. As of December 31, 2017, the Company revised its proved reserves upward by 1.5 MMBoe. The commodity prices at December 31, 2017 increased to $51.34 per Bbl WTI and $2.98 per MMBtu HH from $42.75 per Bbl WTI and $2.48 per MMBtu HH at December 31, 2016, resulting in positive revisions of 5.4 MMBoe. In addition, lower operating cost estimates resulted in positive reserve adjustments (net of price increases) of 1.7 MMBoe, of which 1.4 MMBoe relate to operations in the Wattenberg Field. The Company also had positive other engineering revisions of 2.0 MMBoe, offset by PUD demotions of 7.6 MMBoe. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with accounting authoritative guidance. Future cash inflows were computed by applying prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year-end, based on current costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves. Future income tax expenses give effect to permanent differences, tax credits, and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company's oil and natural gas properties. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): For the Years Ended December 31, 2019 2018 2017 Future cash flows $ 3,827,009 $ 4,742,180 $ 3,307,868 Future production costs (1,029,140) (1,585,032) (1,490,091) Future development costs (850,327) (925,640) (622,344) Future income tax expense — — — Future net cash flows 1,947,542 2,231,508 1,195,433 10% annual discount for estimated timing of cash flows (1,089,395) (1,276,528) (596,935) Standardized measure of discounted future net cash flows $ 858,147 $ 954,980 $ 598,498 Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at period end. The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): For the Years Ended December 31, 2019 2018 2017 Beginning of period $ 954,980 $ 598,498 $ 276,955 Sale of oil and gas produced, net of production costs (233,677) (204,566) (125,992) Net changes in prices and production costs (372,233) 365,952 282,112 Extensions, discoveries and improved recoveries 45,728 153,691 103,937 Development costs incurred 185,086 127,788 24,121 Changes in estimated development cost 81,358 (52,260) 2,122 Purchases of minerals in place 10,135 — — Sales of minerals in place (309) (115,742) — Revisions of previous quantity estimates 79,637 12,341 14,119 Net change in income taxes — — — Accretion of discount 95,498 59,850 27,696 Changes in production rates and other 11,944 9,428 (6,572) End of period $ 858,147 $ 954,980 $ 598,498 The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2019, 2018, and 2017 were calculated using the twelve-month arithmetic average of first-day-of-the-month price inclusive of adjustments for quality and location. For the Years Ended December 31, 2019 2018 2017 Oil (per Bbl) $ 51.22 $ 59.29 $ 46.76 Gas (per Mcf) $ 1.44 $ 2.28 $ 2.45 Natural gas liquids (per Bbl) $ 10.07 $ 22.06 $ 19.57

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018 (in thousands, except per share data): Three Months Ended 2019 March 31 June 30 September 30 December 31 Oil and gas sales $ 72,594 $ 85,783 $ 75,176 $ 79,667 Operating profit (1) $ 40,818 $ 45,744 $ 34,148 $ 36,514 Net income (loss) $ (6,993) $ 41,022 $ 35,893 $ (2,855) Basic net income (loss) per common share $ (0.34) $ 1.99 $ 1.74 $ (0.14) Diluted net income (loss) per common share $ (0.34) $ 1.99 $ 1.74 $ (0.14) Three Months Ended 2018 March 31 June 30 September 30 December 31 Oil and gas sales $ 64,193 $ 71,872 $ 74,380 $ 66,213 Operating profit (1) $ 35,042 $ 40,014 $ 43,959 $ 41,416 Net income $ 13,870 $ 4,859 $ 43,363 $ 106,094 Basic net income per common share $ 0.68 $ 0.24 $ 2.11 $ 5.16 Diluted net income per common share $ 0.68 $ 0.24 $ 2.10 $ 5.15 ________________________

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation As of December 31, 2019, the consolidated balance sheets (“balance sheets”) include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All intercompany accounts and transactions have been eliminated. Certain prior period amounts have been reclassified to conform to the current period presentation. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2019, through the filing date of this report. On August 6, 2018, the Company sold its equity interests in Bonanza Creek Energy Resources, LLC, which owns all of the outstanding equity interest in Bonanza Creek Energy Upstream LLC and Bonanza Creek Energy Midstream, LLC. These subsidiaries comprised the Company's Mid-Continent region and assets. Please refer to Note 3 - Divestitures for additional discussion. On January 4, 2017, the Company and certain of its subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions,” and the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) to pursue the Debtors’ Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as proposed, the “Plan”). The Bankruptcy Court granted the Debtors' motion seeking to administer all of the Debtors' Chapter 11 Cases jointly under the caption “In re Bonanza Creek Energy, Inc., et al” (Case No. 17-10015). The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017 (the “Effective Date”). Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession during a portion of the year ended December 31, 2017. As such, certain aspects of the bankruptcy proceedings of the Company and related matters are described below in order to provide context and explain part of our financial condition and results of operations for the period presented. Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements after April 28, 2017 are not comparable with the financial statements on or prior to April 28, 2017. The Company's condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after April 28, 2017 and dates prior thereto. Please refer to Note 15 - Fresh-Start Accounting for additional discussion. Subsequent to January 4, 2017 and through the date of emergence, all expenses, gains, and losses directly associated with the reorganization are reported as reorganization items, net in the accompanying consolidated statements of operations and comprehensive income (loss) (“statements of operations”). References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or prior to April 28, 2017. Throughout these financial statements, the Company refers to the 2017 annual period which is comprised of both Successor and Predecessor periods. References to “2017 Successor Period” relate to the period of April 29, 2017 through December 31, 2017. References to the “2017 Predecessor Period” relate to the period of January 1, 2017 through April 28, 2017.
Use of Estimates	Use of EstimatesThe preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments.
Accounts Receivable	Accounts Receivable The Company’s accounts receivables are generated from oil and gas sales and from joint interest owners on properties that the Company operates. These receivables are generally unsecured. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated. For receivables from joint interest owners, the Company usually has the ability to withhold future revenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables are typically collected within one two
Inventory of Oilfield Equipment	Inventory of Oilfield Equipment Inventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or net realizable value, which approximates fair value.
Oil and Gas Producing Activities	Oil and Gas Producing Activities The Company follows the successful efforts method of accounting for its oil and gas exploration and development costs. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether economically recoverable reserves have been found. If an exploratory well does not find economically recoverable reserves, the costs of drilling the well and other associated costs are charged to dry hole expense. The costs of development wells are capitalized whether the well is productive or nonproductive. Costs incurred to maintain wells and their related equipment and leases as well as operating costs are charged to expense as incurred. Geological and geophysical costs are expensed as incurred. Depletion, depreciation, and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs and anticipated proceeds from salvaging equipment. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets' net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. The factors used to determine fair value are subject to the Company’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows on all developed proved reserves and risk adjusted probable and possible reserves, net of estimated operating and development costs, future commodity pricing based on the Company's internal budgeting model originating from the NYMEX strip price adjusted for basis differential, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. As of December 31, 2019, the Company's gathering assets comprised $146.4 million, $1.3 million, and $0.1 million of proved properties, wells in progress, and unproved properties, respectively, on the accompanying balance sheets. Depreciation on the Company's gathering assets is calculated using the straight-line method over the estimated useful lives of the assets and the assets it is servicing, which is approximately 30 years. Unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis once proved reserves have been assigned. The unproved property balance at emergence from bankruptcy represents probable and possible well locations that are reassessed at least annually. The assessment of probable and possible locations incorporates key factors such as economic viability, surface constraints, wells per section, limitations on operatorship due to working interest changes, and any relevant components at such time. Changes in probable and possible locations that result in entire areas no longer being represented in the reserve run are impaired. Leases acquired post-emergence are assessed for impairment applying the following factors: • the remaining amount of unexpired term under leases; • the Company's ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration; • its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; • its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; • its evaluation of the continuing successful results from the application of completion technology by the Company or by other operators in areas adjacent to or near its unproved properties; and • strategic shifts in development areas. The Company records the fair value of an asset retirement obligation as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. The increase in carrying value is included in proved properties in the accompanying balance sheets. For additional discussion, please refer to Note 10 - Asset Retirement Obligations. Gains and losses arising from sales of oil and gas properties will be included in income. However, a partial sale of proved properties within an existing field that does not significantly affect the unit-of-production depletion rate will be accounted for as a normal retirement with no gain or loss recognized. The sale of a partial interest within a proved property is accounted for as a recovery of cost. The partial sale of unproved property is accounted for as a recovery of cost when there is uncertainty of the ultimate recovery of the cost applicable to the interest retained.
Other Property and Equipment	Other Property and Equipment Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three
Assets Held for Sale	Assets Held for SaleAssets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent decreases to the estimated fair value less the costs to sell impact the measurement of assets held for sale. Any properties deemed held for sale as of the balance sheet date are presented separately on the accompanying balance sheets at the lower of net book value or fair value less cost to sell.
Revenue Recognition	Revenue Recognition On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606 (“ASC 606”), Revenue from Contracts with Customers, using the modified retrospective approach . Sales of oil, natural gas, and NGLs are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. The Company's contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies. As further described in Note 7 - Commitments and Contingencies , one contract with NGL Crude has an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the NGL Crude agreement based on approved production plans to determine if liquidated damages to NGL Crude are probable. As of December 31, 2019, the Company believes that the volumes delivered to NGL Crude will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the NGL Crude agreement. Under the oil sales contracts, the Company sells oil production at the wellhead, or other contractually agreed-upon delivery points, and collect an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received. Under the natural gas processing contracts, the Company delivers natural gas to an agreed-upon delivery point. The delivery points are specified within each contract, and the transfer of control varies between the inlet and outlet of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. For the contracts where the Company maintains control through the outlet of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the Company's accompanying statements of operations. Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGLs revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis. Under the product sales contracts, the Company invoices customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under this guidance. At December 31, 2019 and 2018, the Company's receivables from contracts with customers were $43.7 million and $31.8 million, respectively. Payment is generally received within 30 to 60 days after the date of production. The Company records revenue in the month production is delivered to the purchaser. However, as stated above, settlement statements for certain natural gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between our estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the period from January 1, 2019 through December 31, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands) for the periods following the adoption of ASC 606: For the years ended December 31, 2019 2018 Operating Revenues: Crude oil sales $ 268,865 $ 228,661 Natural gas sales 28,296 22,369 Natural gas liquids sales 16,059 25,627 Oil and gas sales $ 313,220 $ 276,657
Income Taxes	Income Taxes The Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.
Uncertain Tax Positions	Uncertain Tax PositionsThe Company recognizes interest and penalties related to uncertain tax positions in income tax expense.
Concentrations of Credit Risk	Concentrations of Credit Risk The Company maintains cash balances in excess of the Federal Deposit Insurance Corporation (FDIC) insured limit.
Oil and Gas Derivative Activities	Oil and Gas Derivative ActivitiesThe Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forward contracts. The contracts are placed with major financial institutions and take the form of swaps, collars, or puts. The oil contracts are indexed to NYMEX WTI prices, and natural gas contracts are indexed to NYMEX HH and CIG prices, which have a high degree of historical correlation with actual prices received by the Company, before differentials. The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities at fair value.
Earnings Per Share	Earnings Per Share Earnings per basic and diluted share within the Successor Company are calculated under the treasury stock method. Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. Diluted net income (loss) per common share is calculated by dividing net income (loss) by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested restricted stock units (“RSUs”), in-the-money outstanding stock options, unvested performance stock units (“PSUs”), and exercisable warrants. When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. Earnings per basic and diluted share within the Predecessor Company were calculated under the two-class method. Pursuant to the two-class method, the Company’s unvested restricted stock awards with non-forfeitable rights to dividends are considered participating securities. Under the two-class method, earnings per basic share is calculated by dividing net income available to shareholders by the weighted-average number of common shares outstanding during the period. The two-class method includes an earnings allocation formula that determines earnings per share for each participating security according to undistributed earnings for the period. Net income available to shareholders is reduced by the amount allocated to participating
Stock-Based Compensation	Stock-Based CompensationThe Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, accrued liabilities, credit facilities, and derivative instruments. Cash and cash equivalents, trade receivables, trade payables, and accrued liabilities are carried at cost and approximate fair value due to the short-term nature of these instruments. Our credit facilities have variable interest rates, so they approximate fair value. Derivative instruments are recorded at fair value.
Recently Issued and Adopted Accounting Standards	Recently Issued and Adopted Accounting Standards In February 2016, the FASB issued Update No. 2016-02 - Leases (ASC 842) to increase transparency and comparability among organizations by recognizing right-of-use assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Each lease that is recognized in the balance sheet will be classified as either finance or operating requiring certain quantitative and qualitative disclosures. Leases acquired to explore the development of oil and natural gas resources are not within the scope of this guidance. The new standard was adopted using the optional transition approach at the date of initial application on January 1, 2019. Please refer to Note 2 - Leases for additional disclosure. In June 2016, the FASB issued Update No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . The update changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amended standard is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted, and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. Historically, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the Company does not believe the adoption of this standard will have a material impact on its consolidated financial statements. In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement . The objective of this update is to improve the effectiveness of fair value measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the form of the Company's disclosures.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Disaggregation of Revenue	Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands) for the periods following the adoption of ASC 606: For the years ended December 31, 2019 2018 Operating Revenues: Crude oil sales $ 268,865 $ 228,661 Natural gas sales 28,296 22,369 Natural gas liquids sales 16,059 25,627 Oil and gas sales $ 313,220 $ 276,657
Schedule of Restricted Cash	The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which sums to the total of such amounts shown in the accompanying consolidated statements of cash flows (in thousands): As of December 31, As of 2019 2018 2017 April 28, 2017 Cash and cash equivalents $ 11,008 $ 12,916 $ 12,711 $ 70,183 Restricted cash included in other noncurrent assets (1) 87 86 71 64 Total cash, cash equivalents and restricted cash as shown in the statements of cash flows $ 11,095 $ 13,002 $ 12,782 $ 70,247 ____________________________ (1) Consists of funds for road maintenance and repairs
Schedule of Cash and Cash Equivalents	The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets, which sums to the total of such amounts shown in the accompanying consolidated statements of cash flows (in thousands): As of December 31, As of 2019 2018 2017 April 28, 2017 Cash and cash equivalents $ 11,008 $ 12,916 $ 12,711 $ 70,183 Restricted cash included in other noncurrent assets (1) 87 86 71 64 Total cash, cash equivalents and restricted cash as shown in the statements of cash flows $ 11,095 $ 13,002 $ 12,782 $ 70,247 ____________________________ (1) Consists of funds for road maintenance and repairs

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Schedule of Balance Sheet Activity, Asset Classes	All leases recognized on the Company's balance sheet are classified as operating leases, which include leases related to the asset classes reflected in the table below (in thousands): Right-of-use Asset Lease Liability Field equipment (1) $ 35,057 $ 35,075 Corporate leases 2,462 3,129 Vehicles 1,043 1,026 Total $ 38,562 $ 39,230 ____________________________ (1) Includes compressors, certain gas processing equipment, and other field equipment.
Summary of Operating Lease Costs	The following table summarizes the components of the Company's gross operating lease costs incurred during the year ended December 31, 2019 (in thousands): Twelve Months Ended December 31, 2019 Operating lease cost (1) $ 11,330 Short-term lease cost 8,169 Variable lease cost (2) 259 Sublease income (3) (348) Total lease cost $ 19,410 ____________________________ (1) Includes office rent expense of $1.1 million for the year ended December 31, 2019. (2) Variable lease cost represents differences between lease obligations and actual costs incurred for certain leases that do not have fixed payments related to both lease and non-lease components. Such incremental costs include lease payment increases or decreases driven by market price fluctuations and leased asset maintenance costs. (3) The Company subleased a portion of its office space for the remainder of the office lease term.
Schedule of Weighted-Average Information	The Company's weighted-average remaining lease term and discount rate used during the year ended December 31, 2019 are as follows: Twelve Months Ended December, 2019 Weighted-average lease term (years) 3.5 Weighted-average discount rate 4.33%
Schedule of Future Minimum Commitments for Operating Leases	Future commitments by year for the Company's operating leases with a lease term of one year or more as of December 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet as follows (in thousands): Amount 2020 $ 13,113 2021 11,823 2022 10,028 2023 5,721 2024 1,559 Thereafter — Total lease payments 42,244 Less: imputed interest (3,014) Total lease liability $ 39,230
Schedule of Future Minimum Leases Payments, Before Topic 842	Future minimum lease payments related to the Company’s operating leases as of December 31, 2018 are presented below (in thousands): Amount (1) 2019 1,256 2020 1,351 2021 1,401 2022 234 2023 — Thereafter — Total $ 4,242 ____________________________ (1) Consists of future minimum lease payments not reported on the balance sheet in accordance with ASC 840 - Leases .

OTHER NONCURRENT ASSETS (Tables

OTHER NONCURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2019
Other Assets [Abstract]
Schedule of Other Noncurrent Assets	Other noncurrent assets contain the following (in thousands): As of December 31, 2019 2018 Operating bonds $ 1,638 $ 2,713 Deferred financing costs 1,443 1,710 AMT credit refund (1) 376 376 Restricted cash 87 86 Other noncurrent assets $ 3,544 $ 4,885 ______________________________________ (1) Represents the alternative minimum tax credit refund due to the Company upon application of the newly enacted comprehensive tax legislation that took effect on December 22, 2017.

ACCOUNTS PAYABLE AND ACCRUED _2

ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Tables)	12 Months Ended
	Dec. 31, 2019
Payables and Accruals [Abstract]
Schedule of Accounts Payable and Accrued Expenses	Accounts payable and accrued expenses contain the following (in thousands): As of December 31, 2019 2018 Drilling and completion costs $ 3,248 $ 33,602 Accounts payable trade 17,117 11,532 Accrued general and administrative cost 5,620 12,728 Lease operating expense 2,187 2,183 Accrued interest 692 241 Accrued oil and gas hedging 453 — Production and ad valorem taxes and other 28,321 19,104 Total accounts payable and accrued expenses $ 57,638 $ 79,390

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of Annual Minimum Commitment Payments	The annual minimum commitment payments under the NGL Crude agreement for the next five years as of December 31, 2019 are presented below (in thousands): NGL Crude Commitments (1) 2020 $ 22,474 2021 23,316 2022 24,009 2023 11,200 2024 and thereafter — Total $ 80,999 ____________________ (1) The above calculation is based on the minimum volume commitment schedule (as defined in the NGL Crude agreement) and applicable differential fees.

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Summary of Share-Based Compensation Expense	The Company recorded compensation expense related to the awards granted under the 2017 LTIP as follows (in thousands): For the Years Ended December 31, 2017 Successor Period 2019 2018 Restricted stock units $ 5,518 $ 5,140 $ 7,913 Performance stock units 764 621 — Stock options 604 1,395 3,717 $ 6,886 $ 7,156 $ 11,630
Summary of Unrecognized Compensation Expense	As of December 31, 2019, unrecognized compensation expense will be amortized through the relevant periods as follows (in thousands): Unrecognized Compensation Expense Final Year of Recognition Restricted stock units $ 9,589 2023 Performance stock units 1,714 2021 Stock options 174 2020 $ 11,477
Summary of the Status and Activity of Non-Vested Restricted Stock	A summary of the status and activity of non-vested restricted stock units for the year ended December 31, 2019 is presented below: Restricted Stock Units Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 480,835 $ 30.83 Granted 258,785 $ 22.70 Vested (143,761) $ 23.12 Forfeited (38,042) $ 25.92 Non-vested, end of year 557,817 $ 26.95
Schedule of Assumptions	The following table presents the assumptions used to determine the fair value of the TSR portion of the PSUs: For the Years Ended December 31, 2019 2018 Expected term (in years) 3 3 Risk-free interest rate 2.26 % 2.76 % Expected daily volatility 2.6 % 2.6 % Stock options were valued using a Black-Scholes Model where expected volatility is based on an average historical volatility of a peer group selected by management over a period consistent with the expected life assumption on the grant date, the risk-free rate of return is based on the U.S. Treasury constant maturity yield on the grant date with a remaining term equal to the expected term of the awards, and the Company’s expected life of stock option awards is derived from the midpoint of the average vesting time and contractual term of the awards. For the Year Ended December 31, 2017 Expected term (years) 6.0 Risk-free interest rate 1.96 % Expected volatility 52.1 % Expected dividends — %
Summary of the Status and Activity of PSUs	A summary of the status and activity of performance stock units for the year ended December 31, 2019 is presented below: Performance Stock Units (1) Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 53,689 $ 29.92 Granted 102,379 $ 22.15 Vested (2,598) $ 23.55 Forfeited — $ — Non-vested, end of year 153,470 $ 24.74 ______________________________ (1) The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.
Schedule of Non-Vested Share Activity	A summary of the status and activity of non-vested stock options for the year ended December 31, 2019 is presented below: Stock Options Weighted- Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding, beginning of year 132,809 $ 34.36 Granted — $ — Exercised — $ — Forfeited (32,095) $ 34.36 Outstanding, end of year 100,714 $ 34.36 6.7 $ — Options outstanding and exercisable 70,077 $ 34.36 6.4 $ —
Schedule of Compensation Expense Related to Awards Granted under the Predecessor Plan	The Company recorded compensation expense related to the awards granted under the Predecessor Plan as follows (in thousands): 2017 Predecessor Period Restricted stock units $ 1,267 Performance stock units 451 Plan units 398 $ 2,116

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	The provision for income taxes consists of the following (in thousands): Successor Predecessor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Current tax benefit Federal $ — $ — $ 376 $ — State — — — — Deferred tax benefit — — — — Total income tax benefit $ — $ — $ 376 $ —
Schedule of Temporary Differences, Deferred Tax Assets and Liabilities	Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax asset (liability) result from the following components (in thousands): As of December 31, 2019 2018 Deferred tax liabilities: Oil and gas properties $ 79,187 $ 52,006 Derivative instruments — 8,527 Right-of-use assets 9,508 — Total deferred tax liabilities 88,695 60,533 Deferred tax assets: Federal and state tax net operating loss carryforward 139,546 137,567 Derivative instruments 1,062 — Reclamation costs 6,881 7,251 Stock compensation 2,209 1,635 Accrued compensation — 1,308 Inventory 1,577 1,577 Lease liability 9,673 — Other long-term assets 300 271 Total deferred tax assets 161,248 149,609 Less: Valuation allowance 72,553 89,076 Total deferred tax assets after valuation allowance 88,695 60,533 Total non-current net deferred tax asset (liability) $ — $ —
Schedule of Amount of Effective Income Tax Rate Reconciliation	Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, changes in valuation allowances, rate changes, and other permanent differences, as follows (in thousands): Successor Predecessor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Federal statutory tax (expense) benefit by applying the statutory rate $ 14,084 $ 35,319 $ 1,889 $ (931) Decrease (increase) in tax resulting from: State tax expense net of federal benefit 2,537 6,556 172 (85) Prior year true-up (579) (458) — (7,572) Stock compensation 197 854 — (1,773) Permanent differences 128 61 (715) (35,273) Rate change — (421) (73,956) — NOL Adjustment — 5,973 — — Other 156 — (642) — Valuation allowance (16,523) (47,884) 73,628 45,634 Total income tax benefit $ — $ — $ 376 $ —

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligations Assumed	A roll-forward of the Company's asset retirement obligation is as follows (in thousands): For the Years Ended December 31, 2019 2018 Balance, beginning of year $ 29,405 $ 38,262 Additional liabilities incurred 228 373 Accretion expense 1,467 1,831 Liabilities settled (2,443) (1,627) Revisions to estimate (749) 1,490 Sold properties — (10,924) Balance, end of year $ 27,908 $ 29,405

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of Financial Assets and Liabilities at Fair Value on Recurring Basis	The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of December 31, 2019 and 2018 and their classification within the fair value hierarchy (in thousands): As of December 31, 2019 Level 1 Level 2 Level 3 Derivative assets (1) $ — $ 3,005 $ — Derivative liabilities (1) $ — $ 7,311 $ — Asset retirement obligations (2) $ — $ — $ (749) As of December 31, 2018 Level 1 Level 2 Level 3 Derivative assets (1) $ — $ 38,272 $ — Derivative liabilities (1) $ — $ 183 $ — Asset retirement obligations (2) $ — $ — $ 1,490 _______________________________ (1) Represents a financial asset or liability that is measured at fair value on a recurring basis. (2) Represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion.

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Commodity Derivatives	As of December 31, 2019, the Company had entered into the following commodity derivative contracts: Crude Oil Natural Gas Natural Gas Natural Gas Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu 1Q20 Cashless Collar 5,000 $55.00/$62.88 — — — — — — Swap 4,500 $60.69 20,000 $2.63 20,000 $0.56 2,500 $2.40 2Q20 Cashless Collar 7,500 $54.00/$61.01 — — — — — — Swap 1,500 $54.98 10,000 $2.61 20,000 $0.56 — — 3Q20 Cashless Collar 6,000 $52.67/$58.40 — — — — — — Swap 3,000 $53.60 — — 20,000 $0.56 — — 4Q20 Cashless Collar 6,000 $52.67/$58.40 — — — — — — Swap 3,000 $53.60 — — 20,000 $0.56 — — 1Q21 Cashless Collar 2,000 $50.50/$55.19 — — — — — — Swap 3,500 $53.89 — — — — — — 2Q21 Cashless Collar 500 $52.00/$55.00 — — — — — — Swap 2,000 $53.35 — — — — — — 3Q21 Swap 1,000 $54.87 — — — — — — As of the filing date of this report, the Company had entered into the following commodity derivative contracts: Crude Oil Natural Gas Natural Gas Natural Gas Bbls/day Weighted Avg. Price per Bbl MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu MMBtu/day Weighted Avg. Price per MMBtu 1Q20 Cashless Collar 5,000 $55.00/$62.88 — — — — — — Swap 4,500 $60.69 20,000 $2.63 26,593 $0.55 2,500 $2.40 2Q20 Cashless Collar 7,500 $54.00/$61.01 — — — — — — Swap 1,500 $54.98 10,000 $2.61 30,000 $0.54 — — 3Q20 Cashless Collar 6,000 $52.67/$58.40 — — — — — — Swap 3,500 $54.12 — — 30,000 $0.54 — — 4Q20 Cashless Collar 6,000 $52.67/$58.40 — — — — — — Swap 3,500 $54.12 — — 30,000 $0.54 — — 1Q21 Cashless Collar 2,000 $50.50/$55.19 — — — — — — Swap 5,000 $54.48 — — — — — — 2Q21 Cashless Collar 500 $52.00/$55.00 — — — — — — Swap 4,000 $54.13 — — — — — — 3Q21 Swap 2,500 $54.45 — — — — — — 4Q21 Swap 1,000 $55.20 — — — — — —
Summary of all the Company's Derivative Positions	The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of December 31, 2019 and 2018 (in thousands): As of December 31, 2019 2018 Derivative Assets: Commodity contracts - current $ 2,884 $ 34,408 Commodity contracts - noncurrent 121 3,864 Derivative Liabilities: Commodity contracts - current (6,390) (183) Commodity contracts - long-term (921) — Total derivative assets (liabilities), net $ (4,306) $ 38,089
Summary of the Components of the Derivative Gain (Loss)	The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands): Successor Predecessor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Derivative cash settlement gain (loss): Oil contracts $ 1,185 $ (17,700) $ (1,486) $ — Gas contracts 506 (460) 22 — Total derivative cash settlement gain (loss) (1) 1,691 (18,160) (1,464) — Change in fair value gain (loss) (38,836) 48,431 (13,901) — Total derivative gain (loss) (1) $ (37,145) $ 30,271 $ (15,365) $ — ___________________________ (1) Total derivative gain (loss) and total derivative cash settlement gain (loss) for each of the periods presented above is reported in the derivative (gain) loss line item and derivative cash settlements line item in the accompanying statements of cash flows, within the cash flows from operating activities.

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Schedule of Earnings Per Share	The Company uses the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts): Successor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 Net income (loss) $ 67,067 $ 168,186 $ (5,020) Basic net income (loss) per common share $ 3.25 $ 8.20 $ (0.25) Diluted net income (loss) per common share $ 3.24 $ 8.16 $ (0.25) Weighted-average shares outstanding - basic 20,612 20,507 20,427 Add: dilutive effect of contingent stock awards 69 96 — Weighted-average shares outstanding - diluted 20,681 20,603 20,427 The following table sets forth the calculation of income per basic and diluted shares from net income for the Predecessor Period ended April 28, 2017 (in thousands, except per share amounts): Predecessor January 1, 2017 through April 28, 2017 Net income $ 2,660 Less: undistributed income to unvested restricted stock 120 Undistributed income to common shareholders $ 2,540 Basic net income per common share $ 0.05 Diluted net income per common share $ 0.05 Weighted-average shares outstanding - basic 49,559 Add: dilutive effect of contingent PSUs 1,412 Weighted-average shares outstanding - diluted 50,971

FRESH-START ACCOUNTING (Tables)

FRESH-START ACCOUNTING (Tables)	12 Months Ended
	Dec. 31, 2019
Reorganizations [Abstract]
Reconciliation of Enterprise Value	The following table reconciles the enterprise value to the estimated fair value of Successor Company's common stock as of the Effective Date (in thousands, except per share amounts): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Less: Interest bearing liabilities (29,061) Less: Fair value of warrants (4,081) Fair value of Successor common stock $ 680,040 Shares outstanding at April 28, 2017 20,356 Per share value $ 33.41
Successor Condensed Consolidated Balance Sheet	The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Plus: Working capital liabilities 63,871 Plus: Other long-term liabilities 17,919 Reorganization value of Successor assets $ 794,972 Predecessor Company Reorganization Adjustments Fresh-Start Adjustments Successor Company ASSETS (in thousands, except share amounts) Current Assets: Cash and cash equivalents $ 96,286 $ (26,103) (1) $ — 70,183 Accounts receivable: Oil and gas sales 24,876 — — 24,876 Joint interest and other 3,028 — — 3,028 Prepaid expenses and other 4,952 — — 4,952 Inventory of oilfield equipment 4,218 — — 4,218 Total current assets 133,360 (26,103) — 107,257 Property and equipment (successful efforts method): Proved properties 2,531,834 — (2,031,373) (6) 500,461 Less: accumulated depreciation, depletion and amortization (1,720,736) — 1,720,736 (6) — Total proved properties, net 811,098 — (310,637) 500,461 Unproved properties 163,781 — 14,679 (6) 178,460 Wells in progress 18,002 — (18,002) (7) — Other property and equipment, net 6,056 — — 6,056 Total property and equipment, net 998,937 — (313,960) 684,977 Other noncurrent assets 2,738 — — 2,738 Total assets $ 1,135,035 $ (26,103) $ (313,960) $ 794,972 LIABILITIES AND STOCKHOLDERS'S EQUITY Current liabilities: Accounts payable and accrued expenses $ 72,635 $ (33,701) (2) $ — $ 38,934 Oil and gas revenue distribution payable 24,937 — — 24,937 Predecessor credit facility - current portion 191,667 (191,667) (3) — — Total current liabilities 289,239 (225,368) — 63,871 Long-term liabilities: Ad valorem taxes 17,919 — — 17,919 Asset retirement obligations for oil and gas properties 31,660 — (2,599) (8) 29,061 Liabilities subject to compromise 873,292 (873,292) (4) — — Total liabilities 1,212,110 (1,098,660) (2,599) 110,851 Stockholders' equity: Predecessor preferred stock — — — — Predecessor common stock 49 — (49) (9) — Additional paid in capital 816,679 — (816,679) (9) — Successor common stock — 204 (5) — 204 Successor warrants — 4,081 (5) — 4,081 Additional paid-in capital — 679,836 (5) — 679,836 Retained deficit (893,803) 388,436 (4) 505,367 (10) — Total stockholders' equity (77,075) 1,072,557 (311,361) 684,121 Total liabilities and stockholders' equity $ 1,135,035 $ (26,103) $ (313,960) $ 794,972
Schedule of Net Cash Payments Made Upon Emergence	The following table reflects the net cash payments made upon emergence on the Effective Date (in thousands): Sources: Proceeds from rights offering $ 200,000 Proceeds from ad hoc equity committee 7,500 Total sources $ 207,500 Uses and transfers: Payment on predecessor credit facility (principal, interest and fees) $ (193,729) Payment and funding of escrow account related to professional fees (17,193) Payment of professional fees and other (13,831) Payment of Silo contract settlement and other (7,228) Payment of remaining 2016 STIP (1,622) Total uses and transfers $ (233,603) Total net sources, uses and transfers $ (26,103)
Schedule of Accounts Payable and Accrued Liabilities Attributable to Reorganization Items	The following table shows the decrease of accounts payable and accrued liabilities attributable to reorganization items settled or paid upon emergence (in thousands): Accounts payable and accrued expenses: Accrued 2016 STIP payment $ (1,574) Escrow account funding (17,193) Professional fees and other (13,831) Accrued unpaid interest on predecessor credit facility (1,103) Total accounts payable and accrued expenses settled $ (33,701)
Schedule of Liabilities Subject to Compromise	On the Effective Date, the obligations of the Company with respect to the Senior Notes were canceled. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands): Senior Notes $ 800,000 Accrued interest on Senior Notes (pre-petition) 14,879 Make-whole payment on Senior Notes 51,185 Silo contract settlement accrual 7,228 Total liabilities subject to compromise of the predecessor 873,292 Rights offering 200,000 Fair value of equity issued to creditors, excluding equity issued to existing equity holders (653,212) Payment of Silo contract settlement (7,228) Gain on settlement of liabilities subject to compromise 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007) Total reorganization items at emergence 411,845 Issuance of warrants to existing shareholders (4,081) Proceeds from ad hoc equity committee 7,500 Issuance of shares to existing shareholders (26,828) Total reorganization adjustments to retained deficit $ 388,436
Schedule of Reorganization Items	The following table summarizes reorganization items recorded in the Current Predecessor Period (in thousands): Gain on settlement of liabilities subject to compromise $ 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007) Fresh-start valuation adjustments (311,361) Legal and professional fees and expenses (34,335) Write-off of debt issuance and premium costs (6,156) Make-whole payment on Senior Notes (51,185) Total reorganization items, net $ 8,808

DISCLOSURES ABOUT OIL AND GAS_2

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2019
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
Schedule of Costs Incurred in Oil and Natural Gas Producing Activities	Costs incurred in oil and natural gas producing activities are as follows (in thousands): Successor Predecessor Year Ended December 31, 2019 Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Acquisition (1) $ 12,901 $ 2,861 $ 5,383 $ 445 Development (2)(3) 209,535 304,197 106,449 10,780 Exploration 796 294 3,671 769 Total $ 223,232 $ 307,352 $ 115,503 $ 11,994 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2019 and 2018, the 2017 Successor Period, and the 2017 Predecessor Period were $4.2 million, $2.5 million, $5.4 million, and $0.4 million, respectively. There were $8.7 million and $0.4 million in acquisition costs for proved properties for the years ended December 31, 2019 and 2018, respectively, and no acquisition costs for proved properties for the 2017 Successor Period and the 2017 Predecessor Period. (2) Development costs include workover costs of $1.4 million, $5.6 million, $4.3 million, and $1.8 million charged to lease operating expense for the years ended December 31, 2019 and 2018, the 2017 Successor Period, and the 2017 Predecessor Period, respectively. (3) Includes amounts relating to asset retirement obligations of $(0.9) million, $(9.0) million, $8.3 million, and $3.1 million, for the years ended December 31, 2019 and 2018, the 2017 Successor Period, and the 2017 Predecessor Period, respectively.
Summary of BCEI's Changes in Quantities of Proved Oil, Natural Gas Liquids and Natural Gas Reserves	A summary of the Company's changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2019, 2018, and 2017 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (MMcf) (MBbl) Balance-December 31, 2016 50,096 138,045 17,547 Extensions, discoveries and infills (1) 8,470 22,212 3,376 Production (3,081) (9,010) (1,136) Revisions to previous estimates (3) (2,557) 6,422 3,028 Balance-December 31, 2017 52,928 157,669 22,815 Extensions, discoveries and infills (1) 18,390 31,471 5,197 Production (3,841) (8,567) (1,140) Sales of minerals in place (6,236) (20,534) (1,499) Removed from capital program (2) (1,442) (3,246) (544) Revisions to previous estimates (3) 4,555 8,219 101 Balance-December 31, 2018 64,354 165,012 24,930 Extensions, discoveries and infills (1) 8,825 20,604 3,123 Production (5,136) (11,967) (1,431) Sales of minerals in place (52) (110) (18) Removed from capital program (2) (4,926) (11,508) (1,862) Purchases of minerals in place 303 627 102 Revisions to previous estimates (3) 1,045 49,542 (2,683) Balance-December 31, 2019 64,413 212,200 22,161 Proved developed reserves: December 31, 2017 25,785 92,718 12,702 December 31, 2018 23,725 79,630 11,703 December 31, 2019 25,397 105,840 11,566 Proved undeveloped reserves: December 31, 2017 27,143 64,951 10,113 December 31, 2018 40,629 85,382 13,227 December 31, 2019 39,016 106,360 10,595 ________________________ (1) During the years ended December 31, 2019, 2018, and 2017, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of 15.4 MMBoe, 28.8 MMBoe, and 15.5 MMBoe, respectively. (2) During the years ended December 31, 2019 2018, and 2017, proved undeveloped reserves were reduced by 8.7 MMBoe, 2.5 MMBoe, and 7.6 MMBoe respectively, due to the removal of proved undeveloped locations from our five-year drilling program.
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): For the Years Ended December 31, 2019 2018 2017 Future cash flows $ 3,827,009 $ 4,742,180 $ 3,307,868 Future production costs (1,029,140) (1,585,032) (1,490,091) Future development costs (850,327) (925,640) (622,344) Future income tax expense — — — Future net cash flows 1,947,542 2,231,508 1,195,433 10% annual discount for estimated timing of cash flows (1,089,395) (1,276,528) (596,935) Standardized measure of discounted future net cash flows $ 858,147 $ 954,980 $ 598,498
Schedule of Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands): For the Years Ended December 31, 2019 2018 2017 Beginning of period $ 954,980 $ 598,498 $ 276,955 Sale of oil and gas produced, net of production costs (233,677) (204,566) (125,992) Net changes in prices and production costs (372,233) 365,952 282,112 Extensions, discoveries and improved recoveries 45,728 153,691 103,937 Development costs incurred 185,086 127,788 24,121 Changes in estimated development cost 81,358 (52,260) 2,122 Purchases of minerals in place 10,135 — — Sales of minerals in place (309) (115,742) — Revisions of previous quantity estimates 79,637 12,341 14,119 Net change in income taxes — — — Accretion of discount 95,498 59,850 27,696 Changes in production rates and other 11,944 9,428 (6,572) End of period $ 858,147 $ 954,980 $ 598,498
Schedule of Average Wellhead Prices Used in Determining Future Net Revenues Related to Standardized Measure Calculation	The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2019, 2018, and 2017 were calculated using the twelve-month arithmetic average of first-day-of-the-month price inclusive of adjustments for quality and location. For the Years Ended December 31, 2019 2018 2017 Oil (per Bbl) $ 51.22 $ 59.29 $ 46.76 Gas (per Mcf) $ 1.44 $ 2.28 $ 2.45 Natural gas liquids (per Bbl) $ 10.07 $ 22.06 $ 19.57

QUARTERLY FINANCIAL DATA (UNA_2

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018 (in thousands, except per share data): Three Months Ended 2019 March 31 June 30 September 30 December 31 Oil and gas sales $ 72,594 $ 85,783 $ 75,176 $ 79,667 Operating profit (1) $ 40,818 $ 45,744 $ 34,148 $ 36,514 Net income (loss) $ (6,993) $ 41,022 $ 35,893 $ (2,855) Basic net income (loss) per common share $ (0.34) $ 1.99 $ 1.74 $ (0.14) Diluted net income (loss) per common share $ (0.34) $ 1.99 $ 1.74 $ (0.14) Three Months Ended 2018 March 31 June 30 September 30 December 31 Oil and gas sales $ 64,193 $ 71,872 $ 74,380 $ 66,213 Operating profit (1) $ 35,042 $ 40,014 $ 43,959 $ 41,416 Net income $ 13,870 $ 4,859 $ 43,363 $ 106,094 Basic net income per common share $ 0.68 $ 0.24 $ 2.11 $ 5.16 Diluted net income per common share $ 0.68 $ 0.24 $ 2.10 $ 5.15 ________________________

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Apr. 28, 2017	Apr. 27, 2017
Property, Plant and Equipment [Line Items]
Proved properties	$ 935,025	$ 719,198	$ 500,461	$ 2,531,834
Unproved properties	143,020	154,352	178,460	163,781
Receivables from contracts with customers	43,714	$ 31,799	$ 24,876	$ 24,876
Gathering Assets
Property, Plant and Equipment [Line Items]
Proved properties	146,400
Wells in progress	1,300
Unproved properties	$ 100
PP&E useful life	30 years
Minimum
Property, Plant and Equipment [Line Items]
Receivable collection period	1 month
Minimum | Property, Plant and Equipment, Other Types
Property, Plant and Equipment [Line Items]
PP&E useful life	3 years
Maximum
Property, Plant and Equipment [Line Items]
Receivable collection period	2 months
Maximum | Property, Plant and Equipment, Other Types
Property, Plant and Equipment [Line Items]
PP&E useful life	25 years

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Disaggregation of Revenue (Details) - USD ($) $ in Thousands

3 Months Ended

4 Months Ended

8 Months Ended

12 Months Ended

Dec. 31, 2019

Sep. 30, 2019

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Apr. 28, 2017

Dec. 31, 2017

Dec. 31, 2019

Dec. 31, 2018

Disaggregation of Revenue [Line Items]

Oil and gas sales

$ 79,667

$ 75,176

$ 85,783

$ 72,594

$ 66,213

$ 74,380

$ 71,872

$ 64,193

$ 68,589

$ 123,535

$ 313,220

$ 276,657

Crude oil sales

Disaggregation of Revenue [Line Items]

Oil and gas sales

268,865

228,661

Natural gas sales

Disaggregation of Revenue [Line Items]

Oil and gas sales

28,296

22,369

Natural gas liquids sales

Disaggregation of Revenue [Line Items]

Oil and gas sales

$ 16,059

$ 25,627

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations of Credit Risk (Details) - Sales - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
NGL Crude Logistics
Concentration Risk [Line Items]
Percent of oil and natural gas sales	82.00%	66.00%	44.00%
Lion Oil Trading And Transportation Inc
Concentration Risk [Line Items]
Percent of oil and natural gas sales	0.00%	8.00%	18.00%
Duke Energy Field Services
Concentration Risk [Line Items]
Percent of oil and natural gas sales	6.00%	8.00%	16.00%

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 28, 2017	Apr. 27, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Cash and cash equivalents	$ 11,008	$ 12,916	$ 12,711	$ 70,183	$ 96,286
Restricted cash included in other noncurrent assets(1)	87	86	71	64
Total cash, cash equivalents and restricted cash as shown in the statements of cash flows	$ 11,095	$ 13,002	$ 12,782	$ 70,247		$ 80,747

LEASES - Narrative (Details)

LEASES - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Right-of-use assets	$ 38,562,000	$ 32,800,000
Total lease liability	39,230,000	33,600,000
Deferred rent		800,000
Right-of-use assets, increase in period	16,600,000
Lease liability, increase in period	$ 16,600,000
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative impact to retained earnings		$ 0

LEASES - Assets and Liabilities

LEASES - Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Property Subject to or Available for Operating Lease [Line Items]
Right-of-use assets	$ 38,562	$ 32,800
Total lease liability	39,230	$ 33,600
Field equipment
Property Subject to or Available for Operating Lease [Line Items]
Right-of-use assets	35,057
Total lease liability	35,075
Corporate leases
Property Subject to or Available for Operating Lease [Line Items]
Right-of-use assets	2,462
Total lease liability	3,129
Vehicles
Property Subject to or Available for Operating Lease [Line Items]
Right-of-use assets	1,043
Total lease liability	$ 1,026

LEASES - Lease Cost (Details)

LEASES - Lease Cost (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating lease cost	$ 11,330
Short-term lease cost	8,169
Variable lease cost	259
Sublease Income	(348)
Total lease cost	19,410
Office rent expense	$ 1,100

LEASES - Weighted-Average and D

LEASES - Weighted-Average and Discount Rate Information (Details)	Dec. 31, 2019
Leases [Abstract]
Weighted-average lease term (years)	3 years 6 months
Weighted-average discount rate	4.33%

LEASES - Lease Maturities (Deta

LEASES - Lease Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Leases [Abstract]
2020	$ 13,113
2021	11,823
2022	10,028
2023	5,721
2024	1,559
Thereafter	0
Total lease payments	42,244
Less: imputed interest	(3,014)
Total lease liability	$ 39,230	$ 33,600

LEASES - Lease Maturities, Befo

LEASES - Lease Maturities, Before Topic 842 (Details) $ in Thousands	Dec. 31, 2018USD ($)
Leases [Abstract]
2019	$ 1,256
2020	1,351
2021	1,401
2022	234
2023	0
Thereafter	0
Total	$ 4,242

DIVESTITURES - Narrative (Detai

DIVESTITURES - Narrative (Details) - USD ($) $ in Thousands	Aug. 06, 2018	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of properties, net of purchase price adjustments		$ 0	$ 0	$ 1,177	$ 27,324
Mid-Continent Region
Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses	$ 103,500
Gain on sale of properties, net of purchase price adjustments	$ 28,600

OTHER NONCURRENT ASSETS - Sched

OTHER NONCURRENT ASSETS - Schedule of Other Noncurrent Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 28, 2017	Apr. 27, 2017
Other Assets [Abstract]
Operating bonds	$ 1,638	$ 2,713
Deferred financing costs	1,443	1,710
AMT credit refund	376	376
Restricted cash	87	86	$ 71	$ 64
Other noncurrent assets	$ 3,544	$ 4,885		$ 2,738	$ 2,738

ACCOUNTS PAYABLE AND ACCRUED _3

ACCOUNTS PAYABLE AND ACCRUED EXPENSES - Schedule of Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Apr. 28, 2017	Apr. 27, 2017
Accounts payable and accrued expenses contain the following:
Drilling and completion costs	$ 3,248	$ 33,602
Accounts payable trade	17,117	11,532
Accrued general and administrative cost	5,620	12,728
Lease operating expense	2,187	2,183
Accrued interest	692	241
Accrued oil and gas hedging	453	0
Production and ad valorem taxes and other	28,321	19,104
Total accounts payable and accrued expenses	$ 57,638	$ 79,390	$ 38,934	$ 72,635

LONG-TERM DEBT - Narrative (Det

LONG-TERM DEBT - Narrative (Details)	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017	Feb. 27, 2020USD ($)	Nov. 26, 2019USD ($)
LONG-TERM DEBT
Interest expense	$ 5,700,000	$ 800,000	$ 5,100,000	$ 2,600,000
Capitalized interest	0	$ 0	(2,400,000)	0
LIBOR | Minimum
LONG-TERM DEBT
Basis spread on variable rate					3.00%
LIBOR | Maximum
LONG-TERM DEBT
Basis spread on variable rate					4.00%
Base Rate | Minimum
LONG-TERM DEBT
Basis spread on variable rate					2.00%
Base Rate | Maximum
LONG-TERM DEBT
Basis spread on variable rate					3.00%
Revolver
LONG-TERM DEBT
Maximum borrowing capacity			750,000,000
Borrowing base amount	$ 191,700,000		$ 350,000,000				$ 375,000,000
Maximum senior secured debt to trailing twelve month EBITDAX covenant			4		3.50
Minimum current ratio covenant			1		1
Outstanding debt			$ 80,000,000	50,000,000
Deferred financing costs			2,500,000
Minimum trailing twelve month interest to trailing twelve month EBITDAX coverage covenant					2.50
Revolver | Subsequent Event
LONG-TERM DEBT
Outstanding debt						$ 80,000,000
Revolver | Other Noncurrent Assets
LONG-TERM DEBT
Deferred financing costs			1,400,000	1,700,000
Revolver | Prepaid Expenses and Other Current Assets
LONG-TERM DEBT
Deferred financing costs			$ 500,000	$ 500,000
Revolver | LIBOR | Minimum
LONG-TERM DEBT
Basis spread on variable rate			0.00%
Revolver | Eurodollar | Minimum
LONG-TERM DEBT
Basis spread on variable rate			1.75%
Revolver | Eurodollar | Maximum
LONG-TERM DEBT
Basis spread on variable rate			2.75%
Revolver | Reference Rate | Minimum
LONG-TERM DEBT
Basis spread on variable rate			0.75%
Revolver | Reference Rate | Maximum
LONG-TERM DEBT
Basis spread on variable rate			1.75%

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Narrative (Details) $ in Thousands

Oct. 03, 2017

Apr. 28, 2017

Sep. 30, 2018USD ($)

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2019USD ($)claimbbl

Dec. 31, 2018bbl

Dec. 31, 2017bbl

Dec. 31, 2019USD ($)

Dec. 31, 2019USD ($)

Loss Contingencies [Line Items]

Number of claims | claim

0

Reimbursement of ad valorem taxes

$ 7,400

Potential extended term

3 years

Natural gas liquids sales

Loss Contingencies [Line Items]

Term of commitment period

7 years

Periodic deficiency payment, incremental payment period

6 months

Aggregate financial commitment fee over remainder of contract

$ 80,999

$ 80,999

$ 80,999

Extension term notification period, prior to expiration date

12 months

Natural gas liquids sales | Crude Oil

Loss Contingencies [Line Items]

Minimum commitment of crude oil (barrels) | bbl

10,100

0

Minimum volume increase

41.00%

Maximum volume requirement (barrels) | bbl

16,000

Natural gas liquids sales | Scenario, Forecast | Crude Oil

Loss Contingencies [Line Items]

Minimum volume annual increase

3.00%

3.00%

3.00%

3.00%

Severance and Ad Valorem Taxes

Loss Contingencies [Line Items]

Reimbursement of ad valorem taxes

$ 5,100

CDPHE

Loss Contingencies [Line Items]

COC costs incurred

$ 2,100

Termination period

4 years

COMMITMENT AND CONTINGENCIES -

COMMITMENT AND CONTINGENCIES - Schedule of Purchase Obligations (Details) - Natural gas liquids sales $ in Thousands	Dec. 31, 2019USD ($)
Long-term Purchase Commitment [Line Items]
2020	$ 22,474
2021	23,316
2022	24,009
2023	11,200
2024 and thereafter	0
Total	$ 80,999

STOCK-BASED COMPENSATION - Narr

STOCK-BASED COMPENSATION - Narrative (Details) - USD ($)	1 Months Ended	4 Months Ended	8 Months Ended	12 Months Ended
	Jun. 30, 2017	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance under LTIP (in shares)		2,467,430
Stock-based compensation expense		$ 2,116,000	$ 11,630,000	$ 6,886,000	$ 7,156,000
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)					170,613
Fair value of units granted				4,600,000
Excess tax benefit for vested restricted stock			0	$ 0	$ 0
Restricted stock units | LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				258,785
Vesting period						3 years
Stock-based compensation expense			7,913,000	$ 5,518,000	5,140,000
Restricted stock units | LTIP | Tranche 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent				33.00%
Restricted stock units | LTIP | Tranche 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent				33.00%
Restricted stock units | LTIP | Tranche 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent				33.00%
Restricted stock units | LTIP | Non-executive Board Members
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	63,894
Fair value of units granted	$ 2,300,000		13,400,000	$ 5,900,000	$ 6,200,000
Vesting period						3 years
Restricted stock units | LTIP | Non-executive Board Members | Tranche 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent				33.00%
Restricted stock units | LTIP | Non-executive Board Members | Tranche 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent				33.00%
Restricted stock units | LTIP | Non-executive Board Members | Tranche 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent				33.00%
Restricted stock units | 2011 Long Term Incentive Plan | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		1,267,000
Stock options | LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period				10 years
Granted (shares)				0	0
Fair value of options granted			6,800,000
Stock-based compensation expense			3,717,000	$ 604,000	$ 1,395,000
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted					1,800,000
Performance stock units | LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				102,379
Fair value of units granted				$ 2,300,000
Vesting period						3 years
Number of trading days				30 days
Stock-based compensation expense			$ 0	$ 764,000	$ 621,000
Performance stock units | 2011 Long Term Incentive Plan | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		451,000
Plan units | 2011 Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		$ 398,000
Plan units | 2011 Long Term Incentive Plan | Tranche 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent		33.33%
Plan units | 2011 Long Term Incentive Plan | Tranche 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent		33.33%
Plan units | 2011 Long Term Incentive Plan | Tranche 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent		33.33%
Minimum | Performance stock units | LTIP | Non-executive Board Members
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company		0		0
Maximum | Performance stock units | LTIP | Non-executive Board Members
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company		2		2

STOCK-BASED COMPENSATION - Sche

STOCK-BASED COMPENSATION - Schedule of Expenses (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 2,116	$ 11,630	$ 6,886	$ 7,156
Restricted stock units | LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		7,913	5,518	5,140
Restricted stock units | 2011 Long Term Incentive Plan | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	1,267
Performance stock units | LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		0	764	621
Performance stock units | 2011 Long Term Incentive Plan | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	451
Stock options | LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense		$ 3,717	$ 604	$ 1,395
Plan units | 2011 Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 398

STOCK-BASED COMPENSATION - Unre

STOCK-BASED COMPENSATION - Unrecognized Compensation Expense (Details) $ in Thousands	Dec. 31, 2019USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based payment, expense	$ 11,477
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based payment, expense	9,589
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based payment, expense	1,714
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based payment, expense	$ 174

STOCK-BASED COMPENSATION - Acti

STOCK-BASED COMPENSATION - Activity of Non-Option Awards (Details)	1 Months Ended	4 Months Ended	12 Months Ended
	Jun. 30, 2017shares	Apr. 28, 2017	Dec. 31, 2019$ / sharesshares	Dec. 31, 2018$ / sharesshares
Restricted stock units
Restricted Stock Units
Granted (in shares)				170,613
LTIP | Restricted stock units
Restricted Stock Units
Non-vested at beginning of year (in shares)			480,835
Granted (in shares)			258,785
Vested (in shares)			(143,761)
Forfeited (in shares)			(38,042)
Non-vested at end of year (in shares)			557,817	480,835
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share) | $ / shares			$ 30.83
Granted (in dollars per share) | $ / shares			22.70
Vested (in dollars per share) | $ / shares			23.12
Forfeited (in dollars per share) | $ / shares			25.92
Non-vested at end of year (in dollars per share) | $ / shares			$ 26.95	$ 30.83
LTIP | Restricted stock units | Non-executive Board Members
Restricted Stock Units
Granted (in shares)	63,894
LTIP | Performance stock units
Restricted Stock Units
Non-vested at beginning of year (in shares)			53,689
Granted (in shares)			102,379
Vested (in shares)			(2,598)
Forfeited (in shares)			0
Non-vested at end of year (in shares)			153,470	53,689
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share) | $ / shares			$ 29.92
Granted (in dollars per share) | $ / shares			22.15
Vested (in dollars per share) | $ / shares			23.55
Forfeited (in dollars per share) | $ / shares			0
Non-vested at end of year (in dollars per share) | $ / shares			$ 24.74	$ 29.92
LTIP | Performance stock units | Minimum | Non-executive Board Members
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company		0	0
LTIP | Performance stock units | Maximum | Non-executive Board Members
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company		2	2

STOCK-BASED COMPENSATION - Valu

STOCK-BASED COMPENSATION - Valuation assumptions (Details) - LTIP	8 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)		3 years	3 years
Risk-free interest rate		2.26%	2.76%
Expected daily volatility		2.60%	2.60%
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)	6 years
Risk-free interest rate	1.96%
Expected daily volatility	52.10%
Expected dividends	0.00%

STOCK-BASED COMPENSATION - Ac_2

STOCK-BASED COMPENSATION - Activity of stock options (Details) - LTIP - Stock options - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Stock Options
Outstanding at beginning of period (shares)	132,809
Granted (shares)	0	0
Exercised (shares)	0
Forfeited (shares)	(32,095)
Outstanding at end of period (shares)	100,714	132,809
Outstanding and exercisable at end of period (shares)	70,077
Weighted- Average Exercise Price
Outstanding at beginning of period (in dollars per share)	$ 34.36
Granted (in dollars per share)	0
Exercised (in dollars per share)	0
Forfeited (in dollars per share)	34.36
Outstanding at end of period (in dollars per share)	34.36	$ 34.36
Outstanding and exercisable at end of period (in dollars per share)	$ 34.36
Weighted-Average Remaining Contractual Term (in years)
Outstanding, end of year	6 years 8 months 12 days
Options outstanding and exercisable	6 years 4 months 24 days
Outstanding, end of year, Aggregate Intrinsic Value	$ 0
Options outstanding and exercisable, Aggregate Intrinsic Value	$ 0

INCOME TAXES - Provision For In

INCOME TAXES - Provision For Income Taxes (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Federal	$ 0	$ 376	$ 0	$ 0
State	0	0	0	0
Deferred tax benefit	0	0	0	0
Total income tax benefit	$ 0	$ 376	$ 0	$ 0

INCOME TAXES - Deferred Tax Ass

INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Deferred tax liabilities:
Oil and gas properties	$ 79,187	$ 52,006
Derivative instruments	0	8,527
Right-of-use assets	9,508
Total deferred tax liabilities	88,695	60,533
Deferred tax assets:
Federal and state tax net operating loss carryforward	139,546	137,567
Derivative instruments	1,062	0
Reclamation costs	6,881	7,251
Stock compensation	2,209	1,635
Accrued compensation	0	1,308
Inventory	1,577	1,577
Lease liability	9,673	0
Other long-term assets	300	271
Total deferred tax assets	161,248	149,609
Less: Valuation allowance	72,553	89,076	$ 137,000
Total deferred tax assets after valuation allowance	88,695	60,533
Total non-current net deferred tax asset (liability)	$ 0	$ 0

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($)	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Net operating loss carryovers for federal income tax purposes			$ 582,800,000	$ 577,600,000
Net operating loss carryovers for federal income tax purposes, not benefited for financial statement purposes		$ 470,300,000		112,500,000
Valuation allowance		137,000,000	72,553,000	89,076,000
Decrease in valuation allowance	$ 45,634,000	73,628,000	(16,523,000)	(47,884,000)
Current income tax benefit	$ 0	376,000	0	0
Unrecognized tax benefits		$ 0	$ 0	$ 0

INCOME TAXES - Effective Income

INCOME TAXES - Effective Income Tax Reconciliation (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Federal statutory tax (expense) benefit by applying the statutory rate	$ (931)	$ 1,889	$ 14,084	$ 35,319
State tax expense net of federal benefit	(85)	172	2,537	6,556
Prior year true-up	(7,572)	0	(579)	(458)
Stock compensation	(1,773)	0	197	854
Permanent differences	(35,273)	(715)	128	61
Rate change	0	(73,956)	0	(421)
NOL Adjustment	0	0	0	5,973
Other	0	(642)	156	0
Valuation allowance	45,634	73,628	(16,523)	(47,884)
Total income tax benefit	$ 0	$ 376	$ 0	$ 0

ASSET RETIREMENT OBLIGATIONS -

ASSET RETIREMENT OBLIGATIONS - Schedule of Roll-Forward Activity (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Change in asset retirement obligations
Balance, beginning of year	$ 29,405	$ 38,262
Additional liabilities incurred	228	373
Accretion expense	1,467	1,831
Liabilities settled	(2,443)	(1,627)
Revisions to estimate	(749)	1,490
Sold properties	0	(10,924)
Balance, end of year	$ 27,908	$ 29,405

FAIR VALUE MEASUREMENTS - Sched

FAIR VALUE MEASUREMENTS - Schedule of Non-financial Assets and Liabilities (Details) - Estimate of Fair Value Measurement - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Level 1
Financial assets and liabilities accounted for at fair value
Derivative assets	$ 0	$ 0
Derivative liabilities	0	0
Asset retirement obligations	0	0
Level 2
Financial assets and liabilities accounted for at fair value
Derivative assets	3,005	38,272
Derivative liabilities	7,311	183
Asset retirement obligations	0	0
Level 3
Financial assets and liabilities accounted for at fair value
Derivative assets	0	0
Derivative liabilities	0	0
Asset retirement obligations	$ (749)	$ 1,490

FAIR VALUE MEASUREMENTS - Narra

FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Derivatives measured at fair value
Proved oil and gas property impairments	$ 0	$ 0
Annual amortization	11,200,000	5,300,000
Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Asset retirement obligations for oil and gas properties, revisions of estimates	$ (749,000)	$ 1,490,000

DERIVATIVES - Narrative (Detail

DERIVATIVES - Narrative (Details)	Dec. 31, 2019derivative
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of derivative instruments qualified for hedging instruments	0

DERIVATIVES - Commodity Derivat

DERIVATIVES - Commodity Derivatives (Details) - Scenario, Forecast	3 Months Ended
	Dec. 31, 2021$ / MMBTUbbl	Sep. 30, 2021$ / bbl$ / MMBTUbbl	Jun. 30, 2021$ / bblbbl	Mar. 31, 2021$ / bblbbl	Dec. 31, 2020MMBTU$ / bbl$ / MMBTUbbl	Sep. 30, 2020MMBTU$ / bbl$ / MMBTUbbl	Jun. 30, 2020MMBTU$ / bbl$ / MMBTUbbl	Mar. 31, 2020MMBTU$ / MMBTU$ / bblbbl
Crude Oil (NYMEX WTI) | Cashless Collar
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl			500	2,000	6,000	6,000	7,500	5,000
Crude Oil (NYMEX WTI) | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl			52	50.50	52.67	52.67	54	55
Crude Oil (NYMEX WTI) | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl			55	55.19	58.40	58.40	61.01	62.88
Crude Oil (NYMEX WTI) | Swap
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl		1,000	2,000	3,500	3,000	3,000	1,500	4,500
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl		54.87	53.35	53.89	53.60	53.60	54.98	60.69
Crude Oil (NYMEX WTI) | Subsequent Event | Cashless Collar
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl			500	2,000	6,000	6,000	7,500	5,000
Crude Oil (NYMEX WTI) | Subsequent Event | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl			52	50.50	52.67	52.67	54	55
Crude Oil (NYMEX WTI) | Subsequent Event | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl			55	55.19	58.40	58.40	61.01	62.88
Crude Oil (NYMEX WTI) | Subsequent Event | Swap
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl	1,000	2,500	4,000	5,000	3,500	3,500	1,500	4,500
Weighted Average Price (in dollars per barrel and MMBtu, respectively)	55.20	54.45	54.13	54.48	54.12	54.12	54.98	60.69
Natural Gas (NYMEX Henry Hub) | Swap
Derivative [Line Items]
Natural Gas, notional amount (in MMBtu per day) | MMBTU							10,000	20,000
Weighted Average Price (in dollars per MMBtu) | $ / MMBTU							2.61	2.63
Natural Gas (NYMEX Henry Hub) | Subsequent Event | Swap
Derivative [Line Items]
Natural Gas, notional amount (in MMBtu per day) | MMBTU							10,000	20,000
Weighted Average Price (in dollars per MMBtu) | $ / MMBTU							2.61	2.63
Natural Gas (CIG Basis) | Swap
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / MMBTU					0.56	0.56	0.56	0.56
Natural Gas, notional amount (in MMBtu per day) | MMBTU					20,000	20,000	20,000	20,000
Natural Gas (CIG Basis) | Subsequent Event | Swap
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / MMBTU					0.54	0.54	0.54	0.55
Natural Gas, notional amount (in MMBtu per day) | MMBTU					30,000	30,000	30,000	26,593
Natural Gas (CIG) | Swap
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / MMBTU								2.40
Natural Gas, notional amount (in MMBtu per day) | MMBTU								2,500
Natural Gas (CIG) | Subsequent Event | Swap
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / MMBTU								2.40
Natural Gas, notional amount (in MMBtu per day) | MMBTU								2,500

DERIVATIVES - Derivative Positi

DERIVATIVES - Derivative Positions (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivatives measured at fair value
Total derivative assets (liabilities), net	$ (4,306)	$ 38,089
Commodity contracts - current | Commodity contracts - current
Derivatives measured at fair value
Derivative Assets	2,884	34,408
Commodity contracts - current | Commodity contracts - noncurrent
Derivatives measured at fair value
Derivative Assets	121	3,864
Commodity contracts - current | Commodity contracts - current
Derivatives measured at fair value
Derivative Liabilities	(6,390)	(183)
Commodity contracts - current | Commodity contracts - long-term
Derivatives measured at fair value
Derivative Liabilities	$ (921)	$ 0

DERIVATIVES - Derivative Gains

DERIVATIVES - Derivative Gains (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Components of the derivative gain (loss)
Total derivative gain (loss)	$ 0	$ (15,365)	$ (37,145)	$ 30,271
Commodity derivative
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	0	(1,464)	1,691	(18,160)
Change in fair value gain (loss)	0	(13,901)	(38,836)	48,431
Total derivative gain (loss)	0	(15,365)	(37,145)	30,271
Commodity derivative | Oil contracts
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	0	(1,486)	1,185	(17,700)
Commodity derivative | Gas contracts
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	$ 0	$ 22	$ 506	$ (460)

EARNINGS PER SHARE - Narrative

EARNINGS PER SHARE - Narrative (Details)	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017$ / sharesshares	Dec. 31, 2017shares	Dec. 31, 2019shares	Dec. 31, 2018shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Antidilutive securities excluded from EPS calculation (in shares) | shares	258,126	375,123	269,208	170,755
Plan units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share price cap (in dollars per share) | $ / shares	$ 26
LTIP | Minimum | Non-executive Board Members | Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company	0		0
LTIP | Maximum | Non-executive Board Members | Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company	2		2

EARNINGS PER SHARE - Schedule o

EARNINGS PER SHARE - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Net income:
Net income (loss)	$ (2,855)	$ 35,893	$ 41,022	$ (6,993)	$ 106,094	$ 43,363	$ 4,859	$ 13,870	$ 2,660	$ (5,020)	$ 67,067	$ 168,186
Less: undistributed income to unvested restricted stock									120
Undistributed income to common shareholders									$ 2,540
Basic net income per common share (in dollars per share)	$ (0.14)	$ 1.74	$ 1.99	$ (0.34)	$ 5.16	$ 2.11	$ 0.24	$ 0.68	$ 0.05	$ (0.25)	$ 3.25	$ 8.20
Diluted net income per common share (in dollars per share)	$ (0.14)	$ 1.74	$ 1.99	$ (0.34)	$ 5.15	$ 2.10	$ 0.24	$ 0.68	$ 0.05	$ (0.25)	$ 3.24	$ 8.16
Weighted-average shares outstanding - basic (in shares)									49,559	20,427	20,612	20,507
Add: dilutive effect of contingent PSUs (in shares)									1,412	0	69	96
Weighted-average shares outstanding - diluted (in shares)									50,971	20,427	20,681	20,603

CHAPTER 11 PROCEEDINGS AND EM_2

CHAPTER 11 PROCEEDINGS AND EMERGENCE - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	Apr. 28, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 27, 2017	Feb. 01, 2017	Dec. 23, 2016
Fresh-Start Adjustment [Line Items]
Holders percentage under settlement agreement							51.00%
Term of warrants	3 years
Sources of funding	$ 207,500
Silo contract settlement payment	7,228
Payment and funding of escrow account related to professional fees	17,193
Payment of professional fees and other	13,831
Cash and cash equivalents	$ 70,183	$ 11,008	$ 12,916	$ 12,711	$ 96,286
Assurance deposit maintained						$ 5,000
Crude oil revenue receivable						$ 8,700
LTIP
Fresh-Start Adjustment [Line Items]
Shares reserved for issuance under LTIP (in shares)	2,467,430
STIP
Fresh-Start Adjustment [Line Items]
Payment of remaining incentive plan	$ 1,600
Reorganization Warrants
Fresh-Start Adjustment [Line Items]
Sources of funding	$ 4,081
Warrants issued (in shares)	1,650,510
Reorganization Warrants | Strike Price
Fresh-Start Adjustment [Line Items]
Price per warrant (in dollars per share)	$ 71.23
Proceeds from ad hoc equity committee
Fresh-Start Adjustment [Line Items]
Sources of funding	$ 7,500
Rights Offering
Fresh-Start Adjustment [Line Items]
Shares issued to holders (in shares)	10,071,378
Sources of funding	$ 200,000
Common Stock
Fresh-Start Adjustment [Line Items]
Shares issued to holders (in shares)	803,083
Percentage of shares issued	3.90%
Sources of funding	$ 26,828
Common Stock | Reorganization Warrants
Fresh-Start Adjustment [Line Items]
Percentage of shares issued	7.50%
Common Stock | Proceeds from ad hoc equity committee
Fresh-Start Adjustment [Line Items]
Percentage of shares issued	1.75%
Senior Notes
Fresh-Start Adjustment [Line Items]
Liabilities subject to compromise	$ 800,000
Accrued and unpaid pre-petition interest	14,879
Prepayment premiums	$ 51,185
Percentage of shares exchanged	46.60%
Shares issued to holders (in shares)	9,481,610
Revolver
Fresh-Start Adjustment [Line Items]
Payment on revolving credit facility (principal, interest and fees)	$ 193,729
5.75% Senior Notes | Senior Notes
Fresh-Start Adjustment [Line Items]
Interest rate (as a percent)							5.75%
6.75% Senior Notes | Senior Notes
Fresh-Start Adjustment [Line Items]
Interest rate (as a percent)							6.75%

FRESH-START ACCOUNTING - Narrat

FRESH-START ACCOUNTING - Narrative (Details) $ / shares in Units, $ in Thousands	Apr. 28, 2017USD ($)$ / sharesshares	Dec. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)shares	Apr. 27, 2017USD ($)	Dec. 31, 2016shares
LONG-TERM DEBT
Percentage of voting shares upon emergence (less than)	50.00%
Enterprise value	$ 642,999
Fair value of proved reserves	397,300
Fair value of probable reserves	146,800
Fair value of possible reserves	31,700
Net asset replacement cost, fair value	103,100
Asset retirement obligation	29,061	$ 27,908	$ 29,405	$ 38,262	$ 31,660
Successor warrants	$ 4,081
Term of warrants	3 years
Common Stock
LONG-TERM DEBT
Shares outstanding (in shares) | shares	50,105,217	20,643,738	20,543,940	20,453,549		49,660,683
Common Stock | Cancellation of Predecessor equity
LONG-TERM DEBT
Shares outstanding (in shares) | shares	20,356,071
Reorganization Warrants
LONG-TERM DEBT
Warrants issued (in shares) | shares	1,650,510
Successor warrants	$ 4,081
Minimum
LONG-TERM DEBT
Enterprise value	570,000
Maximum
LONG-TERM DEBT
Enterprise value	$ 680,000
Discount Rate | Discounted Cash Flow Analysis
LONG-TERM DEBT
Measurement input	0.110
Volatility | Reorganization Warrants
LONG-TERM DEBT
Measurement input	0.40
Risk Free Interest Rate | Reorganization Warrants
LONG-TERM DEBT
Measurement input	0.0144
Share Price | Reorganization Warrants
LONG-TERM DEBT
Measurement input | $ / shares	34.36
Strike Price | Reorganization Warrants
LONG-TERM DEBT
Price per warrant (in dollars per share) | $ / shares	$ 71.23

FRESH-START ACCOUNTING - Enterp

FRESH-START ACCOUNTING - Enterprise Value to Fair Value of Stock (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 28, 2017	Apr. 27, 2017
Fresh-Start Adjustment [Line Items]
Enterprise Value				$ 642,999
Plus: Cash and cash equivalents	$ 11,008	$ 12,916	$ 12,711	70,183	$ 96,286
Less: Interest bearing liabilities				(29,061)
Less: Fair value of warrants				(4,081)
Fair value of Successor common stock				$ 680,040
Shares outstanding (in shares)	20,543,940	20,543,940		20,356,000
Per share value (in dollars per share)				$ 33.41
Reorganization Warrants
Fresh-Start Adjustment [Line Items]
Less: Fair value of warrants				$ (4,081)

FRESH-START ACCOUNTING - Ente_2

FRESH-START ACCOUNTING - Enterprise Value to Reorganization Value (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 28, 2017	Apr. 27, 2017
Reorganizations [Abstract]
Enterprise Value				$ 642,999
Plus: Cash and cash equivalents	$ 11,008	$ 12,916	$ 12,711	70,183	$ 96,286
Plus: Working capital liabilities				63,871
Plus: Other long-term liabilities				17,919
Reorganization value of Successor assets				$ 794,972

FRESH-START ACCOUNTING - Succes

FRESH-START ACCOUNTING - Successor Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 28, 2017	Apr. 27, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 11,008	$ 12,916	$ 12,711	$ 70,183	$ 96,286
Accounts receivable:
Oil and gas sales	43,714	31,799		24,876	24,876
Joint interest and other	38,136	47,577		3,028	3,028
Prepaid expenses and other	7,048	4,633		4,952	4,952
Inventory of oilfield equipment	7,726	3,478		4,218	4,218
Total current assets	110,516	134,811		107,257	133,360
Property and equipment (successful efforts method):
Proved properties	935,025	719,198		500,461	2,531,834
Less: accumulated depreciation, depletion and amortization	(126,614)	(52,842)		0	(1,720,736)
Total proved properties, net	808,411	666,356		500,461	811,098
Unproved properties	143,020	154,352		178,460	163,781
Wells in progress	98,750	93,617		0	18,002
Other property and equipment, net	3,394	3,649		6,056	6,056
Total property and equipment, net	1,053,575	917,974		684,977	998,937
Other noncurrent assets	3,544	4,885		2,738	2,738
Total assets	1,206,318	1,061,534		794,972	1,135,035
Current liabilities:
Accounts payable and accrued expenses	57,638	79,390		38,934	72,635
Oil and gas revenue distribution payable	29,021	19,903		24,937	24,937
Predecessor credit facility - current portion				0	191,667
Total current liabilities	104,739	99,476		63,871	289,239
Long-term liabilities:
Ad valorem taxes	28,520	18,740		17,919	17,919
Asset retirement obligations for oil and gas properties	27,908	29,405	38,262	29,061	31,660
Liabilities subject to compromise				873,292	873,292
Total liabilities	269,628	197,621		110,851	1,212,110
Stockholders' equity:
Common stock	4,284	4,286		204	49
Additional paid in capital	702,173	696,461		679,836	816,679
Successor warrants				4,081
Retained deficit	230,233	163,166		0	(893,803)
Total stockholders’ equity	936,690	863,913	$ 688,334	684,121	(77,075)	$ 19,061
Total liabilities and stockholders’ equity	$ 1,206,318	$ 1,061,534		794,972	$ 1,135,035
Fresh-Start Adjustments
Accounts receivable:
Total current assets				0
Property and equipment (successful efforts method):
Proved properties				(2,031,373)
Less: accumulated depreciation, depletion and amortization				1,720,736
Total proved properties, net				(310,637)
Unproved properties				14,679
Wells in progress				(18,002)
Total property and equipment, net				(313,960)
Total assets				(313,960)
Current liabilities:
Total current liabilities				0
Long-term liabilities:
Asset retirement obligations for oil and gas properties				(2,599)
Total liabilities				(2,599)
Stockholders' equity:
Common stock				(49)
Additional paid in capital				(816,679)
Retained deficit				505,367
Total stockholders’ equity				(311,361)
Total liabilities and stockholders’ equity				(313,960)
Reorganization Adjustments
Current Assets:
Cash and cash equivalents				(26,103)
Accounts receivable:
Total current assets				(26,103)
Property and equipment (successful efforts method):
Total proved properties, net				0
Total property and equipment, net				0
Total assets				(26,103)
Current liabilities:
Accounts payable and accrued expenses				(33,701)
Predecessor credit facility - current portion				(191,667)
Total current liabilities				(225,368)
Long-term liabilities:
Liabilities subject to compromise				(873,292)
Total liabilities				(1,098,660)
Stockholders' equity:
Common stock				204
Additional paid in capital				679,836
Successor warrants				4,081
Retained deficit				388,436
Total stockholders’ equity				1,072,557
Total liabilities and stockholders’ equity				$ (26,103)

FRESH-START ACCOUNTING - Source

FRESH-START ACCOUNTING - Sources, Uses and Transfers of Cash (Details) $ in Thousands	Apr. 28, 2017USD ($)
Sources:
Total sources	$ 207,500
Uses and transfers:
Payment and funding of escrow account related to professional fees	(17,193)
Payment of professional fees and other	(13,831)
Payment of Silo contract settlement and other	(7,228)
Payment of remaining 2016 STIP	(1,622)
Total uses and transfers	(233,603)
Total net sources, uses and transfers	(26,103)
Revolver
Uses and transfers:
Payment on predecessor credit facility (principal, interest and fees)	(193,729)
Rights Offering
Sources:
Total sources	200,000
Proceeds from ad hoc equity committee
Sources:
Total sources	$ 7,500

FRESH-START ACCOUNTING - Accoun

FRESH-START ACCOUNTING - Accounts Payable and Accrued Expenses Settled (Details) - USD ($) $ in Thousands	Apr. 28, 2017	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Accounts payable and accrued expenses:
Accrued 2016 STIP payment	$ (1,574)
Escrow account funding	(17,193)
Professional fees and other	(13,831)
Accrued unpaid interest on predecessor credit facility	(1,103)
Total accounts payable and accrued expenses settled	$ (33,701)	$ 5,880	$ 8,470	$ (28,320)	$ (19,953)

FRESH-START ACCOUNTING - Liabil

FRESH-START ACCOUNTING - Liabilities Subject to Compromise (Details) - USD ($) $ in Thousands	Apr. 28, 2017	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Apr. 27, 2017	Dec. 31, 2016
Fresh-Start Adjustment [Line Items]
Silo contract settlement accrual	$ 7,228	$ 7,228
Total liabilities subject to compromise of the predecessor	873,292	873,292				$ 873,292
Rights offering	207,500
Fair value of equity issued to creditors, excluding equity issued to existing equity holders	(653,212)
Payment of Silo contract settlement	(7,228)
Gain on settlement of liabilities subject to compromise	412,852
Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP	(1,007)
Total reorganization items at emergence	411,845	$ 52,968	$ 0	$ 0	$ 0
Total reorganization adjustments to retained deficit	388,436
Common Stock
Fresh-Start Adjustment [Line Items]
Rights offering	$ 26,828
Shares outstanding (in shares)	50,105,217	50,105,217	20,453,549	20,643,738	20,543,940		49,660,683
Reorganization Warrants
Fresh-Start Adjustment [Line Items]
Rights offering	$ 4,081
Warrants issued (in shares)	1,650,510	1,650,510
Rights Offering
Fresh-Start Adjustment [Line Items]
Rights offering	$ 200,000
Proceeds from ad hoc equity committee
Fresh-Start Adjustment [Line Items]
Rights offering	$ 7,500
Cancellation of Predecessor equity | Common Stock
Fresh-Start Adjustment [Line Items]
Shares outstanding (in shares)	20,356,071	20,356,071
Senior Notes
Fresh-Start Adjustment [Line Items]
Senior Notes	$ 800,000	$ 800,000
Accrued interest on Senior Notes (pre-petition)	14,879	14,879
Make-whole payment on Senior Notes	$ 51,185	$ 51,185

FRESH-START ACCOUNTING - Reorga

FRESH-START ACCOUNTING - Reorganization items (Details) - USD ($) $ in Thousands	Apr. 28, 2017	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Reorganizations [Abstract]
Gain on settlement of liabilities subject to compromise	$ 412,852
Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP	(1,007)
Fresh-start valuation adjustments	(311,361)
Legal and professional fees and expenses	(34,335)
Write-off of debt issuance and premium costs	(6,156)
Make-whole payment on Senior Notes	(51,185)
Total reorganization items, net	$ 8,808	$ 8,808	$ 0	$ 0	$ 0

DISCLOSURES ABOUT OIL AND GAS_3

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Costs Incurred in Oil and Natural Gas Producing Activities (Details) - USD ($)	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
Acquisition	$ 445,000	$ 5,383,000	$ 12,901,000	$ 2,861,000
Development	10,780,000	106,449,000	209,535,000	304,197,000
Exploration	769,000	3,671,000	796,000	294,000
Total	11,994,000	115,503,000	223,232,000	307,352,000
Acquisition costs for unproved properties	400,000	5,400,000	4,200,000	2,500,000
Proved property acquisitions			8,700,000	400,000
Workover costs charged to lease operating expense	1,800,000	4,300,000	1,400,000	5,600,000
Increase (decrease) in ARO	$ 3,100,000	$ 8,300,000	$ (900,000)	$ (9,000,000)

DISCLOSURES ABOUT OIL AND GAS_4

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Change in Quantities of Proved Oil, Natural Gas Liquids, and Natural Gas Reserves (Details) bbl in Thousands, Mcf in Thousands	12 Months Ended
	Dec. 31, 2019Boe$ / bbl$ / MMBTUbblMcf	Dec. 31, 2018Boe$ / bbl$ / MMBTUbblMcf	Dec. 31, 2017Boe$ / bbl$ / MMBTUbblMcf	Dec. 31, 2016$ / bbl$ / MMBTUbblMcf
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | Boe		6,000,000	1,500,000
Revisions to previous estimates - increase (decrease) | Boe		2,300,000	5,400,000
Proved reserves demoted to non-proved
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | Boe	(8,700,000)	(2,500,000)	(7,600,000)
Engineering Revisions
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | Boe		2,200,000
Cost estimates
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | Boe		1,500,000	1,700,000
Other engineering revisions
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | Boe			2,000,000
PUD Demotions
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | Boe			(7,600,000)
Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | Boe	6,600,000
Revisions to previous estimates - increase (decrease) | Boe	(1,400,000)		1,400,000
Wattenberg Field, Rocky Mountain Region | Engineering Revisions
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | Boe	(8,100,000)
Horizontal development | Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Extensions and discoveries | Boe	15,400,000	28,800,000	15,500,000
Oil contracts
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period	64,354	52,928	50,096
Extensions, discoveries and infills	8,825	18,390	8,470
Production	(5,136)	(3,841)	(3,081)
Sales of minerals in place	(52)	(6,236)
Removed from capital program	(4,926)	(1,442)
Purchases of minerals in place	303
Revisions to previous estimates	1,045	4,555	(2,557)
Balance at the end of the period	64,413	64,354	52,928	50,096
Proved developed reserves	25,397	23,725	25,785
Proved undeveloped reserves	39,016	40,629	27,143
Oil and gas commodity price (in dollars per share) | $ / bbl		65.56	51.34	42.75
Oil contracts | Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Oil and gas commodity price (in dollars per share) | $ / bbl	55.85
Gas contracts
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period | Mcf	165,012	157,669	138,045
Extensions, discoveries and infills | Mcf	20,604	31,471	22,212
Production | Mcf	(11,967)	(8,567)	(9,010)
Sales of minerals in place | Mcf	(110)	(20,534)
Removed from capital program | Mcf	(11,508)	(3,246)
Purchases of minerals in place | Mcf	627
Revisions to previous estimates | Mcf	49,542	8,219	6,422
Balance at the end of the period | Mcf	212,200	165,012	157,669	138,045
Proved developed reserves | Mcf	105,840	79,630	92,718
Proved undeveloped reserves | Mcf	106,360	85,382	64,951
Oil and gas commodity price (in dollars per share) | $ / MMBTU		3.10	2.98	2.48
Gas contracts | Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Oil and gas commodity price (in dollars per share) | $ / MMBTU	2.58
Natural Gas Liquids
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period	24,930	22,815	17,547
Extensions, discoveries and infills	3,123	5,197	3,376
Production	(1,431)	(1,140)	(1,136)
Sales of minerals in place	(18)	(1,499)
Removed from capital program	(1,862)	(544)
Purchases of minerals in place	102
Revisions to previous estimates	(2,683)	101	3,028
Balance at the end of the period	22,161	24,930	22,815	17,547
Proved developed reserves	11,566	11,703	12,702
Proved undeveloped reserves	10,595	13,227	10,113

DISCLOSURES ABOUT OIL AND GAS_5

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
Future net cash flow discount rate				10.00%
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Future cash flows				$ 3,827,009	$ 4,742,180	$ 3,307,868
Future production costs				(1,029,140)	(1,585,032)	(1,490,091)
Future development costs				(850,327)	(925,640)	(622,344)
Future income tax expense				0	0	0
Future net cash flows				1,947,542	2,231,508	1,195,433
10% annual discount for estimated timing of cash flows				(1,089,395)	(1,276,528)	(596,935)
Standardized measure of discounted future net cash flows	$ 954,980	$ 598,498	$ 276,955	$ 858,147	$ 954,980	$ 598,498
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Beginning of period	954,980	598,498	276,955
Sale of oil and gas produced, net of production costs	(233,677)	(204,566)	(125,992)
Net changes in prices and production costs	(372,233)	365,952	282,112
Extensions, discoveries and improved recoveries	45,728	153,691	103,937
Development costs incurred	185,086	127,788	24,121
Changes in estimated development cost	81,358	(52,260)	2,122
Purchases of minerals in place	10,135	0	0
Sales of minerals in place	(309)	(115,742)	0
Revisions of previous quantity estimates	79,637	12,341	14,119
Net change in income taxes	0	0	0
Accretion of discount	95,498	59,850	27,696
Changes in production rates and other	11,944	9,428	(6,572)
End of period	$ 858,147	$ 954,980	$ 598,498

DISCLOSURES ABOUT OIL AND GAS_6

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Average Wellhead Prices Used in Determining Future Net Revenues (Details)	12 Months Ended
	Dec. 31, 2019$ / bbl$ / MMcf	Dec. 31, 2018$ / bbl$ / MMcf	Dec. 31, 2017$ / bbl$ / MMcf
Oil contracts
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas)	51.22	59.29	46.76
Gas contracts
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | $ / MMcf	1.44	2.28	2.45
Natural Gas Liquids
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas)	10.07	22.06	19.57

QUARTERLY FINANCIAL DATA (UNA_3

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Oil and gas sales	$ 79,667	$ 75,176	$ 85,783	$ 72,594	$ 66,213	$ 74,380	$ 71,872	$ 64,193	$ 68,589	$ 123,535	$ 313,220	$ 276,657
Operating profit	36,514	34,148	45,744	40,818	41,416	43,959	40,014	35,042
Net income (loss)	$ (2,855)	$ 35,893	$ 41,022	$ (6,993)	$ 106,094	$ 43,363	$ 4,859	$ 13,870	$ 2,660	$ (5,020)	$ 67,067	$ 168,186
Basic net income per common share (in dollars per share)	$ (0.14)	$ 1.74	$ 1.99	$ (0.34)	$ 5.16	$ 2.11	$ 0.24	$ 0.68	$ 0.05	$ (0.25)	$ 3.25	$ 8.20
Diluted net income per common share (in dollars per share)	$ (0.14)	$ 1.74	$ 1.99	$ (0.34)	$ 5.15	$ 2.10	$ 0.24	$ 0.68	$ 0.05	$ (0.25)	$ 3.24	$ 8.16