Civitas Resources (CIVI) 10-K 17 Feb 21 2020 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Feb. 15, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Current Fiscal Year End Date	--12-31
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
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Bankruptcy Proceedings, Reporting Current	true
Entity Public Float			$ 271.4
Entity Common Stock, Shares Outstanding (in shares)		20,839,227
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement, will be filed with the Securities and Exchange Commission within 120 days of December 31, 2020, as incorporated by reference into Part III of this report for the year ended December 31, 2020.
Entity Central Index Key	0001509589
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 24,743	$ 11,008
Accounts receivable, net:
Oil and gas sales	32,673	43,714
Joint interest and other	14,748	38,136
Prepaid expenses and other	3,574	7,048
Inventory of oilfield equipment	9,185	7,726
Derivative assets (note 12)	7,482	2,884
Total current assets	92,405	110,516
Property and equipment (successful efforts method):
Proved oil and gas properties	1,056,773	935,025
Less: accumulated depreciation, depletion, and amortization	(211,432)	(126,614)
Total proved oil and gas properties, net	845,341	808,411
Unproved properties	98,122	143,020
Wells in progress	50,609	98,750
Other property and equipment, net of accumulated depreciation of $3,737 in 2020 and $3,142 in 2019	3,239	3,394
Total property and equipment, net	997,311	1,053,575
Long-term derivative assets (note 12)	0	121
Right-of-use assets (note 2)	29,705	38,562
Deferred income tax assets (note 9)	60,520	0
Other noncurrent assets (note 4)	2,871	3,544
Total assets	1,182,812	1,206,318
Current liabilities:
Accounts payable and accrued expenses (note 5)	37,425	57,638
Oil and gas revenue distribution payable	18,613	29,021
Lease liability (note 2)	12,044	11,690
Derivative liability (note 12)	6,402	6,390
Total current liabilities	74,484	104,739
Long-term liabilities:
Credit facility (note 6)	0	80,000
Lease liability (note 2)	17,978	27,540
Ad valorem taxes	15,069	28,520
Derivative liability (note 12)	1,330	921
Asset retirement obligations for oil and gas properties (note 10)	28,699	27,908
Total liabilities	137,560	269,628
Commitments and contingencies (note 7)
Stockholders’ equity:
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding	0	0
Common stock, $.01 par value, 225,000,000 shares authorized, 20,839,227 and 20,643,738 issued and outstanding as of December 31, 2020 and 2019, respectively	4,282	4,284
Additional paid-in capital	707,209	702,173
Retained earnings	333,761	230,233
Total stockholders’ equity	1,045,252	936,690
Total liabilities and stockholders’ equity	$ 1,182,812	$ 1,206,318

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$ 3,737	$ 3,142
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)	20,839,227	20,839,227
Common stock, shares outstanding (in shares)	20,643,738	20,643,738

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating net revenues:
Oil and gas sales	$ 218,090,000	$ 313,220,000	$ 276,657,000
Operating expenses:
Lease operating expense	21,957,000	25,249,000	34,825,000
Severance and ad valorem taxes	3,787,000	25,598,000	18,999,000
Exploration	596,000	797,000	291,000
Depreciation, depletion, and amortization	91,242,000	76,453,000	41,883,000
Abandonment and impairment of unproved properties	37,343,000	11,201,000	5,271,000
Unused commitments	0	0	21,000
Bad debt expense	818,000	0	0
Merger transaction costs	6,676,000	0	0
General and administrative expense (including $6,156, $6,886, and $7,156, respectively, of stock-based compensation)	34,936,000	39,668,000	42,453,000
Total operating expenses	229,235,000	207,662,000	164,263,000
Other income (expense):
Derivative gain (loss)	53,462,000	(37,145,000)	30,271,000
Interest expense, net	(2,045,000)	(2,650,000)	(2,603,000)
Gain (loss) on property transactions, net	(1,398,000)	1,177,000	27,324,000
Other income	4,107,000	127,000	800,000
Total other income (expense)	54,126,000	(38,491,000)	55,792,000
Income before income taxes	42,981,000	67,067,000	168,186,000
Income tax benefit	60,547,000	0	0
Net income	103,528,000	67,067,000	168,186,000
Comprehensive income	$ 103,528,000	$ 67,067,000	$ 168,186,000
Net income per common share:
Basic (in dollars per share)	$ 4.98	$ 3.25	$ 8.20
Diluted (in dollars per share)	$ 4.95	$ 3.24	$ 8.16
Weighted-average common shares outstanding
Basic (in shares)	20,774	20,612	20,507
Diluted (in shares)	20,912	20,681	20,603
Gas plant and midstream operating expense
Operating expenses:
Operating expenses	$ 14,948,000	$ 12,014,000	$ 10,788,000
Gathering, transportation, and processing
Operating expenses:
Operating expenses	$ 16,932,000	$ 16,682,000	$ 9,732,000

CONSOLIDATED STATEMENTS OF OP_2

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement [Abstract]
General and administrative, stock compensation	$ 6,156	$ 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, 2017		20,453,549
Balance at beginning 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	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	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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock issued (in shares)		259,995
Restricted stock used for tax withholdings (in shares)		(64,506)
Restricted stock used for tax withholdings	(1,122)	$ (2)	(1,120)
Stock-based compensation	6,156		6,156
Net income	103,528			103,528
Shares outstanding, end of period (in shares) at Dec. 31, 2020		20,839,227
Balance at end of period at Dec. 31, 2020	$ 1,045,252	$ 4,282	$ 707,209	$ 333,761

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income		$ 103,528	$ 67,067	$ 168,186
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		91,242	76,453	41,883
Deferred income tax benefit		(60,520)	0	0
Abandonment and impairment of unproved properties		37,343	11,201	5,271
Well abandonment costs and dry hole expense		(8)	172	0
Stock-based compensation		6,156	6,886	7,156
Non-cash lease component		(249)	668	0
Amortization of deferred financing costs		864	487	30
Derivative (gain) loss		(53,462)	37,145	(30,271)
Derivative cash settlements		49,406	1,691	(18,160)
(Gain) loss on property transactions, net		1,398	(1,177)	(27,324)
Other		71	3,559	(3,311)
Changes in current assets and liabilities:
Accounts receivable, net		24,945	(2,688)	(46,988)
Prepaid expenses and other assets		3,352	(2,415)	2,214
Accounts payable and accrued liabilities		(41,278)	28,320	19,953
Settlement of asset retirement obligations		(3,992)	(2,722)	(2,041)
Net cash provided by operating activities		158,796	224,647	116,598
Cash flows from investing activities:
Acquisition of oil and gas properties		(3,210)	(14,087)	(2,892)
Exploration and development of oil and gas properties		(60,149)	(242,487)	(264,231)
Proceeds from sale of oil and gas properties		0	1,757	103,134
Additions to property and equipment - non oil and gas		(440)	(341)	(387)
Net cash used in investing activities		(63,799)	(255,158)	(164,376)
Cash flows from financing activities:
Proceeds from credit facility		45,000	55,000	140,000
Payments to credit facility		(125,000)	(25,000)	(90,000)
Proceeds from exercise of stock options		0	0	1,100
Payment of employee tax withholdings in exchange for the return of common stock		(1,122)	(1,176)	(863)
Deferred financing costs		(23)	(220)	(2,239)
Principal payments on finance lease obligations		(102)	0	0
Net cash provided by (used in) financing activities		(81,247)	28,604	47,998
Net change in cash, cash equivalents, and restricted cash		13,750	(1,907)	220
Cash, cash equivalents, and restricted cash:
Beginning of period		11,095	13,002	12,782
End of period		24,845	11,095	13,002
Supplemental Cash Flow Disclosure:
Cash paid for interest, net of capitalization	[1]	1,546	4,110	2,582
Severance and ad valorem tax refund	[1]	0	352	0
Receivables exchanged for additional interests in oil and gas properties	[1]	8,299	0	0
Changes in working capital related to drilling expenditures	[1]	$ 2,795	$ 30,354	$ 11,769
[1]	(1) Refer to Note 2 - Leases in the notes to the consolidated financial statements for discussion of right-of-use assets obtained in exchange for lease liabilities.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2020
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 Colorado. Basis of Presentation As of December 31, 2020, 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, 2020, through the filing date of this report. On August 6, 2018, the Company sold its equity interests in Bonanza Creek Energy Resources, LLC, which owned 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 - Acquisitions & Divestitures for additional discussion. 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. These estimates and other factors, including those outside of the Company's control, such as the impact of lower commodity prices, may impact the Company's business, financial condition, results of operations, and cash flows. 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. Industry Segment and Geographic Information The Company operates in one industry segment, which is the development and production of oil, natural gas, and NGLs, and all of the Company's operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment. 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 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 of proved oil and gas properties is computed using the units-of-production method based on produced volumes and estimated proved reserves. The computation of depletion takes into consideration restoration, dismantlement, and abandonment costs and anticipated proceeds from salvaging equipment. Because all of our oil and gas properties are currently located in a single field, we apply depletion on a single field basis. During the years ended December 31, 2020, 2019, and 2018, the Company incurred $82.6 million, $69.3 million, and $34.6 million, respectively, in depletion expense. 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, based on the Company’s estimate of future reserves, oil and natural gas prices, operating costs, and production levels from oil and natural gas reserves, 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. The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering, and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, differentials, revenues, taxes, capital expenditures, operating expenses, and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, our ability to fund estimated development cost, prevailing oil and gas prices, and other factors, many of which are beyond our control. As of December 31, 2020, the net book value of the Company's gathering assets was $153.0 million in 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. During the years ended December 31, 2020, 2019, and 2018, the Company incurred $37.3 million, $11.2 million, and $5.3 million, respectively, in abandonment and impairment of unproved properties due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases. 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 - Acquisitions & Divestitures for more information. Revenue Recognition 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, 2020, 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 collects 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, 2020 and 2019, the Company's receivables from contracts with customers were $32.7 million and $43.7 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 its 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, 2020 through December 31, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. Revenue attributable to each identified revenue stream is disaggregated below (in thousands): Year Ended December 31, 2020 2019 2018 Operating revenues: Crude oil sales $ 174,536 $ 268,865 $ 228,661 Natural gas sales 24,243 28,296 22,369 Natural gas liquids sales 19,311 16,059 25,627 Oil and gas sales $ 218,090 $ 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 2019, 2018, and 2017 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, 2020, 2019, and 2018, NGL Crude Logistics accounted for 77%, 82%, and 66% of sales, respectively, and Duke Energy Field Services accounted for 9%, 6%, and 8% 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 derivative 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 are calculated under the treasury stock method. Basic net income (loss) per common share is calculated by dividing net income (loss) 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. 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, 2020 2019 2018 Cash and cash equivalents $ 24,743 $ 11,008 $ 12,916 Restricted cash (1) 102 87 86 Total cash, cash equivalents, and restricted cash $ 24,845 $ 11,095 $ 13,002 ____________________________ (1) Included in other noncurrent assets and consists of funds for road maintenance and repairs. Recently Issued and Adopted Accounting Standards 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 was adopted using a modified retrospective approach on January 1, 2020. The Company considered past events (including historical experience), current economic and industry conditions, reasonable and supportable forecasts, and lives of receivable balances and loss experience. Historically and currently, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the adoption of this standard did not have a material impact on its consolidated financial statements. As of December 31, 2020, the Company has an allowance of $0.4 million established against joint interest receivables. 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. The new standard was adopted on January 1, 2020. The standard only impacted the form of the Company's disclosures. In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848), which provides temporary optional guidance to companies impacted by the transition away from the LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are explicitly eligible for certain optional expedients and exceptions in Topic 848. These amendments are effective upon issuance and expire on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition on the Company's consolidated financial statements.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
LEASES	LEASES The Company’s right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet, which include leases related to the asset classes reflected as of the dates indicated in the table below (in thousands): December 31, 2020 2019 Operating Leases Field equipment (1) $ 27,537 $ 35,057 Corporate leases 1,481 2,462 Vehicles 468 1,043 Total right-of-use asset $ 29,486 $ 38,562 Field equipment (1) $ 27,537 $ 35,075 Corporate leases 1,900 3,129 Vehicles 468 1,026 Total lease liability $ 29,905 $ 39,230 Finance Leases Right of use asset - field equipment (1) $ 219 $ — Lease liability - field equipment (1) $ 117 $ — ____________________________ (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 various line items on the statements of operations or capitalized to oil and gas properties or other property and equipment, as applicable. The Company recognizes operating lease expense on a straight-line basis. Finance lease expense is recognized based on the effective interest method for the lease liability and straight-line amortization for the right-of-use asset, resulting in more cost being recognized in earlier lease periods. Short-term and variable lease payments 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 lease costs incurred during the years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, 2020 2019 Operating lease cost (1) $ 13,957 $ 11,330 Finance lease cost Amortization of ROU assets 18 — Interest on lease liabilities 5 — Short-term lease cost 2,058 8,169 Variable lease cost (2) (186) 259 Sublease income (3) (358) (348) Total lease cost $ 15,494 $ 19,410 ___________________________ (1) Includes office rent expense of $1.1 million for each of the years ended December 31, 2020 and 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 has 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, purchase, or terminate early, which was evaluated on each lease to arrive at the proper lease term. There were some leases for which the option to extend or purchase 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 terms and discount rates as of December 31, 2020 are as follows: Operating Leases Finance Leases Weighted-average lease term (years) 2.8 0.2 Weighted-average discount rate 3.90% 3.47% Supplemental cash flow information related to leases for the years ended December 31, 2020 and 2019 consisted of the following (in thousands): Year Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 12,768 $ 10,993 Operating cash flows from finance leases 5 — Financing cash flows from finance leases 102 — Right-of-use assets obtained in exchange for new operating lease obligations $ 8,306 $ 16,568 Right-of-use assets obtained in exchange for new finance lease obligations 219 — Future commitments by year for the Company's operating and finance leases with a lease term of one year or more as of December 31, 2020 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): Operating Leases Finance Leases 2021 $ 12,836 $ 118 2022 9,788 — 2023 6,371 — 2024 2,439 — 2025 108 — Thereafter — — Total lease payments 31,542 118 Less: imputed interest (1,637) (1) Total lease liability $ 29,905 $ 117
LEASES	LEASES The Company’s right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet, which include leases related to the asset classes reflected as of the dates indicated in the table below (in thousands): December 31, 2020 2019 Operating Leases Field equipment (1) $ 27,537 $ 35,057 Corporate leases 1,481 2,462 Vehicles 468 1,043 Total right-of-use asset $ 29,486 $ 38,562 Field equipment (1) $ 27,537 $ 35,075 Corporate leases 1,900 3,129 Vehicles 468 1,026 Total lease liability $ 29,905 $ 39,230 Finance Leases Right of use asset - field equipment (1) $ 219 $ — Lease liability - field equipment (1) $ 117 $ — ____________________________ (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 various line items on the statements of operations or capitalized to oil and gas properties or other property and equipment, as applicable. The Company recognizes operating lease expense on a straight-line basis. Finance lease expense is recognized based on the effective interest method for the lease liability and straight-line amortization for the right-of-use asset, resulting in more cost being recognized in earlier lease periods. Short-term and variable lease payments 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 lease costs incurred during the years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, 2020 2019 Operating lease cost (1) $ 13,957 $ 11,330 Finance lease cost Amortization of ROU assets 18 — Interest on lease liabilities 5 — Short-term lease cost 2,058 8,169 Variable lease cost (2) (186) 259 Sublease income (3) (358) (348) Total lease cost $ 15,494 $ 19,410 ___________________________ (1) Includes office rent expense of $1.1 million for each of the years ended December 31, 2020 and 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 has 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, purchase, or terminate early, which was evaluated on each lease to arrive at the proper lease term. There were some leases for which the option to extend or purchase 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 terms and discount rates as of December 31, 2020 are as follows: Operating Leases Finance Leases Weighted-average lease term (years) 2.8 0.2 Weighted-average discount rate 3.90% 3.47% Supplemental cash flow information related to leases for the years ended December 31, 2020 and 2019 consisted of the following (in thousands): Year Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 12,768 $ 10,993 Operating cash flows from finance leases 5 — Financing cash flows from finance leases 102 — Right-of-use assets obtained in exchange for new operating lease obligations $ 8,306 $ 16,568 Right-of-use assets obtained in exchange for new finance lease obligations 219 — Future commitments by year for the Company's operating and finance leases with a lease term of one year or more as of December 31, 2020 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): Operating Leases Finance Leases 2021 $ 12,836 $ 118 2022 9,788 — 2023 6,371 — 2024 2,439 — 2025 108 — Thereafter — — Total lease payments 31,542 118 Less: imputed interest (1,637) (1) Total lease liability $ 29,905 $ 117

ACQUISITIONS & DIVESTITURES

ACQUISITIONS & DIVESTITURES	12 Months Ended
	Dec. 31, 2020
Business Combinations [Abstract]
ACQUISITIONS & DIVESTITURES	ACQUISITIONS & DIVESTITURES On November 9, 2020, the Company and HighPoint Resources Corporation entered into a Merger Agreement, providing for the Company's acquisition of HighPoint. The preliminary merger consideration is expected to be $337.4 million, consisting of a combination of the issuance of shares of the Company's common stock and senior notes. Upon execution of the Merger Agreement, HighPoint paid BCEI $6.0 million in consideration for, among other things, the costs and expenses to be incurred by the Company to pursue consummation of this acquisition. The transaction is expected to close in the first half of 2021, contingent upon a number of factors disclosed in the Merger Agreement. In August 2018, the Company entered into an agreement to simultaneously close and divest of all of its assets within its Mid-Continent region. Net proceeds, including 2019 purchase price adjustments, amounted to $103.5 million resulting in a gain of approximately $28.6 million, included in the gain (loss) on property transactions, net line item in the accompanying statements of operations. In March 2018, the Company sold its North Park Basin assets 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, 2020
Other Assets [Abstract]
OTHER NONCURRENT ASSETS	OTHER NONCURRENT ASSETS Other noncurrent assets contain the following (in thousands): As of December 31, 2020 2019 Operating bonds $ 1,641 $ 1,638 Deferred financing costs 725 1,443 AMT credit refund (1) 403 376 Restricted cash 102 87 Other noncurrent assets $ 2,871 $ 3,544 ___________________________ (1) Represents the alternative minimum tax credit refund due to the Company upon application of the 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, 2020
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, 2020 2019 Accrued drilling and completion costs $ 453 $ 3,248 Accounts payable trade 1,931 17,117 Accrued general and administrative expense 7,529 5,620 Accrued lease operating expense 1,793 2,187 Accrued interest expense 322 692 Accrued oil and gas hedging — 453 Accrued production and ad valorem taxes and other 25,397 28,321 Total accounts payable and accrued expenses $ 37,425 $ 57,638

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Credit Facility In December 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 $750.0 million Credit Facility has a maturity date of December 7, 2023 and was governed by an initial borrowing base of $350.0 million. The Credit Facility borrowing base is redetermined on a semi-annual basis. In June 2020, the borrowing base and aggregate elected commitments were reduced to $260.0 million. The most recent redetermination was concluded on December 18, 2020, resulting in a reaffirmation of the borrowing base at $260.0 million. The next scheduled redetermination is set to occur in May 2021. The Credit Facility is guaranteed by all wholly owned subsidiaries of the Company and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions. Under the original terms of the Credit Facility, borrowings bore interest at a per annum rate equal to, at the option of the Company, either (i) a 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 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, as tested on the last day of each fiscal quarter, including, without limitation, (i) a maximum ratio of the Company’s consolidated indebtedness (subject to certain exclusions) to EBITDAX 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. On June 18, 2020, in conjunction with the borrowing base redetermination, the Company, together with certain of its subsidiaries, entered into the First Amendment to the Credit Facility (as amended, restated, supplemented or otherwise modified) to, among other things: (i) implement certain anti-cash hoarding provisions, including a weekly mandatory prepayment requirement with respect to the excess of the Company's consolidated cash balance over $35.0 million; (ii) require that, in order to borrow or issue a letter of credit under the Credit Agreement, the consolidated cash balance not exceed the greater of $35.0 million (both before and after giving effect to such borrowing or letter of credit issuance), or expenditures in respect of oil and gas properties in the ordinary course of business (as agreed to by the administrative agent); (iii) decrease the maximum permitted net leverage ratio from 4.00 to 3.50 and the maximum permitted leverage ratio for purposes of making a restricted payment, restricted investment or optional or voluntary redemption from 3.25 to 2.75; (iv) increase the Eurodollar Rate margin to 2.00% to 3.00%; (v) increase the Reference Rate margin to 1.00% to 2.00%; and (vi) amend certain other covenants and provisions. The Company was in compliance with all covenants as of December 31, 2020 and through the filing date of this report. The Company had zero and $80.0 million outstanding on the Credit Facility as of December 31, 2020 and 2019, respectively. As of the date of this filing, the outstanding balance was zero. The Company's Credit Facility approximates fair value as the applicable interest rates are floating. 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, (i) $0.7 million and $1.4 million as of December 31, 2020 and 2019, respectively, are presented within other noncurrent assets and (ii) $0.4 million and $0.5 million as of December 31, 2020 and 2019, respectively, are presented within prepaid expenses and other line items in the accompanying balance sheets. Prior Credit Facility In April 2017, 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 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. Interest Expense For the years ended December 31, 2020, 2019, and 2018, the Company incurred interest expense of $3.8 million, $5.1 million, and $2.6 million respectively. The Company capitalized $1.8 million and $2.4 million of interest expense during the years ended December 31, 2020 and 2019. No interest was capitalized for the year ended December 31, 2018.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2020
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 was aware. 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. Commitments The Company is party to a purchase agreement to deliver fixed determinable quantities of crude oil to NGL Crude. The NGL Crude agreement includes defined volume commitments over a term ending in 2023. Under the terms of the NGL Crude agreement, the Company is required to make periodic deficiency payments for any shortfalls in delivering minimum gross volume commitments, which are set in six-month periods. The minimum gross volume commitment will increase approximately 3% each year for the remainder of the contract, to a maximum of approximately 16,000 gross barrels per day. The aggregate financial commitment fee over the remaining term is $49.7 million as of December 31, 2020. Upon notifying NGL Crude at least twelve months prior to the expiration date of the NGL Crude agreement, the Company may elect to extend the term of the NGL Crude agreement for up to three The annual minimum commitment payments under the NGL Crude agreement for the next five years as of December 31, 2020 are presented below (in thousands): NGL Crude Commitments (1) 2021 $ 22,403 2022 23,097 2023 4,201 2024 — 2025 and thereafter — Total $ 49,701 ___________________________ (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, 2020
Share-based Payment Arrangement [Abstract]
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION Long Term Incentive Plan In 2017, the Company adopted a Long Term Incentive Plan (the “LTIP”), as established by the Board, which allows for the issuance of RSUs, PSUs, and options, and reserved 2,467,430 shares of common stock. See below for further discussion of awards granted under the LTIP. The Company recorded compensation expense related to the awards granted under the LTIP as follows (in thousands): Year Ended December 31, 2020 2019 2018 Restricted stock units $ 5,283 $ 5,518 $ 5,140 Performance stock units 748 764 621 Stock options 125 604 1,395 Total stock-based compensation $ 6,156 $ 6,886 $ 7,156 As of December 31, 2020, unrecognized compensation expense will be amortized through the relevant periods as follows (in thousands): Unrecognized Compensation Expense Final Year of Recognition Restricted stock units $ 7,789 2023 Performance stock units 1,946 2022 Total unrecognized stock-based compensation $ 9,735 Inducement Awards During the year ended December 31, 2018, the Company granted inducement awards in the form of RSUs separate and distinct from the 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 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 years. The RSUs are valued at the grant date share price and are recognized as general and administrative expense over the vesting period of the award. The fair value of the RSUs granted from the LTIP during the years ended December 31, 2020, 2019, and 2018 was $4.9 million, $5.9 million, and $6.2 million, respectively. A summary of the status and activity of non-vested restricted stock units for the year ended December 31, 2020 is presented below: Restricted Stock Units Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 557,817 $ 26.95 Granted 306,945 15.90 Vested (259,995) 15.74 Forfeited (54,711) 24.77 Non-vested, end of year 550,056 $ 20.30 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 periods presented. Performance Stock Units The 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 ranges from zero to two times the number of PSUs awarded. The PSUs vest in their entirety at the end of the three-year performance period. The total number of PSUs granted is split between two performance criteria. The first criterion is based on a comparison of the Company’s absolute and relative total shareholder return (“TSR”) for the performance period compared with the TSRs of a group of peer companies for the same performance period. The TSR for the Company and each of the peer companies is determined by dividing (A) (i) the volume-weighted average share price for the last 30 trading days of the performance period, minus (ii) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period, by (B) the volume-weighted average share price for the 30 trading days preceding the beginning of the performance period. The second criterion is based on the Company's annual return on average capital employed (“ROCE”) for each year during the three-year performance period. The split between the two performance criteria was even for the PSUs granted in 2018 and 2019, whereas the split was two-thirds weighted to the TSR criterion and one-third weighted to the ROCE criterion for the PSUs granted in 2020. Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period. Because these awards depend on a combination of performance-based and market-based settlement criteria, compensation expense may be adjusted in future periods as the number of units expected to vest increases or decreases based on the Company’s expected ROCE performance. As of December 31, 2020, the Company knew and does not expect any of the ROCE portion of the PSUs granted in 2018 and 2019 to vest, respectively, and has accordingly adjusted the related compensation expense. 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: Year Ended December 31, 2020 2019 2018 Expected term (in years) 3 3 3 Risk-free interest rate 0.22 % 2.26 % 2.76 % Expected daily volatility 3.5 % 2.6 % 2.6 % The fair value of the PSUs granted during 2020, 2019, and 2018 was $1.9 million, $2.3 million, and $1.8 million, respectively. The PSUs granted in 2018 expired as of December 31, 2020, with zero distribution of shares to the recipients, as neither the TSR nor the ROCE performance criteria were met. A summary of the status and activity of performance stock units for the year ended December 31, 2020 is presented below: Performance Stock Units (1) Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 153,470 $ 24.74 Granted 83,209 23.22 Vested — — Forfeited — — Expired (51,091) 29.92 Non-vested, end of year 185,588 $ 22.63 ___________________________ (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 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 2020, 2019, and 2018. Stock options are 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. A summary of the status and activity of non-vested stock options for the year ended December 31, 2020 is presented below: Stock Options Weighted- Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding, beginning of year 100,714 $ 34.36 Granted — — Exercised — — Forfeited (28,346) 34.36 Outstanding, end of year 72,368 $ 34.36 6.3 $ — Options outstanding and exercisable 72,368 $ 34.36 6.3 $ —

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2020
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): Year Ended December 31, 2020 2019 2018 Current tax expense Federal $ (27) $ — $ — State — — — Total current tax expense (27) — — Deferred tax benefit Federal (53,784) — — State (6,736) — — Total deferred tax benefit (60,520) — — Total income tax benefit $ (60,547) $ — $ — Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax asset result from the following components (in thousands): As of December 31, 2020 2019 Deferred tax liabilities: Oil and gas properties $ 89,867 $ 79,187 Right-of-use assets 7,306 9,508 Total deferred tax liabilities 97,173 88,695 Deferred tax assets: Federal and state tax net operating loss carryforward 138,372 139,546 Derivative instruments 61 1,062 Reclamation costs 7,058 6,881 Stock compensation 1,653 2,209 Inventory 1,598 1,577 Lease liability 7,384 9,673 Pending acquisition costs 1,478 — Other long-term assets 89 300 Total deferred tax assets 157,693 161,248 Less: Valuation allowance — 72,553 Total deferred tax assets after valuation allowance 157,693 88,695 Total non-current net deferred tax asset $ 60,520 $ — The Company has $579.4 million and $582.8 million of net operating loss carryovers for federal income tax purposes as of December 31, 2020 and 2019, respectively. Federal net operating loss carryforwards incurred prior to January 1, 2018 of $465.7 million will begin to expire in 2036. Federal net operating loss carryforwards incurred after December 31, 2017 of $113.7 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. In making such determination, the Company considers all available (both positive and negative) evidence, including future reversals of temporary differences, tax-planning strategies, projected future taxable income, and results of operations. The Company has cumulative book income for the prior three years and is forecasting future book income, which resulted in the full valuation allowance of $72.6 million, that was recorded against the Company's deferred tax asset as of December 31, 2019, to be removed. 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): Year Ended December 31, 2020 2019 2018 Federal statutory tax expense $ 9,026 $ 14,084 $ 35,319 Increase (decrease) in tax resulting from: State tax expense net of federal benefit 1,694 2,537 6,556 Prior year true-up 292 (579) (458) Stock compensation 690 197 854 Permanent differences 36 128 61 State rate change 124 — (421) NOL Adjustment — — 5,973 Section 162(m) limitation 144 156 — Valuation allowance (72,553) (16,523) (47,884) Total income tax benefit $ (60,547) $ — $ — During the year ended December 31, 2020, the decrease in tax rate was primarily due to fully removing the valuation allowance against net deferred tax assets and net income decreasing between the comparable periods. There was $60.5 million of deferred income tax benefit in the accompanying statements of operations. The valuation allowance decreased by $72.6 million to zero in 2020 when compared to the same period in 2019 due to both current and forecasted book income. During the year ended December 31, 2019, there were no deferred income tax benefits 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 benefits 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. The Company had no unrecognized tax benefits as of December 31, 2020, 2019, and 2018. The tax returns for 2019, 2018, and 2017 are still subject to audit by the Internal Revenue Service.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2020
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): Year Ended December 31, 2020 2019 Balance, beginning of year $ 27,908 $ 29,405 Additional liabilities incurred 357 228 Accretion expense 1,004 1,467 Liabilities settled (2,464) (2,443) Revisions to estimate 1,894 (749) Balance, end of year $ 28,699 $ 27,908

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2020
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. 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, collars, and puts 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. The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019 and their classification within the fair value hierarchy (in thousands): As of December 31, 2020 Level 1 Level 2 Level 3 Derivative assets $ — $ 7,482 $ — Derivative liabilities $ — $ 7,732 $ — As of December 31, 2019 Level 1 Level 2 Level 3 Derivative assets $ — $ 3,005 $ — Derivative liabilities $ — $ 7,311 $ — Proved Oil and Gas Properties Proved oil and gas property costs are evaluated for impairment on a nonrecurring basis and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows of the underlying oil and gas reserves. 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 proved oil and gas property impairments during the years ended December 31, 2020 and 2019.

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2020
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, 2020, 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 1Q21 Cashless Collar 3,000 $43.67/$53.58 30,000 $2.25/$2.57 — — — — Swap 5,000 $54.48 — — 20,000 $0.43 — — 2Q21 Cashless Collar 2,500 $34.40/$49.82 20,000 $2.25/$2.52 — — — — Swap 4,000 $54.13 — — 20,000 $0.43 — — 3Q21 Cashless Collar 3,000 $30.00/$50.62 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75 Swap 2,500 $54.45 — — 20,000 $0.43 — — 4Q21 Cashless Collar 4,000 $30.63/$50.34 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75 Swap 1,000 $55.20 — — 20,000 $0.43 — — 1Q22 Cashless Collar 3,500 $31.43/$51.00 — — — — 20,000 $2.15/$2.75 2Q22 Cashless Collar 2,000 $32.50/$54.85 — — — — 20,000 $2.15/$2.75 3Q22 Cashless Collar 1,000 $35.00/$54.88 — — — — — — 4Q22 Cashless Collar 500 $35.00/$55.00 — — — — — — 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 1Q21 Cashless Collar 3,000 $43.67/$53.58 30,000 $2.25/$2.57 — — — — Swap 5,000 $54.48 — — 20,000 $0.43 — — 2Q21 Cashless Collar 2,500 $34.40/$49.82 20,000 $2.25/$2.52 — — — — Swap 4,000 $54.13 — — 20,000 $0.43 — — 3Q21 Cashless Collar 3,000 $30.00/$50.62 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75 Swap 2,500 $54.45 — — 20,000 $0.43 — — 4Q21 Cashless Collar 4,000 $30.63/$50.34 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75 Swap 1,000 $55.20 — — 20,000 $0.43 — — 1Q22 Cashless Collar 4,000 $31.88/$51.83 — — — — 20,000 $2.15/$2.75 2Q22 Cashless Collar 2,500 $33.00/$55.41 — — — — 20,000 $2.15/$2.75 3Q22 Cashless Collar 1,000 $35.00/$54.88 — — — — — — 4Q22 Cashless Collar 500 $35.00/$55.00 — — — — — — 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, 2020 and 2019 (in thousands): As of December 31, 2020 2019 Derivative Assets: Commodity contracts - current $ 7,482 $ 2,884 Commodity contracts - noncurrent — 121 Derivative Liabilities: Commodity contracts - current (6,402) (6,390) Commodity contracts - long-term (1,330) (921) Total derivative liabilities, net $ (250) $ (4,306) The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations for the periods below (in thousands): Year Ended December 31, 2020 2019 2018 Derivative cash settlement gain (loss): Oil contracts $ 50,133 $ 1,185 $ (17,700) Gas contracts (727) 506 (460) Total derivative cash settlement gain (loss) (1) 49,406 1,691 (18,160) Change in fair value gain (loss) 4,056 (38,836) 48,431 Total derivative gain (loss) (1) $ 53,462 $ (37,145) $ 30,271 ___________________________ (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, 2020
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 ranges 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 and warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period, assuming the date was the end of such stock options' or warrants' term. 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): Year Ended December 31, 2020 2019 2018 Net income $ 103,528 $ 67,067 $ 168,186 Basic net income per common share $ 4.98 $ 3.25 $ 8.20 Diluted net income per common share $ 4.95 $ 3.24 $ 8.16 Weighted-average shares outstanding - basic 20,774 20,612 20,507 Add: dilutive effect of contingent stock awards 138 69 96 Weighted-average shares outstanding - diluted 20,912 20,681 20,603

DISCLOSURES ABOUT OIL AND GAS P

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2020
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): Year Ended December 31, 2020 2019 2018 Acquisition (1) $ 11,296 $ 12,901 $ 2,861 Development (2)(3) 55,934 209,535 304,197 Exploration 595 796 294 Total $ 67,825 $ 223,232 $ 307,352 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2020, 2019, and 2018 were $2.3 million, $4.2 million, and $2.5 million, respectively. There were $9.0 million, $8.7 million, and $0.4 million in acquisition costs for proved properties for the years ended December 31, 2020, 2019, and 2018, respectively. (2) Development costs include workover costs of $1.2 million, $1.4 million, and $5.6 million charged to lease operating expense for the years ended December 31, 2020, 2019, and 2018, respectively. (3) Includes amounts relating to asset retirement obligations of $(1.0) million, $(0.9) million, and $(9.0) million, for the years ended December 31, 2020, 2019, and 2018, respectively. Suspended Well Costs The Company did not incur any exploratory well costs during the years ended December 31, 2020, 2019, and 2018. Reserves The proved reserve estimates were prepared by our third party independent reserve engineers, which were Ryder Scott at December 31, 2020 and NSAI for the estimates at December 31, 2019 and 2018. 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, 2020, 2019, and 2018 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (MMcf) (MBbl) 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 Extensions, discoveries and infills (1) 9,376 32,172 3,269 Production (5,019) (14,166) (1,858) Sales of minerals in place — — — Removed from capital program (2) (14,120) (33,886) (3,141) Purchases of minerals in place 1,430 5,457 570 Revisions to previous estimates (3) (3,287) 33,951 5,110 Balance-December 31, 2020 52,793 235,728 26,111 Proved developed reserves: December 31, 2018 23,725 79,630 11,703 December 31, 2019 25,397 105,840 11,566 December 31, 2020 24,320 123,220 14,315 Proved undeveloped reserves: December 31, 2018 40,629 85,382 13,227 December 31, 2019 39,016 106,360 10,595 December 31, 2020 28,473 112,508 11,796 ________________________ (1) During the years ended December 31, 2020, 2019, and 2018, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of 18.0 MMBoe, 15.4 MMBoe, and 28.8 MMBoe, respectively. (2) During the years ended December 31, 2020, 2019, and 2018, proved undeveloped reserves were reduced by 22.9 MMBoe, 8.7 MMBoe, and 2.5 MMBoe respectively, primarily due to the removal of proved undeveloped locations from our five-year drilling program. (3) As of December 31, 2020, the Company revised its proved reserves upward by 7.5 MMBoe primarily driven by 12.3 MMBoe in positive engineering revisions. The commodity prices at December 31, 2020 decreased to $39.57 per Bbl WTI and $1.99 per MMBtu HH from $55.85 per Bbl WTI and $2.58 per MMBtu HH at December 31, 2019, resulting in a partially offsetting negative revision of 4.8 MMBoe. 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. 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): Year Ended December 31, 2020 2019 2018 Future cash flows $ 2,230,012 $ 3,827,009 $ 4,742,180 Future production costs (675,755) (1,029,140) (1,585,032) Future development costs (530,970) (850,327) (925,640) Future income tax expense — — — Future net cash flows 1,023,287 1,947,542 2,231,508 10% annual discount for estimated timing of cash flows (586,233) (1,089,395) (1,276,528) Standardized measure of discounted future net cash flows $ 437,054 $ 858,147 $ 954,980 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): Year Ended December 31, 2020 2019 2018 Beginning of period $ 858,147 $ 954,980 $ 598,498 Sale of oil and gas produced, net of production costs (160,466) (233,677) (204,566) Net changes in prices and production costs (641,137) (372,233) 365,952 Net changes in extensions, discoveries and improved recoveries (54,269) 45,728 153,691 Development costs incurred 42,325 185,086 127,788 Changes in estimated development cost 220,964 81,358 (52,260) Purchases of minerals in place 12,372 10,135 — Sales of minerals in place — (309) (115,742) Revisions of previous quantity estimates 60,754 79,637 12,341 Net change in income taxes — — — Accretion of discount 85,815 95,498 59,850 Changes in production rates and other 12,549 11,944 9,428 End of period $ 437,054 $ 858,147 $ 954,980 The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2020, 2019, and 2018 were calculated using the twelve-month arithmetic average of first-day-of-the-month prices inclusive of adjustments for quality and location. Year Ended December 31, 2020 2019 2018 Oil (per Bbl) $ 34.96 $ 51.22 $ 59.29 Gas (per Mcf) $ 0.95 $ 1.44 $ 2.28 Natural gas liquids (per Bbl) $ 6.12 $ 10.07 $ 22.06

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation As of December 31, 2020, 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, 2020, through the filing date of this report.
Use of Estimates	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. These estimates and other factors, including those outside of the Company's control, such as the impact of lower commodity prices, may impact the Company's business, financial condition, results of operations, and cash flows.
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 ReceivableThe 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
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 of proved oil and gas properties is computed using the units-of-production method based on produced volumes and estimated proved reserves. The computation of depletion takes into consideration restoration, dismantlement, and abandonment costs and anticipated proceeds from salvaging equipment. Because all of our oil and gas properties are currently located in a single field, we apply depletion on a single field basis. During the years ended December 31, 2020, 2019, and 2018, the Company incurred $82.6 million, $69.3 million, and $34.6 million, respectively, in depletion expense. 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, based on the Company’s estimate of future reserves, oil and natural gas prices, operating costs, and production levels from oil and natural gas reserves, 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. The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluating the available geological, geophysical, engineering, and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, differentials, revenues, taxes, capital expenditures, operating expenses, and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, our ability to fund estimated development cost, prevailing oil and gas prices, and other factors, many of which are beyond our control. As of December 31, 2020, the net book value of the Company's gathering assets was $153.0 million in 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. During the years ended December 31, 2020, 2019, and 2018, the Company incurred $37.3 million, $11.2 million, and $5.3 million, respectively, in abandonment and impairment of unproved properties due to the reassessment of estimated probable and possible reserve locations based primarily upon economic viability and the expiration of non-core leases. 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 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, 2020, 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 collects 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, 2020 and 2019, the Company's receivables from contracts with customers were $32.7 million and $43.7 million, respectively. Payment is generally received within 30 to 60 days after the date of production.
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
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 derivative 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 ShareEarnings per basic and diluted share are calculated under the treasury stock method. Basic net income (loss) per common share is calculated by dividing net income (loss) 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.
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 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 was adopted using a modified retrospective approach on January 1, 2020. The Company considered past events (including historical experience), current economic and industry conditions, reasonable and supportable forecasts, and lives of receivable balances and loss experience. Historically and currently, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the adoption of this standard did not have a material impact on its consolidated financial statements. As of December 31, 2020, the Company has an allowance of $0.4 million established against joint interest receivables. 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. The new standard was adopted on January 1, 2020. The standard only impacted the form of the Company's disclosures. In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848), which provides temporary optional guidance to companies impacted by the transition away from the LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are explicitly eligible for certain optional expedients and exceptions in Topic 848. These amendments are effective upon issuance and expire on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition on the Company's consolidated financial statements.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Schedule of Disaggregation of Revenue	Revenue attributable to each identified revenue stream is disaggregated below (in thousands): Year Ended December 31, 2020 2019 2018 Operating revenues: Crude oil sales $ 174,536 $ 268,865 $ 228,661 Natural gas sales 24,243 28,296 22,369 Natural gas liquids sales 19,311 16,059 25,627 Oil and gas sales $ 218,090 $ 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, 2020 2019 2018 Cash and cash equivalents $ 24,743 $ 11,008 $ 12,916 Restricted cash (1) 102 87 86 Total cash, cash equivalents, and restricted cash $ 24,845 $ 11,095 $ 13,002 ____________________________ (1) Included in other noncurrent assets and 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, 2020 2019 2018 Cash and cash equivalents $ 24,743 $ 11,008 $ 12,916 Restricted cash (1) 102 87 86 Total cash, cash equivalents, and restricted cash $ 24,845 $ 11,095 $ 13,002 ____________________________ (1) Included in other noncurrent assets and consists of funds for road maintenance and repairs.

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Schedule of Balance Sheet Activity, Asset Classes	The Company’s right-of-use assets and lease liabilities are recognized at their discounted present value on the balance sheet, which include leases related to the asset classes reflected as of the dates indicated in the table below (in thousands): December 31, 2020 2019 Operating Leases Field equipment (1) $ 27,537 $ 35,057 Corporate leases 1,481 2,462 Vehicles 468 1,043 Total right-of-use asset $ 29,486 $ 38,562 Field equipment (1) $ 27,537 $ 35,075 Corporate leases 1,900 3,129 Vehicles 468 1,026 Total lease liability $ 29,905 $ 39,230 Finance Leases Right of use asset - field equipment (1) $ 219 $ — Lease liability - field equipment (1) $ 117 $ — ____________________________ (1) Includes compressors, certain gas processing equipment, and other field equipment.
Summary of Operating Lease Costs and Summary of Supplemental Cash Flow Information	The following table summarizes the components of the Company's gross lease costs incurred during the years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, 2020 2019 Operating lease cost (1) $ 13,957 $ 11,330 Finance lease cost Amortization of ROU assets 18 — Interest on lease liabilities 5 — Short-term lease cost 2,058 8,169 Variable lease cost (2) (186) 259 Sublease income (3) (358) (348) Total lease cost $ 15,494 $ 19,410 ___________________________ (1) Includes office rent expense of $1.1 million for each of the years ended December 31, 2020 and 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 has subleased a portion of its office space for the remainder of the office lease term. Supplemental cash flow information related to leases for the years ended December 31, 2020 and 2019 consisted of the following (in thousands): Year Ended December 31, 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 12,768 $ 10,993 Operating cash flows from finance leases 5 — Financing cash flows from finance leases 102 — Right-of-use assets obtained in exchange for new operating lease obligations $ 8,306 $ 16,568 Right-of-use assets obtained in exchange for new finance lease obligations 219 —
Schedule of Weighted-Average Information	The Company's weighted-average remaining lease terms and discount rates as of December 31, 2020 are as follows: Operating Leases Finance Leases Weighted-average lease term (years) 2.8 0.2 Weighted-average discount rate 3.90% 3.47%
Schedule of Future Minimum Commitments for Operating Leases	Future commitments by year for the Company's operating and finance leases with a lease term of one year or more as of December 31, 2020 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): Operating Leases Finance Leases 2021 $ 12,836 $ 118 2022 9,788 — 2023 6,371 — 2024 2,439 — 2025 108 — Thereafter — — Total lease payments 31,542 118 Less: imputed interest (1,637) (1) Total lease liability $ 29,905 $ 117
Schedule of Future Minimum Commitments for Finance Leases	Future commitments by year for the Company's operating and finance leases with a lease term of one year or more as of December 31, 2020 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): Operating Leases Finance Leases 2021 $ 12,836 $ 118 2022 9,788 — 2023 6,371 — 2024 2,439 — 2025 108 — Thereafter — — Total lease payments 31,542 118 Less: imputed interest (1,637) (1) Total lease liability $ 29,905 $ 117

OTHER NONCURRENT ASSETS (Tables

OTHER NONCURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2020
Other Assets [Abstract]
Schedule of Other Noncurrent Assets	Other noncurrent assets contain the following (in thousands): As of December 31, 2020 2019 Operating bonds $ 1,641 $ 1,638 Deferred financing costs 725 1,443 AMT credit refund (1) 403 376 Restricted cash 102 87 Other noncurrent assets $ 2,871 $ 3,544 ___________________________ (1) Represents the alternative minimum tax credit refund due to the Company upon application of the 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, 2020
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, 2020 2019 Accrued drilling and completion costs $ 453 $ 3,248 Accounts payable trade 1,931 17,117 Accrued general and administrative expense 7,529 5,620 Accrued lease operating expense 1,793 2,187 Accrued interest expense 322 692 Accrued oil and gas hedging — 453 Accrued production and ad valorem taxes and other 25,397 28,321 Total accounts payable and accrued expenses $ 37,425 $ 57,638

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 are presented below (in thousands): NGL Crude Commitments (1) 2021 $ 22,403 2022 23,097 2023 4,201 2024 — 2025 and thereafter — Total $ 49,701 ___________________________ (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, 2020
Share-based Payment Arrangement [Abstract]
Summary of Share-Based Compensation Expense	The Company recorded compensation expense related to the awards granted under the LTIP as follows (in thousands): Year Ended December 31, 2020 2019 2018 Restricted stock units $ 5,283 $ 5,518 $ 5,140 Performance stock units 748 764 621 Stock options 125 604 1,395 Total stock-based compensation $ 6,156 $ 6,886 $ 7,156
Summary of Unrecognized Compensation Expense	As of December 31, 2020, unrecognized compensation expense will be amortized through the relevant periods as follows (in thousands): Unrecognized Compensation Expense Final Year of Recognition Restricted stock units $ 7,789 2023 Performance stock units 1,946 2022 Total unrecognized stock-based compensation $ 9,735
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, 2020 is presented below: Restricted Stock Units Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 557,817 $ 26.95 Granted 306,945 15.90 Vested (259,995) 15.74 Forfeited (54,711) 24.77 Non-vested, end of year 550,056 $ 20.30
Schedule of Assumptions	The following table presents the assumptions used to determine the fair value of the TSR portion of the PSUs: Year Ended December 31, 2020 2019 2018 Expected term (in years) 3 3 3 Risk-free interest rate 0.22 % 2.26 % 2.76 % Expected daily volatility 3.5 % 2.6 % 2.6 %
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, 2020 is presented below: Performance Stock Units (1) Weighted-Average Grant-Date Fair Value Non-vested, beginning of year 153,470 $ 24.74 Granted 83,209 23.22 Vested — — Forfeited — — Expired (51,091) 29.92 Non-vested, end of year 185,588 $ 22.63 ___________________________ (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.
Summary of the Status and Activity of Non-Vested Options	A summary of the status and activity of non-vested stock options for the year ended December 31, 2020 is presented below: Stock Options Weighted- Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding, beginning of year 100,714 $ 34.36 Granted — — Exercised — — Forfeited (28,346) 34.36 Outstanding, end of year 72,368 $ 34.36 6.3 $ — Options outstanding and exercisable 72,368 $ 34.36 6.3 $ —

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	The provision for income taxes consists of the following (in thousands): Year Ended December 31, 2020 2019 2018 Current tax expense Federal $ (27) $ — $ — State — — — Total current tax expense (27) — — Deferred tax benefit Federal (53,784) — — State (6,736) — — Total deferred tax benefit (60,520) — — Total income tax benefit $ (60,547) $ — $ —
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 result from the following components (in thousands): As of December 31, 2020 2019 Deferred tax liabilities: Oil and gas properties $ 89,867 $ 79,187 Right-of-use assets 7,306 9,508 Total deferred tax liabilities 97,173 88,695 Deferred tax assets: Federal and state tax net operating loss carryforward 138,372 139,546 Derivative instruments 61 1,062 Reclamation costs 7,058 6,881 Stock compensation 1,653 2,209 Inventory 1,598 1,577 Lease liability 7,384 9,673 Pending acquisition costs 1,478 — Other long-term assets 89 300 Total deferred tax assets 157,693 161,248 Less: Valuation allowance — 72,553 Total deferred tax assets after valuation allowance 157,693 88,695 Total non-current net deferred tax asset $ 60,520 $ —
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): Year Ended December 31, 2020 2019 2018 Federal statutory tax expense $ 9,026 $ 14,084 $ 35,319 Increase (decrease) in tax resulting from: State tax expense net of federal benefit 1,694 2,537 6,556 Prior year true-up 292 (579) (458) Stock compensation 690 197 854 Permanent differences 36 128 61 State rate change 124 — (421) NOL Adjustment — — 5,973 Section 162(m) limitation 144 156 — Valuation allowance (72,553) (16,523) (47,884) Total income tax benefit $ (60,547) $ — $ —

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligation Changes	A roll-forward of the Company's asset retirement obligation is as follows (in thousands): Year Ended December 31, 2020 2019 Balance, beginning of year $ 27,908 $ 29,405 Additional liabilities incurred 357 228 Accretion expense 1,004 1,467 Liabilities settled (2,464) (2,443) Revisions to estimate 1,894 (749) Balance, end of year $ 28,699 $ 27,908

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Schedule of Financial Assets and Liabilities at Fair Value on Recurring Basis	The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019 and their classification within the fair value hierarchy (in thousands): As of December 31, 2020 Level 1 Level 2 Level 3 Derivative assets $ — $ 7,482 $ — Derivative liabilities $ — $ 7,732 $ — As of December 31, 2019 Level 1 Level 2 Level 3 Derivative assets $ — $ 3,005 $ — Derivative liabilities $ — $ 7,311 $ —

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Commodity Derivatives	As of December 31, 2020, 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 1Q21 Cashless Collar 3,000 $43.67/$53.58 30,000 $2.25/$2.57 — — — — Swap 5,000 $54.48 — — 20,000 $0.43 — — 2Q21 Cashless Collar 2,500 $34.40/$49.82 20,000 $2.25/$2.52 — — — — Swap 4,000 $54.13 — — 20,000 $0.43 — — 3Q21 Cashless Collar 3,000 $30.00/$50.62 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75 Swap 2,500 $54.45 — — 20,000 $0.43 — — 4Q21 Cashless Collar 4,000 $30.63/$50.34 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75 Swap 1,000 $55.20 — — 20,000 $0.43 — — 1Q22 Cashless Collar 3,500 $31.43/$51.00 — — — — 20,000 $2.15/$2.75 2Q22 Cashless Collar 2,000 $32.50/$54.85 — — — — 20,000 $2.15/$2.75 3Q22 Cashless Collar 1,000 $35.00/$54.88 — — — — — — 4Q22 Cashless Collar 500 $35.00/$55.00 — — — — — — 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 1Q21 Cashless Collar 3,000 $43.67/$53.58 30,000 $2.25/$2.57 — — — — Swap 5,000 $54.48 — — 20,000 $0.43 — — 2Q21 Cashless Collar 2,500 $34.40/$49.82 20,000 $2.25/$2.52 — — — — Swap 4,000 $54.13 — — 20,000 $0.43 — — 3Q21 Cashless Collar 3,000 $30.00/$50.62 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75 Swap 2,500 $54.45 — — 20,000 $0.43 — — 4Q21 Cashless Collar 4,000 $30.63/$50.34 20,000 $2.25/$2.52 — — 20,000 $2.15/$2.75 Swap 1,000 $55.20 — — 20,000 $0.43 — — 1Q22 Cashless Collar 4,000 $31.88/$51.83 — — — — 20,000 $2.15/$2.75 2Q22 Cashless Collar 2,500 $33.00/$55.41 — — — — 20,000 $2.15/$2.75 3Q22 Cashless Collar 1,000 $35.00/$54.88 — — — — — — 4Q22 Cashless Collar 500 $35.00/$55.00 — — — — — —
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, 2020 and 2019 (in thousands): As of December 31, 2020 2019 Derivative Assets: Commodity contracts - current $ 7,482 $ 2,884 Commodity contracts - noncurrent — 121 Derivative Liabilities: Commodity contracts - current (6,402) (6,390) Commodity contracts - long-term (1,330) (921) Total derivative liabilities, net $ (250) $ (4,306)
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): Year Ended December 31, 2020 2019 2018 Derivative cash settlement gain (loss): Oil contracts $ 50,133 $ 1,185 $ (17,700) Gas contracts (727) 506 (460) Total derivative cash settlement gain (loss) (1) 49,406 1,691 (18,160) Change in fair value gain (loss) 4,056 (38,836) 48,431 Total derivative gain (loss) (1) $ 53,462 $ (37,145) $ 30,271 ___________________________ (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, 2020
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): Year Ended December 31, 2020 2019 2018 Net income $ 103,528 $ 67,067 $ 168,186 Basic net income per common share $ 4.98 $ 3.25 $ 8.20 Diluted net income per common share $ 4.95 $ 3.24 $ 8.16 Weighted-average shares outstanding - basic 20,774 20,612 20,507 Add: dilutive effect of contingent stock awards 138 69 96 Weighted-average shares outstanding - diluted 20,912 20,681 20,603

DISCLOSURES ABOUT OIL AND GAS_2

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2020
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): Year Ended December 31, 2020 2019 2018 Acquisition (1) $ 11,296 $ 12,901 $ 2,861 Development (2)(3) 55,934 209,535 304,197 Exploration 595 796 294 Total $ 67,825 $ 223,232 $ 307,352 _________________________ (1) Acquisition costs for unproved properties for the years ended December 31, 2020, 2019, and 2018 were $2.3 million, $4.2 million, and $2.5 million, respectively. There were $9.0 million, $8.7 million, and $0.4 million in acquisition costs for proved properties for the years ended December 31, 2020, 2019, and 2018, respectively. (2) Development costs include workover costs of $1.2 million, $1.4 million, and $5.6 million charged to lease operating expense for the years ended December 31, 2020, 2019, and 2018, respectively. (3) Includes amounts relating to asset retirement obligations of $(1.0) million, $(0.9) million, and $(9.0) million, for the years ended December 31, 2020, 2019, and 2018, 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, 2020, 2019, and 2018 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (MMcf) (MBbl) 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 Extensions, discoveries and infills (1) 9,376 32,172 3,269 Production (5,019) (14,166) (1,858) Sales of minerals in place — — — Removed from capital program (2) (14,120) (33,886) (3,141) Purchases of minerals in place 1,430 5,457 570 Revisions to previous estimates (3) (3,287) 33,951 5,110 Balance-December 31, 2020 52,793 235,728 26,111 Proved developed reserves: December 31, 2018 23,725 79,630 11,703 December 31, 2019 25,397 105,840 11,566 December 31, 2020 24,320 123,220 14,315 Proved undeveloped reserves: December 31, 2018 40,629 85,382 13,227 December 31, 2019 39,016 106,360 10,595 December 31, 2020 28,473 112,508 11,796 ________________________ (1) During the years ended December 31, 2020, 2019, and 2018, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of 18.0 MMBoe, 15.4 MMBoe, and 28.8 MMBoe, respectively. (2) During the years ended December 31, 2020, 2019, and 2018, proved undeveloped reserves were reduced by 22.9 MMBoe, 8.7 MMBoe, and 2.5 MMBoe respectively, primarily due to the removal of proved undeveloped locations from our five-year drilling program. (3) As of December 31, 2020, the Company revised its proved reserves upward by 7.5 MMBoe primarily driven by 12.3 MMBoe in positive engineering revisions. The commodity prices at December 31, 2020 decreased to $39.57 per Bbl WTI and $1.99 per MMBtu HH from $55.85 per Bbl WTI and $2.58 per MMBtu HH at December 31, 2019, resulting in a partially offsetting negative revision of 4.8 MMBoe.
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): Year Ended December 31, 2020 2019 2018 Future cash flows $ 2,230,012 $ 3,827,009 $ 4,742,180 Future production costs (675,755) (1,029,140) (1,585,032) Future development costs (530,970) (850,327) (925,640) Future income tax expense — — — Future net cash flows 1,023,287 1,947,542 2,231,508 10% annual discount for estimated timing of cash flows (586,233) (1,089,395) (1,276,528) Standardized measure of discounted future net cash flows $ 437,054 $ 858,147 $ 954,980
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): Year Ended December 31, 2020 2019 2018 Beginning of period $ 858,147 $ 954,980 $ 598,498 Sale of oil and gas produced, net of production costs (160,466) (233,677) (204,566) Net changes in prices and production costs (641,137) (372,233) 365,952 Net changes in extensions, discoveries and improved recoveries (54,269) 45,728 153,691 Development costs incurred 42,325 185,086 127,788 Changes in estimated development cost 220,964 81,358 (52,260) Purchases of minerals in place 12,372 10,135 — Sales of minerals in place — (309) (115,742) Revisions of previous quantity estimates 60,754 79,637 12,341 Net change in income taxes — — — Accretion of discount 85,815 95,498 59,850 Changes in production rates and other 12,549 11,944 9,428 End of period $ 437,054 $ 858,147 $ 954,980
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, 2020, 2019, and 2018 were calculated using the twelve-month arithmetic average of first-day-of-the-month prices inclusive of adjustments for quality and location. Year Ended December 31, 2020 2019 2018 Oil (per Bbl) $ 34.96 $ 51.22 $ 59.29 Gas (per Mcf) $ 0.95 $ 1.44 $ 2.28 Natural gas liquids (per Bbl) $ 6.12 $ 10.07 $ 22.06

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)segment	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Property, Plant and Equipment [Line Items]
Number of operating segments | segment	1
Number of reportable segments | segment	1
Depletion expense	$ 82,600	$ 69,300	$ 34,600
Proved oil and gas properties	1,056,773	935,025
Abandonment and impairment of unproved properties	37,343	11,201	$ 5,271
Receivables from contracts with customers	32,673	$ 43,714
Joint interest receivables, allowance	$ 400
Minimum
Property, Plant and Equipment [Line Items]
Receivable collection period	1 month
Maximum
Property, Plant and Equipment [Line Items]
Receivable collection period	2 months
Gathering Assets
Property, Plant and Equipment [Line Items]
Proved oil and gas properties	$ 153,000
PP&E useful life	30 years
Property, Plant and Equipment, Other Types | Minimum
Property, Plant and Equipment [Line Items]
PP&E useful life	3 years
Property, Plant and Equipment, Other Types | Maximum
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	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating revenues:
Oil and gas sales	$ 218,090	$ 313,220	$ 276,657
Crude oil sales
Operating revenues:
Oil and gas sales	174,536	268,865	228,661
Natural gas sales
Operating revenues:
Oil and gas sales	24,243	28,296	22,369
Natural gas liquids sales
Operating revenues:
Oil and gas sales	$ 19,311	$ 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, 2020	Dec. 31, 2019	Dec. 31, 2018
NGL Crude Logistics
Concentration Risk [Line Items]
Percent of oil and natural gas sales	77.00%	82.00%	66.00%
Duke Energy Field Services
Concentration Risk [Line Items]
Percent of oil and natural gas sales	9.00%	6.00%	8.00%

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Cash and cash equivalents	$ 24,743	$ 11,008	$ 12,916
Restricted cash	102	87	86
Total cash, cash equivalents, and restricted cash	$ 24,845	$ 11,095	$ 13,002	$ 12,782

LEASES - Assets and Liabilities

LEASES - Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Operating Leases
Total right-of-use asset	$ 29,486	$ 38,562
Total lease liability	29,905	39,230
Finance Leases
Lease liability - field equipment	117
Field equipment
Operating Leases
Total right-of-use asset	27,537	35,057
Total lease liability	27,537	35,075
Finance Leases
Right-of-use asset - field equipment	219	0
Lease liability - field equipment	117	0
Corporate leases
Operating Leases
Total right-of-use asset	1,481	2,462
Total lease liability	1,900	3,129
Vehicles
Operating Leases
Total right-of-use asset	468	1,043
Total lease liability	$ 468	$ 1,026

LEASES - Lease Cost (Details)

LEASES - Lease Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating lease cost	$ 13,957	$ 11,330
Finance lease cost
Amortization of ROU assets	18	0
Interest on lease liabilities	5	0
Short-term lease cost	2,058	8,169
Variable lease cost	(186)	259
Sublease Income	(358)	(348)
Total lease cost	15,494	19,410
Office rent expense	$ 1,100	$ 1,100

LEASES - Weighted-Average and D

LEASES - Weighted-Average and Discount Rate Information (Details)	Dec. 31, 2020
Operating Leases
Weighted-average lease term (years)	2 years 9 months 18 days
Weighted-average discount rate	3.90%
Finance Leases
Weighted-average lease term (years)	2 months 12 days
Weighted-average discount rate	3.47%

LEASES - Supplemental Cash Flow

LEASES - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 12,768	$ 10,993
Operating cash flows from finance leases	5	0
Financing cash flows from finance leases	102	0	$ 0
Right-of-use assets obtained in exchange for new operating lease obligations	8,306	16,568
Right-of-use assets obtained in exchange for new finance lease obligations	$ 219	$ 0

LEASES - Lease Maturities (Deta

LEASES - Lease Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Operating Leases
2021	$ 12,836
2022	9,788
2023	6,371
2024	2,439
2025	108
Thereafter	0
Total lease payments	31,542
Less: imputed interest	(1,637)
Total lease liability	29,905	$ 39,230
Finance Leases
2021	118
2022	0
2023	0
2024	0
2025	0
Thereafter	0
Total lease payments	118
Less: imputed interest	(1)
Total lease liability	$ 117

ACQUISITIONS & DIVESTITURES - N

ACQUISITIONS & DIVESTITURES - Narrative (Details) - USD ($) $ in Thousands	Nov. 09, 2020	Aug. 06, 2018	Jun. 30, 2021	Dec. 31, 2020	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				$ (1,398)	$ 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
HPR | HPR
Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments for merger costs and expenses to be incurred	$ 6,000
HPR | Scenario, Forecast
Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Merger consideration			$ 337,400

OTHER NONCURRENT ASSETS - Sched

OTHER NONCURRENT ASSETS - Schedule of Other Noncurrent Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other Assets [Abstract]
Operating bonds	$ 1,641	$ 1,638
Deferred financing costs	725	1,443
AMT credit refund	403	376
Restricted cash	102	87	$ 86
Other noncurrent assets	$ 2,871	$ 3,544

ACCOUNTS PAYABLE AND ACCRUED _3

ACCOUNTS PAYABLE AND ACCRUED EXPENSES - Schedule of Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounts payable and accrued expenses contain the following:
Accrued drilling and completion costs	$ 453	$ 3,248
Accounts payable trade	1,931	17,117
Accrued general and administrative expense	7,529	5,620
Accrued lease operating expense	1,793	2,187
Accrued interest expense	322	692
Accrued oil and gas hedging	0	453
Accrued production and ad valorem taxes and other	25,397	28,321
Total accounts payable and accrued expenses	$ 37,425	$ 57,638

LONG-TERM DEBT - Narrative (Det

LONG-TERM DEBT - Narrative (Details)	Jun. 30, 2020USD ($)	Dec. 07, 2018	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Feb. 17, 2021USD ($)	Dec. 18, 2020USD ($)	Jun. 18, 2020USD ($)	Jun. 17, 2020	Apr. 30, 2017USD ($)
LONG-TERM DEBT
Interest expense			$ 3,800,000	$ 5,100,000	$ 2,600,000
Capitalized interest			1,800,000	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	$ 260,000,000		$ 350,000,000				$ 260,000,000			$ 191,700,000
Minimum current ratio covenant			1
Credit facility outstanding			$ 0	80,000,000
Deferred financing costs			2,500,000
Revolver | Subsequent Event
LONG-TERM DEBT
Credit facility outstanding						$ 0
Revolver | Other Noncurrent Assets
LONG-TERM DEBT
Deferred financing costs			700,000	1,400,000
Revolver | Prepaid Expenses and Other Current Assets
LONG-TERM DEBT
Deferred financing costs			$ 400,000	$ 500,000
Revolver | Amended Credit Agreement
LONG-TERM DEBT
Weekly mandatory prepayment requirement, excess cash balance threshold								$ 35,000,000
Borrowing requirement, maximum cash balance								$ 35,000,000
Maximum net leverage ratio								3.50	4
Maximum leverage ratio, restricted payment, restricted investment, optional or voluntary redemption								2.75	3.25
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 | Minimum | Amended Credit Agreement
LONG-TERM DEBT
Basis spread on variable rate	2.00%
Revolver | Eurodollar | Maximum
LONG-TERM DEBT
Basis spread on variable rate		2.75%
Revolver | Eurodollar | Maximum | Amended Credit Agreement
LONG-TERM DEBT
Basis spread on variable rate	3.00%
Revolver | Reference Rate | Minimum
LONG-TERM DEBT
Basis spread on variable rate		0.75%
Revolver | Reference Rate | Minimum | Amended Credit Agreement
LONG-TERM DEBT
Basis spread on variable rate	1.00%
Revolver | Reference Rate | Maximum
LONG-TERM DEBT
Basis spread on variable rate		1.75%
Revolver | Reference Rate | Maximum | Amended Credit Agreement
LONG-TERM DEBT
Basis spread on variable rate	2.00%

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Narrative (Details) bbl in Thousands, $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020USD ($)claimbbl
Loss Contingencies [Line Items]
Number of claims | claim					0
Reimbursement of ad valorem taxes	$ 7,400
Optional extended term (up to)					3 years
NGL
Loss Contingencies [Line Items]
Periodic deficiency payment, incremental payment period					6 months
Minimum differential fee					$ 49,701
Notification period, prior to agreement expiration date, optional extended term (at least)					12 months
NGL | Crude Oil
Loss Contingencies [Line Items]
Purchase commitment, volume required annual increase					3.00%
Maximum volume requirement | bbl					16
NGL | Scenario, Forecast | Crude Oil
Loss Contingencies [Line Items]
Purchase commitment, volume required annual increase		3.00%	3.00%	3.00%
Severance and Ad Valorem Taxes
Loss Contingencies [Line Items]
Reimbursement of ad valorem taxes	$ 5,100

COMMITMENT AND CONTINGENCIES -

COMMITMENT AND CONTINGENCIES - Schedule of Purchase Obligations (Details) - NGL $ in Thousands	Dec. 31, 2020USD ($)
Long-term Purchase Commitment [Line Items]
2021	$ 22,403
2022	23,097
2023	4,201
2024	0
2025 and thereafter	0
Total	$ 49,701

STOCK-BASED COMPENSATION - Narr

STOCK-BASED COMPENSATION - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted		2,300,000	1,800,000
LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for future issuance (in shares)				2,467,430
LTIP | Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	306,945
Vesting period	3 years
LTIP | Restricted stock units | Non-executive Board Members
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units granted	$ 4,900,000	$ 5,900,000	$ 6,200,000
LTIP | Restricted stock units | Vesting Period One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent of shares	33.00%
LTIP | Restricted stock units | Vesting Period Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent of shares	33.00%
LTIP | Restricted stock units | Vesting Period Three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent of shares	33.00%
LTIP | Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	83,209
Fair value of units granted	$ 1,900,000
Distribution of shares to recipients (in shares)	0
Vesting period	3 years
Number of trading days	30 days
TSR criterion percentage	67.00%
ROCE criterion	33.00%
LTIP | Performance stock units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company	0
LTIP | Performance stock units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company	2
LTIP | Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period	10 years
Granted (shares)	0	0	0

STOCK-BASED COMPENSATION - Sche

STOCK-BASED COMPENSATION - Schedule of Expenses (Details) - LTIP - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation	$ 6,156	$ 6,886	$ 7,156
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation	5,283	5,518	5,140
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation	748	764	621
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation	$ 125	$ 604	$ 1,395

STOCK-BASED COMPENSATION - Unre

STOCK-BASED COMPENSATION - Unrecognized Compensation Expense (Details) $ in Thousands	Dec. 31, 2020USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total unrecognized stock-based compensation	$ 9,735
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total unrecognized stock-based compensation	7,789
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total unrecognized stock-based compensation	$ 1,946

STOCK-BASED COMPENSATION - Acti

STOCK-BASED COMPENSATION - Activity of Non-Option Awards (Details)	12 Months Ended
	Dec. 31, 2020$ / sharesshares	Dec. 31, 2018shares
Restricted stock units
Stock Units
Granted (in shares)		170,613
LTIP | Restricted stock units
Stock Units
Non-vested, beginning of year (in shares)	557,817
Granted (in shares)	306,945
Vested (in shares)	(259,995)
Forfeited (in shares)	(54,711)
Non-vested, end of year (in shares)	550,056
Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year (in dollars per share) | $ / shares	$ 26.95
Granted (in dollars per share) | $ / shares	15.90
Vested (in dollars per share) | $ / shares	15.74
Forfeited (in dollars per share) | $ / shares	24.77
Non-vested, end of year (in dollars per share) | $ / shares	$ 20.30
LTIP | Performance stock units
Stock Units
Non-vested, beginning of year (in shares)	153,470
Granted (in shares)	83,209
Vested (in shares)	0
Forfeited (in shares)	0
Expired (in shares)	(51,091)
Non-vested, end of year (in shares)	185,588
Weighted-Average Grant-Date Fair Value
Non-vested, beginning of year (in dollars per share) | $ / shares	$ 24.74
Granted (in dollars per share) | $ / shares	23.22
Vested (in dollars per share) | $ / shares	0
Forfeited (in dollars per share) | $ / shares	0
Expired (in dollars per share) | $ / shares	29.92
Non-vested, end of year (in dollars per share) | $ / shares	$ 22.63
LTIP | Performance stock units | Minimum
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company	0
LTIP | Performance stock units | Maximum
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company	2

STOCK-BASED COMPENSATION - Valu

STOCK-BASED COMPENSATION - Valuation assumptions (Details) - LTIP - Performance stock units	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)	3 years	3 years	3 years
Risk-free interest rate	0.22%	2.26%	2.76%
Expected daily volatility	3.50%	2.60%	2.60%

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Stock Options
Outstanding, beginning of year (shares)	100,714
Granted (shares)	0	0	0
Exercised (shares)	0
Forfeited (shares)	(28,346)
Outstanding, end of year (shares)	72,368	100,714
Options outstanding and exercisable (shares)	72,368
Weighted- Average Exercise Price
Outstanding, beginning of year (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, end of year (in dollars per share)	34.36	$ 34.36
Options outstanding and exercisable (in dollars per share)	$ 34.36
Additional Information
Weighted-Average Remaining Contractual Term (in years)	6 years 3 months 18 days
Options outstanding and exercisable, Weighted-Average Remaining Contractual Term (in years)	6 years 3 months 18 days
Aggregate Intrinsic Value (in thousands)	$ 0
Options outstanding and exercisable, Aggregate Intrinsic Value (in thousands)	$ 0

INCOME TAXES - Provision For In

INCOME TAXES - Provision For Income Taxes (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current tax expense
Federal	$ (27,000)	$ 0	$ 0
State	0	0	0
Total current tax expense	(27,000)	0	0
Deferred tax benefit
Federal	(53,784,000)	0	0
State	(6,736,000)	0	0
Total deferred tax benefit	(60,520,000)	0	0
Total income tax benefit	$ (60,547,000)	$ 0	$ 0

INCOME TAXES - Deferred Tax Ass

INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Deferred tax liabilities:
Oil and gas properties	$ 89,867,000	$ 79,187,000
Right-of-use assets	7,306,000	9,508,000
Total deferred tax liabilities	97,173,000	88,695,000
Deferred tax assets:
Federal and state tax net operating loss carryforward	138,372,000	139,546,000
Derivative instruments	61,000	1,062,000
Reclamation costs	7,058,000	6,881,000
Stock compensation	1,653,000	2,209,000
Inventory	1,598,000	1,577,000
Lease liability	7,384,000	9,673,000
Pending acquisition costs	1,478,000	0
Other long-term assets	89,000	300,000
Total deferred tax assets	157,693,000	161,248,000
Less: Valuation allowance	0	72,553,000	$ 89,100,000
Total deferred tax assets after valuation allowance	157,693,000	88,695,000
Total non-current net deferred tax asset	$ 60,520,000	$ 0

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Net operating loss carryovers for federal income tax purposes	$ 579,400,000	$ 582,800,000
Net operating loss carryovers for federal income tax purposes, not benefited for financial statement purposes			$ 113,700,000	$ 465,700,000
Current income tax benefit	60,547,000	0	0
Decrease in valuation allowance	72,553,000	16,523,000	47,884,000
Valuation allowance	0	72,553,000	89,100,000
Unrecognized tax benefits	$ 0	$ 0	$ 0

INCOME TAXES - Effective Income

INCOME TAXES - Effective Income Tax Reconciliation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Federal statutory tax expense	$ 9,026,000	$ 14,084,000	$ 35,319,000
Increase (decrease) in tax resulting from:
State tax expense net of federal benefit	1,694,000	2,537,000	6,556,000
Prior year true-up	292,000	(579,000)	(458,000)
Stock compensation	690,000	197,000	854,000
Permanent differences	36,000	128,000	61,000
State rate change	124,000	0	(421,000)
NOL Adjustment	0	0	5,973,000
Section 162(m) limitation	144,000	156,000	0
Valuation allowance	(72,553,000)	(16,523,000)	(47,884,000)
Total income tax benefit	$ (60,547,000)	$ 0	$ 0

ASSET RETIREMENT OBLIGATIONS -

ASSET RETIREMENT OBLIGATIONS - Schedule of Roll-Forward Activity (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Change in asset retirement obligations
Balance, beginning of year	$ 27,908	$ 29,405
Additional liabilities incurred	357	228
Accretion expense	1,004	1,467
Liabilities settled	(2,464)	(2,443)
Revisions to estimate	1,894	(749)
Balance, end of year	$ 28,699	$ 27,908

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, 2020	Dec. 31, 2019
Level 1
Financial assets and liabilities accounted for at fair value
Derivative assets	$ 0	$ 0
Derivative liabilities	0	0
Level 2
Financial assets and liabilities accounted for at fair value
Derivative assets	7,482	3,005
Derivative liabilities	7,732	7,311
Level 3
Financial assets and liabilities accounted for at fair value
Derivative assets	0	0
Derivative liabilities	$ 0	$ 0

FAIR VALUE MEASUREMENTS - Narra

FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Proved oil and gas property impairments	$ 0	$ 0

DERIVATIVES - Narrative (Detail

DERIVATIVES - Narrative (Details)	Dec. 31, 2020derivative
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, 2022$ / MMBTU$ / bblbbl	Sep. 30, 2022$ / MMBTU$ / bblbbl	Jun. 30, 2022MMBTU$ / MMBTU$ / bblbbl	Mar. 31, 2022MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2021MMBTU$ / MMBTU$ / bblbbl	Sep. 30, 2021MMBTU$ / MMBTU$ / bblbbl	Jun. 30, 2021MMBTU$ / bbl$ / MMBTUbbl	Mar. 31, 2021MMBTU$ / bbl$ / MMBTUbbl
Crude Oil (NYMEX WTI) | Cashless Collar
Derivative [Line Items]
Crude Oil, notional amount (in Bbls per day) | bbl	500	1,000	2,000	3,500	4,000	3,000	2,500	3,000
Crude Oil (NYMEX WTI) | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Avg. Price (in dollars per Bbl and MMBtu, respectively) | $ / bbl	35	35	32.50	31.43	30.63	30	34.40	43.67
Crude Oil (NYMEX WTI) | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Avg. Price (in dollars per Bbl and MMBtu, respectively) | $ / bbl	55	54.88	54.85	51	50.34	50.62	49.82	53.58
Crude Oil (NYMEX WTI) | Swap
Derivative [Line Items]
Crude Oil, notional amount (in Bbls per day) | bbl					1,000	2,500	4,000	5,000
Weighted Avg. Price (in dollars per Bbl and MMBtu, respectively) | $ / bbl					55.20	54.45	54.13	54.48
Crude Oil (NYMEX WTI) | Subsequent Event | Cashless Collar
Derivative [Line Items]
Crude Oil, notional amount (in Bbls per day) | bbl	500	1,000	2,500	4,000	4,000	3,000	2,500	3,000
Crude Oil (NYMEX WTI) | Subsequent Event | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Avg. Price (in dollars per Bbl and MMBtu, respectively)	35	35	33	31.88	30.63	30	34.40	43.67
Crude Oil (NYMEX WTI) | Subsequent Event | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Avg. Price (in dollars per Bbl and MMBtu, respectively)	55	54.88	55.41	51.83	50.34	50.62	49.82	53.58
Crude Oil (NYMEX WTI) | Subsequent Event | Swap
Derivative [Line Items]
Crude Oil, notional amount (in Bbls per day) | bbl					1,000	2,500	4,000	5,000
Weighted Avg. Price (in dollars per Bbl and MMBtu, respectively) | $ / bbl					55.20	54.45	54.13	54.48
Natural Gas (NYMEX Henry Hub) | Cashless Collar
Derivative [Line Items]
Natural Gas, notional amount (in MMBtu per day) | MMBTU					20,000	20,000	20,000	30,000
Natural Gas (NYMEX Henry Hub) | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per MMBtu)					2.25	2.25	2.25	2.25
Natural Gas (NYMEX Henry Hub) | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per MMBtu)					2.52	2.52	2.52	2.57
Natural Gas (NYMEX Henry Hub) | Subsequent Event | Cashless Collar
Derivative [Line Items]
Natural Gas, notional amount (in MMBtu per day) | MMBTU					20,000	20,000	20,000	30,000
Natural Gas (NYMEX Henry Hub) | Subsequent Event | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per MMBtu)					2.25	2.25	2.25	2.25
Natural Gas (NYMEX Henry Hub) | Subsequent Event | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per MMBtu)					2.52	2.52	2.52	2.57
Natural Gas (CIG Basis) | Swap
Derivative [Line Items]
Weighted Avg. Price (in dollars per Bbl and MMBtu, respectively)					0.43	0.43	0.43	0.43
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 Avg. Price (in dollars per Bbl and MMBtu, respectively)					0.43	0.43	0.43	0.43
Natural Gas, notional amount (in MMBtu per day) | MMBTU					20,000	20,000	20,000	20,000
Natural Gas (CIG) | Cashless Collar
Derivative [Line Items]
Natural Gas, notional amount (in MMBtu per day) | MMBTU			20,000	20,000	20,000	20,000
Natural Gas (CIG) | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per MMBtu)			2.15	2.15	2.15	2.15
Natural Gas (CIG) | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per MMBtu)			2.75	2.75	2.75	2.75
Natural Gas (CIG) | Subsequent Event | Cashless Collar
Derivative [Line Items]
Natural Gas, notional amount (in MMBtu per day) | MMBTU			20,000	20,000	20,000	20,000
Natural Gas (CIG) | Subsequent Event | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per MMBtu)			2.15	2.15	2.15	2.15
Natural Gas (CIG) | Subsequent Event | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per MMBtu)			2.75	2.75	2.75	2.75

DERIVATIVES - Derivative Positi

DERIVATIVES - Derivative Positions (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Derivatives measured at fair value
Total derivative liabilities, net	$ (250)	$ (4,306)
Commodity | Commodity contracts - current
Derivatives measured at fair value
Derivative Assets	7,482	2,884
Commodity | Commodity contracts - noncurrent
Derivatives measured at fair value
Derivative Assets	0	121
Commodity | Commodity contracts - current
Derivatives measured at fair value
Derivative Liabilities	(6,402)	(6,390)
Commodity | Commodity contracts - long-term
Derivatives measured at fair value
Derivative Liabilities	$ (1,330)	$ (921)

DERIVATIVES - Derivative Gains

DERIVATIVES - Derivative Gains (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Components of the derivative gain (loss)
Total derivative gain (loss)	$ 53,462	$ (37,145)	$ 30,271
Commodity derivative
Components of the derivative gain (loss)
Total derivative cash settlement gain (loss)	49,406	1,691	(18,160)
Change in fair value gain (loss)	4,056	(38,836)	48,431
Total derivative gain (loss)	53,462	(37,145)	30,271
Commodity derivative | Oil contracts
Components of the derivative gain (loss)
Total derivative cash settlement gain (loss)	50,133	1,185	(17,700)
Commodity derivative | Gas contracts
Components of the derivative gain (loss)
Total derivative cash settlement gain (loss)	$ (727)	$ 506	$ (460)

EARNINGS PER SHARE - Narrative

EARNINGS PER SHARE - Narrative (Details)	12 Months Ended
	Dec. 31, 2020shares	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)	248,744	269,208	170,755
LTIP | Minimum | 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
LTIP | Maximum | 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

EARNINGS PER SHARE - Schedule o

EARNINGS PER SHARE - Schedule of Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share [Abstract]
Net income	$ 103,528	$ 67,067	$ 168,186
Basic net income per common share (in dollars per share)	$ 4.98	$ 3.25	$ 8.20
Diluted net income per common share (in dollars per share)	$ 4.95	$ 3.24	$ 8.16
Weighted-average shares outstanding - basic (in shares)	20,774	20,612	20,507
Add: dilutive effect of contingent stock awards (in shares)	138	69	96
Weighted-average shares outstanding - diluted (in shares)	20,912	20,681	20,603

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 ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
Acquisition	$ 11,296,000	$ 12,901,000	$ 2,861,000
Development	55,934,000	209,535,000	304,197,000
Exploration	595,000	796,000	294,000
Total	67,825,000	223,232,000	307,352,000
Acquisition costs for unproved properties	2,300,000	4,200,000	2,500,000
Proved property acquisitions	9,000,000	8,700,000	400,000
Workover costs charged to lease operating expense	1,200,000	1,400,000	5,600,000
Increase (decrease) in ARO	$ (1,000,000)	$ (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, MBoe in Millions	12 Months Ended
	Dec. 31, 2020Boe$ / bbl$ / MMBTUMcfbbl	Dec. 31, 2019BoeMBoe$ / MMBTU$ / bblbblMcf	Dec. 31, 2018Boe$ / bbl$ / MMBTUbblMcf	Dec. 31, 2017$ / 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)
Revisions to previous estimates - increase (decrease) | Boe			2,300,000
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	22,900,000	8,700,000	2,500,000
Proved developed and undeveloped reserve, drilling program, term	5 years
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)
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	(7,500,000)	(6,600,000)
Revisions to previous estimates - increase (decrease) | Boe		(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	(12,300,000)	8,100,000
Revisions to previous estimates - increase (decrease) | MBoe		(4.8)
Horizontal development | Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Extensions and discoveries | Boe	18,000,000	15,400,000	28,800,000
Oil contracts
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period	64,413	64,354	52,928
Extensions, discoveries and infills	9,376	8,825	18,390
Production	(5,019)	(5,136)	(3,841)
Sales of minerals in place	0	(52)	(6,236)
Removed from capital program	(14,120)	(4,926)	(1,442)
Purchases of minerals in place	1,430	303
Revisions to previous estimates	(3,287)	1,045	4,555
Balance at the end of the period	52,793	64,413	64,354	52,928
Proved developed reserves	24,320	25,397	23,725
Proved undeveloped reserves	28,473	39,016	40,629
Oil and gas commodity price (in dollars per share) | $ / bbl			65.56	51.34
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	39.57	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	212,200	165,012	157,669
Extensions, discoveries and infills | Mcf	32,172	20,604	31,471
Production | Mcf	(14,166)	(11,967)	(8,567)
Sales of minerals in place | Mcf	0	(110)	(20,534)
Removed from capital program | Mcf	(33,886)	(11,508)	(3,246)
Purchases of minerals in place | Mcf	5,457	627
Revisions to previous estimates | Mcf	33,951	49,542	8,219
Balance at the end of the period | Mcf	235,728	212,200	165,012	157,669
Proved developed reserves | Mcf	123,220	105,840	79,630
Proved undeveloped reserves | Mcf	112,508	106,360	85,382
Oil and gas commodity price (in dollars per share) | $ / MMBTU			3.10	2.98
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	1.99	2.58
Natural gas liquids (per Bbl)
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period	22,161	24,930	22,815
Extensions, discoveries and infills	3,269	3,123	5,197
Production	(1,858)	(1,431)	(1,140)
Sales of minerals in place	0	(18)	(1,499)
Removed from capital program	(3,141)	(1,862)	(544)
Purchases of minerals in place	570	102
Revisions to previous estimates	5,110	(2,683)	101
Balance at the end of the period	26,111	22,161	24,930	22,815
Proved developed reserves	14,315	11,566	11,703
Proved undeveloped reserves	11,796	10,595	13,227

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, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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				$ 2,230,012	$ 3,827,009	$ 4,742,180
Future production costs				(675,755)	(1,029,140)	(1,585,032)
Future development costs				(530,970)	(850,327)	(925,640)
Future income tax expense				0	0	0
Future net cash flows				1,023,287	1,947,542	2,231,508
10% annual discount for estimated timing of cash flows				(586,233)	(1,089,395)	(1,276,528)
Standardized measure of discounted future net cash flows	$ 858,147	$ 858,147	$ 598,498	$ 437,054	$ 858,147	$ 954,980
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Beginning of period	858,147	954,980	598,498
Sale of oil and gas produced, net of production costs	(160,466)	(233,677)	(204,566)
Net changes in prices and production costs	(641,137)	(372,233)	365,952
Net changes in extensions, discoveries and improved recoveries	(54,269)	45,728	153,691
Development costs incurred	42,325	185,086	127,788
Changes in estimated development cost	220,964	81,358	(52,260)
Purchases of minerals in place	12,372	10,135	0
Sales of minerals in place	0	(309)	(115,742)
Revisions of previous quantity estimates	60,754	79,637	12,341
Net change in income taxes	0	0	0
Accretion of discount	85,815	95,498	59,850
Changes in production rates and other	12,549	11,944	9,428
End of period	$ 437,054	$ 858,147	$ 954,980

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, 2020$ / MMcf$ / bbl	Dec. 31, 2019$ / bbl$ / MMcf	Dec. 31, 2018$ / 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)	34.96	51.22	59.29
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	0.95	1.44	2.28
Natural gas liquids (per Bbl)
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)	6.12	10.07	22.06