Civitas Resources (CIVI) 10-K 28 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 25, 2019	Jun. 30, 2018
Document and Entity Information
Entity Registrant Name	Bonanza Creek Energy, Inc.
Entity Central Index Key	1,509,589
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Common Stock, Shares Outstanding		20,558,591
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 776,136,334

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 12,916	$ 12,711
Accounts receivable:
Oil and gas sales	31,799	28,549
Joint interest and other	47,577	3,831
Prepaid expenses and other	4,633	6,555
Inventory of oilfield equipment	3,478	1,019
Derivative asset	34,408	488
Total current assets	134,811	53,153
Property and equipment (successful efforts method):
Proved properties	719,198	555,341
Less: accumulated depreciation, depletion and amortization	(52,842)	(17,032)
Total proved properties, net	666,356	538,309
Unproved properties	154,352	183,843
Wells in progress	93,617	47,224
Other property and equipment, net of accumulated depreciation of $2,546 in 2018 and $2,224 in 2017	3,649	4,706
Total property and equipment, net	917,974	774,082
Long-term derivative asset	3,864	6
Other noncurrent assets	4,885	3,130
Total assets	1,061,534	830,371
Current liabilities:
Accounts payable and accrued expenses (note 6)	79,390	62,129
Oil and gas revenue distribution payable	19,903	15,667
Derivative liability	183	11,423
Total current liabilities	99,476	89,219
Long-term liabilities:
Credit facility (note 7)	50,000	0
Ad valorem taxes	18,740	11,584
Long-term derivative liability	0	2,972
Asset retirement obligations for oil and gas properties	29,405	38,262
Total liabilities	197,621	142,037
Commitments and contingencies (note 8)
Stockholders’ equity:
Successor preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding as of December 31, 2018 and 2017	0	0
Successor common stock, $.01 par value, 225,000,000 shares authorized, 20,543,940 and 20,453,549 issued and outstanding as of December 31, 2018 and 2017, respectively	4,286	4,286
Additional paid-in capital	696,461	689,068
Retained earnings (deficit)	163,166	(5,020)
Total stockholders’ equity	863,913	688,334
Total liabilities and stockholders’ equity	$ 1,061,534	$ 830,371

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation (in dollars)	$ 2,546	$ 2,224
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (shares)	25,000,000	25,000,000
Preferred stock, shares outstanding (shares)	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (shares)	225,000,000	225,000,000
Common stock, shares issued (shares)	20,543,940	20,453,549
Common stock, shares outstanding (shares)	20,543,940	20,453,549

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) shares in Thousands, $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Operating net revenues:
Oil and gas sales		$ 123,535	$ 276,657
Operating expenses:
Lease operating expense		25,862	34,825
Severance and ad valorem taxes		9,590	18,999
Exploration		3,745	291
Depreciation, depletion and amortization		21,312	41,883
Impairment of oil and gas properties		0	0
Abandonment and impairment of unproved properties		0	5,271
Unused commitments		0	21
Contract settlement expense		0	0
General and administrative expense (including $7,156, $11,630, $2,116, and $8,892, respectively, of stock-based compensation)		42,676	42,453
Total operating expenses		111,526	164,263
Income (loss) from operations		12,009	112,394
Other income (expense):
Derivative gain (loss)		(15,365)	30,271
Interest expense		(773)	(2,603)
Gain on sale of properties		0	27,324	$ 0
Reorganization items, net (note 16)		0	0
Gain on termination fee		0	0
Other income (loss)		(1,267)	800
Total other income (expense)		(17,405)	55,792
Income (loss) from operations before taxes		(5,396)	168,186
Current income tax benefit (expense) (note 10)		376	0
Deferred income tax benefit (note 10)		0	0
Net income (loss)		(5,020)	168,186
Comprehensive income (loss)		$ (5,020)	$ 168,186
Basic net income (loss) per common share (in dollars per share)		$ (0.25)	$ 8.20
Diluted net income (loss) per common share (in dollars per share)		$ (0.25)	$ 8.16
Basic weighted-average common shares outstanding (in shares)		20,427	20,507
Diluted weighted-average common shares outstanding (in shares)		20,427	20,603
Predecessor
Operating net revenues:
Oil and gas sales	$ 68,589			195,295
Operating expenses:
Lease operating expense	13,128			43,671
Severance and ad valorem taxes	5,671			15,304
Exploration	3,699			946
Depreciation, depletion and amortization	28,065			111,215
Impairment of oil and gas properties	0			10,000
Abandonment and impairment of unproved properties	0			24,692
Unused commitments	993			7,686
Contract settlement expense	0			21,000
General and administrative expense (including $7,156, $11,630, $2,116, and $8,892, respectively, of stock-based compensation)	15,092			77,065
Total operating expenses	70,189			324,405
Income (loss) from operations	(1,600)			(129,110)
Other income (expense):
Derivative gain (loss)	0			(11,234)
Interest expense	(5,656)			(62,058)
Gain on sale of properties	0			0
Reorganization items, net (note 16)	8,808			0
Gain on termination fee	0			6,000
Other income (loss)	1,108			(2,548)
Total other income (expense)	4,260			(69,840)
Income (loss) from operations before taxes	2,660			(198,950)
Current income tax benefit (expense) (note 10)	0			0
Deferred income tax benefit (note 10)	0			0
Net income (loss)	2,660			(198,950)
Comprehensive income (loss)	$ 2,660			$ (198,950)
Basic net income (loss) per common share (in dollars per share)	$ 0.05			$ (4.04)
Diluted net income (loss) per common share (in dollars per share)	$ 0.05			$ (4.04)
Basic weighted-average common shares outstanding (in shares)	49,559			49,268
Diluted weighted-average common shares outstanding (in shares)	50,971			49,268
Gas plant and midstream operating expense
Operating expenses:
Operating expenses		$ 8,341	$ 10,788
Gas plant and midstream operating expense | Predecessor
Operating expenses:
Operating expenses	$ 3,541			$ 12,826
Gathering, transportation, and processing
Operating expenses:
Operating expenses		$ 0	$ 9,732
Gathering, transportation, and processing | Predecessor
Operating expenses:
Operating expenses	$ 0			$ 0

CONSOLIDATED STATEMENTS OF OP_2

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
General and administrative, stock compensation		$ 11,630	$ 7,156
Predecessor
General and administrative, stock compensation	$ 2,116			$ 8,892

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY Statement - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Cancellation of Predecessor equity	Cancellation of Predecessor equityCommon Stock	Cancellation of Predecessor equityAdditional Paid-in Capital	Cancellation of Predecessor equityRetained Earnings
Shares outstanding, beginning of period (in shares) (Predecessor) at Dec. 31, 2015		49,754,408
Balance at beginning of period (Predecessor) at Dec. 31, 2015	$ 209,407	$ 49	$ 806,386	$ (597,028)
Restricted common stock issued (shares) | Predecessor		154,656
Restricted common stock issued | Predecessor	2	$ 2
Restricted common stock forfeited (in shares) | Predecessor		(120,477)
Restricted common stock forfeited | Predecessor	(1)	$ (1)
Restricted stock used for tax withholdings (in shares) | Predecessor		(127,904)
Restricted stock used for tax withholdings | Predecessor	(289)	$ (1)	(288)
Stock-based compensation | Predecessor	8,892		8,892
Net income (loss) | Predecessor	(198,950)			(198,950)
Shares outstanding, end of period (in shares) (Predecessor) at Dec. 31, 2016		49,660,683
Balance at end of period (Predecessor) at Dec. 31, 2016	19,061	$ 49	814,990	(795,978)
Restricted common stock issued (shares) | Predecessor		767,848
Restricted common stock issued | Predecessor	1	$ 1
Restricted common stock forfeited (in shares) | Predecessor		(5,134)
Restricted common stock forfeited | Predecessor	0
Restricted stock used for tax withholdings (in shares) | Predecessor		(318,180)
Restricted stock used for tax withholdings | Predecessor	(428)	$ (1)	(427)
Stock-based compensation | Predecessor	2,116		2,116
Fair value of equity issued to existing common stockholders | Predecessor	(23,410)		(23,410)
Net income (loss) | Predecessor	2,660			2,660
Shares outstanding, end of period (in shares) (Predecessor) at Apr. 28, 2017		50,105,217				(50,105,217)
Shares outstanding, end of period (in shares) at Apr. 28, 2017		20,356,071				20,356,071
Balance at end of period (Predecessor) at Apr. 28, 2017	(77,075)	$ 49	793,269	(793,318)	$ 0	$ (49)	$ (793,269)	$ 793,318
Balance at end of period at Apr. 28, 2017	684,121	$ 4,285	679,836	0	684,121	$ 4,285	679,836	0
Shares outstanding, beginning of period (in shares) (Predecessor) at Dec. 31, 2016		49,660,683
Balance at beginning of period (Predecessor) at Dec. 31, 2016	19,061	$ 49	814,990	(795,978)
Net income (loss) | Predecessor	(198,950)
Shares outstanding, end of period (in shares) at Dec. 31, 2017		20,453,549
Balance at end of period at Dec. 31, 2017	688,334	$ 4,286	689,068	(5,020)
Shares outstanding, beginning of period (in shares) (Predecessor) at Apr. 28, 2017		50,105,217				(50,105,217)
Shares outstanding, beginning of period (in shares) at Apr. 28, 2017		20,356,071				20,356,071
Balance at beginning of period (Predecessor) at Apr. 28, 2017	(77,075)	$ 49	793,269	(793,318)	0	$ (49)	(793,269)	793,318
Balance at beginning of period at Apr. 28, 2017	684,121	$ 4,285	679,836	0	$ 684,121	$ 4,285	$ 679,836	$ 0
Restricted common stock issued (shares)		173,200
Restricted common stock issued	2	$ 2
Restricted stock used for tax withholdings (in shares)		(75,722)
Restricted stock used for tax withholdings	(2,399)	$ (1)	(2,398)
Stock-based compensation	11,630		11,630
Net income (loss)	(5,020)			(5,020)
Shares outstanding, end of period (in shares) at Dec. 31, 2017		20,453,549
Balance at end of period at Dec. 31, 2017	688,334	$ 4,286	689,068	(5,020)
Restricted common stock issued (shares)		84,345
Restricted common stock issued	0
Restricted stock used for tax withholdings (in shares)		(25,991)
Restricted stock used for tax withholdings	(863)		(863)
Exercise of stock options (in shares)		32,037
Exercise of stock options	1,100		1,100
Stock-based compensation	7,156		7,156
Net income (loss)	168,186			168,186
Shares outstanding, end of period (in shares) at Dec. 31, 2018		20,543,940
Balance at end of period at Dec. 31, 2018	$ 863,913	$ 4,286	$ 696,461	$ 163,166

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)		$ (5,020)	$ 168,186
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		21,312	41,883
Non-cash reorganization items		0	0
Impairment of oil and gas properties		0	0
Abandonment and impairment of unproved properties		0	5,271
Well abandonment costs and dry hole expense		75	0
Stock-based compensation		11,630	7,156
Amortization of deferred financing costs and debt premium		0	30
Derivative (gain) loss		15,365	(30,271)
Derivative cash settlements		(1,464)	(18,160)
Gain on sale of oil and gas properties		0	(27,324)	$ 0
Inventory write-offs		1,758	248
Other		11	(3,559)
Changes in current assets and liabilities:
Accounts receivable		(4,477)	(46,988)
Prepaid expenses and other assets		(1,979)	2,214
Accounts payable and accrued liabilities		(8,470)	19,953
Settlement of asset retirement obligations		(1,167)	(2,041)
Net cash provided by (used in) operating activities		27,574	116,598
Cash flows from investing activities:
Acquisition of oil and gas properties		(5,383)	(2,892)
Exploration and development of oil and gas properties		(76,384)	(264,231)
Proceeds from sale of oil and gas properties		0	103,134	0
Payments of contractual obligation		0	0
Operating bonds		0	0
Additions to property and equipment - non oil and gas		(874)	(387)
Net cash used in investing activities		(82,641)	(164,376)
Cash flows from financing activities:
Proceeds from credit facility		0	0
Payments to credit facility		0	0
Proceeds from sale of common stock		0	0
Proceeds from exercise of stock options		0	1,100
Payment of employee tax withholdings in exchange for the return of common stock		(2,398)	(863)
Deferred financing costs		0	(2,239)
Net cash provided by (used in) financing activities		(2,398)	47,998
Net change in cash, cash equivalents, and restricted cash		(57,465)	220
Cash and cash equivalents, and restricted cash:
Beginning of period		70,247	12,782
End of period	$ 70,247	12,782	13,002
Supplemental cash flow disclosure:
Cash paid for interest		523	2,582
Cash paid for reorganization items		0	0
Changes in working capital related to exploration, development and acquisition of oil and gas properties		16,057	11,769
Predecessor
Cash flows from operating activities:
Net income (loss)	2,660			(198,950)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	28,065			111,215
Non-cash reorganization items	(44,160)			0
Impairment of oil and gas properties	0			10,000
Abandonment and impairment of unproved properties	0			24,692
Well abandonment costs and dry hole expense	2,931			872
Stock-based compensation	2,116			8,892
Amortization of deferred financing costs and debt premium	374			3,180
Derivative (gain) loss	0			11,234
Derivative cash settlements	0			18,333
Gain on sale of oil and gas properties	0			0
Inventory write-offs	0			4,390
Other	18			(323)
Changes in current assets and liabilities:
Accounts receivable	(6,640)			35,282
Prepaid expenses and other assets	963			(1,838)
Accounts payable and accrued liabilities	(5,880)			(11,616)
Settlement of asset retirement obligations	(331)			(800)
Net cash provided by (used in) operating activities	(19,884)			14,563
Cash flows from investing activities:
Acquisition of oil and gas properties	(445)			(98)
Exploration and development of oil and gas properties	(5,123)			(52,344)
Proceeds from sale of oil and gas properties	0
Payments of contractual obligation	0			(12,000)
Operating bonds	0			(2,672)
Additions to property and equipment - non oil and gas	(454)			(346)
Net cash used in investing activities	(6,022)			(67,460)
Cash flows from financing activities:
Proceeds from credit facility	0			209,000
Payments to credit facility	(191,667)			(96,333)
Proceeds from sale of common stock	207,500			0
Proceeds from exercise of stock options	0			0
Payment of employee tax withholdings in exchange for the return of common stock	(427)			(289)
Deferred financing costs	0			(316)
Net cash provided by (used in) financing activities	15,406			112,062
Net change in cash, cash equivalents, and restricted cash	(10,500)			59,165
Cash and cash equivalents, and restricted cash:
Beginning of period	80,747	70,247		21,582
End of period	70,247			80,747
Supplemental cash flow disclosure:
Cash paid for interest	3,509			58,900
Cash paid for reorganization items	52,968			0
Changes in working capital related to exploration, development and acquisition of oil and gas properties	3,360			(30,044)
Current Credit Facility
Cash flows from financing activities:
Proceeds from credit facility		0	50,000
Current Credit Facility | Predecessor
Cash flows from financing activities:
Proceeds from credit facility	0			0
Prior Credit Facility
Cash flows from financing activities:
Proceeds from credit facility		0	90,000
Payments to credit facility		$ 0	$ (90,000)
Prior Credit Facility | Predecessor
Cash flows from financing activities:
Proceeds from credit facility	0			0
Payments to credit facility	$ 0			$ 0

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2018
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, 2018, the 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 significant intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2018 , through the filing date of this report. On August 6, 2018, the Company sold its equity interests in Bonanza Creek Energy Resources, LLC, which owns all of the outstanding equity interest in Bonanza Creek Energy Upstream LLC and Bonanza Creek Energy Midstream, LLC. These subsidiaries comprised the Company's Mid-Continent region and assets. Please refer to Note 4 - Divestitures for additional discussion. As of December 31, 2017, the balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated. On January 4, 2017, the Company and certain of its subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions,” and the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) to pursue the Debtors’ Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as proposed, the “Plan”). The Bankruptcy Court granted the Debtors' motion seeking to administer all of the Debtors' Chapter 11 Cases jointly under the caption “In re Bonanza Creek Energy, Inc., et al” (Case No. 17-10015). The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017 (the “Effective Date”). Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession during a portion of the year ended December 31, 2017. As such, certain aspects of the bankruptcy proceedings of the Company and related matters are described below in order to provide context and explain part of our financial condition and results of operations for the period presented. Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements after April 28, 2017 are not comparable with the financial statements on or prior to April 28, 2017. The Company's condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after April 28, 2017 and dates prior thereto. Please refer to Note 16 - Fresh-Start Accounting for additional discussion. Subsequent to January 4, 2017 and through the date of emergence, all expenses, gains, and losses directly associated with the reorganization are reported as reorganization items, net in the accompanying consolidated statements of operations and comprehensive income (loss) (“statements of operations”). References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or prior to April 28, 2017. Throughout these financial statements, the Company refers to the 2017 annual period which is comprised of both Successor and Predecessor periods. References to “Current Successor Period” relate to the year ended December 31, 2018. References to “2017 Successor Period” relate to the period of April 29, 2017 through December 31, 2017. References to the “2017 Predecessor Period” and “2016 Predecessor Period” relate to the periods of January 1, 2017 through April 28, 2017 and January 1, 2016 through December 31, 2016, respectively. Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities, and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Going Concern Presumption Our consolidated financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets, and the satisfaction of liabilities and other commitments in the normal course of business. Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. Accounts Receivable The Company’s accounts receivables are generated from oil and gas sales and from joint interest owners on properties that the Company operates. These receivables are generally unsecured. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated. For receivables from joint interest owners, the Company usually has the ability to withhold future revenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables are typically collected within one to two months, and the Company has experienced minimal bad debts. Inventory of Oilfield Equipment Inventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or net realizable value, which approximates fair value. Oil and Gas Producing Activities The Company follows the successful efforts method of accounting for its oil and gas exploration and development costs. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether economically recoverable reserves have been found. If an exploratory well does not find economically recoverable reserves, the costs of drilling the well and other associated costs are charged to dry hole expense. The costs of development wells are capitalized whether the well is productive or nonproductive. Costs incurred to maintain wells and their related equipment and leases as well as operating costs are charged to expense as incurred. Geological and geophysical costs are expensed as incurred. Depletion, depreciation, and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs and anticipated proceeds from salvaging equipment. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets' net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. The factors used to determine fair value are subject to the Company’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows on all developed proved reserves and risk adjusted probable and possible reserves, net of estimated operating and development costs, future commodity pricing based on our internal budgeting model originating from the NYMEX strip price adjusted for basis differential, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. As of December 31, 2018, the Company's gathering assets comprised $120.4 million , $0.9 million , and $0.1 million of proved properties, wells in progress, and unproved properties, respectively, on the accompanying consolidated balance sheets. Lease acquisition costs are reclassified to proved properties and depleted on a unit-of-production basis once proved reserves have been assigned. The Company assesses its unproved properties periodically for impairment on a property-by-property basis, which requires significant judgment. Leases that were not held by production upon emergence from bankruptcy are being amortized off over the remainder of those leases. 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; • its evaluation of the current fair market value of acreage; and • strategic shifts in development areas. For additional discussion, please refer to Note 3 - Impairments . 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 consolidated balance sheets (“balance sheets”). For additional discussion, please refer to Note 11 - 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 to ten years. 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 Footnote 4 - Divestitures for more information. Revenue Recognition Sales of oil, natural gas, and natural gas liquids (“NGLs”) are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. Virtually all of our 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. Please refer to Footnote 2 - Revenue Recognition for more information. The Company records revenues, net of royalties, discounts, and allowances, as applicable, from the sales of crude oil, natural gas, and NGLs when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company factors in historical performance, quality and transportation differentials, commodity prices, and other factors when deriving revenue estimates. Payment is generally received within 30 to 90 days after the date of production. The Company has interests with other producers in certain properties, in which case the Company uses the entitlement method to account for gas imbalances. The Company had no material gas imbalances as of December 31, 2018 and 2017. 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 2017 , 2016 , and 2015 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, 2018 , 2017 , and 2016 , NGL Crude Logistics accounted for 66% , 44% , and 0% of sales, respectively; Lion Oil Trading & Transportation, Inc. accounted for 8% , 18% , and 18% of sales, respectively; and Duke Energy Field Services accounted for 8% , 16% , and 14% of sales, respectively. For the year ended December 31, 2016, Silo Energy, LLC accounted for 50% of sales. Oil and Gas Derivative Activities The Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forward contracts. The contracts were 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 13 - Derivatives . Earnings Per Share Earnings per basic and diluted share within the Successor Company are calculated under the treasury stock method. Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. Diluted net income per common share is calculated by dividing net income 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, which are measured using the treasury stock method. When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. Earnings per basic and diluted share within the Predecessor Company were calculated under the two-class method. Pursuant to the two-class method, the Company’s unvested restricted stock awards with non-forfeitable rights to dividends are considered participating securities. Under the two-class method, earnings per basic share is calculated by dividing net income available to shareholders by the weighted-average number of common shares outstanding during the period. The two-class method includes an earnings allocation formula that determines earnings per share for each participating security according to undistributed earnings for the period. Net income available to shareholders is reduced by the amount allocated to participating restricted shares to arrive at the earnings allocated to common stock shareholders for purposes of calculating earnings per share. Participating shares are not contractually obligated to share in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding shares. Earnings per diluted share is computed on the basis of the weighted-average number of common shares outstanding during the period plus the dilutive effect of any potential common shares outstanding during the period using the more dilutive of the treasury method or two-class method. For additional discussion, please refer to Note 14 - 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 9 - 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. Recently Issued and Adopted Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) Accounting Standards Codification (“ASC”) 606 (“ASC 606”). Several additional related updates were issued since that point. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The guidance also requires enhanced financial statement disclosures over revenue recognition and provisions regarding future revenues and expenses under a gross-versus-net presentation. The standard was required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. We adopted the new standard on January 1, 2018, and its adoption did not have a significant impact on our financial statements. Please refer to Note 2 - Revenue Recognition for additional discussion. In January 2016, the FASB issued Update No. 2016-01 – Financial Instruments - Overall to require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. This authoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. We adopted the new standard on January 1, 2018, and its adoption did not have a material impact on our financial statements and disclosures. Effective January 1, 2017, the Company adopted FASB Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting . The objective of this update was to simplify the current guidance for stock compensation. The areas for simplification involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update is effective for the annual periods beginning after December 15, 2016, and interim periods within those annual periods. As of January 1, 2017, and thereafter, the Company did not have excess tax benefits associated with its stock compensation, and therefore, there was no tax impact upon adoption of this standard. In addition, the employee taxes paid on the statement of cash flows when shares were withheld for taxes have already been classified as a financing activity; therefore, there was no cash flow statement impact upon adoption of this standard. This standard allowed companies to elect to account for forfeitures as they occurred or estimate the number of awards that will vest. The Company elected to account for forfeitures as they occur, resulting in a minimal impact upon adoption of this standard. In August 2016, the FASB issued Update No. 2016-15 - Classification of Certain Cash Receipts and Cash Payments , which clarifies the presentation of specific cash receipts and cash payments within the statement of cash flows. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018, and its adoption did not have a material impact on our consolidated statements of cash flows (“statements of cash flows”) and related disclosures. In November 2016, the FASB issued Update No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash . This update clarifies how entities should present restricted cash and restricted cash equivalents in the statement of cash flows by including them with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statements of cash flows. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018, and the prior period has been adjusted to conform to the current period presentation, which resulted in an increase in cash used in investing activities of $0.1 million for the 2017 Successor and Predecessor Periods, respectively, and $0.2 million for the year ended December 31, 2016. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets that sums to the total of such amounts shown in the accompanying statements of cash flows (in thousands): Successor Predecessor As of December 31, As of 2018 2017 April 28, 2017 December 31, 2016 Cash and cash equivalents $ 12,916 $ 12,711 $ 70,183 $ 80,565 Restricted cash included in other noncurrent assets 86 71 64 182 Total cash, cash equivalents and restricted cash as shown in the statements of cash flows $ 13,002 $ 12,782 $ 70,247 $ 80,747 Restricted cash consists of funds for road maintenance and repairs. In January 2017, the FASB issued U pdate No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business . This update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted this new standard on January 1, 2018 and will apply it to any future acquisitions or disposals of assets or business. In February 2017, the FASB issued Update No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets . This update is meant to clarify existing guidance and to add guidance for partial sales of nonfinancial assets. This guidance is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidance and is effective at the same time as Update 2014-09, Revenue from Contracts with Customers (Topic 606) . We adopted this new standard on January 1, 2018, and its adoption did not have a material impact on our financial statements and disclosures. In May 2017, the FASB issued Update No. 2017-09 Compensation – Stock Compensation (Topic 718) . The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718. Previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. This guidance was effective for annual or any interim periods beginning after December 15, 2017. We adopted this new standard on January 1, 2018. There was no material impact due to the adoption of this guidance. In February 2016, the FASB issued Update No. 2016-02 - Leases (Topic 842) to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Each lease that is recognized in the balance sheet will be classified as either finance or operating, with such classification affecting the presentation within the statements of cash flows. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. The Company adopted this guidance on January 1, 2019, using the modified retrospective approach. As part of the assessment process, the Company utilized external consultants to evaluate agreements under this guidance as well as assess the completeness of the lease population. The types of agreements evaluated under this guidance included the Company’s office leases, corporate asset rentals, drilling rig agreements, well-completion agreements, midstream infrastructure agreements, generator and compressor rentals, various other field equipment rentals, and other arrangements that included potential lease obligations under this guidance. The Company has completed the process of reviewing and determining the contracts and agreements to which the new guidance applies, and has implemented policies, internal controls, and processes that will be necessary to support the Company’s compliance with the additional accounting and disclosure requirements under this guidance. The lease administration system that will support the Company’s compliance with this guidance after adoption is operational and currently being populated with the necessary lease data and relevant assumptions. Policy elections made by the Company as allowed under this guidance include (a) not recognizing leases with terms that are less than twelve months on the balance sheet, (b) combining lease and non-lease components as a single lease, (c) and applying practical expedients, which allow the Company to avoid reassessing contracts that commenced prior to adoption and were correctly classified under ASC 840. Adoption of this guidance will result in right-of-use assets and right-of-use liabilities on the balance sheets; however, the Company is not in a position to provide an estimate of the full quantitative impacts at this time. In January 2018, the FASB issued Update 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 , which permits an entity to elect an optional transition practical expedient to not evaluate land easements existing or expiring before the entity's adoption of Update 2016-02 and not previously accounted for as leases. An entity that elects this practical expedient should evaluate new or modified land easements under this guidance beginning at the date Update 2016-02 is adopted. The Company plans to elect this practical expedient option at the same time it adopts Update 2016-02. In July 2018, the FASB issued Update No. 2018-11, Leases (Topic 842): Targeted Improvements , which provides for an additional transition method that allows an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings (deficit) in the period of adoption. The Company plans to elect this transition method, which will eliminate the need for adjusting prior period comparable financial statements prepared under current lease accounting guidance. The Company will adopt this guidance at the same time it adopts Update 2016-02. In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement . The objective of this update is to improve the effectiveness of fair value measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the Company's disclosures. In August 2018, the Securities and Exchange Commission, (“SEC”) issued a final rule, Disclosure Update and Simplification, that updates and simplifies SEC disclosure requirements. The primary changes include removing the requirement to disclose outside of the consolidated financial statements historical and pro forma ratios of earnings to fixed charges and historical low and high trading prices of the Company's common stock and adding a requirement to provide within the interim financial statements an analysis of changes in stockholders' equity for the current and comparative quarterly and year-to-date periods. Other changes included requirements related to segment, geographic area and dividend disclosures. The final rule was effective November 5, 2018. The Company adopted

REVENUE RECOGNITION

REVENUE RECOGNITION	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
REVENUE RECOGNITION	REVENUE RECOGNITION On January 1, 2018, the Company adopted ASC 606, using the modified retrospective approach for all applicable contracts at the date of initial adoption. Results for reporting periods beginning January 1, 2018 are presented in accordance with ASC 606, while prior period amounts are reported in accordance with ASC 605 - Revenue Recognition. The impact of adoption is as follows (in thousands): Year Ended December 31, 2018 As Unadjusted (1) ASC 606 Adjustments As Reported Operating Revenues: Oil sales $ 228,661 $ — $ 228,661 Natural gas sales 18,076 4,293 22,369 NGLs sales 20,188 5,439 25,627 Oil and gas sales $ 266,925 $ 9,732 $ 276,657 Operating expenses: Gathering, transportation and processing $ — $ 9,732 $ 9,732 Net income $ 168,186 $ — $ 168,186 ____________________ (1) This column excludes the impact of ASC 606 and is consistent with the presentation prior to January 1, 2018. Revenue from Contracts with Customers 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. Virtually all of our 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. Performance Obligations Oil Sales Under our oil sales contracts we sell oil production at the wellhead, or other contractually agreed-upon delivery points, and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead, tank outlet, lease automatic custody transfer meter, or other contractually agreed-upon delivery point, at the net contracted price received. Natural Gas and NGLs Sales Under our natural gas processing contracts, we deliver 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 we maintain control through the outlet of the midstream processing facility, we recognize revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in our consolidated 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, we recognize revenue on a net basis. Working Interest Partners The Company and its working interest partners have entered into joint operating agreements, which govern the marketing and selling of the working interest partners' share of oil, natural gas, and NGLs. When selling oil, natural gas, and NGLs on behalf of working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. Transaction Price As noted above, the transaction price is generally tied to a market index, net of adjustments or price differentials, with the variable consideration being the estimation process and related accruals; however, any identified differences between our revenue estimates and actual revenue received historically have not been significant. As further described in Note 8 - Commitments and Contingencies , one contract with NGL Crude Logistics, LLP (“NGL”, known as the “NGL agreement”) 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 agreement based on approved production plans to determine if liquidated damages to NGL are probable. As of December 31, 2018, the Company believes that the volumes delivered to NGL will be in excess of the MVCs required then and during 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 agreement. Transaction Price Allocated to Remaining Performance Obligations Under our sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and the transaction price for remaining performance obligations is determined in accordance with the preceding section during the period in which the performance obligation is satisfied. For our product sales that have a contract term of one year or less, we applied the practical expedient under the guidance, which states that a Company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Contract Balances Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities under this guidance. At December 31, 2018 and December 31, 2017, our receivables from contracts with customers were $31.8 million and $28.5 million , respectively. Prior-Period Performance Obligations We record revenue in the month production is delivered to the purchaser. However, 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, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the period from January 1, 2018 through December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

IMPAIRMENTS

IMPAIRMENTS	12 Months Ended
	Dec. 31, 2018
Tangible Asset Impairment Charges [Abstract]
IMPAIRMENTS	IMPAIRMENTS During 2018, the Company incurred its standard annual amortization of $5.3 million on its emergence leases that were not held by production at the time of our emergence as disclosed in the abandonment and impairment of unproved properties line item in the accompanying statements of operations. There were no impairments for the year ended December 31, 2017. During the first quarter of 2016, the Company impaired its oil and gas properties in the Mid-Continent region by $10.0 million , based upon the most recent bid for the assets received while the assets were held for sale. The Company also recorded unproved properties impairments of $24.7 million for non-core leases expiring within the Wattenberg Field. For additional discussion, please refer to Note 12 - Fair Value Measurements.

DIVESTITURES

DIVESTITURES	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
DIVESTITURES	DIVESTITURES During the first quarter of 2018, the Company established a plan to sell all of the Company's assets within its Mid-Continent region and North Park Basin in order to focus on and partially fund the development of our core assets in the Wattenberg Field in Colorado, at which point they were deemed held for sale. The Company sold its North Park Basin assets on March 9, 2018 for minimal net proceeds and full release of all current and future obligations resulting in a minimal net loss. As of December 31, 2017, the assets within the Company's North Park Basin represented $5.4 million , net of accumulated depreciation, depletion, and amortization; and a corresponding asset retirement obligation liability of approximately $5.4 million . On August 6, 2018, the Company entered into an agreement to simultaneously close and divest of all of its assets within its Mid-Continent region. Net proceeds from the sale amounted to $102.9 million , subject to customary post-closing adjustments, resulting in a gain of approximately $27.3 million , included in the gain on sale of properties line item in the accompanying statements of operations. The original purchase price of $117.0 million was subject to customary purchase-price adjustments, comprised of operational cash activity related to the Mid-Continent assets, for the time period between the effective date of February 1, 2018 and the closing date of August 6, 2018. The divestiture did not represent a strategic shift and is not expected to have a significant effect on the Company's operations or financial results; therefore, the disposal did not meet the criteria of discontinued operations.

OTHER NONCURRENT ASSETS

OTHER NONCURRENT ASSETS	12 Months Ended
	Dec. 31, 2018
Other Assets [Abstract]
OTHER NONCURRENT ASSETS	OTHER NONCURRENT ASSETS Other noncurrent assets contain the following (in thousands): Successor As of December 31, 2018 2017 Operating bonds $ 2,713 $ 2,683 Deferred financing costs 1,710 — AMT credit refund (1) 376 376 Restricted cash 86 71 Other noncurrent assets $ 4,885 $ 3,130 ______________________________________ (1) Represents the alternative minimum tax credit refund due to the Company upon application of the newly enacted comprehensive tax legislation that took effect on December 22, 2017.

ACCOUNTS PAYABLE AND ACCRUED EX

ACCOUNTS PAYABLE AND ACCRUED EXPENSES	12 Months Ended
	Dec. 31, 2018
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND ACCRUED EXPENSES	ACCOUNTS PAYABLE AND ACCRUED EXPENSES Accounts payable and accrued expenses contain the following (in thousands): Successor As of December 31, 2018 2017 Drilling and completion costs $ 33,602 $ 21,833 Accounts payable trade 11,532 6,256 Accrued general and administrative cost 12,728 10,025 Lease operating expense 2,183 5,005 Accrued interest 241 250 Accrued oil and gas hedging — 808 Production and ad valorem taxes and other 19,104 17,952 Total accounts payable and accrued expenses $ 79,390 $ 62,129

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Successor Debt Current Credit Facility On December 7, 2018, the Company entered into a reserve-based revolving facility, as the borrower, with JPMorgan Chase Bank, N.A., as the administrative agent, and a syndicate of financial institutions, as lenders (the “Current Credit Facility”). The Current Credit Facility has an aggregate original commitment amount of $750.0 million and matures on December 7, 2023. The initial borrowing base is $350.0 million , and there are no scheduled borrowing base redeterminations until May 1, 2019, with subsequent semi-annual redeterminations thereafter. Borrowings under the Current Credit Facility will bear interest at a per annum rate equal to, at the option of the Company, either (i) a London InterBank Offered Rate (“LIBOR”), subject to a 0% LIBOR floor plus a margin of 1.75% to 2.75% , based on the utilization of the Current 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 and (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 Current 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 Current Credit Facility is guaranteed by all wholly owned domestic subsidiaries of the Company (each, a “Guarantor” and, together with the Company, the “Credit Parties”), and is secured by first priority security interests on substantially all assets of each Credit Party, subject to customary exceptions. The Current Credit Facility contains customary representations and affirmative covenants. The Current 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, and (xix) sales or discounts of receivables (xx) dividend payments. The Credit Parties are subject to certain financial covenants under the Current Credit Facility, including, without limitation, tested on the last day of each fiscal quarter, (i) a maximum ratio of the Company’s consolidated indebtedness (subject to certain exclusions) to adjusted EBITDAX of 4.00 to 1.00 and (ii) a current ratio, as defined in the agreement, inclusive of the unused Commitments then available to be borrowed, to not be less than 1.00 to 1.00 . The Company had $50.0 million outstanding on the Current Credit Facility as of December 31, 2018 and had no amounts outstanding under the credit facility in effect as of December 31, 2017 . In connection with the Current Credit Facility, the Company capitalized $2.2 million in deferred financing costs, of which, $1.7 million and $0.5 million of the total amounts capitalized are presented within other noncurrent assets and prepaid expenses and other line items, respectively, in the accompanying balance sheets as of December 31, 2018. Prior Credit Facility On the Effective Date, the Company entered into a new revolving credit facility, as the borrower, with KeyBank National Association, as the administrative agent, and certain lenders party thereto (the “Prior Credit Facility”). The new borrowing base of $191.7 million was redetermined semiannually, as early as April and October of each year. The original maturity date of this Prior Credit Facility was March 31, 2021. The Prior Credit Facility restricted, among other items, certain dividend payments, additional indebtedness, purchase of margin stock, asset sales, loans, investments, and mergers. The Prior Credit Facility also contains certain financial covenants, which require the maintenance of certain financial and leverage ratios, as defined by the Prior Credit Facility. The Prior Credit Facility stated that beginning with the fiscal quarter ending September 30, 2017, and each following fiscal quarter through the maturity of the Prior Credit Facility, the Company's leverage ratio of indebtedness to EBITDAX was not to exceed 3.50 to 1.00 . Beginning also with the fiscal quarter ending September 30, 2017, and each following fiscal quarter, the Company was required to maintain a minimum current ratio of 1.00 to 1.00 and a minimum interest coverage ratio of trailing twelve-month EBITDAX to trailing twelve-month interest expense of 2.50 to 1.00 as of the end of the respective fiscal quarter. The Prior Credit Facility also required the Company maintain a minimum asset coverage ratio of 1.35 to 1.00 as of the fiscal quarters ending September 30, 2017 and December 31, 2017. The minimum asset coverage ratio was only applicable until the first redetermination in April of 2018. As of December 31, 2017, and through the filing date of this report, the Company is in compliance with all of the Prior Credit Facility covenants. Our obligations under the Prior Credit Facility were secured by first priority liens on all of our property and assets (whether real, personal, or mixed, tangible or intangible), including our proved reserves and our oil and gas properties (which term was defined to include fee mineral interests, term mineral interests, leases, subleases, farm-outs, royalties, overriding royalties, net profit interests, carried interests, production payments, back in interests, and reversionary interests). The Prior Credit Facility was guaranteed by the Company and all of its direct and indirect subsidiaries. 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 dissolved and settled in full as of December 7, 2018. Predecessor Debt Predecessor Credit Facility The predecessor credit facility, dated March 29, 2011, as amended, with a syndication of banks, provided for a total credit facility size of $1.0 billion . The predecessor 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 1.50% to 2.50% depending on the utilization level, and the base rate borrowings bore interest at the “Bank Prime Rate,” as defined in the predecessor credit facility, plus 0.50% to 1.50% . The borrowing base on the predecessor credit facility was $150.0 million on October 31, 2016. As of December 31, 2016, the Company had $191.7 million outstanding under the credit facility and had a borrowing base deficiency of $41.7 million . Predecessor Senior Unsecured Notes The $500.0 million aggregate principal amount of 6.75% Senior Notes that, prior to the Company's Chapter 11 filing, matured on April 15, 2021 and the $300.0 million aggregate principal amount of 5.75% Senior Notes that matured on February 1, 2023 were unsecured senior obligations. On the Effective Date, by operation of the Plan, all outstanding obligations under the Senior Notes were canceled and 9,481,610 shares of the Company's new common stock were issued. Please refer to Note 15 - Chapter 11 Proceedings and Emergence for additional discussion.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2018
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 material pending or overtly threatened legal actions against the Company of which it is aware. Following negotiations with the Colorado Department of Public Health and Environment (“CDPHE”), over self-reported air quality noncompliance, on October 3, 2017, the Company agreed to a Compliance Order on Consent (the “COC”) with the CDPHE. As part of the COC, the Company was required to pay a $0.2 million penalty. Additionally, as further required by the COC, the Company will perform certain mitigation projects and adopt certain procedures and processes addressing the monitoring, reporting, and control of air emissions with respect to the Company's storage tank facilities in the Wattenberg Field. The COC further set forth compliance requirements and criteria for continued operations and contains provisions regarding, record-keeping, modifications to the COC, circumstances under which the COC may terminate with respect to certain wells and facilities, and the sale or transfer of operational or ownership interests covered by the COC. In order to be in compliance, the Company incurred $1.2 million and $0.7 million in 2018 and 2017, respectively, and currently anticipates spending $3.1 million for 2019 through 2022. The COC can be terminated after four years with a showing of substantial compliance and CDPHE approval. 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 Company estimates that $2.3 million of the reimbursement is due to the Company’s associated interest owners as shown in the accounts payable and accrued expenses line item in the accompanying balance sheets. The remaining net settlement amount of $5.1 million is presented as a reimbursement in the accompanying statements of operations within the severance and ad valorem taxes line item. This net settlement amount will be further reduced to reflect the reimbursement to the State of Colorado of a certain amount of severance tax credits received in connection with ad valorem taxes historically paid by the Company. In February 2019, the Company was sent a notice of intent to sue (“NOI”) letter by WildEarth Guardians (“WEG”), alleging failure to obtain required permits under the federal Clean Air Act before constructing and operating well production facilities in the ozone non-attainment area around the Denver Metropolitan and North Front Range of Colorado, among other things. The NOI letter appears to challenge long-established federal and state regulations and policies for permitting the construction and initial operation of upstream oil and gas production facilities in Colorado and elsewhere under the Clean Air Act and state counterpart statutes. Because the allegations made in the NOI letter are based on novel and unprecedented interpretations of complex federal and state air quality laws and regulations, it is not possible for the Company to determine at this time whether the allegations have merit or will lead to actual suit by WEG against the Company, but the Company will vigorously defend against such allegations if sued, and will coordinate as much as possible with state and federal permitting authorities to maintain the validity of its current and future air permits for such facilities. Commitments Upon emergence from bankruptcy, the new purchase agreement to deliver fixed determinable quantities of crude oil with NGL Crude Logistics, LLC became effective and the original purchase agreement with NGL was canceled. The terms of the new NGL agreement consists of defined volume commitments over an initial seven -year term. Under the terms of the new NGL agreement, the Company will be required to make periodic deficiency payments for any shortfalls in delivering minimum volume commitments, which are set in six-month periods beginning in January 2018. There were no minimum volume commitments for the year ending December 31, 2017. During 2018, the average minimum volume commitment was approximately 10,100 barrels per day and increases by approximately 41% from 2018 to 2019 and approximately 3% each year for the remainder of the contract, to a maximum of approximately 16,000 barrels per day. The aggregate financial commitment fee over the seven -year term, based on the minimum volume commitment schedule (as defined in the agreement) and the applicable differential fee, is $136.3 million as of December 31, 2018 . Upon notifying NGL at least twelve months prior to the expiration date of the new NGL agreement, the Company may elect to extend the term of the new NGL agreement for up to three additional years. The Company rejected its Denver office lease, which was confirmed in the Plan. On April 29, 2017, the Company entered into a new office lease agreement to rent office facilities. The lease is non-cancelable and expires in February 2022. Rent expense was $0.9 million for the year ended December 31, 2018, 2017 Successor Period, and 2017 Predecessor Period and $2.8 million for the year ended December 31, 2016. The annual minimum commitment payments on the new NGL agreement and the new office lease for the next five years as of December 31, 2018 are presented below (in thousands): NGL Commitments (1) Office Lease Commitments (2) Total 2019 $ 19,580 1,256 20,836 2020 27,949 1,351 29,300 2021 28,791 1,401 30,192 2022 29,485 234 29,719 2023 30,448 — 30,448 2024 and thereafter — — — Total $ 136,253 4,242 140,495 ____________________ (1) The above calculation is based on the minimum volume commitment schedule (as defined in the new NGL agreement) and applicable differential fees. (2) The Company has subleased a portion of its office lease. The contractual amounts disclosed are presented gross, excluding total sublease income of $1.4 million .

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION 2017 Long Term Incentive Plan Upon emergence from bankruptcy, the Company adopted a new Long Term Incentive Plan (the “2017 LTIP”), as established by the pre-emergence Board, which allows for the issuance of restricted stock units, performance stock units, and stock options. On the Effective Date, the Company reserved 2,467,430 shares of the new common stock for issuance under its 2017 Long Term Incentive Plan. See below for further discussion of awards granted under the 2017 LTIP. Inducement Awards During the year ended December 31, 2018, the Company granted inducement awards in the form of RSUs separate and distinct from the 2017 LTIP. The total number of inducement awards granted to employees during the year ended December 31, 2018 was 170,613 representing a total fair value of $4.6 million . Restricted Stock Units The 2017 LTIP, established by the pre-emergence Board, allows for the issuance of RSUs to members of the Board of Directors and employees of the Company at the discretion of the Board of Directors. Each RSU represents one share of the Company's new 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. During June 2017, the Company granted 63,894 RSUs to non-executive members of the Board of Directors, with a fair value of $2.3 million . This grant is intended to cover a three -year period, and the RSUs will vest in equal installments on each of the first three anniversaries. The vested shares will be released upon the earlier of the third anniversary of the grant date, a change of control, or the director's separation from the Company. Total expense recorded for RSUs, inclusive of the Board of Director grants, for the Current and 2017 Successor Periods was $5.2 million and $7.9 million , respectively. The fair value of the RSUs granted from the 2017 LTIP during the Current and 2017 Successor Periods was $6.2 million and $13.4 million , respectively. As of December 31, 2018, unrecognized compensation cost related to all RSUs was $10.2 million and will be amortized through 2023 . A summary of the status and activity of non-vested restricted stock units is presented below: Restricted Stock Units Weighted- Average Grant-Date Fair Value Non-vested at beginning of 2017 Successor Period — $ — Granted 452,996 $ 34.62 Vested (173,200 ) $ 34.19 Forfeited (18,631 ) $ 34.36 Non-vested as of December 31, 2017 261,165 $ 34.93 Granted 387,720 $ 27.80 Vested (84,345 ) $ 30.63 Forfeited (83,705 ) $ 29.78 Non-vested as of December 31, 2018 480,835 $ 30.83 Cash flows resulting from excess tax benefits are to be classified as part of cash flows from financing 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 Current and 2017 Successor Periods. Performance Stock Units The 2017 LTIP, established by the pre-emergence Board, allows for the issuance of PSUs to employees at the sole discretion of the Board of Directors. The number of shares of the Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded. The PSUs vest in their entirety at the end of the three-year performance period. The total number of PSUs granted is evenly split between two performance criterion. 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 average annual return on capital employed (“ROCE”) for each year during the three-year performance period. Compensation expense associated with PSUs is recognized as general and administrative expense over the performance period. The fair value of the PSUs was measured at the grant date with 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 PSUs, the Company could not predict with certainty the path its stock price or the stock prices of its peers would take over the performance period. By using a stochastic simulation, the Company created multiple prospective stock pathways, statistically analyzed these simulations, and ultimately made inferences regarding the most likely path the stock price would take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Brownian Motion Model, was deemed an appropriate method by which to determine the fair value of the portion of the PSUs tied to the TSR. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the performance period, as well as the volatilities for each of the Company’s peers. The following table presents the assumptions used to determine the fair value of the TSR portion of the PSUs: For the Year Ended December 31, 2018 Expected term of award (in years) 3 Risk-free interest rate 2.76 % Expected daily volatility 2.6 % During the Current Successor Period, the Company recognized compensation expense for the PSUs of $0.6 million . The fair value of the PSUs granted during the Current Successor Period was $1.8 million . As of December 31, 2018, unrecognized compensation cost was $1.2 million and will be amortized through 2020. A summary of the status and activity of performance stock units is presented below: Performance Stock Units Weighted- Non-vested as of December 31, 2017 — $ — Granted (1) 59,641 $ 29.92 Forfeited (5,952 ) $ 29.92 Non-vested as of December 31, 2018 53,689 $ 29.92 ______________________________ (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 times the number of units awarded, depending on the level of satisfaction of the performance condition. Stock Options The 2017 LTIP, established by the pre-emergence Board, allows for the issuance of stock options to the Company's employees at the sole discretion of the Board of Directors. Options expire ten years from the grant date unless otherwise determined by the Board of Directors. Compensation expense on the stock options are recognized as general and administrative expense over the vesting period of the award. There were no stock options granted during the Current Successor Period. Total expense recorded for stock options for the Current and 2017 Successor Periods was $1.4 million and $3.7 million , respectively. The fair value of the stock options granted during the 2017 Successor Period was $6.8 million . As of December 31, 2018, unrecognized compensation cost was $0.8 million and will be amortized through 2020 . Stock options were valued using a Black-Scholes Model using the following assumptions: For the Year Ended December 31, 2017 Expected volatility 52.1 % Expected dividends — % Expected term (years) 6.0 Risk-free interest rate 1.96 % 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. 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 is presented below: Stock Options Weighted- Average Exercise Price Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding at beginning of Current Successor Period — $ — — $ — Granted 389,102 34.36 — $ — Exercised — — — $ — Forfeited (191,831 ) 34.36 9.3 $ — Outstanding as of December 31, 2017 197,271 $ 34.36 9.3 $ — Granted — — — $ — Exercised (32,037 ) 34.36 — $ — Forfeited (32,425 ) 34.36 — $ — Outstanding as of December 31, 2018 132,809 $ 34.36 6.7 $ — Options outstanding and exercisable as of December 31, 2018 61,880 $ 34.36 4.8 $ — Predecessor Long Term Incentive Plan The Company’s Predecessor Long Term Incentive Plan (the “Predecessor Plan”) had different forms of equity issuances allowed under it, including restricted stock, performance stock units, and long term incentive plan units (“predecessor awards”), as further described in this section. Upon emergence from bankruptcy, the Company's predecessor awards were canceled. Restricted Stock under the Predecessor Long Term Incentive Plan The Company granted shares of restricted stock to directors, eligible employees, and officers under its Predecessor Plan. Each share of restricted stock represented one share of the Company’s common stock to be released from restriction upon completion of the vesting period. The awards typically vested in one-third increments over three years. Each share of restricted stock was entitled to a non-forfeitable dividend, if the Company were to declare one, and has the same voting rights as a share of the Company’s common stock. Shares of restricted stock were valued at the closing price of the Company’s common stock on the grant date and were recognized as general and administrative expense over the vesting period of the award . The Company granted no shares of restricted stock under the Predecessor Plan during the 2017 or 2016 Predecessor Periods. The Company granted 568,832 shares of restricted stock under the Predecessor Plan to certain employees during 2015. The fair value of the restricted stock granted in 2015 was $13.8 million . The Company recognized compensation expense of $1.2 million and $6.1 million for the 2017 and 2016 Predecessor Periods, respectively. There were no shares of restricted stock granted to non-employee directors under the Predecessor Plan during the 2017 Predecessor Period. During the year ended December 31, 2016, the Company issued 113,044 shares of restricted common stock under the Predecessor Plan to its non-employee directors. The Company recognized compensation expense of $0.04 million and $0.7 million for the 2017 and 2016 Predecessor Periods, respectively. These awards vested approximately one year after issuance. A summary of the status and activity of non-vested restricted stock is presented below: Predecessor January 1, 2017 through April 28, 2017 For the Year Ended December 31, 2016 Restricted Stock Weighted- Average Grant-Date Fair Value Restricted Stock Weighted- Average Grant-Date Fair Value Non-vested at beginning of year 368,887 $ 19.45 731,818 $ 29.47 Granted — $ — 113,044 $ 0.98 Vested (111,996 ) $ 32.22 (355,498 ) $ 31.68 Forfeited (5,134 ) $ 29.55 (120,477 ) $ 27.34 Canceled (251,757 ) $ 13.08 — $ — Non-vested at end of period — $ — 368,887 $ 19.45 The Company recorded no excess tax benefits for the 2017 and 2016 Predecessor Periods. Performance Stock Units under the Predecessor Long Term Incentive Plan The Company granted PSUs to certain officers under its Predecessor Plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranged from zero to two times the number of PSUs awarded. PSUs were determined at the end of each annual measurement period over the course of the three -year performance cycle in an amount up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equal to 200% of the target number of PSUs may be earned during the performance cycle), although no stock was actually awarded to the participant until the end of the entire three -year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited. The performance criteria for the PSUs is based on a comparison of the Company’s TSR for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. Compensation expense associated with PSUs was recognized as general and administrative expense over the measurement period. The TSR for the Company and each of the peer companies was determined by dividing (A)(i) the average share price for the last 30 trading days of the applicable measuring period, minus (ii) the average share price for the 30 trading days immediately preceding the beginning of the applicable measuring period, by (B) the average share price for the 30 trading days immediately preceding the beginning of the applicable measuring period. The number of earned shares of the Company's common stock was calculated based on which quartile its TSR percentage ranks as of the end of the annual measurement period relative to the other companies in the comparator group. The fair value of the PSUs was measured at the grant date with a stochastic process method using a Monte Carlo 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 PSUs, 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 Monte Carlo Model, was deemed an appropriate method by which to determine the fair value of the PSUs. 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 measurement period, as well as the volatilities for each of the Company’s peers. The Company granted no PSUs under the Predecessor Plan during the 2017 and 2016 Predecessor Periods. The Company recognized compensation expense for the Predecessor Company of $0.5 million and $1.8 million for the 2017 and 2016 Predecessor Periods, respectively, relating to the 2015 PSUs. A summary of the status and activity of PSUs is presented in the following table: Predecessor January 1, 2017 through April 28, 2017 For the Year Ended December 31, 2016 PSU Weighted-Average PSU Weighted-Average Non-vested at beginning of year (1) 21,538 $ 33.31 114,833 $ 35.27 Granted (1) — $ — — $ — Vested (1) — $ — (59,725 ) $ 36.61 Forfeited (1) — $ — (33,570 ) $ 35.55 Canceled (1) (21,538 ) $ 33.31 — $ — Non-vested at end of period (1) — $ — 21,538 $ 33.31 ___________________________ (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 times the number of PSUs awarded, depending on the level of satisfaction of the performance condition. During the 2017 Predecessor Period the third tranche of the 2015 awards had a zero -times multiplier, in accordance with the terms of the respective PSU awards. During the year ended December 31, 2016, the third tranche of the 2014 awards and the second tranche of the 2015 awards had a zero-times multiplier, in accordance with the terms of the respective PSU awards. Predecessor Long Term Incentive Plan Units The Company granted no Predecessor LTIP units (“units”) during the 2017 Predecessor Period. During the year end December 31, 2016, the Company granted 2,958,558 units for a total fair value $2.9 million , that settled in shares of the Company's common stock upon vesting. The units would vest in one-third increments over three years. The units contained a share price cap of $26 that incrementally decreases the number of shares of the Company's common stock that will be released upon vesting if the Company's common stock were to exceed the share price cap. Total expense recorded for the units for the Predecessor Company for the 2017 and 2016 Predecessor Periods was $0.4 million and $0.9 million , respectively. A summary of the status and activity of non-vested units for the 2017 and 2016 Predecessor Periods is presented below. Predecessor January 1, 2017 through April 28, 2017 For the Year Ended December 31, 2016 LTIP Units Weighted- LTIP Units Weighted- Non-vested at beginning of year 2,443,402 $ 0.99 — $ — Granted — $ — 2,958,558 $ 0.99 Vested (767,848 ) $ 0.98 — $ — Forfeited (126,616 ) $ 0.98 (515,156 ) $ 0.98 Canceled (1,548,938 ) $ 0.99 — $ — Non-vested at end of period — $ — 2,443,402 $ 0.99 401(k) Plan The Company has a defined contribution retirement plan (the “401(k) Plan”) that is subject to the Employee Retirement Income Security Act of 1974. The 401(k) Plan allows eligible employees to contribute up to the contribution limits established under the IRC. The Company matches each employee’s contribution up to six percent of the employee’s base salary. The Company’s matching contributions to the 401(k) Plan were $1.1 million , $0.6 million , $0.6 million , and $2.0 million for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and the year ended December 31, 2016 , respectively.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax basis of assets and liabilities and amounts reported in the Company’s balance sheets. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes. The provision for income taxes consists of the following (in thousands): Successor Predecessor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 Current tax benefit Federal $ — $ 376 $ — $ — State — — — — Deferred tax benefit — — — — Total income tax benefit $ — $ 376 $ — $ — Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax liability result from the following components (in thousands): Successor As of December 31, 2018 2017 Deferred tax liabilities: Oil and gas properties $ 52,006 $ — Derivative liability 8,527 — Total deferred tax liabilities 60,533 — Deferred tax assets: Federal and state tax net operating loss carryforward 137,567 117,115 Oil and gas properties — 1,319 Derivative liability — 3,457 Reclamation costs 7,251 9,516 Stock compensation 1,635 1,419 Accrued compensation 1,308 1,285 Inventory 1,577 1,529 Settlement liabilities — — AMT credit — — State bonus depreciation addback — 1,089 Other long-term assets 271 231 Total deferred tax assets 149,609 136,960 Less: Valuation allowance 89,076 136,960 Total deferred tax assets after valuation allowance — — Total non-current net deferred tax liability $ — $ — The Company has $577.6 million and $470.3 million of net operating loss carryovers for federal income tax purposes as of December 31, 2018 and 2017, respectively. Federal net operating loss carryforwards incurred prior to January 1, 2018 of $470.3 million will begin to expire in 2036. Federal net operating loss carryforwards incurred after December 31, 2017 of $107.3 million have no expiration and can only be used to offset 80% of taxable income when utilized. 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, rate changes, and other permanent differences, as follows (in thousands): Successor Predecessor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 Federal statutory tax (expense) benefit by applying the statutory rate $ 35,319 $ 1,889 $ (931 ) $ 69,633 Decrease (increase) in tax resulting from: State tax expense net of federal benefit 6,556 172 (85 ) 6,358 Prior year true-up (458 ) — (7,572 ) — Stock compensation 854 — (1,773 ) — Permanent differences 61 (715 ) (35,273 ) — Rate change (421 ) (73,956 ) — — NOL Adjustment 5,973 — — — Other — (642 ) — (317 ) Valuation allowance (47,884 ) 73,628 45,634 (75,674 ) Total income tax benefit $ — $ 376 $ — $ — During the year ended December 31, 2018 , the decrease in tax rate was primarily due to placing a valuation allowance against net deferred tax assets. There was no deferred income tax benefit or expense in the accompanying statements of operations. The valuation allowance decreased to $89.1 million in 2018 due to improvement of operational results. Net operating losses are inherently subject to changes in ownership. The net operating loss adjustment was derived from the write-off of the Company's Mid-continent tax attributes upon the sale of those assets. During the year ended December 31, 2017, the decrease in tax rate was primarily due to the enactment of the Tax Cuts and Jobs Act (“Tax Act”). There was $0.4 million of current income tax benefits in the accompanying statements of operations due to the AMT payments being refunded as prescribed in the Tax Act. The valuation allowance decreased to $137.0 million in 2017 due to decreased tax rate as mandated by the Tax Act. During the year ended December 31, 2016, the decrease in tax rate was primarily due to placing a valuation allowance against net deferred tax assets. There was no deferred income tax benefit or expense in the accompanying statements of operations. The valuation allowance increased to $256.2 million in 2016 due to continued deterioration of our operational results. The Company had no unrecognized tax benefits as of December 31, 2018 , 2017 , and 2016 .

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2018
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 and ranges from 8% to 18% for the Predecessor Company and ranges from 5% to 7% for the Successor Company. Upon the Company's emergence from bankruptcy, as discussed in Note 15 - Chapter 11 Proceedings and Emergence and Note 16 - Fresh-Start Accounting , the Company applied fresh-start accounting. This included adjusting the asset retirement obligations based on the estimated fair values at April 28, 2017. A roll-forward of the Company’s asset retirement obligation is as follows (in thousands): Balance as of January 1, 2017 (Predecessor) $ 30,833 Liabilities settled (218 ) Accretion expense 1,045 Ending balance as of April 28, 2017 (Predecessor) $ 31,660 Fair value fresh-start adjustment $ (2,599 ) Beginning balance as of April 29, 2017 (Successor) $ 29,061 Additional liabilities incurred 130 Accretion expense 1,370 Liabilities settled (780 ) Revisions to estimate 8,481 Ending balance as of December 31, 2017 (Successor) $ 38,262 Additional liabilities incurred 373 Accretion expense 1,831 Liabilities settled (1,627 ) Revisions to estimate 1,490 Sold properties (10,924 ) Ending balance as of December 31, 2018 (Successor) 29,405 Revisions to the liability could occur due to changes in the estimated economic lives, abandonment costs of the wells, inflation rates, credit-adjusted risk-free rates, along with newly enacted regulatory requirements. Revisions to estimates for the year ended December 31, 2018 were primarily a result of an increase in the credit-adjusted risk-free rate applied at year-end and an increase in the inflation rate on wells that had an asset retirement obligation as of the beginning of the year, offset by a slight decrease in abandonment costs. Revisions to estimates for the 2017 Successor Period were a result of a decrease in the credit-adjusted risk-free rate applied at year-end, decreased estimated economic well lives, and an increase in abandonment costs.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2018
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. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1: Quoted prices are available in active markets for identical assets or liabilities Level 2: Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable Level 3: Significant inputs to the valuation model are unobservable Financial and non-financial assets and liabilities are to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of December 31, 2018 and 2017 and their classification within the fair value hierarchy: Successor As of December 31, 2018 Level 1 Level 2 Level 3 (in thousands) Derivative assets (1) $ — $ 38,272 $ — Derivative liabilities (1) $ — $ 183 $ — Asset retirement obligations (2) $ — $ — $ 1,490 Successor As of December 31, 2017 Level 1 Level 2 Level 3 (in thousands) Derivative assets (1) $ — $ 494 $ — Derivative liabilities (1) $ — $ 14,395 $ — Asset retirement obligations (2) $ — $ — $ 8,481 _______________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion. Derivatives Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps and collars were validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and were designated as Level 2 within the valuation hierarchy. Proved Oil and Gas Properties Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. Depending on the availability of data, the Company uses Level 3 inputs and either the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of risk-adjusted discount rates and price forecasts selected by the Company’s management, or the market valuation approach. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the Company's internal budgeting model derived from the NYMEX strip pricing, adjusted for management estimates and basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no oil and gas property impairments during the years ended December 31, 2018 and 2017. For the year ended December 31, 2016, the Company impaired its oil and gas properties in the Mid-Continent region by $10.0 million , reflecting the difference between their $110.0 million carrying value and their $100.0 million fair value. For additional discussion on impairments, please refer to Note 3 - Impairments . Unproved Oil and Gas Properties Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be fully recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, remaining lease life, and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant estimated selling price is not available, the Company uses the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. During 2018, the Company incurred its standard annual amortization of $5.3 million on its emergence leases that were not held by production as disclosed in the abandonment and impairment of unproved properties line item in the accompanying statements of operations. There were no unproved oil and gas property impairments during the year ended December 31, 2017. During the year ended December 31, 2016, the Company impaired non-core acreage in the Wattenberg Field due to lease expirations, which had a carrying value of $187.4 million , to its fair value of $162.7 million , and recognized an impairment of unproved properties of $24.7 million . Asset Retirement Obligation The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. The Company had $1.5 million and $8.5 million of asset retirement obligations recorded at fair value as of December 31, 2018 and 2017 , respectively. Long-term Debt Upon emergence from bankruptcy, the Company's Senior Notes were canceled and the predecessor credit facility was paid in full. The Company's credit facility approximates fair value as the applicable interest rates are floating. The Company had $50.0 million outstanding under the credit facility as of December 31, 2018. There were no long-term debt amounts outstanding as of December 31, 2017.

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2018
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, collar, and put arrangements for oil and 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 fixed price, the Company receives the difference between the index price and the agreed upon swap fixed price. If the index price is higher than the swap fixed price, the Company pays the difference. 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. 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. A put option provides the Company the right, but not the obligation, to sell a specified underlying security at a designated price within a specified time frame. As of December 31, 2018 , 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 1Q19 Cashless Collar 4,000 $50.88/$63.83 7,600 $2.75/$3.22 — — — — Swap 4,000 $59.16 1,500 $3.13 7,600 $0.67 10,000 $2.17 Put 500 $55.00 — — — — — — 2Q19 Cashless Collar 5,330 $54.42/$67.57 2,505 $2.75/$3.22 — — — — Swap 3,500 $57.84 — — — — 16,703 $2.11 Put 500 $55.00 — — — — — — 3Q19 Cashless Collar 3,000 $59.17/$75.72 — — — — — — Swap 5,000 $59.92 — — — — 20,000 $2.10 Put 500 $55.00 — — — — — — 4Q19 Cashless Collar 3,000 $59.17/$75.72 — — — — — — Swap 5,000 $59.92 — — — — 20,000 $2.10 Put 500 $55.00 — — — — — — 1Q20 Swap 3,000 $63.48 — — — — — — 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 1Q19 Cashless Collar 4,656 $51.46/$65.40 7,600 $2.75/$3.22 — — — — Swap 4,000 $59.16 1,500 $3.13 7,600 $0.67 11,639 $2.20 Put 172 $55.00 — — — — — — 2Q19 Cashless Collar 6,330 $54.51/$68.74 2,505 $2.75/$3.22 — — — — Swap 3,500 $57.84 — — — — 19,203 $2.15 Put — — — — — — — — 3Q19 Cashless Collar 4,000 $58.13/$75.54 — — — — — — Swap 5,000 $59.92 — — — — 22,500 $2.13 Put — — — — — — — — 4Q19 Cashless Collar 4,000 $58.13/$75.54 — — — — — — Swap 5,000 $59.92 — — — — 22,500 $2.13 Put — — — — — — — — 1Q20 Swap 3,000 $63.48 — — — — 2,500 $2.40 Collar 2,000 $55.00/$62.00 — — — — — — 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, 2018 and 2017 (in thousands): Successor As of December 31, 2018 2017 Balance Sheet Location Fair Value Fair Value Derivative Assets: Commodity contracts Current assets $ 34,408 $ 488 Commodity contracts Noncurrent assets 3,864 6 Derivative Liabilities: Commodity contracts Current liabilities (183 ) (11,423 ) Commodity contracts Long-term liabilities — (2,972 ) Total derivative assets (liabilities), net $ 38,089 $ (13,901 ) The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations (in thousands): Successor Predecessor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 Derivative cash settlement gain (loss): Oil contracts $ (17,700 ) $ (1,486 ) $ — $ 18,333 Gas contracts (460 ) 22 — — Total derivative cash settlement gain (loss) (1) $ (18,160 ) $ (1,464 ) $ — $ 18,333 Change in fair value gain (loss) 48,431 (13,901 ) $ — $ (29,567 ) Total derivative gain (loss) (1) $ 30,271 $ (15,365 ) $ — $ (11,234 ) ___________________________ (1) Total derivative gain (loss) and the derivative cash settlement gain (loss) for each of the periods presented above is reported in the derivative (gain) loss and derivative cash settlements line items on the accompanying statements of cash flows within the net cash provided by operating activities.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE The Company issues RSUs, which represent the right to receive, upon vesting, one share of the Company's common stock. The number of potentially dilutive shares related to RSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the vesting period. The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company's common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the performance period applicable to such PSUs. The Company issued stock options and warrants, which both represent the right to purchase the Company's common stock at a specified price. The number of potentially dilutive shares related to the stock options is based on the number of shares, if any, that would be exercised at the end of the respective reporting period, assuming that date was the end of such stock options' term. The number of potentially dilutive shares related to the warrants is based on the number of shares, if any, that would be exercisable at the end of the respective reporting period. Please refer to Note 9 - Stock-Based Compensation for additional discussion. The RSUs, PSUs, stock options, and warrants of the Company are all non-participating securities, and therefore, the Company uses the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts): Successor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 Net income (loss) $ 168,186 $ (5,020 ) Basic net income (loss) per common share $ 8.20 $ (0.25 ) Diluted net income (loss) per common share $ 8.16 $ (0.25 ) Weighted-average shares outstanding - basic 20,507 20,427 Add: dilutive effect of contingent stock awards 96 — Weighted-average shares outstanding - diluted 20,603 20,427 There were 170,755 shares which were anti-dilutive for the year ended December 31, 2018. The Company's warrants exercise price were in excess of the Company's stock price, therefore, they were excluded from the earnings per share calculation. The Company was in a net loss position for the 2017 Successor Period, which made the 375,123 potentially dilutive shares anti-dilutive. The Predecessor Company issued shares of restricted stock, which entitled the holders to receive non-forfeitable dividends if and when the Predecessor Company was to declare a dividend before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two -class method. The two-class method allocates earnings for the period between common shareholders and unvested participating shareholders and losses to common shareholders only. The Predecessor Company issued units, which represented the right to receive, upon vesting, shares of the Predecessor Company's common stock on a one-to-one basis up to a share price of $26 . In the event the price of the Company's common stock were to exceed $26 , the number of shares distributed would be adjusted downward so that the shares distributed would represent a value equivalent to $26 per share. The Predecessor Company issued PSUs, which represented the right to receive, upon settlement of the PSUs, a number of shares of the Predecessor Company’s common stock that range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the measurement period applicable to such PSUs. Please refer to Note 9 - Stock-Based Compensation for additional discussion. The following table sets forth the calculation of income (loss) per basic and diluted shares from net income (loss) for the Predecessor Periods ended April 28, 2017 and December 31, 2016: Predecessor January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 (in thousands, except per share amounts) Net income (loss) $ 2,660 $ (198,950 ) Less: undistributed income to unvested restricted stock 120 — Undistributed income (loss) to common shareholders 2,540 (198,950 ) Basic net income (loss) per common share $ 0.05 $ (4.04 ) Diluted net income (loss) per common share $ 0.05 $ (4.04 ) Weighted-average shares outstanding - basic 49,559 49,268 Add: dilutive effect of contingent PSUs 1,412 — Weighted-average shares outstanding - diluted 50,971 49,268 The 2017 Predecessor Period had 258,126 anti-dilutive shares. The Company was in a net loss position for the 2016 Predecessor Period, which made the 519,362 potentially dilutive shares, anti-dilutive. The participating shareholders are not contractually obligated to share in losses, and therefore, the entire net loss is allocated to the outstanding common shareholders.

CHAPTER 11 PROCEEDINGS AND EMER

CHAPTER 11 PROCEEDINGS AND EMERGENCE	12 Months Ended
	Dec. 31, 2018
Reorganizations [Abstract]
CHAPTER 11 PROCEEDINGS AND EMERGENCE	CHAPTER 11 PROCEEDINGS AND EMERGENCE On December 23, 2016, Bonanza Creek Energy, Inc. and its subsidiaries entered into a Restructuring Support Agreement with (i) holders of approximately 51% in aggregate principal amount of the Company's 5.75% Senior Notes due 2023 (“ 5.75% Senior Notes”) and 6.75% Senior Notes due 2021 (“ 6.75% Senior Notes”), collectively (the “Senior Notes”) and (ii) NGL Energy Partners, LP and NGL Crude Logistics, LLC (collectively “NGL”). On January 4, 2017, the Company filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code. The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017. During the bankruptcy proceedings, the Company conducted normal business activities and was authorized to pay and did pay pre-petition liabilities. In addition, subject to specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, we did not record interest expense on the Company’s Senior Notes from January 6, 2017, the agreed-upon date, through April 28, 2017. For that period, contractual interest on the Senior Notes totaled $16.0 million . Reorganization On the Effective Date, the Senior Notes and existing common shares of the Company (“existing common shares”) were canceled, and the reorganized Company issued: (i) new common stock; (ii) three year warrants (“warrants”); and (iii) rights (the “subscription rights”) to acquire the new common shares offered in connection with the rights offering (the “rights offering”). • the Senior Notes aggregate principal amount of $800.0 million , plus $14.9 million of accrued and unpaid pre-petition interest and $51.2 million of prepayment premiums was settled for 46.6% or 9,481,610 shares of the Company's new common stock; • the Company issued 803,083 or 3.9% of the new common stock to holders of our existing common stock, of which 1.75% was for the ad hoc equity committee settlement in exchange for $7.5 million , on terms equivalent to the rights offering; • the Company issued 10,071,378 shares of new common stock in exchange for $200.0 million relating to the rights offering; • the Company issued 1,650,510 of warrants entitling their holders upon exercise thereof, on a pro rata basis, to 7.5% of the total outstanding new common shares at a per share price of $71.23 per warrant; and • the Company reserved 2,467,430 shares of the new common stock for issuance under its 2017 Long Term Incentive Plan (“LTIP”). Pursuant to the terms of the approved Plan the following transactions were completed on the Effective Date; • the Company paid Silo Energy, LLC (“Silo”) the contract settlement amount of $7.2 million in full; • with respect to the predecessor credit facility, dated March 29, 2011 (the “predecessor credit facility”), principal, accrued interest, and fees of $193.7 million were paid in full; • the Company paid $1.6 million for the 2016 Short Term Incentive Plan (“2016 STIP”) to various employees; • the Company funded an escrow account in the amount of $17.2 million for professional service fees attributable to its advisers; • the Company paid $13.8 million for professional services attributable to advisers of third parties involved in the bankruptcy proceedings; • the Company emerged with cash on hand of $70.2 million for operations; and • the Company amended its articles of incorporation and bylaws for the authorization of the new common stock. As confirmed in the Plan, the Company terminated its purchase agreement with Silo on February 1, 2017, and entered into a settlement agreement that allowed Silo to: (i) retain the $5.0 million adequate assurance deposit maintained, (ii) retain the Company's $8.7 million crude oil revenue receivable due to the Company for December 2016 production, and (iii) receive additional cash payment of $7.2 million , which was paid on the Effective Date. The $21.0 million settlement is shown in the contract settlement expense line item in the accompanying statements of operations as of December 31, 2016. Board of Directors Upon emergence from bankruptcy the Company's Board of Directors was made up of seven individuals, two of which were existing board members, Richard J. Carty and Jeffrey E. Wojahn, and five new board members consisting of Paul Keglevic, Brian Steck, Thomas B. Tyree, Jr., Jack E. Vaughn, and Scott D. Vogel were appointed. Executive Departure On June 11, 2017, Richard J. Carty resigned as a member of the Board of Directors and left his role as President and Chief Executive Officer of the Company. In connection with the departure of Mr. Carty, the Board of Directors appointed R. Seth Bullock, a managing director of Alvarez & Marsal, LLC, interim Chief Executive Officer. Effective April 11, 2018, the Company appointed Eric T. Greager as the new President and Chief Executive Officer of the Company. Mr. Greager also joined the Company's Board of Directors. FRESH-START ACCOUNTING Upon the Company's emergence from Chapter 11 bankruptcy, the Company adopted fresh-start accounting, pursuant to FASB ASC 852, Reorganizations , and applied the provisions thereof to its financial statements. The Company qualified for fresh-start accounting because: (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company; and (ii) the reorganization value of the Company's assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh-start accounting as of April 28, 2017, when it emerged from bankruptcy protection. Adopting fresh-start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit as of the fresh-start reporting date. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares of the Successor Company caused a related change of control of the Company under ASC 852. Reorganization Value Under fresh-start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Under application of fresh-start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values. The Company's reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt, other interest bearing liabilities, and shareholders’ equity, less total cash and cash equivalents. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $570.0 million to $680.0 million . Based on the estimates and assumptions used in determining the enterprise value, as further discussed below, the Company estimated the enterprise value to be approximately $643.0 million . This valuation analysis was prepared with the assistance of an independent third-party consultant utilizing reserve information prepared by the Company's internal reserve engineers, internal development plans and schedules, other internal financial information and projections and the application of standard valuation techniques including risked net asset value analysis and comparable public company metrics. The Company's principal assets are its oil and gas properties. The Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets segregated into geographic regions. The computations were based on market conditions and reserves in place as of the Effective Date. Discounted cash flow models were generated using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising our proved reserves. The proved locations were limited to wells expected to be drilled in the Company's five year plan. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange five year forward prices for West Texas Intermediate oil and Henry Hub natural gas with inflation adjustments applied to periods beyond five years. The prices were further adjusted for typical differentials realized by the Company for the location and product quality. Wattenberg Field oil differential estimates were based on the new NGL purchase agreement that was confirmed as part of the Plan. Development costs were based on recent bids received by the Company and the operating costs were based on actual costs, and both were adjusted by the same inflation rate used for revenues. The discounted cash flow models also included estimates not typically included in proved reserves, such as an industry standard general and administrative expense and income tax expense. Due to the limited drilling plans that we had in place, proved undeveloped locations were risked within industry standards. The risk-adjusted after-tax cash flows were discounted at a rate of 11.0% . This rate was determined from a weighted-average cost of capital computation, which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. From this analysis the Company concluded the fair value of its proved, probable, and possible reserves was $397.3 million , $146.8 million , and $31.7 million , respectively, as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and determined that the fair value of its probable and possible reserves appropriately capture the fair value of its undeveloped leasehold acreage. The Company performed an analysis of its Rocky Mountain Infrastructure, LLC (“RMI”) assets using a replacement cost method which estimated the assets' replacement cost (for new assets), less any depreciation, physical deterioration, or obsolescence, resulting in a fair value of $103.1 million . The Company follows the lower of cost or net realizable value when valuing inventory of oilfield equipment. The valuation of the inventory of oilfield equipment as of the Effective Date did not yield a material difference from the Company's carrying value immediately prior to emergence from bankruptcy; as such, there was no valuation adjustment recorded. The valuation of the Company's other property and equipment as of the Effective Date did not yield a material difference from the Predecessor Company's net book value; as such there was no valuation adjustment recorded. Our liabilities on the Effective Date include working capital liabilities and asset retirement obligations. Our working capital liabilities are ordinary course obligations, and their carrying amounts approximate their fair values. The asset retirement obligation was reset using a revised credit-adjusted risk-free rate and known attributes as of the Effective Date, resulting in a $29.1 million obligation. In conjunction with the Company's emergence from bankruptcy, the Company issued 1,650,510 warrants to existing equity holders. The fair value of $4.1 million was estimated using a Black-Scholes pricing model. The model used the following assumptions; an expected volatility of 40% , a risk-free interest rate of 1.44% , a stock price of $34.36 , a strike price of $71.23 , and an expiration date of 3 years. The following table reconciles the enterprise value to the estimated fair value of Successor Company's common stock as of the Effective Date (in thousands, except per share amounts): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Less: Interest bearing liabilities (29,061 ) Less: Fair value of warrants (4,081 ) Fair value of Successor common stock $ 680,040 Shares outstanding at April 28, 2017 20,356 Per share value $ 33.41 The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Plus: Working capital liabilities 63,871 Plus: Other long-term liabilities 17,919 Reorganization value of Successor assets $ 794,972 Successor Condensed Consolidated Balance Sheet The adjustments set forth in the following condensed consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as estimated fair value adjustments as a result of the adoption of fresh-start accounting (reflected in the column “Fresh-Start Adjustments”). The explanatory notes highlight methods used to determine estimated fair values or other amounts of assets and liabilities, as well as significant assumptions. Predecessor Company Reorganization Adjustments Fresh-Start Adjustments Successor Company (in thousands, except share amounts) ASSETS Current Assets: Cash and cash equivalents $ 96,286 $ (26,103 ) (1) $ — $ 70,183 Accounts receivable: Oil and gas sales 24,876 — — 24,876 Joint interest and other 3,028 — — 3,028 Prepaid expenses and other 4,952 — — 4,952 Inventory of oilfield equipment 4,218 — — 4,218 Total current assets 133,360 (26,103 ) — 107,257 Property and equipment (successful efforts method): Proved properties 2,531,834 — (2,031,373 ) (6) 500,461 Less: accumulated depreciation, depletion and amortization (1,720,736 ) — 1,720,736 (6) — Total proved properties, net 811,098 — (310,637 ) 500,461 Unproved properties 163,781 — 14,679 (6) 178,460 Wells in progress 18,002 — (18,002 ) (7) — Other property and equipment, net 6,056 — — 6,056 Total property and equipment, net 998,937 — (313,960 ) 684,977 Other noncurrent assets 2,738 — — 2,738 Total assets $ 1,135,035 $ (26,103 ) $ (313,960 ) $ 794,972 LIABILITIES AND STOCKHOLDERS'S EQUITY Current liabilities: Accounts payable and accrued expenses $ 72,635 $ (33,701 ) (2) $ — $ 38,934 Oil and gas revenue distribution payable 24,937 — — 24,937 Predecessor credit facility - current portion 191,667 (191,667 ) (3) — — Total current liabilities 289,239 (225,368 ) — 63,871 Long-term liabilities: Ad valorem taxes 17,919 — — 17,919 Asset retirement obligations for oil and gas properties 31,660 — (2,599 ) (8) 29,061 Liabilities subject to compromise 873,292 (873,292 ) (4) — — Total liabilities $ 1,212,110 $ (1,098,660 ) $ (2,599 ) $ 110,851 Stockholders' equity: Predecessor preferred stock — — — — Predecessor common stock 49 — (49 ) (9) — Additional paid in capital 816,679 — (816,679 ) (9) — Successor common stock — 204 (5) — 204 Successor warrants — 4,081 (5) — 4,081 Additional paid-in capital — 679,836 (5) — 679,836 Retained deficit (893,803 ) 388,436 (4) 505,367 (10) — Total stockholders' equity (77,075 ) 1,072,557 (311,361 ) 684,121 Total liabilities and stockholders' equity $ 1,135,035 $ (26,103 ) $ (313,960 ) $ 794,972 Reorganization Adjustments (1) The following table reflects the net cash payments made upon emergence on the Effective Date (in thousands): Sources: Proceeds from rights offering $ 200,000 Proceeds from ad hoc equity committee 7,500 Total sources $ 207,500 Uses and transfers: Payment on predecessor credit facility (principal, interest and fees) $ (193,729 ) Payment and funding of escrow account related to professional fees (17,193 ) Payment of professional fees and other (13,831 ) Payment of Silo contract settlement and other (7,228 ) Payment of remaining 2016 STIP (1,622 ) Total uses and transfers $ (233,603 ) Total net sources, uses and transfers $ (26,103 ) (2) The following table shows the decrease of accounts payable and accrued liabilities attributable to reorganization items settled or paid upon emergence (in thousands): Accounts payable and accrued expenses: Accrued 2016 STIP payment $ (1,574 ) Escrow account funding (17,193 ) Professional fees and other (13,831 ) Accrued unpaid interest on predecessor credit facility (1,103 ) Total accounts payable and accrued expenses settled $ (33,701 ) (3) Represents the payment in full of the predecessor credit facility on the Effective Date. (4) On the Effective Date, the obligations of the Company with respect to the Senior Notes were canceled. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands): Senior Notes $ 800,000 Accrued interest on Senior Notes (pre-petition) 14,879 Make-whole payment on Senior Notes 51,185 Silo contract settlement accrual 7,228 Total liabilities subject to compromise of the predecessor 873,292 Rights offering 200,000 Fair value of equity issued to creditors, excluding equity issued to existing equity holders (653,212 ) Payment of Silo contract settlement (7,228 ) Gain on settlement of liabilities subject to compromise 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007 ) Total reorganization items at emergence $ 411,845 Issuance of warrants to existing shareholders $ (4,081 ) Proceeds from ad hoc equity committee 7,500 Issuance of shares to existing shareholders (26,828 ) Total reorganization adjustments to retained deficit $ 388,436 (5) Represents the fair value of 20,356,071 shares of new common stock and 1,650,510 warrants issued upon emergence from bankruptcy on the Effective Date. Fresh-Start Adjustments (6) Fair value adjustments to proved and unproved oil and natural gas properties. A combination of the market and income approach were utilized to perform valuations. Included in this line items were adjustments to the fully-owned subsidiary, Rocky Mountain Infrastructure, LLC. Lastly, the accumulated depreciation was reset to zero in accordance with fresh-start accounting. (7) Represents the reset of wells in progress with fair valuation of the associated reserves in proved property. (8) Upon application of fresh-start accounting and due to the Company’s emergence with no debt, the Company revalued its asset retirement obligations based upon comparable companies’ credit-adjusted risk-free rates in accordance with ASC 410 - Asset Retirement and Environmental Obligations. (9) Cancellation of Predecessor Company’s common stock and additional paid-in capital. (10) Adjustment to reset retained deficit to zero. Reorganization Items, Net Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan, and are classified as Reorganization items, net in our statement of operations. The following table summarizes reorganization items recorded in the Current Predecessor Period (in thousands): Gain on settlement of liabilities subject to compromise $ 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007 ) Fresh-start valuation adjustments (311,361 ) Legal and professional fees and expenses (34,335 ) Write-off of debt issuance and premium costs (6,156 ) Make-whole payment on Senior Notes (51,185 ) Total reorganization items, net $ 8,808

FRESH-START ACCOUNTING

FRESH-START ACCOUNTING	12 Months Ended
	Dec. 31, 2018
Reorganizations [Abstract]
FRESH-START ACCOUNTING	CHAPTER 11 PROCEEDINGS AND EMERGENCE On December 23, 2016, Bonanza Creek Energy, Inc. and its subsidiaries entered into a Restructuring Support Agreement with (i) holders of approximately 51% in aggregate principal amount of the Company's 5.75% Senior Notes due 2023 (“ 5.75% Senior Notes”) and 6.75% Senior Notes due 2021 (“ 6.75% Senior Notes”), collectively (the “Senior Notes”) and (ii) NGL Energy Partners, LP and NGL Crude Logistics, LLC (collectively “NGL”). On January 4, 2017, the Company filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code. The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017. During the bankruptcy proceedings, the Company conducted normal business activities and was authorized to pay and did pay pre-petition liabilities. In addition, subject to specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, we did not record interest expense on the Company’s Senior Notes from January 6, 2017, the agreed-upon date, through April 28, 2017. For that period, contractual interest on the Senior Notes totaled $16.0 million . Reorganization On the Effective Date, the Senior Notes and existing common shares of the Company (“existing common shares”) were canceled, and the reorganized Company issued: (i) new common stock; (ii) three year warrants (“warrants”); and (iii) rights (the “subscription rights”) to acquire the new common shares offered in connection with the rights offering (the “rights offering”). • the Senior Notes aggregate principal amount of $800.0 million , plus $14.9 million of accrued and unpaid pre-petition interest and $51.2 million of prepayment premiums was settled for 46.6% or 9,481,610 shares of the Company's new common stock; • the Company issued 803,083 or 3.9% of the new common stock to holders of our existing common stock, of which 1.75% was for the ad hoc equity committee settlement in exchange for $7.5 million , on terms equivalent to the rights offering; • the Company issued 10,071,378 shares of new common stock in exchange for $200.0 million relating to the rights offering; • the Company issued 1,650,510 of warrants entitling their holders upon exercise thereof, on a pro rata basis, to 7.5% of the total outstanding new common shares at a per share price of $71.23 per warrant; and • the Company reserved 2,467,430 shares of the new common stock for issuance under its 2017 Long Term Incentive Plan (“LTIP”). Pursuant to the terms of the approved Plan the following transactions were completed on the Effective Date; • the Company paid Silo Energy, LLC (“Silo”) the contract settlement amount of $7.2 million in full; • with respect to the predecessor credit facility, dated March 29, 2011 (the “predecessor credit facility”), principal, accrued interest, and fees of $193.7 million were paid in full; • the Company paid $1.6 million for the 2016 Short Term Incentive Plan (“2016 STIP”) to various employees; • the Company funded an escrow account in the amount of $17.2 million for professional service fees attributable to its advisers; • the Company paid $13.8 million for professional services attributable to advisers of third parties involved in the bankruptcy proceedings; • the Company emerged with cash on hand of $70.2 million for operations; and • the Company amended its articles of incorporation and bylaws for the authorization of the new common stock. As confirmed in the Plan, the Company terminated its purchase agreement with Silo on February 1, 2017, and entered into a settlement agreement that allowed Silo to: (i) retain the $5.0 million adequate assurance deposit maintained, (ii) retain the Company's $8.7 million crude oil revenue receivable due to the Company for December 2016 production, and (iii) receive additional cash payment of $7.2 million , which was paid on the Effective Date. The $21.0 million settlement is shown in the contract settlement expense line item in the accompanying statements of operations as of December 31, 2016. Board of Directors Upon emergence from bankruptcy the Company's Board of Directors was made up of seven individuals, two of which were existing board members, Richard J. Carty and Jeffrey E. Wojahn, and five new board members consisting of Paul Keglevic, Brian Steck, Thomas B. Tyree, Jr., Jack E. Vaughn, and Scott D. Vogel were appointed. Executive Departure On June 11, 2017, Richard J. Carty resigned as a member of the Board of Directors and left his role as President and Chief Executive Officer of the Company. In connection with the departure of Mr. Carty, the Board of Directors appointed R. Seth Bullock, a managing director of Alvarez & Marsal, LLC, interim Chief Executive Officer. Effective April 11, 2018, the Company appointed Eric T. Greager as the new President and Chief Executive Officer of the Company. Mr. Greager also joined the Company's Board of Directors. FRESH-START ACCOUNTING Upon the Company's emergence from Chapter 11 bankruptcy, the Company adopted fresh-start accounting, pursuant to FASB ASC 852, Reorganizations , and applied the provisions thereof to its financial statements. The Company qualified for fresh-start accounting because: (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company; and (ii) the reorganization value of the Company's assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh-start accounting as of April 28, 2017, when it emerged from bankruptcy protection. Adopting fresh-start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit as of the fresh-start reporting date. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares of the Successor Company caused a related change of control of the Company under ASC 852. Reorganization Value Under fresh-start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Under application of fresh-start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values. The Company's reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt, other interest bearing liabilities, and shareholders’ equity, less total cash and cash equivalents. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the Bankruptcy Court to be in the range of $570.0 million to $680.0 million . Based on the estimates and assumptions used in determining the enterprise value, as further discussed below, the Company estimated the enterprise value to be approximately $643.0 million . This valuation analysis was prepared with the assistance of an independent third-party consultant utilizing reserve information prepared by the Company's internal reserve engineers, internal development plans and schedules, other internal financial information and projections and the application of standard valuation techniques including risked net asset value analysis and comparable public company metrics. The Company's principal assets are its oil and gas properties. The Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets segregated into geographic regions. The computations were based on market conditions and reserves in place as of the Effective Date. Discounted cash flow models were generated using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising our proved reserves. The proved locations were limited to wells expected to be drilled in the Company's five year plan. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange five year forward prices for West Texas Intermediate oil and Henry Hub natural gas with inflation adjustments applied to periods beyond five years. The prices were further adjusted for typical differentials realized by the Company for the location and product quality. Wattenberg Field oil differential estimates were based on the new NGL purchase agreement that was confirmed as part of the Plan. Development costs were based on recent bids received by the Company and the operating costs were based on actual costs, and both were adjusted by the same inflation rate used for revenues. The discounted cash flow models also included estimates not typically included in proved reserves, such as an industry standard general and administrative expense and income tax expense. Due to the limited drilling plans that we had in place, proved undeveloped locations were risked within industry standards. The risk-adjusted after-tax cash flows were discounted at a rate of 11.0% . This rate was determined from a weighted-average cost of capital computation, which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. From this analysis the Company concluded the fair value of its proved, probable, and possible reserves was $397.3 million , $146.8 million , and $31.7 million , respectively, as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and determined that the fair value of its probable and possible reserves appropriately capture the fair value of its undeveloped leasehold acreage. The Company performed an analysis of its Rocky Mountain Infrastructure, LLC (“RMI”) assets using a replacement cost method which estimated the assets' replacement cost (for new assets), less any depreciation, physical deterioration, or obsolescence, resulting in a fair value of $103.1 million . The Company follows the lower of cost or net realizable value when valuing inventory of oilfield equipment. The valuation of the inventory of oilfield equipment as of the Effective Date did not yield a material difference from the Company's carrying value immediately prior to emergence from bankruptcy; as such, there was no valuation adjustment recorded. The valuation of the Company's other property and equipment as of the Effective Date did not yield a material difference from the Predecessor Company's net book value; as such there was no valuation adjustment recorded. Our liabilities on the Effective Date include working capital liabilities and asset retirement obligations. Our working capital liabilities are ordinary course obligations, and their carrying amounts approximate their fair values. The asset retirement obligation was reset using a revised credit-adjusted risk-free rate and known attributes as of the Effective Date, resulting in a $29.1 million obligation. In conjunction with the Company's emergence from bankruptcy, the Company issued 1,650,510 warrants to existing equity holders. The fair value of $4.1 million was estimated using a Black-Scholes pricing model. The model used the following assumptions; an expected volatility of 40% , a risk-free interest rate of 1.44% , a stock price of $34.36 , a strike price of $71.23 , and an expiration date of 3 years. The following table reconciles the enterprise value to the estimated fair value of Successor Company's common stock as of the Effective Date (in thousands, except per share amounts): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Less: Interest bearing liabilities (29,061 ) Less: Fair value of warrants (4,081 ) Fair value of Successor common stock $ 680,040 Shares outstanding at April 28, 2017 20,356 Per share value $ 33.41 The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Plus: Working capital liabilities 63,871 Plus: Other long-term liabilities 17,919 Reorganization value of Successor assets $ 794,972 Successor Condensed Consolidated Balance Sheet The adjustments set forth in the following condensed consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as estimated fair value adjustments as a result of the adoption of fresh-start accounting (reflected in the column “Fresh-Start Adjustments”). The explanatory notes highlight methods used to determine estimated fair values or other amounts of assets and liabilities, as well as significant assumptions. Predecessor Company Reorganization Adjustments Fresh-Start Adjustments Successor Company (in thousands, except share amounts) ASSETS Current Assets: Cash and cash equivalents $ 96,286 $ (26,103 ) (1) $ — $ 70,183 Accounts receivable: Oil and gas sales 24,876 — — 24,876 Joint interest and other 3,028 — — 3,028 Prepaid expenses and other 4,952 — — 4,952 Inventory of oilfield equipment 4,218 — — 4,218 Total current assets 133,360 (26,103 ) — 107,257 Property and equipment (successful efforts method): Proved properties 2,531,834 — (2,031,373 ) (6) 500,461 Less: accumulated depreciation, depletion and amortization (1,720,736 ) — 1,720,736 (6) — Total proved properties, net 811,098 — (310,637 ) 500,461 Unproved properties 163,781 — 14,679 (6) 178,460 Wells in progress 18,002 — (18,002 ) (7) — Other property and equipment, net 6,056 — — 6,056 Total property and equipment, net 998,937 — (313,960 ) 684,977 Other noncurrent assets 2,738 — — 2,738 Total assets $ 1,135,035 $ (26,103 ) $ (313,960 ) $ 794,972 LIABILITIES AND STOCKHOLDERS'S EQUITY Current liabilities: Accounts payable and accrued expenses $ 72,635 $ (33,701 ) (2) $ — $ 38,934 Oil and gas revenue distribution payable 24,937 — — 24,937 Predecessor credit facility - current portion 191,667 (191,667 ) (3) — — Total current liabilities 289,239 (225,368 ) — 63,871 Long-term liabilities: Ad valorem taxes 17,919 — — 17,919 Asset retirement obligations for oil and gas properties 31,660 — (2,599 ) (8) 29,061 Liabilities subject to compromise 873,292 (873,292 ) (4) — — Total liabilities $ 1,212,110 $ (1,098,660 ) $ (2,599 ) $ 110,851 Stockholders' equity: Predecessor preferred stock — — — — Predecessor common stock 49 — (49 ) (9) — Additional paid in capital 816,679 — (816,679 ) (9) — Successor common stock — 204 (5) — 204 Successor warrants — 4,081 (5) — 4,081 Additional paid-in capital — 679,836 (5) — 679,836 Retained deficit (893,803 ) 388,436 (4) 505,367 (10) — Total stockholders' equity (77,075 ) 1,072,557 (311,361 ) 684,121 Total liabilities and stockholders' equity $ 1,135,035 $ (26,103 ) $ (313,960 ) $ 794,972 Reorganization Adjustments (1) The following table reflects the net cash payments made upon emergence on the Effective Date (in thousands): Sources: Proceeds from rights offering $ 200,000 Proceeds from ad hoc equity committee 7,500 Total sources $ 207,500 Uses and transfers: Payment on predecessor credit facility (principal, interest and fees) $ (193,729 ) Payment and funding of escrow account related to professional fees (17,193 ) Payment of professional fees and other (13,831 ) Payment of Silo contract settlement and other (7,228 ) Payment of remaining 2016 STIP (1,622 ) Total uses and transfers $ (233,603 ) Total net sources, uses and transfers $ (26,103 ) (2) The following table shows the decrease of accounts payable and accrued liabilities attributable to reorganization items settled or paid upon emergence (in thousands): Accounts payable and accrued expenses: Accrued 2016 STIP payment $ (1,574 ) Escrow account funding (17,193 ) Professional fees and other (13,831 ) Accrued unpaid interest on predecessor credit facility (1,103 ) Total accounts payable and accrued expenses settled $ (33,701 ) (3) Represents the payment in full of the predecessor credit facility on the Effective Date. (4) On the Effective Date, the obligations of the Company with respect to the Senior Notes were canceled. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands): Senior Notes $ 800,000 Accrued interest on Senior Notes (pre-petition) 14,879 Make-whole payment on Senior Notes 51,185 Silo contract settlement accrual 7,228 Total liabilities subject to compromise of the predecessor 873,292 Rights offering 200,000 Fair value of equity issued to creditors, excluding equity issued to existing equity holders (653,212 ) Payment of Silo contract settlement (7,228 ) Gain on settlement of liabilities subject to compromise 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007 ) Total reorganization items at emergence $ 411,845 Issuance of warrants to existing shareholders $ (4,081 ) Proceeds from ad hoc equity committee 7,500 Issuance of shares to existing shareholders (26,828 ) Total reorganization adjustments to retained deficit $ 388,436 (5) Represents the fair value of 20,356,071 shares of new common stock and 1,650,510 warrants issued upon emergence from bankruptcy on the Effective Date. Fresh-Start Adjustments (6) Fair value adjustments to proved and unproved oil and natural gas properties. A combination of the market and income approach were utilized to perform valuations. Included in this line items were adjustments to the fully-owned subsidiary, Rocky Mountain Infrastructure, LLC. Lastly, the accumulated depreciation was reset to zero in accordance with fresh-start accounting. (7) Represents the reset of wells in progress with fair valuation of the associated reserves in proved property. (8) Upon application of fresh-start accounting and due to the Company’s emergence with no debt, the Company revalued its asset retirement obligations based upon comparable companies’ credit-adjusted risk-free rates in accordance with ASC 410 - Asset Retirement and Environmental Obligations. (9) Cancellation of Predecessor Company’s common stock and additional paid-in capital. (10) Adjustment to reset retained deficit to zero. Reorganization Items, Net Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan, and are classified as Reorganization items, net in our statement of operations. The following table summarizes reorganization items recorded in the Current Predecessor Period (in thousands): Gain on settlement of liabilities subject to compromise $ 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007 ) Fresh-start valuation adjustments (311,361 ) Legal and professional fees and expenses (34,335 ) Write-off of debt issuance and premium costs (6,156 ) Make-whole payment on Senior Notes (51,185 ) Total reorganization items, net $ 8,808

DISCLOSURES ABOUT OIL AND GAS P

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2018
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The Company’s oil and natural gas activities are located entirely within the United States. Costs incurred in oil and natural gas producing activities are as follows (in thousands): Successor Predecessor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 Acquisition (1) $ 2,861 $ 5,383 $ 445 $ 97 Development (2)(3) 304,197 106,449 10,780 31,209 Exploration 294 3,671 769 74 Total (4) $ 307,352 $ 115,503 $ 11,994 $ 31,380 _________________________ (1) Acquisition costs for unproved properties for the year ended December 31, 2018, 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period were $2.5 million , $5.4 million , $0.4 million , and $0.1 million , respectively. There was $0.4 million in acquisition costs for proved properties for the year ended December 31, 2018 and no acquisition costs for proved properties for the 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period. (2) Development costs include workover costs of $5.6 million , $4.3 million , $1.8 million , and $6.0 million charged to lease operating expense for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period, respectively. (3) Includes amounts relating to asset retirement obligations of $(9.0) million , $8.3 million , $3.1 million , and $2.4 million for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period, respectively. Suspended Well Costs The Company did not incur any exploratory well costs during the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period. Reserves The proved reserve estimates at December 31, 2018 and 2017 were prepared by NSAI, our third party independent reserve engineers. The proved reserve estimate at December 31, 2016 was internally generated with an audit performed by NSAI. 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 BCEI’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of BCEI’s changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2018 , 2017 , and 2016 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (MMcf) (MBbl) Balance-December 31, 2015 57.393 144.227 19.918 Extensions, discoveries and infills (1) 6.133 15.128 2.142 Production (4.310 ) (11.907 ) (1.491 ) Sales of minerals in place (0.100 ) (0.343 ) (0.035 ) Revisions to previous estimates (3) (9.020 ) (9.060 ) (2.987 ) Balance-December 31, 2016 50.096 138.045 17.547 Extensions, discoveries and infills (1) 8.470 22.212 3.376 Production (3.081 ) (9.010 ) (1.136 ) Revisions to previous estimates (3) (2.557 ) 6.422 3.028 Balance-December 31, 2017 52.928 157.669 22.815 Extensions, discoveries and infills (1) 18.390 31.471 5.197 Production (3.841 ) (8.567 ) (1.140 ) Sales of minerals in place (6.236 ) (20.534 ) (1.499 ) Removed from capital program (2) (1.442 ) (3.246 ) (0.544 ) Revisions to previous estimates (3) 4.555 8.219 0.101 Balance-December 31, 2018 64.354 165.012 24.930 Proved developed reserves: December 31, 2016 26.313 85.972 9.951 December 31, 2017 25.785 92.718 12.702 December 31, 2018 23.725 79.630 11.703 Proved undeveloped reserves: December 31, 2016 23.783 52.073 7.596 December 31, 2017 27.143 64.951 10.113 December 31, 2018 40.629 85.382 13.227 ________________________ (1) At December 31, 2018, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of 28,832 MBoe. At December 31, 2017, horizontal development in the Wattenberg Field resulted in additions in extensions and discoveries of 15,548 MBoe. At December 31, 2016, horizontal development in the Wattenberg Field resulted in additions of 1,632 MBoe, and infill down-spacing within the Wattenberg Field resulted in 9,164 MBoe to the additions, extensions, and infills category. (2) As of December 31, 2018, proved undeveloped reserves were reduced by 2,527 MBoe due to the removal of proved undeveloped locations from our five-year drilling program. (3) As of December 31, 2018, the Company revised its proved reserves upward by 6,026 MBoe. 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 2,333 MBoe. In addition, lower operating cost estimates resulted in positive reserve adjustments of 1,536 MBoe. There were net positive engineering revisions of 2,163 MBoe. As of December 31, 2017, the Company revised its proved reserves upward by 1,542 MBoe. The commodity prices at December 31, 2017 increased to $51.34 per Bbl WTI and $2.98 per MMBtu HH from $42.75 per Bbl WTI and $2.48 per MMBtu HH at December 31, 2016, resulting in positive revisions of 5,405 MBoe. In addition, lower operating cost estimates resulted in positive reserve adjustments (net of price increases) of 1,672 MBoe, of which 1,370 MBoe relate to operations in the Wattenberg Field. The Company also had positive other engineering revisions of 2,042 MBoe, offset by PUD demotions of 7,577 MBoe. As of December 31, 2016, the Company revised its proved reserves downward by 13,517 MBoe. The commodity prices at December 31, 2016 decreased to $42.75 per Bbl WTI and $2.48 per MMBtu HH from $50.28 per Bbl WTI and $2.59 per MMBtu HH at December 31, 2015. The negative effects of commodity price reductions on reserves were offset by lower cost estimates to drill and complete future development locations in the Wattenberg Field along with lower operating cost estimates across the Company's operations, to reflect a positive reserves adjustment (net of price reductions) of 4,652 MBoe. Also, all future proved undeveloped locations in the Mid-Continent region were demoted to non-proved reserves resulting in a negative revision of 7,761 MBoe. In the Wattenberg Field, certain proved undeveloped locations totaling 8,611 MBoe were demoted due to their not being centric to current infrastructure. The Company also had negative other engineering revisions of 1,797 MBoe in 2016. 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 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: For the Years Ended December 31, 2018 2017 2016 (in thousands) Future cash flows $ 4,742,180 $ 3,307,868 $ 2,424,415 Future production costs (1,585,032 ) (1,490,091 ) (1,365,765 ) Future development costs (925,640 ) (622,344 ) (468,804 ) Future income tax expense — — — Future net cash flows 2,231,508 1,195,433 589,846 10% annual discount for estimated timing of cash flows (1,276,528 ) (596,935 ) (312,891 ) Standardized measure of discounted future net cash flows $ 954,980 $ 598,498 $ 276,955 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: For the Years Ended December 31, 2018 2017 2016 (in thousands) Beginning of period $ 598,498 $ 276,955 $ 327,816 Sale of oil and gas produced, net of production costs (204,566 ) (125,992 ) (123,494 ) Net changes in prices and production costs 365,952 282,112 (126,536 ) Extensions, discoveries and improved recoveries 153,691 103,937 22,800 Development costs incurred 127,788 24,121 19,701 Changes in estimated development cost (52,260 ) 2,122 281,062 Purchases of minerals in place — — — Sales of minerals in place (115,742 ) — 16 Revisions of previous quantity estimates 12,341 14,119 (182,938 ) Net change in income taxes — — Accretion of discount 59,850 27,696 32,782 Changes in production rates and other 9,428 (6,572 ) 25,746 End of period $ 954,980 $ 598,498 $ 276,955 The average wellhead prices used in determining future net revenues related to the standardized measure calculation as of December 31, 2018 , 2017 , and 2016 were calculated using the twelve-month arithmetic average of first-day-of-the-month price inclusive of adjustments for quality and location. For the Years Ended December 31, 2018 2017 2016 Oil (per Bbl) $ 59.29 $ 46.76 $ 38.42 Gas (per Mcf) $ 2.28 $ 2.45 $ 2.07 Natural gas liquids (per Bbl) $ 22.06 $ 19.57 $ 12.12

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2018 and 2017 (in thousands, except per share data): Successor Three Months Ended 2018 March 31 June 30 September 30 December 31 Oil and gas sales $ 64,193 $ 71,872 $ 74,380 $ 66,213 Operating profit (1) $ 35,042 $ 40,014 $ 43,959 $ 41,416 Net Income $ 13,870 $ 4,859 $ 43,363 $ 106,094 Basic net income per common share $ 0.68 $ 0.24 $ 2.11 $ 5.16 Diluted net income per common share $ 0.68 $ 0.24 $ 2.10 $ 5.15 Predecessor Successor Three Months Ended March 31, 2017 April 1, 2017 through April 28, 2017 April 29, 2017 through June 30, 2017 Three Months Ended September 30, 2017 Three Months Ended December 31, 2017 2017 Oil and gas sales $ 52,559 $ 16,030 $ 28,114 $ 45,232 $ 50,189 Operating profit (1) 14,398 3,786 12,955 22,540 22,935 Net income (loss) (94,276 ) 96,936 (3,580 ) 4,328 (5,768 ) Basic net income (loss) per common share $ (1.91 ) $ 1.88 $ (0.18 ) $ 0.21 $ (0.28 ) Diluted net income (loss) per common share $ (1.91 ) $ 1.85 $ (0.18 ) $ 0.21 $ (0.28 ) ________________________ (1) Oil and gas sales less lease operating expense, gas plant and midstream operating expense, gathering, transportation, and processing, severance and ad valorem taxes, depreciation, and depletion and amortization.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation As of December 31, 2018, the 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 significant intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2018 , through the filing date of this report. On August 6, 2018, the Company sold its equity interests in Bonanza Creek Energy Resources, LLC, which owns all of the outstanding equity interest in Bonanza Creek Energy Upstream LLC and Bonanza Creek Energy Midstream, LLC. These subsidiaries comprised the Company's Mid-Continent region and assets. Please refer to Note 4 - Divestitures for additional discussion. As of December 31, 2017, the balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, Holmes Eastern Company, LLC, and Rocky Mountain Infrastructure, LLC. All significant intercompany accounts and transactions have been eliminated. On January 4, 2017, the Company and certain of its subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions,” and the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) to pursue the Debtors’ Joint Prepackaged Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (as proposed, the “Plan”). The Bankruptcy Court granted the Debtors' motion seeking to administer all of the Debtors' Chapter 11 Cases jointly under the caption “In re Bonanza Creek Energy, Inc., et al” (Case No. 17-10015). The Debtors received bankruptcy court confirmation of their Plan on April 7, 2017, and emerged from bankruptcy on April 28, 2017 (the “Effective Date”). Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession during a portion of the year ended December 31, 2017. As such, certain aspects of the bankruptcy proceedings of the Company and related matters are described below in order to provide context and explain part of our financial condition and results of operations for the period presented. Upon emergence from bankruptcy, the Company adopted fresh-start accounting and became a new entity for financial reporting purposes. As a result of the application of fresh-start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements after April 28, 2017 are not comparable with the financial statements on or prior to April 28, 2017. The Company's condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented after April 28, 2017 and dates prior thereto. Please refer to Note 16 - Fresh-Start Accounting for additional discussion. Subsequent to January 4, 2017 and through the date of emergence, all expenses, gains, and losses directly associated with the reorganization are reported as reorganization items, net in the accompanying consolidated statements of operations and comprehensive income (loss) (“statements of operations”). References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company on or prior to April 28, 2017. Throughout these financial statements, the Company refers to the 2017 annual period which is comprised of both Successor and Predecessor periods. References to “Current Successor Period” relate to the year ended December 31, 2018. References to “2017 Successor Period” relate to the period of April 29, 2017 through December 31, 2017. References to the “2017 Predecessor Period” and “2016 Predecessor Period” relate to the periods of January 1, 2017 through April 28, 2017 and January 1, 2016 through December 31, 2016, respectively.
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.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments.
Accounts Receivable	Accounts Receivable The Company’s accounts receivables are generated from oil and gas sales and from joint interest owners on properties that the Company operates. These receivables are generally unsecured. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated. For receivables from joint interest owners, the Company usually has the ability to withhold future revenue disbursements to satisfy the outstanding balance. The Company’s oil and gas receivables are typically collected within one to two months, and the Company has experienced minimal bad debts.
Inventory of Oilfield Equipment	Inventory of Oilfield Equipment Inventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of cost or net realizable value, which approximates fair value.
Oil and Gas Producing Activities	Oil and Gas Producing Activities The Company follows the successful efforts method of accounting for its oil and gas exploration and development costs. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether economically recoverable reserves have been found. If an exploratory well does not find economically recoverable reserves, the costs of drilling the well and other associated costs are charged to dry hole expense. The costs of development wells are capitalized whether the well is productive or nonproductive. Costs incurred to maintain wells and their related equipment and leases as well as operating costs are charged to expense as incurred. Geological and geophysical costs are expensed as incurred. Depletion, depreciation, and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs and anticipated proceeds from salvaging equipment. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets' net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value. The factors used to determine fair value are subject to the Company’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows on all developed proved reserves and risk adjusted probable and possible reserves, net of estimated operating and development costs, future commodity pricing based on our internal budgeting model originating from the NYMEX strip price adjusted for basis differential, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. As of December 31, 2018, the Company's gathering assets comprised $120.4 million , $0.9 million , and $0.1 million of proved properties, wells in progress, and unproved properties, respectively, on the accompanying consolidated balance sheets. Lease acquisition costs are reclassified to proved properties and depleted on a unit-of-production basis once proved reserves have been assigned. The Company assesses its unproved properties periodically for impairment on a property-by-property basis, which requires significant judgment. Leases that were not held by production upon emergence from bankruptcy are being amortized off over the remainder of those leases. 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; • its evaluation of the current fair market value of acreage; and • strategic shifts in development areas. For additional discussion, please refer to Note 3 - Impairments . 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 consolidated balance sheets (“balance sheets”). For additional discussion, please refer to Note 11 - 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 to ten years.
Assets Held for Sale	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.
Revenue Recognition	Revenue Recognition Sales of oil, natural gas, and natural gas liquids (“NGLs”) are recognized when performance obligations are satisfied at the point control of the product is transferred to the customer. Virtually all of our 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. Please refer to Footnote 2 - Revenue Recognition for more information. The Company records revenues, net of royalties, discounts, and allowances, as applicable, from the sales of crude oil, natural gas, and NGLs when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company factors in historical performance, quality and transportation differentials, commodity prices, and other factors when deriving revenue estimates. Payment is generally received within 30 to 90 days after the date of production. The Company has interests with other producers in certain properties, in which case the Company uses the entitlement method to account for gas imbalances. The Company had no material gas imbalances as of December 31, 2018 and 2017.
Income Taxes	Income Taxes The Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.
Uncertain Tax Positions	Uncertain Tax Positions The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax returns for 2017 , 2016 , and 2015 are still subject to audit by the Internal Revenue Service. There were no uncertain tax positions during any period presented.
Concentrations of Credit Risk	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, 2018 , 2017 , and 2016 , NGL Crude Logistics accounted for 66% , 44% , and 0% of sales, respectively; Lion Oil Trading & Transportation, Inc. accounted for 8% , 18% , and 18% of sales, respectively; and Duke Energy Field Services accounted for 8% , 16% , and 14% of sales, respectively. For the year ended December 31, 2016, Silo Energy, LLC accounted for 50% of sales.
Oil and Gas Derivative Activities	Oil and Gas Derivative Activities The Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forward contracts. The contracts were 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 13 - Derivatives .
Earnings Per Share	Earnings Per Share Earnings per basic and diluted share within the Successor Company are calculated under the treasury stock method. Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. Diluted net income per common share is calculated by dividing net income 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, which are measured using the treasury stock method. When the Company recognizes a loss from continuing operations, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share. Earnings per basic and diluted share within the Predecessor Company were calculated under the two-class method. Pursuant to the two-class method, the Company’s unvested restricted stock awards with non-forfeitable rights to dividends are considered participating securities. Under the two-class method, earnings per basic share is calculated by dividing net income available to shareholders by the weighted-average number of common shares outstanding during the period. The two-class method includes an earnings allocation formula that determines earnings per share for each participating security according to undistributed earnings for the period. Net income available to shareholders is reduced by the amount allocated to participating restricted shares to arrive at the earnings allocated to common stock shareholders for purposes of calculating earnings per share. Participating shares are not contractually obligated to share in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding shares. Earnings per diluted share is computed on the basis of the weighted-average number of common shares outstanding during the period plus the dilutive effect of any potential common shares outstanding during the period using the more dilutive of the treasury method or two-class method. For additional discussion, please refer to Note 14 - Earnings Per Share .
Stock-Based Compensation	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 9 - Stock-Based Compensation .
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 May 2014, the Financial Accounting Standards Board (“FASB”) issued Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) Accounting Standards Codification (“ASC”) 606 (“ASC 606”). Several additional related updates were issued since that point. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. The guidance also requires enhanced financial statement disclosures over revenue recognition and provisions regarding future revenues and expenses under a gross-versus-net presentation. The standard was required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. We adopted the new standard on January 1, 2018, and its adoption did not have a significant impact on our financial statements. Please refer to Note 2 - Revenue Recognition for additional discussion. In January 2016, the FASB issued Update No. 2016-01 – Financial Instruments - Overall to require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. This authoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. We adopted the new standard on January 1, 2018, and its adoption did not have a material impact on our financial statements and disclosures. Effective January 1, 2017, the Company adopted FASB Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting . The objective of this update was to simplify the current guidance for stock compensation. The areas for simplification involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update is effective for the annual periods beginning after December 15, 2016, and interim periods within those annual periods. As of January 1, 2017, and thereafter, the Company did not have excess tax benefits associated with its stock compensation, and therefore, there was no tax impact upon adoption of this standard. In addition, the employee taxes paid on the statement of cash flows when shares were withheld for taxes have already been classified as a financing activity; therefore, there was no cash flow statement impact upon adoption of this standard. This standard allowed companies to elect to account for forfeitures as they occurred or estimate the number of awards that will vest. The Company elected to account for forfeitures as they occur, resulting in a minimal impact upon adoption of this standard. In August 2016, the FASB issued Update No. 2016-15 - Classification of Certain Cash Receipts and Cash Payments , which clarifies the presentation of specific cash receipts and cash payments within the statement of cash flows. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018, and its adoption did not have a material impact on our consolidated statements of cash flows (“statements of cash flows”) and related disclosures. In November 2016, the FASB issued Update No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash . This update clarifies how entities should present restricted cash and restricted cash equivalents in the statement of cash flows by including them with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statements of cash flows. This guidance is to be applied using a retrospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted the new standard on January 1, 2018, and the prior period has been adjusted to conform to the current period presentation, which resulted in an increase in cash used in investing activities of $0.1 million for the 2017 Successor and Predecessor Periods, respectively, and $0.2 million for the year ended December 31, 2016. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets that sums to the total of such amounts shown in the accompanying statements of cash flows (in thousands): Successor Predecessor As of December 31, As of 2018 2017 April 28, 2017 December 31, 2016 Cash and cash equivalents $ 12,916 $ 12,711 $ 70,183 $ 80,565 Restricted cash included in other noncurrent assets 86 71 64 182 Total cash, cash equivalents and restricted cash as shown in the statements of cash flows $ 13,002 $ 12,782 $ 70,247 $ 80,747 Restricted cash consists of funds for road maintenance and repairs. In January 2017, the FASB issued U pdate No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business . This update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This guidance is to be applied using a prospective method and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted. We adopted this new standard on January 1, 2018 and will apply it to any future acquisitions or disposals of assets or business. In February 2017, the FASB issued Update No. 2017-05, Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets . This update is meant to clarify existing guidance and to add guidance for partial sales of nonfinancial assets. This guidance is to be applied using a full retrospective method or a modified retrospective method as outlined in the guidance and is effective at the same time as Update 2014-09, Revenue from Contracts with Customers (Topic 606) . We adopted this new standard on January 1, 2018, and its adoption did not have a material impact on our financial statements and disclosures. In May 2017, the FASB issued Update No. 2017-09 Compensation – Stock Compensation (Topic 718) . The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718. Previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. This guidance was effective for annual or any interim periods beginning after December 15, 2017. We adopted this new standard on January 1, 2018. There was no material impact due to the adoption of this guidance. In February 2016, the FASB issued Update No. 2016-02 - Leases (Topic 842) to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. Each lease that is recognized in the balance sheet will be classified as either finance or operating, with such classification affecting the presentation within the statements of cash flows. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. The Company adopted this guidance on January 1, 2019, using the modified retrospective approach. As part of the assessment process, the Company utilized external consultants to evaluate agreements under this guidance as well as assess the completeness of the lease population. The types of agreements evaluated under this guidance included the Company’s office leases, corporate asset rentals, drilling rig agreements, well-completion agreements, midstream infrastructure agreements, generator and compressor rentals, various other field equipment rentals, and other arrangements that included potential lease obligations under this guidance. The Company has completed the process of reviewing and determining the contracts and agreements to which the new guidance applies, and has implemented policies, internal controls, and processes that will be necessary to support the Company’s compliance with the additional accounting and disclosure requirements under this guidance. The lease administration system that will support the Company’s compliance with this guidance after adoption is operational and currently being populated with the necessary lease data and relevant assumptions. Policy elections made by the Company as allowed under this guidance include (a) not recognizing leases with terms that are less than twelve months on the balance sheet, (b) combining lease and non-lease components as a single lease, (c) and applying practical expedients, which allow the Company to avoid reassessing contracts that commenced prior to adoption and were correctly classified under ASC 840. Adoption of this guidance will result in right-of-use assets and right-of-use liabilities on the balance sheets; however, the Company is not in a position to provide an estimate of the full quantitative impacts at this time. In January 2018, the FASB issued Update 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 , which permits an entity to elect an optional transition practical expedient to not evaluate land easements existing or expiring before the entity's adoption of Update 2016-02 and not previously accounted for as leases. An entity that elects this practical expedient should evaluate new or modified land easements under this guidance beginning at the date Update 2016-02 is adopted. The Company plans to elect this practical expedient option at the same time it adopts Update 2016-02. In July 2018, the FASB issued Update No. 2018-11, Leases (Topic 842): Targeted Improvements , which provides for an additional transition method that allows an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings (deficit) in the period of adoption. The Company plans to elect this transition method, which will eliminate the need for adjusting prior period comparable financial statements prepared under current lease accounting guidance. The Company will adopt this guidance at the same time it adopts Update 2016-02. In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement . The objective of this update is to improve the effectiveness of fair value measurement disclosures. This update is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods. The standard will only impact the Company's disclosures. In August 2018, the Securities and Exchange Commission, (“SEC”) issued a final rule, Disclosure Update and Simplification, that updates and simplifies SEC disclosure requirements. The primary changes include removing the requirement to disclose outside of the consolidated financial statements historical and pro forma ratios of earnings to fixed charges and historical low and high trading prices of the Company's common stock and adding a requirement to provide within the interim financial statements an analysis of changes in stockholders' equity for the current and comparative quarterly and year-to-date periods. Other changes included requirements related to segment, geographic area and dividend disclosures. The final rule was effective November 5, 2018. The Company adopted the standard for this annual report ending December 31, 2018, and it did not have a material impact on the Company's disclosures. There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of December 31, 2018, and through the filing date of this report.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Restrictions on Cash and Cash Equivalents	The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets that sums to the total of such amounts shown in the accompanying statements of cash flows (in thousands): Successor Predecessor As of December 31, As of 2018 2017 April 28, 2017 December 31, 2016 Cash and cash equivalents $ 12,916 $ 12,711 $ 70,183 $ 80,565 Restricted cash included in other noncurrent assets 86 71 64 182 Total cash, cash equivalents and restricted cash as shown in the statements of cash flows $ 13,002 $ 12,782 $ 70,247 $ 80,747

REVENUE RECOGNITION (Tables)

REVENUE RECOGNITION (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Schedule of New Revenue Recognition Standard	The impact of adoption is as follows (in thousands): Year Ended December 31, 2018 As Unadjusted (1) ASC 606 Adjustments As Reported Operating Revenues: Oil sales $ 228,661 $ — $ 228,661 Natural gas sales 18,076 4,293 22,369 NGLs sales 20,188 5,439 25,627 Oil and gas sales $ 266,925 $ 9,732 $ 276,657 Operating expenses: Gathering, transportation and processing $ — $ 9,732 $ 9,732 Net income $ 168,186 $ — $ 168,186 ____________________ (1) This column excludes the impact of ASC 606 and is consistent with the presentation prior to January 1, 2018.

OTHER NONCURRENT ASSETS (Tables

OTHER NONCURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2018
Other Assets [Abstract]
Schedule of other assets	Other noncurrent assets contain the following (in thousands): Successor As of December 31, 2018 2017 Operating bonds $ 2,713 $ 2,683 Deferred financing costs 1,710 — AMT credit refund (1) 376 376 Restricted cash 86 71 Other noncurrent assets $ 4,885 $ 3,130 ______________________________________ (1) Represents the alternative minimum tax credit refund due to the Company upon application of the newly enacted comprehensive tax legislation that took effect on December 22, 2017.

ACCOUNTS PAYABLE AND ACCRUED _2

ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Tables)	12 Months Ended
	Dec. 31, 2018
Payables and Accruals [Abstract]
Schedule of accounts payable and accrued expenses	Accounts payable and accrued expenses contain the following (in thousands): Successor As of December 31, 2018 2017 Drilling and completion costs $ 33,602 $ 21,833 Accounts payable trade 11,532 6,256 Accrued general and administrative cost 12,728 10,025 Lease operating expense 2,183 5,005 Accrued interest 241 250 Accrued oil and gas hedging — 808 Production and ad valorem taxes and other 19,104 17,952 Total accounts payable and accrued expenses $ 79,390 $ 62,129

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	The annual minimum commitment payments on the new NGL agreement and the new office lease for the next five years as of December 31, 2018 are presented below (in thousands): NGL Commitments (1) Office Lease Commitments (2) Total 2019 $ 19,580 1,256 20,836 2020 27,949 1,351 29,300 2021 28,791 1,401 30,192 2022 29,485 234 29,719 2023 30,448 — 30,448 2024 and thereafter — — — Total $ 136,253 4,242 140,495 ____________________ (1) The above calculation is based on the minimum volume commitment schedule (as defined in the new NGL agreement) and applicable differential fees. (2) The Company has subleased a portion of its office lease. The contractual amounts disclosed are presented gross, excluding total sublease income of $1.4 million .

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of the status and activity of non-vested restricted stock	A summary of the status and activity of non-vested restricted stock units is presented below: Restricted Stock Units Weighted- Average Grant-Date Fair Value Non-vested at beginning of 2017 Successor Period — $ — Granted 452,996 $ 34.62 Vested (173,200 ) $ 34.19 Forfeited (18,631 ) $ 34.36 Non-vested as of December 31, 2017 261,165 $ 34.93 Granted 387,720 $ 27.80 Vested (84,345 ) $ 30.63 Forfeited (83,705 ) $ 29.78 Non-vested as of December 31, 2018 480,835 $ 30.83 A summary of the status and activity of non-vested restricted stock is presented below: Predecessor January 1, 2017 through April 28, 2017 For the Year Ended December 31, 2016 Restricted Stock Weighted- Average Grant-Date Fair Value Restricted Stock Weighted- Average Grant-Date Fair Value Non-vested at beginning of year 368,887 $ 19.45 731,818 $ 29.47 Granted — $ — 113,044 $ 0.98 Vested (111,996 ) $ 32.22 (355,498 ) $ 31.68 Forfeited (5,134 ) $ 29.55 (120,477 ) $ 27.34 Canceled (251,757 ) $ 13.08 — $ — Non-vested at end of period — $ — 368,887 $ 19.45
Schedule of assumptions used to determine the fair value of the PSUs granted	Stock options were valued using a Black-Scholes Model using the following assumptions: For the Year Ended December 31, 2017 Expected volatility 52.1 % Expected dividends — % Expected term (years) 6.0 Risk-free interest rate 1.96 % The following table presents the assumptions used to determine the fair value of the TSR portion of the PSUs: For the Year Ended December 31, 2018 Expected term of award (in years) 3 Risk-free interest rate 2.76 % Expected daily volatility 2.6 %
Summary of the status and activity of PSUs	A summary of the status and activity of performance stock units is presented below: Performance Stock Units Weighted- Non-vested as of December 31, 2017 — $ — Granted (1) 59,641 $ 29.92 Forfeited (5,952 ) $ 29.92 Non-vested as of December 31, 2018 53,689 $ 29.92 ______________________________ (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 times the number of units awarded, depending on the level of satisfaction of the performance condition. A summary of the status and activity of PSUs is presented in the following table: Predecessor January 1, 2017 through April 28, 2017 For the Year Ended December 31, 2016 PSU Weighted-Average PSU Weighted-Average Non-vested at beginning of year (1) 21,538 $ 33.31 114,833 $ 35.27 Granted (1) — $ — — $ — Vested (1) — $ — (59,725 ) $ 36.61 Forfeited (1) — $ — (33,570 ) $ 35.55 Canceled (1) (21,538 ) $ 33.31 — $ — Non-vested at end of period (1) — $ — 21,538 $ 33.31 ___________________________ (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 times the number of PSUs awarded, depending on the level of satisfaction of the performance condition.
Schedule of non-vested share activity	A summary of the status and activity of non-vested units for the 2017 and 2016 Predecessor Periods is presented below. Predecessor January 1, 2017 through April 28, 2017 For the Year Ended December 31, 2016 LTIP Units Weighted- LTIP Units Weighted- Non-vested at beginning of year 2,443,402 $ 0.99 — $ — Granted — $ — 2,958,558 $ 0.99 Vested (767,848 ) $ 0.98 — $ — Forfeited (126,616 ) $ 0.98 (515,156 ) $ 0.98 Canceled (1,548,938 ) $ 0.99 — $ — Non-vested at end of period — $ — 2,443,402 $ 0.99 A summary of the status and activity of non-vested stock options is presented below: Stock Options Weighted- Average Exercise Price Weighted-Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding at beginning of Current Successor Period — $ — — $ — Granted 389,102 34.36 — $ — Exercised — — — $ — Forfeited (191,831 ) 34.36 9.3 $ — Outstanding as of December 31, 2017 197,271 $ 34.36 9.3 $ — Granted — — — $ — Exercised (32,037 ) 34.36 — $ — Forfeited (32,425 ) 34.36 — $ — Outstanding as of December 31, 2018 132,809 $ 34.36 6.7 $ — Options outstanding and exercisable as of December 31, 2018 61,880 $ 34.36 4.8 $ —

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of provision for income taxes	The provision for income taxes consists of the following (in thousands): Successor Predecessor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 Current tax benefit Federal $ — $ 376 $ — $ — State — — — — Deferred tax benefit — — — — Total income tax benefit $ — $ 376 $ — $ —
Schedule of temporary differences, deferred tax assets and liabilities	Temporary differences between the financial statement carrying amounts and tax basis of assets and liabilities that give rise to the net deferred tax liability result from the following components (in thousands): Successor As of December 31, 2018 2017 Deferred tax liabilities: Oil and gas properties $ 52,006 $ — Derivative liability 8,527 — Total deferred tax liabilities 60,533 — Deferred tax assets: Federal and state tax net operating loss carryforward 137,567 117,115 Oil and gas properties — 1,319 Derivative liability — 3,457 Reclamation costs 7,251 9,516 Stock compensation 1,635 1,419 Accrued compensation 1,308 1,285 Inventory 1,577 1,529 Settlement liabilities — — AMT credit — — State bonus depreciation addback — 1,089 Other long-term assets 271 231 Total deferred tax assets 149,609 136,960 Less: Valuation allowance 89,076 136,960 Total deferred tax assets after valuation allowance — — Total non-current net deferred tax liability $ — $ —
Schedule of amount of effective income tax rate reconciliation	Federal income tax expense differs from the amount that would be provided by applying the statutory United States federal income tax rate of 21% to income before income taxes primarily due to the effect of state income taxes, rate changes, and other permanent differences, as follows (in thousands): Successor Predecessor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 Federal statutory tax (expense) benefit by applying the statutory rate $ 35,319 $ 1,889 $ (931 ) $ 69,633 Decrease (increase) in tax resulting from: State tax expense net of federal benefit 6,556 172 (85 ) 6,358 Prior year true-up (458 ) — (7,572 ) — Stock compensation 854 — (1,773 ) — Permanent differences 61 (715 ) (35,273 ) — Rate change (421 ) (73,956 ) — — NOL Adjustment 5,973 — — — Other — (642 ) — (317 ) Valuation allowance (47,884 ) 73,628 45,634 (75,674 ) Total income tax benefit $ — $ 376 $ — $ —

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule of change in asset retirement obligations assumed	A roll-forward of the Company’s asset retirement obligation is as follows (in thousands): Balance as of January 1, 2017 (Predecessor) $ 30,833 Liabilities settled (218 ) Accretion expense 1,045 Ending balance as of April 28, 2017 (Predecessor) $ 31,660 Fair value fresh-start adjustment $ (2,599 ) Beginning balance as of April 29, 2017 (Successor) $ 29,061 Additional liabilities incurred 130 Accretion expense 1,370 Liabilities settled (780 ) Revisions to estimate 8,481 Ending balance as of December 31, 2017 (Successor) $ 38,262 Additional liabilities incurred 373 Accretion expense 1,831 Liabilities settled (1,627 ) Revisions to estimate 1,490 Sold properties (10,924 ) Ending balance as of December 31, 2018 (Successor) 29,405

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of financial assets and liabilities at fair value on recurring basis	The following tables present the Company’s financial and non-financial assets and liabilities that were accounted for at fair value as of December 31, 2018 and 2017 and their classification within the fair value hierarchy: Successor As of December 31, 2018 Level 1 Level 2 Level 3 (in thousands) Derivative assets (1) $ — $ 38,272 $ — Derivative liabilities (1) $ — $ 183 $ — Asset retirement obligations (2) $ — $ — $ 1,490 Successor As of December 31, 2017 Level 1 Level 2 Level 3 (in thousands) Derivative assets (1) $ — $ 494 $ — Derivative liabilities (1) $ — $ 14,395 $ — Asset retirement obligations (2) $ — $ — $ 8,481 _______________________________ (1) This represents a financial asset or liability that is measured at fair value on a recurring basis. (2) This represents the revision to estimates of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion.

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of commodity derivatives	As of December 31, 2018 , 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 1Q19 Cashless Collar 4,000 $50.88/$63.83 7,600 $2.75/$3.22 — — — — Swap 4,000 $59.16 1,500 $3.13 7,600 $0.67 10,000 $2.17 Put 500 $55.00 — — — — — — 2Q19 Cashless Collar 5,330 $54.42/$67.57 2,505 $2.75/$3.22 — — — — Swap 3,500 $57.84 — — — — 16,703 $2.11 Put 500 $55.00 — — — — — — 3Q19 Cashless Collar 3,000 $59.17/$75.72 — — — — — — Swap 5,000 $59.92 — — — — 20,000 $2.10 Put 500 $55.00 — — — — — — 4Q19 Cashless Collar 3,000 $59.17/$75.72 — — — — — — Swap 5,000 $59.92 — — — — 20,000 $2.10 Put 500 $55.00 — — — — — — 1Q20 Swap 3,000 $63.48 — — — — — — 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 1Q19 Cashless Collar 4,656 $51.46/$65.40 7,600 $2.75/$3.22 — — — — Swap 4,000 $59.16 1,500 $3.13 7,600 $0.67 11,639 $2.20 Put 172 $55.00 — — — — — — 2Q19 Cashless Collar 6,330 $54.51/$68.74 2,505 $2.75/$3.22 — — — — Swap 3,500 $57.84 — — — — 19,203 $2.15 Put — — — — — — — — 3Q19 Cashless Collar 4,000 $58.13/$75.54 — — — — — — Swap 5,000 $59.92 — — — — 22,500 $2.13 Put — — — — — — — — 4Q19 Cashless Collar 4,000 $58.13/$75.54 — — — — — — Swap 5,000 $59.92 — — — — 22,500 $2.13 Put — — — — — — — — 1Q20 Swap 3,000 $63.48 — — — — 2,500 $2.40 Collar 2,000 $55.00/$62.00 — — — — — —
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, 2018 and 2017 (in thousands): Successor As of December 31, 2018 2017 Balance Sheet Location Fair Value Fair Value Derivative Assets: Commodity contracts Current assets $ 34,408 $ 488 Commodity contracts Noncurrent assets 3,864 6 Derivative Liabilities: Commodity contracts Current liabilities (183 ) (11,423 ) Commodity contracts Long-term liabilities — (2,972 ) Total derivative assets (liabilities), net $ 38,089 $ (13,901 )
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 (in thousands): Successor Predecessor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 Derivative cash settlement gain (loss): Oil contracts $ (17,700 ) $ (1,486 ) $ — $ 18,333 Gas contracts (460 ) 22 — — Total derivative cash settlement gain (loss) (1) $ (18,160 ) $ (1,464 ) $ — $ 18,333 Change in fair value gain (loss) 48,431 (13,901 ) $ — $ (29,567 ) Total derivative gain (loss) (1) $ 30,271 $ (15,365 ) $ — $ (11,234 ) ___________________________ (1) Total derivative gain (loss) and the derivative cash settlement gain (loss) for each of the periods presented above is reported in the derivative (gain) loss and derivative cash settlements line items on the accompanying statements of cash flows within the net cash provided by operating activities.

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Schedule of earnings per share	The following table sets forth the calculation of income (loss) per basic and diluted shares from net income (loss) for the Predecessor Periods ended April 28, 2017 and December 31, 2016: Predecessor January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 (in thousands, except per share amounts) Net income (loss) $ 2,660 $ (198,950 ) Less: undistributed income to unvested restricted stock 120 — Undistributed income (loss) to common shareholders 2,540 (198,950 ) Basic net income (loss) per common share $ 0.05 $ (4.04 ) Diluted net income (loss) per common share $ 0.05 $ (4.04 ) Weighted-average shares outstanding - basic 49,559 49,268 Add: dilutive effect of contingent PSUs 1,412 — Weighted-average shares outstanding - diluted 50,971 49,268 The RSUs, PSUs, stock options, and warrants of the Company are all non-participating securities, and therefore, the Company uses the treasury stock method to calculate earnings per share as shown in the following table (in thousands, except per share amounts): Successor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 Net income (loss) $ 168,186 $ (5,020 ) Basic net income (loss) per common share $ 8.20 $ (0.25 ) Diluted net income (loss) per common share $ 8.16 $ (0.25 ) Weighted-average shares outstanding - basic 20,507 20,427 Add: dilutive effect of contingent stock awards 96 — Weighted-average shares outstanding - diluted 20,603 20,427

FRESH-START ACCOUNTING (Tables)

FRESH-START ACCOUNTING (Tables)	12 Months Ended
	Dec. 31, 2018
Reorganizations [Abstract]
Reconciliation of Enterprise Value	The following table reconciles the enterprise value to the estimated fair value of Successor Company's common stock as of the Effective Date (in thousands, except per share amounts): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Less: Interest bearing liabilities (29,061 ) Less: Fair value of warrants (4,081 ) Fair value of Successor common stock $ 680,040 Shares outstanding at April 28, 2017 20,356 Per share value $ 33.41
Successor Condensed Consolidated Balance Sheet	The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands): Enterprise Value $ 642,999 Plus: Cash and cash equivalents 70,183 Plus: Working capital liabilities 63,871 Plus: Other long-term liabilities 17,919 Reorganization value of Successor assets $ 794,972 The explanatory notes highlight methods used to determine estimated fair values or other amounts of assets and liabilities, as well as significant assumptions. Predecessor Company Reorganization Adjustments Fresh-Start Adjustments Successor Company (in thousands, except share amounts) ASSETS Current Assets: Cash and cash equivalents $ 96,286 $ (26,103 ) (1) $ — $ 70,183 Accounts receivable: Oil and gas sales 24,876 — — 24,876 Joint interest and other 3,028 — — 3,028 Prepaid expenses and other 4,952 — — 4,952 Inventory of oilfield equipment 4,218 — — 4,218 Total current assets 133,360 (26,103 ) — 107,257 Property and equipment (successful efforts method): Proved properties 2,531,834 — (2,031,373 ) (6) 500,461 Less: accumulated depreciation, depletion and amortization (1,720,736 ) — 1,720,736 (6) — Total proved properties, net 811,098 — (310,637 ) 500,461 Unproved properties 163,781 — 14,679 (6) 178,460 Wells in progress 18,002 — (18,002 ) (7) — Other property and equipment, net 6,056 — — 6,056 Total property and equipment, net 998,937 — (313,960 ) 684,977 Other noncurrent assets 2,738 — — 2,738 Total assets $ 1,135,035 $ (26,103 ) $ (313,960 ) $ 794,972 LIABILITIES AND STOCKHOLDERS'S EQUITY Current liabilities: Accounts payable and accrued expenses $ 72,635 $ (33,701 ) (2) $ — $ 38,934 Oil and gas revenue distribution payable 24,937 — — 24,937 Predecessor credit facility - current portion 191,667 (191,667 ) (3) — — Total current liabilities 289,239 (225,368 ) — 63,871 Long-term liabilities: Ad valorem taxes 17,919 — — 17,919 Asset retirement obligations for oil and gas properties 31,660 — (2,599 ) (8) 29,061 Liabilities subject to compromise 873,292 (873,292 ) (4) — — Total liabilities $ 1,212,110 $ (1,098,660 ) $ (2,599 ) $ 110,851 Stockholders' equity: Predecessor preferred stock — — — — Predecessor common stock 49 — (49 ) (9) — Additional paid in capital 816,679 — (816,679 ) (9) — Successor common stock — 204 (5) — 204 Successor warrants — 4,081 (5) — 4,081 Additional paid-in capital — 679,836 (5) — 679,836 Retained deficit (893,803 ) 388,436 (4) 505,367 (10) — Total stockholders' equity (77,075 ) 1,072,557 (311,361 ) 684,121 Total liabilities and stockholders' equity $ 1,135,035 $ (26,103 ) $ (313,960 ) $ 794,972
Schedule of Net Cash Payments Made Upon Emergence	The following table reflects the net cash payments made upon emergence on the Effective Date (in thousands): Sources: Proceeds from rights offering $ 200,000 Proceeds from ad hoc equity committee 7,500 Total sources $ 207,500 Uses and transfers: Payment on predecessor credit facility (principal, interest and fees) $ (193,729 ) Payment and funding of escrow account related to professional fees (17,193 ) Payment of professional fees and other (13,831 ) Payment of Silo contract settlement and other (7,228 ) Payment of remaining 2016 STIP (1,622 ) Total uses and transfers $ (233,603 ) Total net sources, uses and transfers $ (26,103 )
Schedule of Accounts Payable and Accrued Liabilities Attributable to Reorganization Items	The following table shows the decrease of accounts payable and accrued liabilities attributable to reorganization items settled or paid upon emergence (in thousands): Accounts payable and accrued expenses: Accrued 2016 STIP payment $ (1,574 ) Escrow account funding (17,193 ) Professional fees and other (13,831 ) Accrued unpaid interest on predecessor credit facility (1,103 ) Total accounts payable and accrued expenses settled $ (33,701 )
Schedule of Liabilities Subject to Compromise	On the Effective Date, the obligations of the Company with respect to the Senior Notes were canceled. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands): Senior Notes $ 800,000 Accrued interest on Senior Notes (pre-petition) 14,879 Make-whole payment on Senior Notes 51,185 Silo contract settlement accrual 7,228 Total liabilities subject to compromise of the predecessor 873,292 Rights offering 200,000 Fair value of equity issued to creditors, excluding equity issued to existing equity holders (653,212 ) Payment of Silo contract settlement (7,228 ) Gain on settlement of liabilities subject to compromise 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007 ) Total reorganization items at emergence $ 411,845 Issuance of warrants to existing shareholders $ (4,081 ) Proceeds from ad hoc equity committee 7,500 Issuance of shares to existing shareholders (26,828 ) Total reorganization adjustments to retained deficit $ 388,436
Schedule of Reorganization Items	The following table summarizes reorganization items recorded in the Current Predecessor Period (in thousands): Gain on settlement of liabilities subject to compromise $ 412,852 Payment on predecessor credit facility fees and remaining unaccrued 2016 STIP (1,007 ) Fresh-start valuation adjustments (311,361 ) Legal and professional fees and expenses (34,335 ) Write-off of debt issuance and premium costs (6,156 ) Make-whole payment on Senior Notes (51,185 ) Total reorganization items, net $ 8,808

DISCLOSURES ABOUT OIL AND GAS_2

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2018
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
Schedule of costs incurred in oil and natural gas producing activities	Costs incurred in oil and natural gas producing activities are as follows (in thousands): Successor Predecessor Year Ended December 31, 2018 April 29, 2017 through December 31, 2017 January 1, 2017 through April 28, 2017 Year Ended December 31, 2016 Acquisition (1) $ 2,861 $ 5,383 $ 445 $ 97 Development (2)(3) 304,197 106,449 10,780 31,209 Exploration 294 3,671 769 74 Total (4) $ 307,352 $ 115,503 $ 11,994 $ 31,380 _________________________ (1) Acquisition costs for unproved properties for the year ended December 31, 2018, 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period were $2.5 million , $5.4 million , $0.4 million , and $0.1 million , respectively. There was $0.4 million in acquisition costs for proved properties for the year ended December 31, 2018 and no acquisition costs for proved properties for the 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period. (2) Development costs include workover costs of $5.6 million , $4.3 million , $1.8 million , and $6.0 million charged to lease operating expense for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period, respectively. (3) Includes amounts relating to asset retirement obligations of $(9.0) million , $8.3 million , $3.1 million , and $2.4 million for the Current Successor Period, 2017 Successor Period, 2017 Predecessor Period, and 2016 Predecessor Period, respectively.
Summary of BCEI's changes in quantities of proved oil, natural gas liquids and natural gas reserves	All of BCEI’s oil, natural gas liquids, and natural gas reserves are attributable to properties within the United States. A summary of BCEI’s changes in quantities of proved oil, natural gas liquids, and natural gas reserves for the years ended December 31, 2018 , 2017 , and 2016 are as follows: Natural Natural Oil Gas Gas Liquids (MBbl) (MMcf) (MBbl) Balance-December 31, 2015 57.393 144.227 19.918 Extensions, discoveries and infills (1) 6.133 15.128 2.142 Production (4.310 ) (11.907 ) (1.491 ) Sales of minerals in place (0.100 ) (0.343 ) (0.035 ) Revisions to previous estimates (3) (9.020 ) (9.060 ) (2.987 ) Balance-December 31, 2016 50.096 138.045 17.547 Extensions, discoveries and infills (1) 8.470 22.212 3.376 Production (3.081 ) (9.010 ) (1.136 ) Revisions to previous estimates (3) (2.557 ) 6.422 3.028 Balance-December 31, 2017 52.928 157.669 22.815 Extensions, discoveries and infills (1) 18.390 31.471 5.197 Production (3.841 ) (8.567 ) (1.140 ) Sales of minerals in place (6.236 ) (20.534 ) (1.499 ) Removed from capital program (2) (1.442 ) (3.246 ) (0.544 ) Revisions to previous estimates (3) 4.555 8.219 0.101 Balance-December 31, 2018 64.354 165.012 24.930 Proved developed reserves: December 31, 2016 26.313 85.972 9.951 December 31, 2017 25.785 92.718 12.702 December 31, 2018 23.725 79.630 11.703 Proved undeveloped reserves: December 31, 2016 23.783 52.073 7.596 December 31, 2017 27.143 64.951 10.113 December 31, 2018 40.629 85.382 13.227 ________________________ (1) At December 31, 2018, horizontal development in the Wattenberg Field resulted in additions in extensions, discoveries, and infills of 28,832 MBoe. At December 31, 2017, horizontal development in the Wattenberg Field resulted in additions in extensions and discoveries of 15,548 MBoe. At December 31, 2016, horizontal development in the Wattenberg Field resulted in additions of 1,632 MBoe, and infill down-spacing within the Wattenberg Field resulted in 9,164 MBoe to the additions, extensions, and infills category. (2) As of December 31, 2018, proved undeveloped reserves were reduced by 2,527 MBoe due to the removal of proved undeveloped locations from our five-year drilling program. (3) As of December 31, 2018, the Company revised its proved reserves upward by 6,026 MBoe. 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 2,333 MBoe. In addition, lower operating cost estimates resulted in positive reserve adjustments of 1,536 MBoe. There were net positive engineering revisions of 2,163 MBoe. As of December 31, 2017, the Company revised its proved reserves upward by 1,542 MBoe. The commodity prices at December 31, 2017 increased to $51.34 per Bbl WTI and $2.98 per MMBtu HH from $42.75 per Bbl WTI and $2.48 per MMBtu HH at December 31, 2016, resulting in positive revisions of 5,405 MBoe. In addition, lower operating cost estimates resulted in positive reserve adjustments (net of price increases) of 1,672 MBoe, of which 1,370 MBoe relate to operations in the Wattenberg Field. The Company also had positive other engineering revisions of 2,042 MBoe, offset by PUD demotions of 7,577 MBoe. As of December 31, 2016, the Company revised its proved reserves downward by 13,517 MBoe. The commodity prices at December 31, 2016 decreased to $42.75 per Bbl WTI and $2.48 per MMBtu HH from $50.28 per Bbl WTI and $2.59 per MMBtu HH at December 31, 2015. The negative effects of commodity price reductions on reserves were offset by lower cost estimates to drill and complete future development locations in the Wattenberg Field along with lower operating cost estimates across the Company's operations, to reflect a positive reserves adjustment (net of price reductions) of 4,652 MBoe. Also, all future proved undeveloped locations in the Mid-Continent region were demoted to non-proved reserves resulting in a negative revision of 7,761 MBoe. In the Wattenberg Field, certain proved undeveloped locations totaling 8,611 MBoe were demoted due to their not being centric to current infrastructure. The Company also had negative other engineering revisions of 1,797 MBoe in 2016.
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: For the Years Ended December 31, 2018 2017 2016 (in thousands) Future cash flows $ 4,742,180 $ 3,307,868 $ 2,424,415 Future production costs (1,585,032 ) (1,490,091 ) (1,365,765 ) Future development costs (925,640 ) (622,344 ) (468,804 ) Future income tax expense — — — Future net cash flows 2,231,508 1,195,433 589,846 10% annual discount for estimated timing of cash flows (1,276,528 ) (596,935 ) (312,891 ) Standardized measure of discounted future net cash flows $ 954,980 $ 598,498 $ 276,955
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: For the Years Ended December 31, 2018 2017 2016 (in thousands) Beginning of period $ 598,498 $ 276,955 $ 327,816 Sale of oil and gas produced, net of production costs (204,566 ) (125,992 ) (123,494 ) Net changes in prices and production costs 365,952 282,112 (126,536 ) Extensions, discoveries and improved recoveries 153,691 103,937 22,800 Development costs incurred 127,788 24,121 19,701 Changes in estimated development cost (52,260 ) 2,122 281,062 Purchases of minerals in place — — — Sales of minerals in place (115,742 ) — 16 Revisions of previous quantity estimates 12,341 14,119 (182,938 ) Net change in income taxes — — Accretion of discount 59,850 27,696 32,782 Changes in production rates and other 9,428 (6,572 ) 25,746 End of period $ 954,980 $ 598,498 $ 276,955
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, 2018 , 2017 , and 2016 were calculated using the twelve-month arithmetic average of first-day-of-the-month price inclusive of adjustments for quality and location. For the Years Ended December 31, 2018 2017 2016 Oil (per Bbl) $ 59.29 $ 46.76 $ 38.42 Gas (per Mcf) $ 2.28 $ 2.45 $ 2.07 Natural gas liquids (per Bbl) $ 22.06 $ 19.57 $ 12.12

QUARTERLY FINANCIAL DATA (UNA_2

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2018 and 2017 (in thousands, except per share data): Successor Three Months Ended 2018 March 31 June 30 September 30 December 31 Oil and gas sales $ 64,193 $ 71,872 $ 74,380 $ 66,213 Operating profit (1) $ 35,042 $ 40,014 $ 43,959 $ 41,416 Net Income $ 13,870 $ 4,859 $ 43,363 $ 106,094 Basic net income per common share $ 0.68 $ 0.24 $ 2.11 $ 5.16 Diluted net income per common share $ 0.68 $ 0.24 $ 2.10 $ 5.15 Predecessor Successor Three Months Ended March 31, 2017 April 1, 2017 through April 28, 2017 April 29, 2017 through June 30, 2017 Three Months Ended September 30, 2017 Three Months Ended December 31, 2017 2017 Oil and gas sales $ 52,559 $ 16,030 $ 28,114 $ 45,232 $ 50,189 Operating profit (1) 14,398 3,786 12,955 22,540 22,935 Net income (loss) (94,276 ) 96,936 (3,580 ) 4,328 (5,768 ) Basic net income (loss) per common share $ (1.91 ) $ 1.88 $ (0.18 ) $ 0.21 $ (0.28 ) Diluted net income (loss) per common share $ (1.91 ) $ 1.85 $ (0.18 ) $ 0.21 $ (0.28 ) ________________________ (1) Oil and gas sales less lease operating expense, gas plant and midstream operating expense, gathering, transportation, and processing, severance and ad valorem taxes, depreciation, and depletion and amortization.

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Proved properties		$ 555,341	$ 719,198
Unproved properties		183,843	154,352
Net cash provided by (used in) investing activities		$ (82,641)	(164,376)
Gathering Assets
Property, Plant and Equipment [Line Items]
Proved properties			120,400
Wells in progress			900
Unproved properties			$ 100
Minimum
Property, Plant and Equipment [Line Items]
Receivable collection period			1 month
Minimum | Property, Plant and Equipment, Other Types
Property, Plant and Equipment [Line Items]
PP&E useful life			3 years
Maximum
Property, Plant and Equipment [Line Items]
Receivable collection period			2 months
Maximum | Property, Plant and Equipment, Other Types
Property, Plant and Equipment [Line Items]
PP&E useful life			10 years
Predecessor
Property, Plant and Equipment [Line Items]
Proved properties	$ 2,531,834
Unproved properties	163,781
Net cash provided by (used in) investing activities	(6,022)			$ (67,460)
Accounting Standards Update 2016-18 | Predecessor
Property, Plant and Equipment [Line Items]
Net cash provided by (used in) investing activities	$ (100)			$ (200)

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations of Credit Risk (Details) - Sales - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
NGL Crude Logistics
Concentration Risk [Line Items]
Percent of oil and natural gas sales	66.00%	44.00%	0.00%
Lion Oil Trading And Transportation Inc
Concentration Risk [Line Items]
Percent of oil and natural gas sales	8.00%	18.00%	18.00%
Duke Energy Field Services
Concentration Risk [Line Items]
Percent of oil and natural gas sales	8.00%	16.00%	14.00%
Silo Energy Company
Concentration Risk [Line Items]
Percent of oil and natural gas sales			50.00%

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Cash, Cash Equivalents, and Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Apr. 28, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	$ 12,916	$ 12,711
Restricted cash included in other noncurrent assets	86	71
Total cash, cash equivalents and restricted cash as shown in the statements of cash flows	$ 13,002	$ 12,782	$ 70,247
Predecessor
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents			70,183	$ 80,565
Restricted cash included in other noncurrent assets			64	182
Total cash, cash equivalents and restricted cash as shown in the statements of cash flows			$ 70,247	$ 80,747	$ 21,582

REVENUE RECOGNITION (Details)

REVENUE RECOGNITION (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended						8 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2018
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales	$ 28,114	$ 66,213	$ 74,380	$ 71,872	$ 64,193	$ 50,189	$ 45,232	$ 123,535	$ 276,657
Net income	$ (3,580)	106,094	$ 43,363	$ 4,859	$ 13,870	(5,768)	$ 4,328	(5,020)	168,186
Oil and gas sales		$ 31,799				$ 28,549		28,549	31,799
As Unadjusted
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									266,925
Net income									168,186
Accounting Standards Update 2014-09 | ASC 606 Adjustments
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									9,732
Net income									0
Oil sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									228,661
Oil sales | As Unadjusted
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									228,661
Oil sales | Accounting Standards Update 2014-09 | ASC 606 Adjustments
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									0
Natural gas sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									22,369
Natural gas sales | As Unadjusted
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									18,076
Natural gas sales | Accounting Standards Update 2014-09 | ASC 606 Adjustments
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									4,293
NGLs sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									25,627
NGLs sales | As Unadjusted
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									20,188
NGLs sales | Accounting Standards Update 2014-09 | ASC 606 Adjustments
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Oil and gas sales									5,439
Gathering, transportation, and processing
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Operating expenses								$ 0	9,732
Gathering, transportation, and processing | As Unadjusted
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Operating expenses									0
Gathering, transportation, and processing | Accounting Standards Update 2014-09 | ASC 606 Adjustments
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Operating expenses									$ 9,732

IMPAIRMENTS (Details)

IMPAIRMENTS (Details) - USD ($)	8 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Abandonment and impairment of unproved properties	$ 0	$ 5,271,000
Mid-Continent Region
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved oil and gas property impairments		0	$ 10,000,000
Wattenburg Field Region
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Unproven oil and gas property impairments		$ 0	$ 24,700,000

DIVESTITURES (Details)

DIVESTITURES (Details) - USD ($) $ in Thousands	Aug. 06, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Asset retirement obligations for oil and gas properties		$ 38,262	$ 29,405
Gain on sale of properties		0	$ 27,324	$ 0
North Park Basin Region
Property, Plant and Equipment [Line Items]
Assets, held-for-sale		5,400
Mid-Continent Region
Property, Plant and Equipment [Line Items]
Proceeds from divestiture of businesses	$ 102,900
Gain on sale of properties	27,300
Purchase price	$ 117,000
Held-for-sale | North Park Basin Region
Property, Plant and Equipment [Line Items]
Asset retirement obligations for oil and gas properties		$ 5,400

OTHER NONCURRENT ASSETS (Detail

OTHER NONCURRENT ASSETS (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Other Assets [Abstract]
Operating bonds	$ 2,713	$ 2,683
Deferred financing costs	1,710	0
AMT credit refund	376	376
Restricted cash	86	71
Other noncurrent assets	$ 4,885	$ 3,130

ACCOUNTS PAYABLE AND ACCRUED _3

ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounts payable and accrued expenses contain the following:
Drilling and completion costs	$ 33,602	$ 21,833
Accounts payable trade	11,532	6,256
Accrued general and administrative cost	12,728	10,025
Lease operating expense	2,183	5,005
Accrued interest	241	250
Accrued oil and gas hedging	0	808
Production and ad valorem taxes and other	19,104	17,952
Total accounts payable and accrued expenses	$ 79,390	$ 62,129

LONG-TERM DEBT - Narrative (Det

LONG-TERM DEBT - Narrative (Details)	Mar. 29, 2011USD ($)	Sep. 30, 2017	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Apr. 28, 2017shares	Dec. 31, 2016USD ($)	Dec. 23, 2016	Oct. 31, 2016USD ($)
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			$ 350,000,000	$ 191,700,000
Maximum senior secured debt to trailing twelve month EBITDAX covenant			4	3.50
Minimum current ratio covenant			1	1
Borrowing base			$ 50,000,000	$ 0
Deferred financing costs			$ 2,200,000
Minimum trailing twelve month interest to trailing twelve month EBITDAX coverage covenant		1.35		2.50
Revolver | LIBOR
LONG-TERM DEBT
Debt Instrument, Description of Variable Rate Basis			LIBOR
Revolver | LIBOR | Minimum
LONG-TERM DEBT
Basis spread on variable rate			0.00%
Revolver | Reference Rate | Minimum
LONG-TERM DEBT
Basis spread on variable rate			0.75%
Revolver | Reference Rate | Maximum
LONG-TERM DEBT
Basis spread on variable rate			1.75%
Revolver | Eurodollar | Minimum
LONG-TERM DEBT
Basis spread on variable rate			1.75%
Revolver | Eurodollar | Maximum
LONG-TERM DEBT
Basis spread on variable rate			2.75%
Predecessor | Senior Notes
LONG-TERM DEBT
Shares issued to holders (in shares) | shares					9,481,610
Predecessor | Revolver
LONG-TERM DEBT
Maximum borrowing capacity	$ 1,000,000,000
Borrowing capacity deficiency						$ (41,700,000)		$ (150,000,000)
Long-term debt, gross						$ 191,700,000
Predecessor | Revolver | LIBOR | Minimum
LONG-TERM DEBT
Basis spread on variable rate	1.50%
Predecessor | Revolver | LIBOR | Maximum
LONG-TERM DEBT
Basis spread on variable rate	2.50%
Predecessor | Revolver | Prime Rate | Minimum
LONG-TERM DEBT
Basis spread on variable rate	0.50%
Predecessor | Revolver | Prime Rate | Maximum
LONG-TERM DEBT
Basis spread on variable rate	1.50%
6.75% Senior Notes | Predecessor | Senior Notes
LONG-TERM DEBT
Amount of notes issued			$ 500,000,000
Interest rate (as a percent)			6.75%				6.75%
5.75% Senior Notes | Predecessor | Senior Notes
LONG-TERM DEBT
Amount of notes issued			$ 300,000,000
Interest rate (as a percent)			5.75%				5.75%
Noncurrent Assets | Revolver
LONG-TERM DEBT
Deferred financing costs			$ 1,700,000
Prepaid Expenses and Other Current Assets | Revolver
LONG-TERM DEBT
Deferred financing costs			$ 500,000

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details) $ in Thousands	Oct. 03, 2017USD ($)	Sep. 30, 2018USD ($)	Apr. 28, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019bbl	Dec. 31, 2018USD ($)claimbbl	Dec. 31, 2017USD ($)bbl	Dec. 31, 2016USD ($)
Commitments [Line Items]
Number of claims | claim										0
Term of commitment period										7 years
Reimbursement of ad valorem taxes		$ 7,400
Potential extended term										3 years
Rent expense				$ 900						$ 900
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,019										20,836
2,020										29,300
2,021										30,192
2,022										29,719
2,023										30,448
2024 and thereafter										0
Total										140,495
Sublease income										$ 1,400
Crude Oil
Commitments [Line Items]
Minimum commitment of crude oil (barrels) | bbl										10,100	0
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Total										$ 136,300
NGL
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,019										19,580
2,020										27,949
2,021										28,791
2,022										29,485
2,023										30,448
2024 and thereafter										0
Total										136,253
CDPHE
Commitments [Line Items]
Settlement, administrative penalty (in excess of)	$ 200
COC costs incurred										1,200	$ 700
Purchase obligation, due within four years										$ 3,100
Term of commitment period										4 years
Office Lease Commitments(2)
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,019										$ 1,256
2,020										1,351
2,021										1,401
2,022										234
2,023										0
2024 and thereafter										0
Total										$ 4,242
Predecessor
Commitments [Line Items]
Rent expense			$ 900									$ 2,800
Scenario, Forecast | Crude Oil
Commitments [Line Items]
Minimum volume annual increase					3.00%	3.00%	3.00%	3.00%	41.00%
Maximum volume requirement (barrels) | bbl									16,000
Accounts Payable and Accrued Expenses
Commitments [Line Items]
Reimbursement of ad valorem taxes		2,300
Severance and Ad Valorem Taxes
Commitments [Line Items]
Reimbursement of ad valorem taxes		$ 5,100

STOCK-BASED COMPENSATION - Narr

STOCK-BASED COMPENSATION - Narrative (Details)	1 Months Ended	4 Months Ended	8 Months Ended	12 Months Ended
	Jun. 30, 2017USD ($)shares	Apr. 28, 2017USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017$ / sharesshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation not yet recognized				$ 800,000
Percent of employer match, up to				6.00%
Matching contribution for 401k plan			$ 600,000	$ 1,100,000
Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares				170,613
Fair value of units granted				$ 4,600,000
Unrecognized compensation cost				10,200,000
PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense				600,000
Unrecognized compensation cost				1,200,000
Fair value of shares granted				$ 1,800,000
PSUs | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company				0
PSUs | 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
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance under LTIP (in shares) | shares		2,467,430
LTIP | Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price (in dollars per share) | $ / shares		$ 0	$ 34.36	$ 34.36	$ 34.36
Stock-based compensation expense			$ 3,700,000	$ 1,400,000
Granted (shares) | shares			389,102	0
Fair value of options granted			$ 6,800,000
LTIP | Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares			452,996	387,720
Stock-based compensation expense			$ 7,900,000	$ 5,200,000
LTIP | Restricted shares | Non-executive Board Members
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				3 years
Granted (in shares) | shares	63,894
Fair value of units granted	$ 2,300,000		$ 13,400,000	$ 6,200,000
LTIP | PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares				59,641
Number of trading days				30 days
2011 Long Term Incentive Plan | Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				3 years
Ratio of restricted stock to common stock to be released from restrictions upon completion of the vesting period | shares				1
Vesting portion of shares				0.333
2011 Long Term Incentive Plan | Restricted shares | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares							568,832
2011 Long Term Incentive Plan | Restricted shares | Non Employee Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period				1 year
2011 Long Term Incentive Plan | PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percent				0.00%
Percentage of awards earned during performance cycle				200.00%
2011 Long Term Incentive Plan | PSUs | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company				0
2011 Long Term Incentive Plan | PSUs | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company				2
2011 Long Term Incentive Plan | PSUs | Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Measurement period				3 years
2011 Long Term Incentive Plan | PSUs | Officers | Tranche 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of trading days				30 days
2011 Long Term Incentive Plan | PSUs | Officers | Tranche 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of trading days				30 days
2011 Long Term Incentive Plan | PSUs | Officers | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company				0
2011 Long Term Incentive Plan | PSUs | Officers | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio at which award holders get common stock of the company				2
Predecessor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Matching contribution for 401k plan		$ 600,000				$ 2,000,000
Predecessor | Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Excess tax benefit for vested restricted stock		$ 0				$ 0
Predecessor | LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance under LTIP (in shares) | shares		2,467,430
Predecessor | 2011 Long Term Incentive Plan | Restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares		0				113,044
Predecessor | 2011 Long Term Incentive Plan | Restricted shares | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares		0				0
Stock-based compensation expense		$ 1,200,000				$ 6,100,000
Fair value of shares granted							$ 13,800,000
Predecessor | 2011 Long Term Incentive Plan | Restricted shares | Non Employee Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares					113,044
Stock-based compensation expense		$ 40,000				$ 700,000
Predecessor | 2011 Long Term Incentive Plan | PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares		0				0
Predecessor | 2011 Long Term Incentive Plan | PSUs | Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares) | shares						0
Stock-based compensation expense		$ 500,000				$ 1,800,000
Predecessor | 2011 Long Term Incentive Plan | Stock compensation plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period						3 years
Granted (in shares) | shares		0				2,958,558
Fair value of units granted						$ 2,900,000
Stock-based compensation expense		$ 400,000				$ 900,000
Predecessor | 2015 Awards | Tranche 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier		0.00%

STOCK-BASED COMPENSATION - Acti

STOCK-BASED COMPENSATION - Activity of non-vested restricted stock (Details) - Restricted shares - $ / shares	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted Stock
Granted (in shares)			170,613
LTIP
Restricted Stock
Non-vested at beginning of year (in shares)		0	261,165
Granted (in shares)		452,996	387,720
Vested (in shares)		(173,200)	(84,345)
Forfeited (in shares)		(18,631)	(83,705)
Non-vested at end of year (in shares)	0	261,165	480,835	261,165
Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)		$ 0	$ 34.93
Granted (in dollars per share)		34.62	27.80
Vested (in dollars per share)		34.19	30.63
Forfeited (in dollars per share)		34.36	29.78
Non-vested at end of year (in dollars per share)	$ 0	$ 34.93	$ 30.83	$ 34.93
Predecessor | 2011 Long Term Incentive Plan
Restricted Stock
Non-vested at beginning of year (in shares)	731,818	0	368,887	731,818
Granted (in shares)	0				113,044
Vested (in shares)	(111,996)				(355,498)
Forfeited (in shares)	(5,134)				(120,477)
Non-vested at end of year (in shares)	0	368,887		368,887	731,818
Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)	$ 29.47	$ 0	$ 19.45	$ 29.47
Granted (in dollars per share)	0				$ 0.98
Vested (in dollars per share)	32.22				31.68
Forfeited (in dollars per share)	29.55				27.34
Non-vested at end of year (in dollars per share)	$ 0	$ 19.45		$ 19.45	$ 29.47

STOCK-BASED COMPENSATION - Valu

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

STOCK-BASED COMPENSATION - Ac_2

STOCK-BASED COMPENSATION - Activity of stock options (Details) - LTIP - Employee Stock Option - USD ($)	8 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Apr. 28, 2017
Stock Options
Outstanding at beginning of period (shares)	0	197,271
Granted (shares)	389,102	0
Exercised (shares)	0	(32,037)
Forfeited (shares)	(191,831)	(32,425)
Outstanding at end of period (shares)	197,271	132,809
Outstanding and exercisable at end of period (shares)		61,880
Weighted- Average Exercise Price
Outstanding at beginning of period (in dollars per share)	$ 0	$ 34.36
Granted (in dollars per share)	34.36	0
Exercised (in dollars per share)	0	34.36
Forfeited (in dollars per share)	34.36	34.36
Outstanding and exercisable at end of period (in dollars per share)		34.36
Outstanding at end of period (in dollars per share)	$ 34.36	$ 34.36
Weighted-Average Remaining Contractual Term (in years)
Forfeited (in years)	9 years 3 months 18 days
Weighted Average Remaining Contractual Term (in years)	9 years 3 months 18 days	6 years 8 months 12 days
Outstanding and exercisable, end of period		4 years 9 months 18 days
Outstanding, Aggregate Intrinsic Value	$ 0	$ 0	$ 0

STOCK-BASED COMPENSATION - Summ

STOCK-BASED COMPENSATION - Summary of status and activity of non-vested stock (Details) - Restricted shares - $ / shares	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted Stock
Granted (in shares)			170,613
Predecessor | 2011 Long Term Incentive Plan
Restricted Stock
Non-vested at beginning of year (in shares)	731,818	0	368,887	731,818
Granted (in shares)	0				113,044
Vested (in shares)	(111,996)				(355,498)
Forfeited (in shares)	(5,134)				(120,477)
Canceled (in shares)	(251,757)				0
Non-vested at end of year (in shares)	0	368,887		368,887	731,818
Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)	$ 29.47	$ 0	$ 19.45	$ 29.47
Granted (in dollars per share)	0				$ 0.98
Vested (in dollars per share)	32.22				31.68
Forfeited (in dollars per share)	29.55				27.34
Canceled (in dollars per share)	13.08				0
Non-vested at end of year (in dollars per share)	$ 0	$ 19.45		$ 19.45	$ 29.47

STOCK-BASED COMPENSATION - Su_2

STOCK-BASED COMPENSATION - Summary of status and activity of PSUs (Details) - PSUs - $ / shares	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
LTIP
LTIP Units
Non-vested at beginning of year (in shares)			0
Granted (in shares)			59,641
Forfeited (in shares)			(5,952)
Non-vested at end of year (in shares)		0	53,689	0
Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)			$ 0
Granted (in dollars per share)			29.92
Forfeited (in dollars per share)			29.92
Non-vested at end of year (in dollars per share)		$ 0	$ 29.92	$ 0
Predecessor | 2011 Long Term Incentive Plan
LTIP Units
Non-vested at beginning of year (in shares)	114,833	0	21,538	114,833
Granted (in shares)	0				0
Vested (in shares)	0				(59,725)
Forfeited (in shares)	0				(33,570)
Canceled (in shares)	(21,538)				0
Non-vested at end of year (in shares)	0	21,538		21,538	114,833
Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)	$ 35.27	$ 0	$ 33.31	$ 35.27
Granted (in dollars per share)	0				$ 0
Vested (in dollars per share)	0				36.61
Forfeited (in dollars per share)	0				35.55
Canceled (in dollars per share)	33.31				0
Non-vested at end of year (in dollars per share)	$ 0	$ 33.31		$ 33.31	$ 35.27

STOCK-BASED COMPENSATION - Long

STOCK-BASED COMPENSATION - Long-term incentive plan units (Details) - Predecessor - 2011 Long Term Incentive Plan - Stock compensation plan - USD ($) $ / shares in Units, $ in Millions	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted (in shares)				2,958,558
Fair value of units granted				$ 2.9
Vesting period				3 years
Share price cap (in dollars per share)			$ 26
Stock-based compensation expense	$ 0.4			$ 0.9
LTIP Units
Non-vested at beginning of year (in shares)	0	0	0
Granted (in shares)	0			2,958,558
Vested (in shares)	(767,848)			0
Forfeited (in shares)	(126,616)			(515,156)
Canceled (in shares)	(1,548,938)			0
Non-vested at end of year (in shares)	0	2,443,402	2,443,402	0
Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)	$ 0	$ 0	$ 0
Granted (in dollars per share)	0			$ 0.99
Vested (in dollars per share)	0.98			0
Forfeited (in dollars per share)	0.98			0.98
Canceled (in dollars per share)	0.99			0
Non-vested at end of year (in dollars per share)	$ 0	$ 0.99	$ 0.99	$ 0

INCOME TAXES - Provision For In

INCOME TAXES - Provision For Income Taxes (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Examination [Line Items]
Federal		$ 376	$ 0
State		0	0
Deferred tax benefit		0	0
Total income tax benefit		$ 376	$ 0	$ (400)
Predecessor
Income Tax Examination [Line Items]
Federal	$ 0				$ 0
State	0				0
Deferred tax benefit	0				0
Total income tax benefit	$ 0				$ 0

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($)	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Examination [Line Items]
AMT credit		$ 0	$ 0	$ 0
Net operating loss carryovers for federal income tax purposes		470,300,000	577,600,000	470,300,000
Net operating loss carryovers for federal income tax purposes, not benefited for financial statement purposes		470,300,000	107,300,000	470,300,000
Unrecognized tax benefits		0	0	0	$ 0
Total income tax expense (benefit)		(376,000)	0	400,000
Valuation allowance		136,960,000	89,076,000	$ 136,960,000
Deferred tax expense (benefit)		$ 0	$ 0
Predecessor
Income Tax Examination [Line Items]
Total income tax expense (benefit)	$ 0				0
Valuation allowance					256,200,000
Deferred tax expense (benefit)	$ 0				$ 0

INCOME TAXES - Deferred Tax Ass

INCOME TAXES - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Oil and gas properties	$ 52,006	$ 0
Derivative liability	8,527	0
Total deferred tax liabilities	60,533	0
Federal and state tax net operating loss carryforward	137,567	117,115
Oil and gas properties	0	1,319
Derivative liability	0	3,457
Reclamation costs	7,251	9,516
Stock compensation	1,635	1,419
Accrued compensation	1,308	1,285
Inventory	1,577	1,529
Settlement liabilities	0	0
AMT credit	0	0
State bonus depreciation addback	0	1,089
Other long-term assets	271	231
Total deferred tax assets	149,609	136,960
Less: Valuation allowance	89,076	136,960
Total deferred tax assets after valuation allowance	0	0
Total non-current net deferred tax liability	$ 0	$ 0

INCOME TAXES - Effective Income

INCOME TAXES - Effective Income Tax Reconciliation (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Examination [Line Items]
Federal statutory tax (expense) benefit by applying the statutory rate		$ 1,889	$ 35,319
State tax expense net of federal benefit		172	6,556
Prior year true-up		0	(458)
Stock compensation		0	854
Permanent differences		(715)	61
Rate change		(73,956)	(421)
NOL Adjustment		0	5,973
Other		(642)	0
Valuation allowance		73,628	(47,884)
Total income tax benefit		$ 376	$ 0	$ (400)
Predecessor
Income Tax Examination [Line Items]
Federal statutory tax (expense) benefit by applying the statutory rate	$ (931)				$ 69,633
State tax expense net of federal benefit	(85)				6,358
Prior year true-up	(7,572)				0
Stock compensation	(1,773)				0
Permanent differences	(35,273)				0
Rate change	0				0
NOL Adjustment	0				0
Other	0				(317)
Valuation allowance	45,634				(75,674)
Total income tax benefit	$ 0				$ 0

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2018USD ($)
Change in asset retirement obligations
Beginning of year			$ 38,262
Additional liabilities incurred		$ 130	373
Accretion expense		1,370	1,831
Liabilities settled		(780)	(1,627)
Revisions to estimate		8,481	1,490
Sold properties			(10,924)
End of year		38,262	29,405
Predecessor
Change in asset retirement obligations
Beginning of year		31,660	$ 30,833
Accretion expense	$ 1,045
Liabilities settled	(218)
End of year	31,660	30,833
Successor
Change in asset retirement obligations
Beginning of year		29,061
End of year	29,061
Fresh-Start Adjustments
Change in asset retirement obligations
Beginning of year		$ (2,599)
End of year	$ (2,599)
Risk Free Interest Rate | Predecessor | Minimum
Business Acquisition [Line Items]
Measurement input			0.08
Risk Free Interest Rate | Predecessor | Maximum
Business Acquisition [Line Items]
Measurement input			0.18
Risk Free Interest Rate | Successor | Minimum
Business Acquisition [Line Items]
Measurement input			0.05
Risk Free Interest Rate | Successor | Maximum
Business Acquisition [Line Items]
Measurement input			0.07

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, 2018	Dec. 31, 2017
Level 1
Financial assets and liabilities accounted for at fair value
Derivative assets	$ 0	$ 0
Derivative liabilities	0	0
Asset retirement obligations	0	0
Level 2
Financial assets and liabilities accounted for at fair value
Derivative assets	38,272	494
Derivative liabilities	183	14,395
Asset retirement obligations	0	0
Level 3
Financial assets and liabilities accounted for at fair value
Derivative assets	0	0
Derivative liabilities	0	0
Asset retirement obligations	$ 1,490	$ 8,481

FAIR VALUE MEASUREMENTS - Narra

FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($)	8 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Derivatives measured at fair value
Proved properties	$ 555,341,000	$ 719,198,000
Abandonment and impairment of unproved properties	0	5,271,000
Unproved properties	183,843,000	154,352,000
Revolver
Derivatives measured at fair value
Long-term debt	0	50,000,000
Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Asset retirement obligations for oil and gas properties	$ 8,481,000	1,490,000
Mid-Continent Region
Derivatives measured at fair value
Proved oil and gas property impairments		0	$ 10,000,000
Proved properties			110,000,000
Mid-Continent Region | Estimate of Fair Value Measurement | Level 3
Derivatives measured at fair value
Proved properties			100,000,000
Wattenberg Field
Derivatives measured at fair value
Unproved properties			187,400,000
Wattenberg Field | Estimate of Fair Value Measurement
Derivatives measured at fair value
Unproved properties			162,700,000
Wattenburg Field Region
Derivatives measured at fair value
Unproven oil and gas property impairments		$ 0	$ 24,700,000

DERIVATIVES - Narrative (Detail

DERIVATIVES - Narrative (Details)	Dec. 31, 2018derivative
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, 2020$ / bblbbl	Mar. 31, 2020$ / bblbbl	Dec. 31, 2019MMBTU$ / MMBTU$ / bblbbl	Sep. 30, 2019MMBTU$ / MMBTU$ / bblbbl	Jun. 30, 2019MMBTU$ / MMBTU$ / bblbbl	Mar. 31, 2019MMBTU$ / MMBTU$ / bblbbl
Crude Oil (NYMEX WTI) | Cashless Collar
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl			3,000	3,000	5,330	4,000
Crude Oil (NYMEX WTI) | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl			59.17	59.17	54.42	50.88
Crude Oil (NYMEX WTI) | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl			75.72	75.72	67.57	63.83
Crude Oil (NYMEX WTI) | Swap
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl		3,000	5,000	5,000	3,500	4,000
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl		63.48	59.92	59.92	57.84	59.16
Crude Oil (NYMEX WTI) | Put
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl			500	500	500	500
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl			55	55	55	55
Natural Gas (NYMEX Henry Hub) | Cashless Collar
Derivative [Line Items]
Natural Gs, notional amount (in MMBtu per day) | MMBTU					2,505	7,600
Natural Gas (NYMEX Henry Hub) | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively)					2.75	2.75
Natural Gas (NYMEX Henry Hub) | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively)					3.22	3.22
Natural Gas (NYMEX Henry Hub) | Swap
Derivative [Line Items]
Natural Gs, notional amount (in MMBtu per day) | MMBTU						1,500
Weighted Average Price (in dollars per MMBtu)						3.13
Natural Gas (CIG Basis) | Swap
Derivative [Line Items]
Natural Gs, notional amount (in MMBtu per day) | MMBTU						7,600
Weighted Average Price (in dollars per barrel and MMBtu, respectively)						0.67
Natural Gas (CIG) | Swap
Derivative [Line Items]
Natural Gs, notional amount (in MMBtu per day) | MMBTU			20,000	20,000	16,703	10,000
Weighted Average Price (in dollars per barrel and MMBtu, respectively)			2.10	2.10	2.11	2.17
Subsequent Event | Crude Oil (NYMEX WTI) | Cashless Collar
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl		2,000	4,000	4,000	6,330	4,656
Subsequent Event | Crude Oil (NYMEX WTI) | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl		55	58.13	58.13	54.41	51.46
Subsequent Event | Crude Oil (NYMEX WTI) | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl		62	75.54	75.54	68.74	65.40
Subsequent Event | Crude Oil (NYMEX WTI) | Swap
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl		3,000	5,000	5,000	3,500	4,000
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl		63.48	59.92	59.92	57.84	59.16
Subsequent Event | Crude Oil (NYMEX WTI) | Put
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl						172
Weighted Average Price (in dollars per barrel and MMBtu, respectively) | $ / bbl						55
Subsequent Event | Natural Gas (NYMEX Henry Hub) | Cashless Collar
Derivative [Line Items]
Natural Gs, notional amount (in MMBtu per day) | MMBTU					2,505	7,600
Subsequent Event | Natural Gas (NYMEX Henry Hub) | Cashless Collar | Minimum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively)					2.75	2.75
Subsequent Event | Natural Gas (NYMEX Henry Hub) | Cashless Collar | Maximum
Derivative [Line Items]
Weighted Average Price (in dollars per barrel and MMBtu, respectively)					3.43	3.43
Subsequent Event | Natural Gas (NYMEX Henry Hub) | Swap
Derivative [Line Items]
Natural Gs, notional amount (in MMBtu per day) | MMBTU						1,500
Weighted Average Price (in dollars per MMBtu)						3.13
Subsequent Event | Natural Gas (CIG Basis) | Swap
Derivative [Line Items]
Natural Gs, notional amount (in MMBtu per day) | MMBTU						7,600
Weighted Average Price (in dollars per barrel and MMBtu, respectively)						0.67
Subsequent Event | Natural Gas (CIG) | Swap
Derivative [Line Items]
Crude Oil, notional amount (in barrels per day) | bbl	2,500
Natural Gs, notional amount (in MMBtu per day) | MMBTU			22,500	22,500	19,203	11,639
Weighted Average Price (in dollars per barrel and MMBtu, respectively)	2.40		2.13	2.13	2.15	2.20

DERIVATIVES - Derivative positi

DERIVATIVES - Derivative positions (Details) - Commodity derivative - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivatives measured at fair value
Total derivative liabilities, net	$ 38,089	$ (13,901)
Current assets
Derivatives measured at fair value
Derivative Assets:	34,408	488
Noncurrent assets
Derivatives measured at fair value
Derivative Assets:	3,864	6
Current liabilities
Derivatives measured at fair value
Derivative Liabilities:	(183)	(11,423)
Long-term liabilities
Derivatives measured at fair value
Derivative Liabilities:	$ 0	$ (2,972)

DERIVATIVES - Derivative gains

DERIVATIVES - Derivative gains (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Components of the derivative gain (loss)
Derivative gain (loss)		$ (15,365)	$ 30,271
Commodity derivative
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)		(1,464)	(18,160)
Change in fair value gain (loss)		(13,901)	48,431
Derivative gain (loss)		(15,365)	30,271
Commodity derivative | Oil
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)		(1,486)	(17,700)
Commodity derivative | Natural gas
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)		$ 22	$ (460)
Predecessor
Components of the derivative gain (loss)
Derivative gain (loss)	$ 0			$ (11,234)
Predecessor | Commodity derivative
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	0			18,333
Change in fair value gain (loss)	0			(29,567)
Derivative gain (loss)	0			(11,234)
Predecessor | Commodity derivative | Oil
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	0			18,333
Predecessor | Commodity derivative | Natural gas
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	$ 0			$ 0

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) $ / shares in Units, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017USD ($)$ / shares	Jun. 30, 2017USD ($)$ / shares	Dec. 31, 2018USD ($)$ / shares	Sep. 30, 2018USD ($)$ / shares	Jun. 30, 2018USD ($)$ / shares	Mar. 31, 2018USD ($)$ / shares	Dec. 31, 2017USD ($)$ / shares	Sep. 30, 2017USD ($)$ / shares	Mar. 31, 2017USD ($)$ / shares	Apr. 28, 2017USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Antidilutive securities excluded from EPS calculation (in shares)											375,123	170,755	519,362
Net income (loss):
Net income (loss) | $		$ (3,580)	$ 106,094	$ 43,363	$ 4,859	$ 13,870	$ (5,768)	$ 4,328			$ (5,020)	$ 168,186
Basic net income (loss) per common share (in dollars per share) | $ / shares		$ (0.18)	$ 5.16	$ 2.11	$ 0.24	$ 0.68	$ (0.28)	$ 0.21			$ (0.25)	$ 8.20
Diluted net income (loss) per common share (in dollars per share) | $ / shares		$ (0.18)	$ 5.15	$ 2.10	$ 0.24	$ 0.68	$ (0.28)	$ 0.21			$ (0.25)	$ 8.16
Weighted-average shares outstanding - basic (in shares)											20,427,000	20,507,000
Add: dilutive effect of contingent PSUs (in shares)											0	96,000
Weighted-average shares outstanding - diluted (in shares)											20,427,000	20,603,000
PSUs | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of awards earned during performance cycle												0
PSUs | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of awards earned during performance cycle												2
Predecessor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Antidilutive securities excluded from EPS calculation (in shares)										258,126
Net income (loss):
Net income (loss) | $	$ 96,936								$ (94,276)	$ 2,660			$ (198,950)	$ (198,950)
Less: undistributed income to unvested restricted stock | $										120			0
Undistributed income (loss) to common shareholders | $										$ 2,540			$ (198,950)
Basic net income (loss) per common share (in dollars per share) | $ / shares	$ 1.88								$ (1.91)	$ 0.05			$ (4.04)	$ (4.04)
Diluted net income (loss) per common share (in dollars per share) | $ / shares	$ 1.85								$ (1.91)	$ 0.05			$ (4.04)	$ (4.04)
Weighted-average shares outstanding - basic (in shares)										49,559,000			49,268,000	49,268,000
Add: dilutive effect of contingent PSUs (in shares)										1,412,000			0
Weighted-average shares outstanding - diluted (in shares)										50,971,000			49,268,000	49,268,000
2011 Long Term Incentive Plan | PSUs | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of awards earned during performance cycle												0
2011 Long Term Incentive Plan | PSUs | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of awards earned during performance cycle												2
2011 Long Term Incentive Plan | Predecessor | Stock compensation plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share price cap (in dollars per share) | $ / shares													$ 26

CHAPTER 11 PROCEEDINGS AND EM_2

CHAPTER 11 PROCEEDINGS AND EMERGENCE (Details) - USD ($)	Apr. 28, 2017	Apr. 28, 2017	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016	Feb. 01, 2017	Dec. 23, 2016
Fresh-Start Adjustment [Line Items]
Holders percentage under settlement agreement								51.00%
Term of warrants	3 years
Liabilities subject to compromise	$ 800,000,000	$ 800,000,000	$ 800,000,000
Accrued and unpaid pre-petition interest	14,879,000	14,879,000	14,879,000
Prepayment premiums	51,185,000	$ 51,185,000	$ 51,185,000
Sources of funding	207,500,000
Silo contract settlement payment	7,228,000
Payment and funding of escrow account related to professional fees	17,193,000
Payment of professional fees and other	$ 13,831,000
Cash and cash equivalents				$ 12,711,000	$ 12,916,000
Assurance deposit maintained							$ 5,000,000
Crude oil revenue receivable							$ 8,700,000
Contract settlement expense				$ 0	$ 0
LTIP
Fresh-Start Adjustment [Line Items]
Shares reserved for issuance under LTIP (in shares)	2,467,430	2,467,430	2,467,430
Reorganization Warrants
Fresh-Start Adjustment [Line Items]
Percentage of shares issued	7.50%	7.50%	7.50%
Sources of funding	$ 4,081,000
Warrants issued (in shares)	1,650,510	1,650,510	1,650,510
Price per warrant (in dollars per share)	$ 71.23	$ 71.23	$ 71.23
Ad Hoc Equity Committee Settlement
Fresh-Start Adjustment [Line Items]
Sources of funding	$ 7,500,000
Rights Offering
Fresh-Start Adjustment [Line Items]
Shares issued to holders (in shares)	10,071,378	10,071,378	10,071,378
Sources of funding	$ 200,000,000
Common Stock
Fresh-Start Adjustment [Line Items]
Sources of funding	26,828,000
Senior Notes
Fresh-Start Adjustment [Line Items]
Contractual interest on senior notes, not recorded in income statement		$ 16,000,000
Predecessor
Fresh-Start Adjustment [Line Items]
Cash and cash equivalents	$ 70,183,000	$ 70,183,000	$ 70,183,000			$ 80,565,000
Contract settlement expense			$ 0			$ 21,000,000
Predecessor | LTIP
Fresh-Start Adjustment [Line Items]
Shares reserved for issuance under LTIP (in shares)	2,467,430	2,467,430	2,467,430
Predecessor | STIP
Fresh-Start Adjustment [Line Items]
Payment of remaining incentive plan	$ 1,600,000
Predecessor | Common Stock
Fresh-Start Adjustment [Line Items]
Shares issued to holders (in shares)	803,083	803,083	803,083
Percentage of shares issued	3.90%	3.90%	3.90%
Predecessor | Common Stock | Ad Hoc Equity Committee Settlement
Fresh-Start Adjustment [Line Items]
Percentage of shares issued	1.75%	1.75%	1.75%
Predecessor | Senior Notes
Fresh-Start Adjustment [Line Items]
Liabilities subject to compromise	$ 800,000,000	$ 800,000,000	$ 800,000,000
Accrued and unpaid pre-petition interest	14,900,000	14,900,000	14,900,000
Prepayment premiums	$ 51,200,000	$ 51,200,000	$ 51,200,000
Percentage of shares exchanged	46.60%
Shares issued to holders (in shares)	9,481,610	9,481,610	9,481,610
Predecessor | Senior Notes | 5.75% Senior Notes
Fresh-Start Adjustment [Line Items]
Interest rate (as a percent)					5.75%			5.75%
Predecessor | Senior Notes | 6.75% Senior Notes
Fresh-Start Adjustment [Line Items]
Interest rate (as a percent)					6.75%			6.75%
Predecessor | Revolver
Fresh-Start Adjustment [Line Items]
Payment on revolving credit facility (principal, interest and fees)	$ 193,729,000
Successor
Fresh-Start Adjustment [Line Items]
Term of warrants	3 years
Cash and cash equivalents	$ 70,183,000	$ 70,183,000	$ 70,183,000

FRESH-START ACCOUNTING - Narrat

FRESH-START ACCOUNTING - Narrative (Details) $ / shares in Units, $ in Thousands	Apr. 28, 2017USD ($)$ / sharesshares	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)shares
LONG-TERM DEBT
Percentage of voting shares upon emergence (less than)	50.00%
Fair value of proved reserves	$ 397,300
Fair value of probable reserves	146,800
Fair value of possible reserves	31,700
Net asset replacement cost, fair value	$ 103,100
Asset retirement obligations for oil and gas properties		$ 29,405	$ 38,262
Term of warrants	3 years
Common Stock
LONG-TERM DEBT
Shares outstanding (in shares) | shares	20,356,071	20,543,940	20,453,549
Common Stock | Cancellation of Predecessor equity
LONG-TERM DEBT
Shares outstanding (in shares) | shares	20,356,071
Reorganization Warrants
LONG-TERM DEBT
Warrants issued (in shares) | shares	1,650,510
Successor warrants	$ 4,081
Minimum
LONG-TERM DEBT
Enterprise Value	570,000
Maximum
LONG-TERM DEBT
Enterprise Value	680,000
Successor
LONG-TERM DEBT
Enterprise Value	642,999
Asset retirement obligations for oil and gas properties	29,061
Successor warrants	$ 4,081
Per share value (in dollars per share) | $ / shares	$ 33.41
Term of warrants	3 years
Successor | Common Stock | Cancellation of Predecessor equity
LONG-TERM DEBT
Shares outstanding (in shares) | shares	20,356,071
Discount Rate | Discounted Cash Flow Analysis
LONG-TERM DEBT
Measurement input	0.110
Volatility | Reorganization Warrants
LONG-TERM DEBT
Measurement input	0.40
Risk Free Interest Rate | Reorganization Warrants
LONG-TERM DEBT
Measurement input	0.0144
Risk Free Interest Rate | Successor | Minimum
LONG-TERM DEBT
Measurement input		0.05
Risk Free Interest Rate | Successor | Maximum
LONG-TERM DEBT
Measurement input		0.07
Share Price | Reorganization Warrants
LONG-TERM DEBT
Measurement input | $ / shares	34.36
Strike Price | Reorganization Warrants
LONG-TERM DEBT
Measurement input | $ / shares	71.23

FRESH-START ACCOUNTING - Enterp

FRESH-START ACCOUNTING - Enterprise value to fair value of stock (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Apr. 28, 2017
Fresh-Start Adjustment [Line Items]
Plus: Cash and cash equivalents	$ 12,916	$ 12,711
Shares outstanding (in shares)	20,543,940	20,453,549
Successor
Fresh-Start Adjustment [Line Items]
Enterprise Value			$ 642,999
Plus: Cash and cash equivalents			70,183
Less: Interest bearing liabilities			(29,061)
Less: Fair value of warrants			(4,081)
Fair value of Successor common stock			$ 680,040
Shares outstanding (in shares)			20,356,000
Per share value (in dollars per share)			$ 33.41
Reorganization Warrants
Fresh-Start Adjustment [Line Items]
Less: Fair value of warrants			$ (4,081)

FRESH-START ACCOUNTING - Ente_2

FRESH-START ACCOUNTING - Enterprise value to reorganization value (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Apr. 28, 2017
Fresh-Start Adjustment [Line Items]
Plus: Cash and cash equivalents	$ 12,916	$ 12,711
Common stock, shares outstanding (shares)	20,543,940	20,453,549
Successor
Fresh-Start Adjustment [Line Items]
Enterprise Value			$ 642,999
Plus: Cash and cash equivalents			70,183
Plus: Working capital liabilities			63,871
Plus: Other long-term liabilities			17,919
Reorganization value of Successor assets			794,972
Postconfirmation, Long-term Debt			29,061
Warrants and Rights Outstanding			4,081
Fair value of Successor common stock			$ 680,040
Common stock, shares outstanding (shares)			20,356,000
Per share value (in dollars per share)			$ 33.41

FRESH-START ACCOUNTING - Succes

FRESH-START ACCOUNTING - Successor balance sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Apr. 28, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 12,916	$ 12,711
Accounts receivable:
Oil and gas sales	31,799	28,549
Joint interest and other	47,577	3,831
Prepaid expenses and other	4,633	6,555
Inventory of oilfield equipment	3,478	1,019
Total current assets	134,811	53,153
Property and equipment (successful efforts method):
Proved properties	719,198	555,341
Less: accumulated depreciation, depletion and amortization	(52,842)	(17,032)
Total proved properties, net	666,356	538,309
Unproved properties	154,352	183,843
Wells in progress	93,617	47,224
Other property and equipment, net	3,649	4,706
Total property and equipment, net	917,974	774,082
Other noncurrent assets	4,885	3,130
Total assets	1,061,534	830,371
Current liabilities:
Accounts payable and accrued expenses	79,390	62,129
Oil and gas revenue distribution payable	19,903	15,667
Total current liabilities	99,476	89,219
Long-term liabilities:
Ad valorem taxes	18,740	11,584
Asset retirement obligations for oil and gas properties	29,405	38,262
Liabilities subject to compromise			$ 873,292
Total liabilities	197,621	142,037
Stockholders' equity:
Predecessor preferred stock	0	0
Common stock	4,286	4,286
Additional paid-in capital	696,461	689,068
Retained deficit	163,166	(5,020)
Total stockholders’ equity	863,913	688,334	684,121
Total liabilities and stockholders’ equity	$ 1,061,534	830,371
Fresh-Start Adjustments
Current Assets:
Cash and cash equivalents			0
Accounts receivable:
Oil and gas sales			0
Joint interest and other			0
Prepaid expenses and other			0
Inventory of oilfield equipment			0
Total current assets			0
Property and equipment (successful efforts method):
Proved properties			(2,031,373)
Less: accumulated depreciation, depletion and amortization			1,720,736
Total proved properties, net			(310,637)
Unproved properties			14,679
Wells in progress			(18,002)
Other property and equipment, net			0
Total property and equipment, net			(313,960)
Other noncurrent assets			0
Total assets			(313,960)
Current liabilities:
Accounts payable and accrued expenses			0
Oil and gas revenue distribution payable			0
Revolving credit facility - current portion			0
Total current liabilities			0
Long-term liabilities:
Ad valorem taxes			0
Asset retirement obligations for oil and gas properties			(2,599)
Liabilities subject to compromise			0
Total liabilities			(2,599)
Stockholders' equity:
Predecessor preferred stock			0
Common stock			(49)
Additional paid-in capital			(816,679)
Retained deficit			505,367
Total stockholders’ equity			(311,361)
Total liabilities and stockholders’ equity			(313,960)
Predecessor
Current Assets:
Cash and cash equivalents			96,286
Cash and cash equivalents			70,183	$ 80,565
Accounts receivable:
Oil and gas sales			24,876
Joint interest and other			3,028
Prepaid expenses and other			4,952
Inventory of oilfield equipment			4,218
Total current assets			133,360
Property and equipment (successful efforts method):
Proved properties			2,531,834
Less: accumulated depreciation, depletion and amortization			(1,720,736)
Total proved properties, net			811,098
Unproved properties			163,781
Wells in progress			18,002
Other property and equipment, net			6,056
Total property and equipment, net			998,937
Other noncurrent assets			2,738
Total assets			1,135,035
Current liabilities:
Accounts payable and accrued expenses			72,635
Oil and gas revenue distribution payable			24,937
Revolving credit facility - current portion			191,667
Total current liabilities			289,239
Long-term liabilities:
Ad valorem taxes			17,919
Asset retirement obligations for oil and gas properties		$ 30,833	31,660
Liabilities subject to compromise			873,292
Total liabilities			1,212,110
Stockholders' equity:
Predecessor preferred stock			0
Common stock			49
Additional paid-in capital			816,679
Retained deficit			(893,803)
Total stockholders’ equity			(77,075)	$ 19,061	$ 209,407
Total liabilities and stockholders’ equity			1,135,035
Successor
Current Assets:
Cash and cash equivalents			70,183
Accounts receivable:
Oil and gas sales			24,876
Joint interest and other			3,028
Prepaid expenses and other			4,952
Inventory of oilfield equipment			4,218
Total current assets			107,257
Property and equipment (successful efforts method):
Proved properties			500,461
Less: accumulated depreciation, depletion and amortization			0
Total proved properties, net			500,461
Unproved properties			178,460
Wells in progress			0
Other property and equipment, net			6,056
Total property and equipment, net			684,977
Other noncurrent assets			2,738
Total assets			794,972
Current liabilities:
Accounts payable and accrued expenses			38,934
Oil and gas revenue distribution payable			24,937
Revolving credit facility - current portion			0
Total current liabilities			63,871
Long-term liabilities:
Ad valorem taxes			17,919
Asset retirement obligations for oil and gas properties			29,061
Liabilities subject to compromise			0
Total liabilities			110,851
Stockholders' equity:
Common stock			204
Successor warrants			4,081
Additional paid-in capital			679,836
Retained deficit			0
Total stockholders’ equity			684,121
Total liabilities and stockholders’ equity			794,972
Reorganization Adjustments
Current Assets:
Cash and cash equivalents			(26,103)
Accounts receivable:
Oil and gas sales			0
Joint interest and other			0
Prepaid expenses and other			0
Inventory of oilfield equipment			0
Total current assets			(26,103)
Property and equipment (successful efforts method):
Proved properties			0
Less: accumulated depreciation, depletion and amortization			0
Total proved properties, net			0
Unproved properties			0
Wells in progress			0
Other property and equipment, net			0
Total property and equipment, net			0
Other noncurrent assets			0
Total assets			(26,103)
Current liabilities:
Accounts payable and accrued expenses			(33,701)
Oil and gas revenue distribution payable			0
Revolving credit facility - current portion			(191,667)
Total current liabilities			(225,368)
Long-term liabilities:
Ad valorem taxes			0
Asset retirement obligations for oil and gas properties			0
Liabilities subject to compromise			(873,292)
Total liabilities			(1,098,660)
Stockholders' equity:
Common stock			204
Successor warrants			4,081
Additional paid-in capital			679,836
Retained deficit			388,436
Total stockholders’ equity			1,072,557
Total liabilities and stockholders’ equity			$ (26,103)

FRESH-START ACCOUNTING - Source

FRESH-START ACCOUNTING - Sources, uses and transfers of cash (Details)	Apr. 28, 2017USD ($)
Sources:
Sources of funding	$ 207,500,000
Uses and transfers:
Payment and funding of escrow account related to professional fees	(17,193,000)
Payment of professional fees and other	(13,831,000)
Payment of Silo contract settlement and other	(7,228,000)
Payment of remaining 2016 STIP	(1,622,000)
Total uses and transfers	(233,603,000)
Total net sources, uses and transfers	(26,103,000)
Predecessor | Revolver
Uses and transfers:
Payment on revolving credit facility (principal, interest and fees)	(193,729,000)
Rights Offering
Sources:
Sources of funding	200,000,000
Ad Hoc Equity Committee Settlement
Sources:
Sources of funding	$ 7,500,000

FRESH-START ACCOUNTING - Accoun

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

FRESH-START ACCOUNTING - Liabil

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

FRESH-START ACCOUNTING - Reorga

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

DISCLOSURES ABOUT OIL AND GAS_3

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Costs incurred in oil and natural gas producing activities (Details) - USD ($)	4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Acquisition		$ 5,383,000	$ 2,861,000
Development		106,449,000	304,197,000
Exploration		3,671,000	294,000
Total		115,503,000	307,352,000
Acquisition costs for unproved properties		5,400,000	2,500,000
Proved property acquisitions		0	400,000
Workover costs charged to lease operating expense		4,300,000	5,600,000
Increase (decrease) in ARO		$ 8,300,000	(9,000,000)
Predecessor
Acquisition	$ 445,000				$ 97,000
Development	10,780,000				31,209,000
Exploration	769,000				74,000
Total	11,994,000				31,380,000
Acquisition costs for unproved properties	400,000			$ 100,000
Proved property acquisitions	0		$ 0		0
Workover costs charged to lease operating expense	1,800,000			$ 6,000,000
Increase (decrease) in ARO	$ 3,100,000				$ 2,400,000

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)	12 Months Ended
	Dec. 31, 2018MBoe$ / MMBTU$ / bblbblMcf	Dec. 31, 2017MBoe$ / MMBTU$ / bblbblMcf	Dec. 31, 2016MBoe$ / MMBTU$ / bblbblMcf	Dec. 31, 2015$ / MMBTU$ / bblbblMcf
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | MBoe	6,026	1,542	13,517
Revisions to previous estimates - increase (decrease) | MBoe	2,333	5,405
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) | MBoe	(2,527)
Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Revisions to previous estimates - increase (decrease) | MBoe		1,370
Wattenberg Field, Rocky Mountain Region | 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) | MBoe	1,536	1,672	4,652
Wattenberg Field, Rocky Mountain Region | 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) | MBoe			(8,611)
Wattenberg Field, Rocky Mountain Region | Other engineering revisions
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | MBoe	2,163	2,042	(1,797)
Wattenberg Field, Rocky Mountain Region | PUD Demotions
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Proved developed and undeveloped reserve, revision of previous estimate (energy) | MBoe		(7,577)
Mid-Continent Region | 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) | MBoe			(7,761)
Horizontal development | Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Extensions and discoveries | MBoe	28,832	15,548	1,632
Infill down-spacing | Wattenberg Field, Rocky Mountain Region
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Extensions and discoveries | MBoe			9,164
Oil
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period	52,928	50,096	57,393
Extensions and discoveries	18,390	8,470	6,133
Production	(3,841)	(3,081)	(4,310)
Sales of minerals in place	(6,236)		(100)
Proved Developed and Undeveloped Reserves, Removed from Capital Program	(1,442)
Revisions to previous estimates	4,555	(2,557)	(9,020)
Balance at the end of the period	64,354	52,928	50,096	57,393
Proved developed reserves	23,725	25,785	26,313
Proved undeveloped reserves	40,629	27,143	23,783
Oil | 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 Bbl) | $ / bbl	65.56	51.34	42.75	50.28
Natural gas
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period | Mcf	157,669	138,045	144,227
Extensions and discoveries | Mcf	31,471	22,212	15,128
Production | Mcf	(8,567)	(9,010)	(11,907)
Sales of minerals in place | Mcf	(20,534)		(343)
Proved Developed and Undeveloped Reserves, Removed from Capital Program | Mcf	(3,246)
Revisions to previous estimates | Mcf	8,219	6,422	(9,060)
Balance at the end of the period | Mcf	165,012	157,669	138,045	144,227
Proved developed reserves | Mcf	79,630	92,718	85,972
Proved undeveloped reserves | Mcf	85,382	64,951	52,073
Natural gas | 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 Bbl) | $ / MMBTU	3.10	2.98	2.48	2.59
Natural gas liquids
Changes in quantities of proved oil, natural gas liquids and natural gas reserves
Balance at the beginning of the period	22,815	17,547	19,918
Extensions and discoveries	5,197	3,376	2,142
Production	(1,140)	(1,136)	(1,491)
Sales of minerals in place	(1,499)		(35)
Proved Developed and Undeveloped Reserves, Removed from Capital Program	(544)
Revisions to previous estimates	101	3,028	(2,987)
Balance at the end of the period	24,930	22,815	17,547	19,918
Proved developed reserves	11,703	12,702	9,951
Proved undeveloped reserves	13,227	10,113	7,596

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, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Results of Operations, Revenue from Oil and Gas Producing Activities [Abstract]
Future net cash flows discount rate	10.00%
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Future cash flows				$ 4,742,180	$ 3,307,868	$ 2,424,415
Future production costs				(1,585,032)	(1,490,091)	(1,365,765)
Future development costs				(925,640)	(622,344)	(468,804)
Future income tax expense				0	0	0
Future net cash flows				2,231,508	1,195,433	589,846
10% annual discount for estimated timing of cash flows				(1,276,528)	(596,935)	(312,891)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$ 598,498	$ 276,955	$ 327,816	$ 954,980	$ 598,498	$ 276,955
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Beginning of period	598,498	276,955	327,816
Sale of oil and gas produced, net of production costs	(204,566)	(125,992)	(123,494)
Net changes in prices and production costs	365,952	282,112	(126,536)
Extensions, discoveries and improved recoveries	153,691	103,937	22,800
Development costs incurred	127,788	24,121	19,701
Changes in estimated development cost	(52,260)	2,122	281,062
Purchases of minerals in place	0	0	0
Sales of minerals in place	(115,742)	0	16
Revisions of previous quantity estimates	12,341	14,119	(182,938)
Net change in income taxes		0	0
Accretion of discount	59,850	27,696	32,782
Changes in production rates and other	9,428	(6,572)	25,746
End of period	$ 954,980	$ 598,498	$ 276,955

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, 2018$ / bbl$ / MMcf	Dec. 31, 2017$ / bbl$ / MMcf	Dec. 31, 2016$ / bbl$ / MMcf
Oil
Average wellhead prices
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas)	59.29	46.76	38.42
Natural gas
Average wellhead prices
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas) | $ / MMcf	2.28	2.45	2.07
Natural gas liquids
Average wellhead prices
Average sales price (in dollars per Bbl for oil and dollars per Mcf for gas)	22.06	19.57	12.12

QUARTERLY FINANCIAL DATA (UNA_3

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							4 Months Ended	8 Months Ended	12 Months Ended
	Apr. 28, 2017	Jun. 30, 2017	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Apr. 28, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and gas sales		$ 28,114	$ 66,213	$ 74,380	$ 71,872	$ 64,193	$ 50,189	$ 45,232			$ 123,535	$ 276,657
Operating profit		12,955	41,416	43,959	40,014	35,042	22,935	22,540			12,009	112,394
Net income (loss)		$ (3,580)	$ 106,094	$ 43,363	$ 4,859	$ 13,870	$ (5,768)	$ 4,328			$ (5,020)	$ 168,186
Basic net income (loss) per common share (in dollars per share)		$ (0.18)	$ 5.16	$ 2.11	$ 0.24	$ 0.68	$ (0.28)	$ 0.21			$ (0.25)	$ 8.20
Diluted net income (loss) per common share (in dollars per share)		$ (0.18)	$ 5.15	$ 2.10	$ 0.24	$ 0.68	$ (0.28)	$ 0.21			$ (0.25)	$ 8.16
Predecessor
Oil and gas sales	$ 16,030								$ 52,559	$ 68,589				$ 195,295
Operating profit	3,786								14,398	(1,600)				(129,110)
Net income (loss)	$ 96,936								$ (94,276)	$ 2,660			$ (198,950)	$ (198,950)
Basic net income (loss) per common share (in dollars per share)	$ 1.88								$ (1.91)	$ 0.05			$ (4.04)	$ (4.04)
Diluted net income (loss) per common share (in dollars per share)	$ 1.85								$ (1.91)	$ 0.05			$ (4.04)	$ (4.04)