Battalion Oil (BATL) 10-K 25 Mar 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Mar. 20, 2020	Jun. 30, 2019
Cover [Abstract]
Entity Registrant Name	Battalion Oil Corp
Entity Central Index Key	0001282648
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 25.4
Entity Common Stock, Shares Outstanding		16,203,967
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2019	Oct. 01, 2019	Dec. 31, 2018	Dec. 31, 2017
Financial Designation, Predecessor and Successor [Fixed List]	Successor	Predecessor	Predecessor	Predecessor
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	$ 65,115	$ 158,360	$ 225,529	$ 375,837
Other	467	743	1,080	2,128
Total operating revenues	65,582	159,103	226,609	377,965
Production:
Lease operating	12,804	39,617	25,075	61,743
Workover and other	1,655	5,580	8,574	21,739
Taxes other than income	3,730	9,213	12,787	30,757
Gathering and other	10,812	36,057	60,090	40,783
Restructuring	1,175	15,148	128	7,535
General and administrative	5,111	36,550	62,056	111,351
Depletion, depreciation and accretion	19,996	90,912	77,527	110,207
Full cost ceiling impairment		985,190
(Gain) loss on sale of oil and natural gas properties			7,235	(721,573)
(Gain) loss on sale of Water Assets	(506)	3,618	(119,003)
Total operating expenses	54,777	1,221,885	134,469	(337,458)
Income (loss) from operations	10,805	(1,062,782)	92,140	715,423
Other income (expenses):
Net gain (loss) on derivative contracts	(16,692)	(34,332)	92,625	1,291
Interest expense and other	(1,275)	(37,606)	(43,015)	(71,097)
Reorganization items, net	(3,298)	(117,124)
Gain (loss) on extinguishment of debt				(114,931)
Total other income (expenses)	(21,265)	(189,062)	49,610	(184,737)
Income (loss) before income taxes	(10,460)	(1,251,844)	141,750	530,686
Income tax benefit (provision)		95,791	(95,791)	5,000
Net income (loss)	(10,460)	(1,156,053)	45,959	535,686
Non-cash preferred dividend				(48,007)
Net income (loss) available to common stockholders	$ (10,460)	$ (1,156,053)	$ 45,959	$ 487,679
Net income (loss) per share of common stock:
Basic (in dollars per share)	$ (0.65)	$ (7.27)	$ 0.29	$ 3.67
Diluted (in dollars per share)	$ (0.65)	$ (7.27)	$ 0.29	$ 3.65
Weighted average common shares outstanding:
Basic (in shares)	16,204	158,925	157,011	132,763
Diluted (in shares)	16,204	158,925	157,295	133,576
Oil
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	$ 58,325	$ 145,024	$ 199,601	$ 340,674
Oil
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	58,325	145,024	199,601	340,674
NGLs
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	$ 5,071	$ 13,229	$ 19,137	$ 18,969

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 02, 2019	Jan. 01, 2019	Dec. 31, 2016
CONSOLIDATED BALANCE SHEETS
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
Current assets:
Cash and cash equivalents	$ 15,546	$ 5,701	$ 15,546		$ 46,866		$ 15,546
Accounts receivable, net	37,826	48,504	37,826		35,718		37,826
Assets from derivative contracts	15,310	4,995	15,310		57,280		15,310
Restricted cash		4,574
Prepaids and other	14,642	7,379	14,642		4,788		10,290
Total current assets	84,787	71,153	84,787		144,652		92,811
Oil and natural gas properties (full cost method):
Evaluated	2,155,288	420,609	2,155,288		1,470,509		380,364
Unevaluated	438,365	105,009	438,365		971,918		108,954
Gross oil and natural gas properties	2,593,653	525,618	2,593,653		2,442,427		489,318
Less - accumulated depletion	(1,709,719)	(19,474)	(1,709,719)		(639,951)
Net oil and natural gas properties	883,934	506,144	883,934		1,802,476		489,318
Other operating property and equipment:
Other operating property and equipment	203,373	3,655	203,373		130,251		3,655
Less - accumulated depreciation	(14,416)	(378)	(14,416)		(8,388)
Net other operating property and equipment	188,957	3,277	188,957		121,863		3,655
Other noncurrent assets:
Assets from derivative contracts	4,120	224	4,120		12,437		4,120
Operating lease right of use assets	3,694	3,165	3,694				3,394	$ 5,462
Funds in escrow and other	1,138	703	1,138		2,181		1,138
Total assets	1,166,630	584,666	1,166,630		2,083,609		594,436
Current liabilities:
Accounts payable and accrued liabilities	112,578	97,333	112,578		157,848		115,305	157,763
Liabilities from derivative contracts	6,829	8,069	6,829		3,768		6,829
Current portion of long-term debt, net	258,234		258,234
Operating lease liabilities	1,337	923	1,337				913	2,103
Asset retirement obligations		109			126
Total current liabilities	378,978	106,434	378,978		161,742		123,047
Long-term debt, net		144,000			613,105		130,000
Liabilities subject to compromise	625,005		625,005
Other noncurrent liabilities:
Liabilities from derivative contracts	1,625	4,854	1,625		9,139		1,625
Asset retirement obligations	10,153	10,481	10,153		6,788		10,153
Operating lease liabilities	2,438	2,247	2,438				2,482	$ 3,444
Deferred income taxes					95,791
Commitments and contingencies (Note 12)
Stockholders' equity:
Common stock	16	2	16		16		2
Additional paid-in capital	1,087,441	327,108	1,087,441		1,095,367		327,127
Retained earnings (accumulated deficit)	(939,026)	(10,460)	(939,026)		101,661
Total stockholders' equity	148,431	316,650	148,431	$ 30,477	1,197,044	$ 1,071,998	327,129		$ 112,688
Total liabilities and stockholders' equity	$ 1,166,630	$ 584,666	$ 1,166,630		$ 2,083,609		$ 594,436

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2019$ / sharesshares
Stockholders' equity:
Common stock, shares authorized	100,000,000
Common stock, par value (in dollars per share) | $ / shares	$ 0.0001
Common stock, shares issued	16,203,940
Common stock, shares outstanding	16,203,940

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY - USD ($) $ in Thousands	Preferred Stock	Common Stock	Additional Paid-In Capital	Accumulated Deficit	Total
Increase (Decrease) in Stockholders' Equity
Financial Designation, Predecessor and Successor [Fixed List]					Predecessor
Balances at Dec. 31, 2016		$ 9	$ 592,663	$ (479,984)	$ 112,688
Balances (in shares) at Dec. 31, 2016		92,991
Increase (Decrease) in Stockholders' Equity
Net income (loss)				535,686	535,686
Sale of preferred stock			352,048		352,048
Sale of preferred stock (in shares)	6
Preferred beneficial conversion feature			48,007		48,007
Conversion of preferred stock		$ 6	(6)
Conversion of preferred stock (in shares)	(6)	55,180
Equity issuance costs			(11,919)		(11,919)
Long-term incentive plan grants (in shares)		2,022
Long-term incentive plan forfeitures (in shares)		(498)
Reduction in shares to cover individuals' tax withholding			(1,995)		(1,995)
Reduction in shares to cover individuals' tax withholding (in shares)		(316)
Stock-based compensation			37,483		37,483
Balances at Dec. 31, 2017		$ 15	1,016,281	55,702	$ 1,071,998
Balances (in shares) at Dec. 31, 2017		149,379
Increase (Decrease) in Stockholders' Equity
Financial Designation, Predecessor and Successor [Fixed List]					Predecessor
Net income (loss)				45,959	$ 45,959
Common stock issuance		$ 1	63,479		63,480
Common stock issuance (in shares)		9,200
Equity issuance costs			(3,044)		(3,044)
Stock option exercises			323		323
Stock option exercises (in shares)		42
Long-term incentive plan grants (in shares)		2,327
Long-term incentive plan forfeitures (in shares)		(262)
Reduction in shares to cover individuals' tax withholding			(301)		(301)
Reduction in shares to cover individuals' tax withholding (in shares)		(73)
Stock-based compensation			18,629		18,629
Balances at Dec. 31, 2018		$ 16	1,095,367	101,661	$ 1,197,044
Balances (in shares) at Dec. 31, 2018		160,613
Increase (Decrease) in Stockholders' Equity
Financial Designation, Predecessor and Successor [Fixed List]					Predecessor
Net income (loss)				(1,156,053)	$ (1,156,053)
Common stock issuance		$ 2	322,294		322,296
Common stock issuance (in shares)		16,204
Equity issuance costs			(2,503)		(2,503)
Long-term incentive plan grants (in shares)		4,164
Long-term incentive plan forfeitures (in shares)		(2,101)
Reduction in shares to cover individuals' tax withholding			(494)		(494)
Reduction in shares to cover individuals' tax withholding (in shares)		(1,174)
Stock-based compensation			(10,020)		(10,020)
Cancellation of Predecessor equity		$ (16)	(1,084,853)	1,054,392	(30,477)
Cancellation of Predecessor equity (in shares)		(161,502)
Warrants issued			7,336		7,336
Balances at Oct. 01, 2019					$ 148,431
Increase (Decrease) in Stockholders' Equity
Financial Designation, Predecessor and Successor [Fixed List]					Predecessor
Balances at Dec. 31, 2018		$ 16	1,095,367	101,661	$ 1,197,044
Balances (in shares) at Dec. 31, 2018		160,613
Balances at Sep. 30, 2019		$ 16	1,084,853	(1,054,392)	$ 30,477
Balances (in shares) at Sep. 30, 2019		161,502
Increase (Decrease) in Stockholders' Equity
Financial Designation, Predecessor and Successor [Fixed List]					Predecessor
Balances at Oct. 01, 2019					$ 148,431
Increase (Decrease) in Stockholders' Equity
Fair value of equity issued to Predecessor common stockholders					319,793
Equity issuance costs					(2,503)
Balances at Oct. 02, 2019		$ 2	327,127		$ 327,129
Balances (in shares) at Oct. 02, 2019		16,204
Increase (Decrease) in Stockholders' Equity
Financial Designation, Predecessor and Successor [Fixed List]					Successor
Balances at Oct. 01, 2019					$ 148,431
Increase (Decrease) in Stockholders' Equity
Net income (loss)					(10,460)
Balances at Dec. 31, 2019		$ 2	327,108	(10,460)	316,650
Balances (in shares) at Dec. 31, 2019		16,204
Balances at Oct. 02, 2019		$ 2	327,127		327,129
Balances (in shares) at Oct. 02, 2019		16,204
Increase (Decrease) in Stockholders' Equity
Net income (loss)				(10,460)	(10,460)
Equity issuance costs			(19)		(19)
Balances at Dec. 31, 2019		$ 2	$ 327,108	$ (10,460)	$ 316,650
Balances (in shares) at Dec. 31, 2019		16,204

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2019	Oct. 01, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Financial Designation, Predecessor and Successor [Fixed List]	Successor	Predecessor	Predecessor	Predecessor
Net income (loss)	$ (10,460)	$ (1,156,053)	$ 45,959	$ 535,686
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	19,996	90,912	77,527	110,207
Full cost ceiling impairment		985,190
(Gain) loss on sale of oil and natural gas properties			7,235	(721,573)
(Gain) loss on sale of Water Assets	(506)	3,618	(119,003)
Deferred income tax provision (benefit)		(95,791)	95,791
Stock-based compensation, net		(8,035)	15,266	36,757
Unrealized loss (gain) on derivative contracts	18,681	45,834	(84,274)	16,468
Amortization and write-off of deferred loan costs		1,859	1,405	1,795
Amortization of discount and premium		134	288	2,597
Reorganization items, net	(3,615)	108,887		(739)
Loss (gain) on extinguishment of debt				114,931
Other expense (income)	253	535	(1,608)	(3,331)
Change in assets and liabilities:
Accounts receivable	(10,571)	3,781	378	103,166
Prepaids and other	2,911	(6,729)	5,840	(3,688)
Accounts payable and accrued liabilities	(3,035)	(13,873)	22,351	(77,685)
Net cash provided by (used in) operating activities	13,654	(39,731)	67,155	114,591
Cash flows from investing activities:
Oil and natural gas capital expenditures	(43,230)	(167,235)	(475,685)	(331,257)
Proceeds received from sales of oil and natural gas assets		1,247	3,816	2,003,894
Acquisition of oil and natural gas properties		(2,809)	(333,857)	(1,018,546)
Acquisition of other operating property and equipment				(25,538)
Other operating property and equipment capital expenditures		(85,613)	(116,995)	(53,214)
Proceeds received from sale of other operating property and equipment	6		216,083	21,798
Funds held in escrow and other	434	(7)	153	1,455
Net cash provided by (used in) investing activities	(42,790)	(254,417)	(706,485)	598,592
Cash flows from financing activities:
Proceeds from borrowings	36,000	445,234	438,000	1,349,000
Repayments of borrowings	(22,000)	(315,234)	(232,000)	(1,922,826)
Cash payments to Common Holders, Noteholders and Preferred Holders		(4)		(83,653)
Debt issuance costs	(1,471)	(8,764)	(4,334)	(17,799)
Preferred stock issued				400,055
Common stock issued		155,929	63,480
Equity issuance costs and other	(2,503)	(494)	(3,021)	(13,913)
Net cash provided by (used in) financing activities	10,026	276,667	262,125	(289,136)
Net increase (decrease) in cash, cash equivalents and restricted cash	(19,110)	(17,481)	(377,205)	424,047
Cash, cash equivalents and restricted cash at beginning of period	29,385	46,866	424,071	24
Cash, cash equivalents and restricted cash at end of period	10,275	29,385	46,866	424,071
Supplemental cash flow information:
Cash paid (received) for interest	(197)
Cash paid (received) for interest		33,071	37,526	90,835
Cash paid (refunded) for income taxes			(5,000)	1,250
Cash paid for reorganization items	6,913	8,237		739
Disclosure of non-cash investing and financing activities:
Asset retirement obligations	293	2,932	2,217	(29,313)
Accretion of non-cash preferred dividend				48,007
Accrued equity issuance costs	(2,484)	2,503
Accrued debt issuance costs	$ (1,471)	$ 1,471	$ (90)	$ 90

SUMMARY OF SIGNIFICANT EVENTS A

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES
SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES	1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES Basis of Presentation and Principles of Consolidation Battalion Oil Corporation (Battalion or the Company) is the successor reporting company to Halcón Resources Corporation (Halcón). On January 21, 2020, Battalion filed a Certificate of Amendment to the Company’s Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Halcón Resources Corporation to Battalion Oil Corporation. Battalion is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids‑rich oil and natural gas assets in the United States. The consolidated financial statements include the accounts of all majority‑owned, controlled subsidiaries. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. Allocation of capital is made across the Company’s entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. The Company has evaluated events and transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements. Emergence From Voluntary Reorganization Under Chapter 11 On August 7, 2019 (the Petition Date), the Company and its subsidiaries filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to pursue a prepackaged plan of reorganization (the Plan). The Company’s chapter 11 proceedings were administered under the caption In re Halcón Resources Corporation, et al. (Case No. 19-34446). On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019, the Plan became effective (the Effective Date) and the Company emerged from chapter 11 bankruptcy. See Note 2, “ Reorganization, ” for further details on the Company’s chapter 11 bankruptcy and the Plan. Upon emergence from chapter 11 bankruptcy, the Company adopted fresh-start accounting in accordance with provisions of the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852) which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. The Company elected to apply fresh-start accounting effective October 1, 2019, to coincide with the timing of its normal fourth quarter reporting period, which resulted in the Company becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate. As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related reorganization adjustments and fresh-start adjustments are included in the accompanying statement of operations for the period from January 1, 2019 through October 1, 2019 (Predecessor). Upon the adoption of fresh-start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh-start reporting date. As a result of the adoption of fresh-start accounting, the Company’s consolidated financial statements subsequent to October 1, 2019 are not comparable to its consolidated financial statements prior to, and including, October 1, 2019. See Note 3, “Fresh-start Accounting,” for further details on the impact of fresh-start accounting on the Company’s consolidated financial statements. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, October 1, 2019. Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates, including estimates of Reorganization Value, Enterprise Value and the fair value of assets and liabilities recorded as a result of the adoption of fresh-start accounting, plus the estimated fair values of assets acquired and liabilities assumed in connection with the Pecos County Acquisition and the fair value of assets sold in connection with the Williston Divestiture and the El Halcón Divestiture (see Note 6, “Acquisitions and Divestitures,” for information on the Pecos County Acquisition, the Williston Divestiture and the El Halcón Divestiture), including the gains on sales recorded, and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements. Cash, Cash Equivalents and Restricted Cash The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. Amounts in the consolidated balance sheets included in cash, cash equivalents and restricted cash on the Company’s consolidated statement of cash flows are as follows: Successor Predecessor December 31, 2019 December 31, 2018 Cash and cash equivalents $ 5,701 $ 46,866 Restricted cash 4,574 — Total cash, cash equivalents and restricted cash $ 10,275 $ 46,866 Restricted Cash consists of funds related to payments prescribed under the Plan that are held in an interest-bearing escrow account. Accounts Receivable and Allowance for Doubtful Accounts The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. As of December 31, 2019 (Successor) and 2018 (Predecessor), allowances for doubtful accounts were approximately $0.1 million and $0.2 million, respectively. Oil and Natural Gas Properties The Company uses the full cost method of accounting for its investment in oil and natural gas properties as prescribed by the United States Securities and Exchange Commission (SEC). Accordingly, all costs incurred in the acquisition, exploration and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, treating equipment and gathering support facilities, dry holes, geophysical costs, and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on estimated proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company reviews its unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The Company determines capitalized interest, when applicable, by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The Company’s accounting policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization. Other Operating Property and Equipment Other operating property and equipment additions are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: buildings, twenty years; automobiles and computers, three years; computer software, fixtures, furniture and equipment, the lesser of lease term or five years; trailers, seven years; heavy equipment, eight to ten years and leasehold improvements, lease term. Land and artwork are not depreciated. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. Refer to Note 3, “ Fresh-start Accounting,” for a discussion of the valuation approach used to record other operating property and equipment at fair value as of October 1, 2019. Refer to Note 6, “Acquisitions and Divestitures,” for a discussion of other operating property and equipment acquired and divested. The Company reviews its other operating property and equipment for impairment in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate other operating property and equipment for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its other operating property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods. Concentrations of Credit Risk The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. For the combined periods of October 2, 2019 through December 31, 2019 (Successor), and January 1, 2019 through October 1, 2019 (Predecessor), two individual purchasers of our production, Western Refining Inc. and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 80% of our total sales for the period. For the year ended December 31, 2018 (Predecessor), two individual purchasers of the Company’s production, Sunoco, Inc. and Western Refining, Inc., each accounted for more than 10% of total sales, collectively representing 77% of the Company’s total sales for the year. In 2017 (Predecessor), two individual purchasers of the Company’s production, Crestwood Midstream Partners and Suncor Energy Marketing, Inc., each accounted for more than 10% of total sales, collectively representing 58% of the Company’s total sales for the year. The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected. Risk Management Activities The Company follows ASC 815, Derivatives and Hedging (ASC 815). From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted oil, natural gas, and natural gas liquids production. The Company recognized all derivative instruments as either assets or liabilities in the consolidated balance sheets at fair value. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark‑to‑market valuation of these positions, as well as payments and receipts on settled contracts, in “ Net gain (loss) on derivative contracts ” on the consolidated statements of operations. Income Taxes The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets. The Company follows ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the consolidated financial statements. The evaluation of a tax position in accordance with ASC 740 is a two‑step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement. The Company has no liability for unrecognized tax benefits as of December 31, 2019 (Successor) and 2018 (Predecessor). Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (Predecessor). In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months. The Company includes interest and penalties relating to uncertain tax positions within “ Interest expense and other ” on the Company’s consolidated statements of operations. Refer to Note 14, “ Income Taxes, ” for more details. Generally, the Company’s income tax years 2016 through 2019 remain open for federal purposes and are subject to examination by Federal tax authorities. No claims were filed with respect to any historical income tax periods that caused any challenge to the Plan. The Company’s income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statue expiration period for federal purposes. Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates. Asset Retirement Obligations ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells, treating equipment and gathering support facilities. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, treating equipment and gathering support facilities as these obligations are incurred. Leases Effective January 1, 2019 (Predecessor), the Company accounts for leases in accordance with ASC 842, Leases (ASC 842). The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified asset for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset, and (2) the customer has the right to control the use of the identified asset. The Company leases equipment and office space pursuant to net operating leases. Operating leases where the Company is the lessee are included in “Operating lease right of use assets” and “Operating lease liabilities” on the consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date. Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The incremental borrowing rate for a lease is the rate of interest the Company would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. Additionally, the Company applies a portfolio approach to determine the discount rate (the incremental borrowing rate for leases with similar characteristics). The Company uses the implicit rate when readily determinable. The lease term includes the noncancellable period of the lease plus any additional periods covered by either a lessee option to extend (or not to terminate) the lease that the lessee is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. Lease payments included in the measurement of the lease asset or liability comprise the following, when applicable: fixed payments (including in‑substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if the lessee is reasonably certain to exercise. The right of use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For the Company’s operating leases, the right of use asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight‑line basis over the lease term. Variable lease payments associated with the Company’s leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as “Gathering and other” or “General and administrative” in the consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases. The Company has lease agreements which include lease and nonlease components and the Company has elected to combine lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. The Company determines whether the lease or nonlease component is the predominant component on a case‑by‑case basis. The Company reviews its right of use assets for impairment in accordance with ASC 360. ASC 360 requires the Company to evaluate right of use assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. The Company monitors for events or changes in circumstances that would require a reassessment of a lease. When a reassessment results in the remeasurement of a lease liability, an adjustment is made to the carrying amount of the corresponding right of use asset unless doing so would reduce the carrying amount of the right of use asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative right of use asset balance is recorded in the consolidated statements of operations. The Company elected not to recognize right of use assets and lease liabilities for all short‑term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short‑term leases as an expense on a straight‑line basis over the lease term. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases. Restructuring During 2019 (both in Successor and Predecessor periods), senior executives of the Company resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the third quarter of 2019 (Predecessor), the Company made the decision to consolidate into one corporate office located in Houston, Texas in an effort to improve efficiencies and go forward costs. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions. Consequently, for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company incurred approximately $1.2 million and $15.1 million, respectively, in costs which were recorded in “Restructuring” on the consolidated statements of operations. 401(k) Plan The Company sponsors a 401(k) tax deferred savings plan, whereby the Company matches a portion of employees’ contributions in cash. Participation in the plan is voluntary and all employees of the Company who are 18 years of age are eligible to participate. The Company provided matching contributions of $0.2 million and $1.1 million for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. The Company provided matching contributions of $1.5 million and $2.2 million for the years ended December 31, 2018 and 2017 (Predecessor), respectively. The Company matches employee contributions dollar-for-dollar on the first 10% of an employee’s pre‑tax earnings, subject to individual IRS limitations. Related Party Transactions Crude Oil Gathering Agreement On July 27, 2018 (Predecessor), a subsidiary of the Company entered into a crude oil gathering agreement with SCM Crude, LLC (SCM) pursuant to which the Company agreed to dedicate, for a term of 15 years, production of crude oil from its currently owned, or later acquired, acreage in designated areas in Ward and Winkler Counties, Texas (excluding certain specific wells) for the receipt, gathering and transportation on a gathering system to be designed, engineered and constructed by SCM. For the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company recorded revenue $101.6 million and $13.0 million, respectively, from SCM under the crude oil gathering agreement. As of December 31, 2018 (Predecessor), the Company recorded a $10.9 million receivable from SCM for its crude oil sales. Certain funds under the control of Ares Management LLC (Ares) are the majority owners and controlling parties of SCM. Ares also controls other funds which owned in excess of ten percent (10%) of the common stock of the Company prior to the Effective Date of the Plan. No Ares fund that was a stockholder of the Company had an interest in SCM but one of the Company’s former directors, who is employed by Ares, also serves on the board of directors of SCM’s parent company. As of the Effective Date, SCM is no longer a related party to the Successor Company. Gas Purchase and Processing Agreement On November 16, 2017 (Predecessor), a subsidiary of the Company entered into a gas purchase and processing agreement with Salt Creek Midstream, LLC (Salt Creek) pursuant to which the Company agreed to dedicate for a term of 15 years, all production from its acreage in Ward County, Texas (that is not otherwise previously dedicated) and certain sections in Winkler County, Texas to a natural gas gathering pipeline and processing facilities to be constructed by Salt Creek. For the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company recorded revenue of $6.0 million and $0.4 million, respectively, from Salt Creek under the gas purchase and processing agreement. As of December 31, 2018 (Predecessor), the Company had no receivables outstanding from Salt Creek. Certain funds under the control of Ares are the majority owners and controlling parties of Salt Creek. Ares also controls other funds which owned in excess of ten percent (10%) of the stock of the Company prior to the Effective Date of the Plan. No Ares fund that was a stockholder of the Company had an interest in Salt Creek but one of the Company’s former directors, who is employed by Ares, also serves on the board of directors of Salt Creek. As of the Effective Date, Salt Creek is no longer a related party to the Successor Company. Pipeline Testing Services In February 2019 (Predecessor), the Company entered into an agreement with Cima Inspection LLC (Cima), a company specializing in advanced, non-destructive methods of testing pipes and tubing, pursuant to which Cima will inspect various Company gathering and transportation assets. One of the Company's former directors (as of the Effective Date of the Plan) owns a minority interest in Cima and serves as its chief executive officer. For the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company incurred charges of approximately $0.9 million for services provided by Cima. As of the Effective Date, Cima is no longer a related party to the Successor Company. Charter of Aircraft In the ordinary course of business, the Company occasionally chartered a private aircraft for business use. The Company’s former Chairman, Chief Executive Officer and President indirectly owns an aircraft that the Company chartered from time to time. During 2018 and a portion of 2017 (Predecessor), fees for the use of the Company’s former Chairman, Chief Executive Officer and President’s aircraft by the Company were based upon comparable costs that the Company would have incurred in chartering the same type and size of aircraft from an independent third party utilizing data from several independent third party aircraft leasing companies. In the first quarter of 2019 (Predecessor), the Company terminated all charter arrangements with the Company’s former Chairman, Chief Executive Officer and President relating to the use of his aircraft. During the period of January 1, 2019 to October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company paid approximately $0.2 million and $0.9 million, respectively, related to use of the aircraft indirectly owned by the Company’s former Chairman, Chief Executive Officer and President during 2018. As of December 31, 2018 (Predecessor), the Company recorded a $0.2 million payable to the Company’s former Chairman, Chief Executive Officer and President. Recently Issued Accounting Pronouncements In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after D

REORGANIZATION

REORGANIZATION	12 Months Ended
	Dec. 31, 2019
REORGANIZATION
REORGANIZATION	2. REORGANIZATION On August 2, 2019, the Company entered into a Restructuring Support Agreement (the Restructuring Support Agreement) with certain holders of the Company’s 6.75% senior unsecured notes due 2025 (the Unsecured Senior Noteholders). On August 7, 2019, the Company filed voluntary petitions for relief under chapter 11 of the Bankruptcy Court to effect an accelerated prepackaged bankruptcy restructuring as contemplated in the Restructuring Support Agreement. The Company continued to operate its businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the United States Bankruptcy Code and orders of the Bankruptcy Court. On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019 (the Effective Date), the Company emerged from chapter 11 bankruptcy. Pursuant to the terms of the Plan contemplated by the Restructuring Support Agreement, the Unsecured Senior Noteholders and other claim and interest holders received the following treatment in full and final satisfaction of their claims and interests: · borrowings outstanding under the Predecessor Credit Agreement, plus unpaid interest and fees, were repaid in full, in cash, including by a refinancing (refer to Note 8, “ Long-Term Debt ” for further details regarding the credit agreement); · the Unsecured Senior Noteholders received their pro rata share of 91% of the common stock of reorganized Battalion (New Common Shares), subject to dilution, issued pursuant to the Plan and participated in the Senior Noteholder Rights Offering (defined below); · the Company’s general unsecured claims were unimpaired and paid in full in the ordinary course; and · all of the Predecessor Company’s outstanding shares of common stock were cancelled and the existing common stockholders received their pro rata share of 9% of the New Common Shares issued pursuant to the Plan, subject to dilution, together with Warrants (defined below) to purchase common stock of reorganized Battalion and participated in the Existing Equity Interests Rights Offering (defined below and, collectively, the Existing Equity Total Consideration); provided, however, that registered holders of existing common stock with 2,000 shares or fewer of common stock received cash in an amount equal to the inherent value of such holder’s pro rata share of the Existing Equity Total Consideration (the Existing Equity Cash Out). Each of the foregoing percentages of equity in the reorganized Company were as of October 8, 2019 and are subject to dilution by New Common Shares issued in connection with (i) a management incentive plan, (ii) the Warrants (defined below), (iii) the Equity Rights Offerings (defined below), and (iv) the Backstop Commitment Premium (defined below). As a component of the Restructuring Support Agreement (i) certain Unsecured Senior Noteholders purchased their pro rata share of New Common Shares for an aggregate purchase price of $150.2 million (the Senior Noteholder Rights Offering) and (ii) certain existing common stockholders purchased their pro rata share of New Common Shares for an aggregate purchase price of $5.8 million (the Existing Equity Interests Rights Offering, and together with the Senior Noteholder Rights Offering, the Equity Rights Offerings), in each case, at a price per share equal to a 26% discount to the value of the New Common Shares based on an assumed total enterprise value of $425.0 million. Certain of the Unsecured Senior Noteholders backstopped the Senior Noteholder Rights Offering and received as consideration (the Backstop Commitment Premium) New Common Shares equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering, subject to dilution by New Common Shares issued in connection with a management incentive plan and the Warrants. If the backstop agreement had been terminated, the Company would have been obligated to make a cash payment equal to 6% of the aggregate amount of the Senior Noteholder Rights Offering. The proceeds of the Equity Rights Offerings were used by the Company to (i) provide additional liquidity for working capital and general corporate purposes, (ii) pay reasonable and documented restructuring expenses, and (iii) fund Plan distributions. Under the Restructuring Support Agreement, the existing common stockholders (subject to the Existing Equity Cash Out) were issued a series of warrants exercisable for cash for a three year period subsequent to the effective date of the Plan (Warrants). The Warrants were issued with strike prices based upon stipulated rate-of-return levels achieved by the Unsecured Senior Noteholders. The Warrants cumulatively represent 30% of the New Common Shares issued pursuant to the Plan. Registration Rights Agreement On the Effective Date, the Company and the other signatories thereto (the Demand Stockholders), entered into a registration rights agreement (the Registration Rights Agreement), pursuant to which, subject to certain conditions and limitations, the Company agreed to file with the SEC a registration statement concerning the resale of the registrable shares of New Common Shares of the Company held by Demand Stockholders (the Registrable Securities), as soon as reasonably practicable but in no event later than the later to occur of (i) ninety (90) days after the Effective Date and (ii) a date specified by a written notice to the Company by Demand Stockholders holding at least a majority of the Registerable Securities, and thereafter to use its commercially reasonable best efforts to cause the registration statement to be declared effective by the SEC as soon as reasonably practicable. In addition, from time to time, the Demand Stockholders may request that additional Registrable Securities be registered for resale by the Company. Subject to certain limitations, the Demand Stockholders also have the right to request that the Company facilitate the resale of Registrable Securities pursuant to firm commitment underwritten public offerings. The Registration Rights Agreement contains other customary terms and conditions, including, without limitation, provisions with respect to suspensions of our registration obligations and indemnification.

FRESH-START ACCOUNTING

FRESH-START ACCOUNTING	12 Months Ended
	Dec. 31, 2019
FRESH-START ACCOUNTING
FRESH-START ACCOUNTING	3. FRESH-START ACCOUNTING Upon the Company’s emergence from chapter 11 bankruptcy, the Company qualified for and adopted fresh-start accounting in accordance with the provisions set forth in ASC 852 as (i) the Reorganization Value of the Company’s assets immediately prior to the date of confirmation was less than the total of the post-petition liabilities and allowed claims, and (ii) the holders of the existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity. Refer to Note 2 , “Reorganization,” for the terms of the Plan. Fresh-start accounting requires the Company to present its assets, liabilities, and equity as if it were a new entity upon emergence from bankruptcy. The new entity is referred to as “Successor” or “Successor Company.” However, the Company will continue to present financial information for any periods before adoption of fresh-start accounting for the Predecessor Company. The Predecessor and Successor Companies lack comparability, as required in ASC Topic 205, Presentation of Financial Statements (ASC 205). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, “black-line” financial statements are presented to distinguish between the Predecessor and Successor Companies. Adopting fresh-start accounting results in a new financial reporting entity with no beginning retained earnings or deficit as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, the Company allocated the Reorganization Value (the fair value of the Successor Company’s total assets) to its individual assets based on their estimated fair values. The Reorganization Value is intended to represent the approximate amount a willing buyer would pay for the Company’s assets immediately after the reorganization. Reorganization Value is derived from an estimate of Enterprise Value, or the fair value of the Company’s long-term debt, stockholders’ equity and working capital. The estimated Enterprise Value of $441.6 million at the Effective Date was in the Bankruptcy Court approved range of $425.0 million and $475.0 million. The Enterprise Value was derived from an independent valuation using an asset based methodology of estimated proved reserves, undeveloped acreage, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh-start reporting date of October 1, 2019. The Company elected to adopt fresh-start accounting effective October 1, 2019, to coincide with the timing of its normal fourth quarter reporting period, which resulted in the Company becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate. As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related reorganization adjustments and fresh-start adjustments are included in the accompanying consolidated statement of operations in “ Reorganization items, net ” for the period from January 1, 2019 through October 1, 2019 (Predecessor). The Company’s principal assets are its oil and natural gas properties. For purposes of estimating the fair value of the Company’s proved reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.0%. The proved reserve locations were limited to wells expected to be drilled in the Company’s five year development plan. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $71.51 per barrel of oil, $3.37 per MMBtu of natural gas and $29.50 per barrel of oil equivalent of natural gas liquids. Base pricing was derived from an average of forward strip prices and analysts’ estimated prices. In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company’s unproved acreage from a market participant perspective. See further discussion below in the “Fresh-start accounting adjustments” for the specific assumptions used in the valuation of the Company’s various other assets. Although the Company believes the assumptions and estimates used to develop Enterprise Value and Reorganization Value are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating these values are inherently uncertain and require judgment. The following table reconciles the Company’s Enterprise Value to the estimated fair value of the Successor’s common stock as of October 1, 2019 (in thousands): October 1, 2019 Enterprise Value $ 441,583 Plus: Cash 15,546 Less: Fair value of debt (130,000) Less: Fair value of warrants (7,336) Fair Value of Successor common stock $ 319,793 The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of October 1, 2019 (in thousands): October 1, 2019 Enterprise Value $ 441,583 Plus: Cash 15,546 Plus: Current liabilities 122,134 Plus: Lease liabilities 3,395 Plus: Noncurrent asset retirement obligation 10,153 Plus: Other noncurrent liabilities 1,625 Reorganization Value of Successor assets $ 594,436 Condensed Consolidated Balance Sheet The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh-start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the Company’s assumptions and methods used to determine fair value for its assets, liabilities, and warrants. Amounts included in the table below are rounded to thousands. As of October 1, 2019 Predecessor Reorganization Fresh-Start Successor Current assets: Cash and cash equivalents $ 17,009 $ (1,463) (1) $ — $ 15,546 Accounts receivable, net 37,826 — — 37,826 Assets from derivative contracts 15,310 — — 15,310 Restricted cash — 13,839 (2) — 13,839 Prepaids and other 14,642 7,110 (3) (11,462) (11) 10,290 Total current assets 84,787 19,486 (11,462) 92,811 Oil and natural gas properties (full cost method): Evaluated 2,155,288 — (1,774,924) (12)(13) 380,364 Unevaluated 438,365 — (329,411) (13) 108,954 Gross oil and natural gas properties 2,593,653 — (2,104,335) 489,318 Less - accumulated depletion (1,709,719) — 1,709,719 (13) — Net oil and natural gas properties 883,934 — (394,616) 489,318 Other operating property and equipment: Other operating property and equipment 203,373 — (199,718) (12)(14) 3,655 Less - accumulated depreciation (14,416) — 14,416 (14) — Net other operating property and equipment 188,957 — (185,302) 3,655 Other noncurrent assets: Assets from derivative contracts 4,120 — — 4,120 Operating lease right of use assets 3,694 — (300) (15) 3,394 Funds in escrow and other 1,138 — — 1,138 Total assets $ 1,166,630 $ 19,486 $ (591,680) $ 594,436 Current liabilities: Accounts payable and accrued liabilities $ 112,578 $ 2,727 (4) $ — $ 115,305 Liabilities from derivative contracts 6,829 — — 6,829 Current portion of long-term debt, net 258,234 (258,234) (5) — — Operating lease liabilities 1,337 — (424) (15) 913 Total current liabilities 378,978 (255,507) (424) 123,047 Long-term debt, net — 130,000 (6) — 130,000 Liabilities subject to compromise 625,005 (625,005) (7) — — Other noncurrent liabilities: Liabilities from derivative contracts 1,625 — — 1,625 Asset retirement obligations 10,153 — — 10,153 Operating lease liabilities 2,438 — 44 (15) 2,482 Commitments and contingencies Stockholders' equity: Common Stock (Predecessor) 16 (16) (8) — — Common Stock (Successor) — 2 (9) — 2 Additional paid-in capital (Predecessor) 1,087,441 (1,087,441) (8) — — Additional paid-in capital (Successor) — 327,127 (9) — 327,127 Retained earnings (accumulated deficit) (939,026) 1,530,326 (10) (591,300) (16) — Total stockholders' equity 148,431 769,998 (591,300) 327,129 Total liabilities and stockholders' equity $ 1,166,630 $ 19,486 $ (591,680) $ 594,436 Reorganization adjustments 1) The table below details cash payments as of October 1, 2019, pursuant to the terms of the Plan described in Note 2, “ Reorganization, ” (in thousands): Sources: Proceeds from Senior Noteholder Rights Offering $ 150,150 Proceeds from Senior Credit Agreement 130,000 Proceeds from Existing Equity Interests Rights Offering 5,779 Total Sources $ 285,929 Uses: Payment of Predecessor Credit Agreement principal, accrued interest, and fees $ (226,580) Payment of DIP Facility principal and accrued interest (35,174) Funding of professional fee escrow and cash collateral account (13,839) Payment of debt issuance costs on Senior Credit Agreement (8,764) Payment of professional fees and other (3,035) Total Uses $ (287,392) Total Sources and Uses $ (1,463) 2) Reflects the funding of an escrow account for professional fees associated with the chapter 11 bankruptcy and an account to cash collateralize the Predecessor Company’s outstanding letters of credit. 3) Represents $10.2 million in debt issuance costs related to the Senior Credit Agreement, partially offset by the release of $3.1 million in fees paid to the Company’s restructuring advisors prior to the emergence from chapter 11 bankruptcy. 4) Represents $7.7 million in fees to be paid to the Company’s restructuring advisors subsequent to the Company’s emergence from chapter 11 bankruptcy, partially offset by payments of i) payments of accrued interest and fees on the Predecessor Credit Agreement and the DIP Facility of $3.5 million and ii) professional fees associated with the chapter 11 bankruptcy of $1.5 million. 5) On the Emergence Date, in accordance with the Plan, the Company repaid the principal outstanding on the Predecessor Credit Agreement of $223.2 million and the DIP Facility of $35.0 million using proceeds from the Equity Rights Offerings and borrowings under the Senior Credit Agreement. 6) Reflects the initial borrowing on the Senior Credit Agreement. 7) Liabilities subject to compromise were as follows (in thousands): 6.75% senior notes due 2025 $ 625,005 Liabilities subject to compromise 625,005 Discount on shares issued per the Senior Noteholder Subscription Rights Offering (67,840) Issuance of common stock to Class 4 claimholders (75,388) Gain on settlement of liabilities subject to compromise $ 481,777 8) Reflects the cancellation of Predecessor common stock and additional paid-in capital. 9) The following table reconciles reorganization adjustments made to Successor common stock and additional paid-in capital (in thousands): Par value of 16,203,940 shares of new common stock issued to holders of senior note claims and existing equity interest claims (valued at $19.74 per share) $ 2 Fair Value of warrants issued to holder of the Existing Equity Interests (1) 7,336 Additional paid-in-capital (Successor) 322,294 Equity issuance costs associated with Equity Rights Offering (2,503) Total change in Successor common stock and additional paid-in capital $ 327,129 (1) The fair value of the warrants was estimated using a Binomial Lattice model with the following assumptions: implied stock price of the Successor Company of $19.74; initial strike price per share of $40.17, $48.28, and $60.45, for Series A, B, and C warrants, respectively, increased each month at an annualized rate of 6.75%; expected volatility of 45%; and risk free interest rate using the USD Yield Curve at each time-step in the lattice. 10) The table below reflects the cumulative effect of the adjustments discussed above (in thousands): Gain on settlement of liabilities subject to compromise $ 481,777 Success fees incurred upon emergence (8,376) Fair value of equity issued to Predecessor common stockholders (7,449) Fair value of warrants issued to Predecessor common stockholders (7,336) Issuance of common stock to backstop commitment parties (13,079) Other (2,668) Cancellation of Predecessor Company equity 1,087,457 Net impact to retained earnings (accumulated deficit) $ 1,530,326 Fresh-start accounting adjustments 11) Adjustment reflects the write-off of debt issuance costs associated with the Senior Credit Agreement of $10.2 million and the write-off of prepaid expenses related to $1.2 million of premiums for the Predecessor Company’s directors and officers’ insurance policy. 12) Includes the reclassification of treating equipment and gathering support facilities from “Other operating property and equipment” to “Oil and natural gas properties, evaluated.” The Successor Company’s policy of accounting for its treating equipment and gathering support facilities identifies these assets as part of the Company’s full cost pool due to their supporting nature to the Company’s oil and natural gas operations. 13) Reflects the adjustment to fair value of the Company’s oil and natural gas properties and unproved acreage, as well as the elimination of accumulated depletion. In estimating the fair value of its oil and natural gas properties, the Company used a combination of the income and market approaches. For purposes of estimating the fair value of the Company’s proved reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.0%. The proved reserve locations were limited to wells expected to be drilled in the Company’s five year development plan. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $71.51 per barrel of oil, $3.37 per MMBtu of natural gas and $29.50 per barrel of natural gas liquids. Base pricing was derived from an average of forward strip prices and analysts’ estimated prices. In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company’s unproved acreage from a market participant perspective. 14) Reflects the adjustment to fair value of the Company’s other operating property and equipment, as well as the elimination of accumulated depreciation. For purposes of estimating the fair value of its other operating property and equipment, the Company used a combination of the market and cost approaches. A market approach was relied upon to value land and vehicles, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and age of the assets. 15) Upon adoption of fresh start accounting, the Company’s lease obligations were recalculated using the incremental borrowing rate applicable to the Company upon emergence from chapter 11 bankruptcy and commensurate with its new capital structure. The incremental borrowing rate used decreased from 4.83% in the Predecessor period to 3.70% in the Successor period. Additionally represents the removal of right-of-use assets and lease liabilities associated with the Company’s compressors, as the remaining contract term of the compressor leases were less than one year as of the Effective Date. See Note 4, “Leases,” for details associated with the Company’s short-term lease costs. 16) Reflects the cumulative effect of the fresh-start accounting adjustments discussed above. Reorganization Items Reorganization items represent (i) expenses or income incurred subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled, and (iii) fresh‑start accounting adjustments and are recorded in “ Reorganization items, net ” in the Company’s consolidated statements of operations. The following table summarizes the net reorganization items (in thousands): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through December 31, 2019 October 1, 2019 Gain on settlement of liabilities subject to compromise $ — $ 481,777 Fresh start adjustments — (591,300) Gain on adjustment of prepetition liabilities subject to compromise to the allowed claims amount — 20,274 Write-off debt discount/premium and debt issuance costs — (10,953) Reorganization professional fees and other (3,298) (16,922) Gain (loss) on reorganization items $ (3,298) $ (117,124)

LEASES

LEASES	12 Months Ended
	Dec. 31, 2019
LEASES
LEASES	4. LEASES Adoption of Accounting Standards Codification 842, Leases On January 1, 2019 (Predecessor), the Company adopted ASC 842 using the modified retrospective approach as of the adoption date. Reporting periods beginning after January 1, 2019 are presented under ASC 842, while prior period amounts are not adjusted and continue to be reported under the accounting standards in effect for those periods. The table below details the impact of adoption on the Company’s unaudited condensed consolidated balance sheet as of January 1, 2019 (Predecessor) (in thousands): Predecessor December 31, 2018 Impact of adoption January 1, 2019 Other noncurrent assets: Operating lease right of use assets $ — $ 5,462 $ 5,462 Current liabilities: Accounts payable and accrued liabilities $ 157,848 $ (85) $ 157,763 Operating lease liabilities — 2,103 2,103 Other noncurrent liabilities: Operating lease liabilities — 3,444 3,444 Practical Expedients The Company elected the following practical expedients for transition to, and ongoing accounting under, ASC 842: (i) the Company does not separate lease and non-lease components of a contract, (ii) the Company does not reassess whether expired or existing contracts contain leases, nor does it reassess the lease classification for expired or existing leases and does not reassess whether previously capitalized initial direct costs would qualify for capitalization under ASC 842, (iii) the Company applies a single discount rate to a portfolio of leases with reasonably similar characteristics and iv) the Company does not assess whether existing or expired land easements that were not previously accounted for as leases are or contain a lease under ASC 842. Leases The Company leases equipment and office space under operating leases. The Company has no leases that meet the criteria for classification as a finance lease. The operating leases have initial lease terms ranging from 2 to 5 years for the period from October 2, 2019 through December 31, 2019 (Successor) and 1 to 4 years for the period from January 1, 2019 through October 1, 2019 (Predecessor). Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. The table below summarizes the Company’s leases for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) (in thousands, except years and discount rate): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through December 31, 2019 October 1, 2019 Lease cost Operating lease costs $ 260 $ 1,932 Short-term lease costs 4,408 12,262 Variable lease costs 215 1,210 Total lease costs $ 4,883 $ 15,404 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 254 $ 1,936 Right-of-use assets obtained in exchange for new operating lease liabilities 3,394 5,462 Weighted-average remaining lease term - operating leases 3.5 years 3.7 years Weighted-average discount rate - operating leases 3.70 % 4.83 % Refer to Note 3, “ Fresh-start Accounting,” for a discussion of the valuation approach used to record the right of use asset at fair value as of October 1, 2019. Future minimum lease payments associated with the Company’s non-cancellable operating leases for office space and equipment as of December 31, 2019 (Successor), are presented in the table below (in thousands): Successor December 31, 2019 2020 $ 1,022 2021 876 2022 574 2023 585 2024 345 Thereafter — Total operating lease payments 3,402 Less: discount to present value 232 Total operating lease liabilities 3,170 Less: current operating lease liabilities 923 Noncurrent operating lease liabilities $ 2,247 Prior to the adoption of ASC 842, future obligations, including variable nonlease components, associated with the Company’s non-cancellable operating leases for office space and equipment as of December 31, 2018 (Predecessor), are presented in the table below (in thousands): Predecessor December 31, 2018 2019 $ 3,792 2020 2,350 2021 1,899 2022 968 2023 999 Thereafter 599 Total operating lease payments $ 10,607

OPERATING REVENUES

OPERATING REVENUES	12 Months Ended
	Dec. 31, 2019
OPERATING REVENUES
OPERATING REVENUES	5. OPERATING REVENUES Revenue Recognition Revenue is measured based on consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that are collected by the Company from a customer are excluded from revenue. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of the commodity to the customer. Because the Company’s performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of $36.4 million and $26.4 million as of December 31, 2019 (Successor) and 2018 (Predecessor), respectively, as “Accounts receivable” on the consolidated balance sheets. Substantially all of the Company’s revenues are derived from its single basin operations, the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. The following table disaggregates the Company’s revenues by major product, in order to depict how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company’s single basin operations, for the periods indicated (in thousands): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through Years Ended December 31, December 31, 2019 October 1, 2019 2018 2017 Operating revenues: Oil, natural gas and natural gas liquids sales: Oil $ 58,325 $ 145,024 $ 199,601 $ 340,674 Natural gas 1,719 107 6,791 16,194 Natural gas liquids 5,071 13,229 19,137 18,969 Total oil, natural gas and natural gas liquids sales 65,115 158,360 225,529 375,837 Other 467 743 1,080 2,128 Total operating revenues $ 65,582 $ 159,103 $ 226,609 $ 377,965 (1) The Company adopted ASC 606, “Revenue from Contracts with Customers” effective January 1, 2018 (Predecessor) using the modified retrospective approach under which prior period amounts have not been adjusted. Oil Sales The Company generally markets its crude oil production directly to the customer using two methods. Under the first method, crude oil is sold at the wellhead at an index price adjusted for pricing differentials and other deductions. Revenue is recognized at the wellhead, where control of the crude oil transfers to the customer, at the net price received. Under the second method, crude oil is delivered to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. The Company receives a specified index price from the customer, net of applicable market-related adjustments. Revenue is recognized when control of the crude oil transfers at the delivery point at the net price received. Settlement statements for the Company’s crude oil production are typically received within the month following the date of production and therefore the amount of production delivered to the customer and the price that will be received for that production are known at the time the revenue is recorded. Payment under the Company’s crude oil contracts is typically due on or before the 20 th of the month following the delivery month. Natural Gas and Natural Gas Liquids Sales The Company evaluates its natural gas gathering and processing arrangements in place with midstream companies to determine when control of the natural gas is transferred. Under contracts where it is determined that control of the natural gas transfers at the wellhead, any fees incurred to gather or process the unprocessed natural gas are treated as a reduction of the sales price of unprocessed natural gas, and therefore revenues from such transactions are presented on a net basis. Under contracts where it is determined that control of the natural gas transfers at the tailgate of the midstream entity’s processing plant, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third party purchasers through the gathering and treating process and presented as "Natural gas" or "Natural gas liquids" and any fees incurred to gather or process the natural gas are presented separately as “ Gathering and other " on the consolidated statement of operations. Under certain contracts, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees incurred to gather, process or transport the commodities are presented separately as “ Gathering and other " on the consolidated statement of operations. Settlement statements for the Company’s natural gas and natural gas liquids production are typically received 30 days after the date of production and therefore the Company estimates the amount of production delivered to the customer and the price that will be received for that production. Historically, differences between the Company’s estimates and the actual revenue received have not been material. Payment under the Company’s natural gas gathering and processing contracts is typically due on or before the fifth day of the second month following the delivery month. Practical Expedients The Company does not disclose the transaction price of unsatisfied performance obligations for i) contracts with an original expected duration of one year or less and ii) contracts where variable consideration is allocated entirely to a wholly unsatisfied performance obligation (each unit of product typically represents a separate performance obligation, and therefore, future volumes under the Company’s long-term contracts are wholly unsatisfied).

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2019
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES	6. ACQUISITIONS AND DIVESTITURES Acquisitions West Quito Draw Properties On February 6, 2018 (Predecessor), a wholly owned subsidiary of the Company entered into a Purchase and Sale Agreement (the Shell PSA) with SWEPI LP (Shell), an affiliate of Shell Oil Company, pursuant to which the Company purchased acreage and related assets in the Delaware Basin located in Ward County, Texas (the West Quito Draw Properties) for a total adjusted purchase price of $198.5 million. The effective date of the acquisition was February 1, 2018 (Predecessor), and the Company closed the transaction on April 4, 2018 (Predecessor). The Company funded the cash consideration for the acquisition of the West Quito Draw Properties with the net proceeds from the issuance of additional 6.75% senior notes due 2025 and common stock, which are discussed in Note 8, “ Long-term Debt ,” and Note 13, “ Stockholders’ Equity ,” respectively. Monument Draw Assets (Ward and Winkler Counties, Texas) On June 15, 2017 (Predecessor) and January 9, 2018 (Predecessor), the Company purchased acreage in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) that is prospective for the Wolfcamp and Bone Spring formations from a private company for $87.4 million and $108.2 million in cash, respectively. Acquisition of Additional Properties in Monument Draw (Ward and Winkler Counties, Texas) On December 13, 2017 (Predecessor), the Company acquired undeveloped acreage and related assets in the Delaware Basin, in an area contiguous to the western and southern areas of the Company’s existing Monument Draw properties in Ward County, Texas from a private company, for a total adjusted cash purchase price of $101.8 million. The effective date of the acquisition was September 1, 2017 (Predecessor). Hackberry Draw Assets (Pecos and Reeves Counties, Texas) On January 18, 2017 (Predecessor), a wholly owned subsidiary of the Company, entered into a Purchase and Sale Agreement with Samson Exploration, LLC (Samson), pursuant to which it agreed to acquire acreage and related assets in the Hackberry Draw area of the Delaware Basin, located in Pecos and Reeves Counties, Texas (collectively, the Pecos County Assets), for a total adjusted purchase price of $699.2 million (the Pecos County Acquisition). The Pecos County Acquisition closed on February 28, 2017 (Predecessor). The transaction had an effective date of November 1, 2016 (Predecessor). The Company funded the Pecos County Acquisition with the net proceeds from the private placement of new 8% automatically convertible preferred stock and borrowings under its Predecessor Credit Agreement. Refer to Note 13, “Stockholders’ Equity,” for further discussion of the Company’s issuance of the preferred stock. The Pecos County Acquisition was accounted for as a business combination in accordance with ASC 805, Business Combinations (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. The estimated fair value of the properties acquired approximates the fair value of consideration and as a result no goodwill was recognized. The following table summarizes the consideration paid to acquire the Pecos County Assets, as well as the estimated values of assets acquired and liabilities assumed as of the acquisition date (in thousands): Cash consideration paid to Samson at closing (1) $ 703,865 Less: Post-effective closing date adjustments (2) (4,677) Final consideration transferred $ 699,188 Plus: Estimated Fair Value of Liabilities Assumed: Current liabilities $ 839 Asset retirement obligations 2,116 Amount attributable to liabilities assumed 2,955 Total purchase price plus liabilities assumed $ 702,143 Estimated Fair Value of Assets Acquired: Evaluated oil and natural gas properties (3)(4) $ 188,275 Unevaluated oil and natural gas properties (3)(4) 487,489 Gas gathering and other operating assets (5) 26,379 Amount attributable to assets acquired $ 702,143 (1) Represents amount of cash consideration, adjusted for customary closing items, for the purchase of the Pecos County Assets funded by the issuance of approximately $400.1 million of new 8% automatically convertible preferred stock and borrowings under the Predecessor Credit Agreement. (2) In accordance with the purchase agreement, the effective date of the acquisition was November 1, 2016 (Predecessor) and therefore revenues, expenses and related capital expenditures from November 1, 2016 through February 28, 2017 (Predecessor), the closing date of the Pecos County Acquisition, have been reflected as adjustments to the purchase price consideration. (3) In estimating the fair value of the Pecos County Assets’ oil and natural gas properties, the Company used an income approach. For purposes of estimating the fair value of the proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Pecos County Assets’ estimated reserves risked by reserve category and discounted using a weighted average cost of capital rate of 10.0% for proved reserves and 12.0% for probable and possible reserves. The proved reserve locations were limited to wells expected to be drilled in the Company’s five-year development plan. This estimation includes the use of unobservable inputs, such as estimated future production, oil and natural gas revenues and expenses. The use of these unobservable inputs results in the fair value estimate of the Pecos County Assets being classified as Level 3. (4) Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $76.10 per barrel of oil, $4.14 per Mcf of natural gas and $29.48 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and research analysts’ estimated prices. (5) In estimating the fair value of the Pecos County Assets’ other operating property and equipment, the Company used a combination of the cost and market approaches. A market approach was relied upon to value the land, heavy equipment and vehicles, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and age of the assets. The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2017 (Predecessor) as though the Pecos County Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2016 (Predecessor). The pro forma combined results of operations for the year ended December 31, 2017 (Predecessor) have been prepared by adjusting the historical results of the Company to include the historical results of the Pecos County Assets. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined Company for the periods presented or that may be achieved by the combined Company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Pecos County Acquisition or any estimated costs that will be incurred to integrate the Pecos County Assets. Future results may vary significantly from the results reflected in this unaudited pro forma financial information because of future events and transactions, as well as other factors. Amounts included in the table below are rounded to thousands, except per share amounts. Predecessor Year Ended December 31, 2017 (Unaudited) Revenue $ 385,867 Net income (loss) 542,724 Net income (loss) available to common stockholders 494,717 Pro forma net income (loss) per share of common stock: Basic $ 3.73 Diluted $ 3.70 The Company’s historical financial information was adjusted to give effect to the pro forma events that are directly attributable to the Pecos County Assets and are factually supportable. The unaudited pro forma consolidated results include the historical revenues and expenses of assets acquired and liabilities assumed, with the following adjustments:  Adjustment to recognize incremental depletion expense under the full cost method of accounting based on the fair value of the oil and natural gas properties and incremental accretion expense based on the asset retirement costs of the oil and natural gas properties at acquisition;  Adjustment to recognize incremental depreciation expense of the other operating property and equipment and incremental accretion expense based on the asset retirement costs of the other operating property and equipment at acquisition; and  Eliminate transaction costs and non-recurring charges directly related to the transactions that were included in the historical results of operations for the Company in the amount of approximately $1.0 million. Transaction costs directly related to the transaction that do not have a continuing impact on the combined Company’s operating results have been excluded from the pro forma earnings. For the year ended December 31, 2017 (Predecessor), the Company recognized $46.2 million of oil, natural gas and natural gas liquids and other revenue related to the Pecos County Assets and $5.9 million of net field operating income (oil, natural gas and natural gas liquids and other revenues less lease operating expense, workover expense, production taxes, gathering and other expense, and depletion, depreciation and accretion expense) related to the Pecos County Assets. Additionally, non-recurring transaction costs of approximately $1.0 million related to the Pecos County Acquisition for the year ended December 31, 2017 (Predecessor) are included in the consolidated statements of operations in “ General and administrative” expenses; these non-recurring transaction costs have been excluded from the pro forma results in the above table. Divestitures Water Infrastructure Assets On December 20, 2018 (Predecessor), the Company sold its water infrastructure assets located in the Delaware Basin (the Water Assets) to WaterBridge Resources LLC (the Purchaser) for a total adjusted purchase price of $210.9 million in cash (the Water Infrastructure Divestiture). The effective date of the transaction was October 1, 2018 (Predecessor). Additional incentive payments of up to $25.0 million per year for the years from 2019 to 2023 were available based on the Company’s ability to meet certain annual incentive thresholds relating to the number of wells connected to the Water Assets per year. In August 2019 (Predecessor), the Company and the Purchaser agreed to terminate the incentive payments provision. Upon closing, the Company dedicated all of the produced water from its oil and natural gas wells within its Monument Draw, Hackberry Draw and West Quito Draw operating areas to the Purchaser. There were no drilling or throughput commitments associated with the Water Infrastructure Divestiture. The Purchaser will receive a market price, subject to annual adjustments for inflation, in exchange for the transportation, disposal and treatment of such produced water, and the Purchaser will receive a market price for the supply of freshwater and recycled produced water to the Company. During the year ended December 31, 2018 (Predecessor), the Company recorded a gain of $119.0 million on the sale of the Water Assets on the consolidated statements of operations in “(Gain) loss on sale of Water Assets.” The gain on the sale was increased by $0.5 million during the period of October 2, 2019 through December 31, 2019 (Successor) and reduced during the period of January 1, 2019 through October 1, 2019 (Predecessor) by approximately $3.6 million as a result of customary post-closing adjustments. Williston Basin Non-Operated Assets On September 19, 2017 (Predecessor), certain wholly owned subsidiaries of the Company entered into an agreement with a privately-owned company pursuant to which the Company sold its non-operated properties and related assets located in the Williston Basin in North Dakota and Montana (the Non-Operated Williston Assets) for a total adjusted sales price of approximately $103.4 million. The effective date of the transaction was April 1, 2017 (Predecessor) and the transaction closed on November 9, 2017 (Predecessor). Proceeds from the sale were recorded as a reduction to the carrying value of the Company’s full cost pool with no gain or loss recorded. Williston Basin Operated Assets On July 10, 2017 (Predecessor), the Company and certain of its subsidiaries entered into an agreement with Bruin Williston Holdings, LLC for the sale of all of the Company’s operated oil and natural gas leases, oil and natural gas wells and related assets located in the Williston Basin in North Dakota, as well as 100% of the membership interests in two of its subsidiaries (the Williston Assets) for a total adjusted sales price of approximately $1.4 billion (the Williston Divestiture). The effective date of the sale was June 1, 2017 (Predecessor) and the transaction closed on September 7, 2017 (Predecessor). The Company used the net proceeds from the sale to repay borrowings outstanding under its Predecessor Credit Agreement, repurchase approximately $425.0 million principal amount of the then outstanding $850 million principal amount of its 6.75% senior notes (refer to Note 8, “Long-term Debt”) , redeem all of its then outstanding 12% senior secured second lien notes due 2022 (the 2022 second lien notes) and for general corporate purposes. The Company recognized a loss on the extinguishment of the 2022 Second Lien Notes of approximately $29.2 million, representing a $23.0 million loss on the redemption for the make whole premium paid and a $6.2 million loss on the write-off of the discount on the 2022 Second Lien Notes. The loss was recorded in “Gain (loss) on extinguishment of debt” on the consolidated statements of operations. The net proceeds from the sale were allocated between the Company’s oil and natural gas properties, other operating property and equipment and liabilities transferred on a fair value basis. Approximately $1.39 billion was allocated to the Company’s oil and natural gas properties and approximately $10.9 million was allocated to other operating property and equipment. As discussed further in Note 7, “Oil and Natural Gas Properties,” the Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the Williston Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of the Williston Assets of $485.9 million during the year ended December 31, 2017 (Predecessor). This gain was reduced by $7.2 million during the year ended December 31, 2018 (Predecessor) as the result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in “Gain (loss) on the sale of oil and natural gas properties,” on the Company’s consolidated statements of operations. East Texas Eagle Ford Assets On January 24, 2017 (Predecessor), certain of the Company’s subsidiaries entered into an agreement with a subsidiary of Hawkwood Energy, LLC (Hawkwood) for the sale of all of the Company’s oil and natural gas properties and related assets located in the Eagle Ford formation of East Texas (the El Halcón Assets) for a total adjusted sales price of $491.1 million (the El Halcón Divestiture). The effective date of the sale was January 1, 2017 (Predecessor) and the transaction closed on March 9, 2017 (Predecessor). The Company used the net proceeds from the sale to repay borrowings outstanding under its Predecessor Credit Agreement and for general corporate purposes. The net proceeds from the sale were allocated between the Company’s oil and natural gas properties, other operating property and equipment and liabilities transferred on a fair value basis. Approximately $484.1 million was allocated to the Company’s oil and natural gas properties and $10.2 million was allocated to other operating property and equipment. Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the El Halcón Divestiture was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale in connection with this transaction of $235.7 million during the year ended December 31, 2017 (Predecessor). The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain was recorded in “Gain (loss) on sale of oil and natural gas properties,” on the Company’s consolidated statements of operations.

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	12 Months Ended
	Dec. 31, 2019
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES	7. OIL AND NATURAL GAS PROPERTIES Oil and natural gas properties as of December 31, 2019 (Successor) and 2018 (Predecessor) consisted of the following (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Subject to depletion $ 420,609 $ 1,470,509 Not subject to depletion: Exploration and extension wells in progress — 23,536 Other capital costs: Incurred in 2019 (1) 105,009 — Incurred in 2018 — 310,113 Incurred in 2017 — 638,269 Incurred in 2016 and prior — — Total not subject to depletion 105,009 971,918 Gross oil and natural gas properties 525,618 2,442,427 Less accumulated depletion (19,474) (639,951) Net oil and natural gas properties $ 506,144 $ 1,802,476 (1) In 2019, with the adoption of fresh-start accounting, the Company’s unevaluated properties were recorded at fair value. The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, treating equipment and gathering support facilities costs, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense. With the adoption of fresh-start accounting, the Company recorded its oil and natural gas properties at fair value as of the Emergence Date. The Company’s evaluated and unevaluated properties were assigned fair values of $380.4 million and $109.0 million, respectively. Refer to Note 3, “ Fresh-start Accounting ,” for a discussion of the valuation approaches used. The Successor Company’s policy of accounting for its treating equipment and gathering support facilities identifies these assets as part of the Company’s full cost pool due to their supporting nature to the Company’s oil and natural gas operations. The Company’s treating equipment and gathering support facilities were included in “ Oil and natural gas properties, evaluated ” on the consolidated balance sheet as of the Emergence Date. Refer to Note 3, “ Fresh-start Accounting ,” for a discussion of the valuation approaches used. Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation. For the three months ended June 30, 2019 (Predecessor), the Company transferred approximately $481.7 million of unevaluated property costs to the full cost pool, the majority of which were associated with the Company’s Hackberry Draw area. For the three months ended March 31, 2019 (Predecessor), the Company identified certain leases in the Hackberry Draw area with near-term expirations and transferred approximately $51.0 million of associated unevaluated property costs to the full cost pool. These transfers of unevaluated property to the full cost pool in 2019 were the result of the Company’s focus on its most economic area, Monument Draw. The ceiling test value of the Company’s reserves was calculated based on the following prices: West Texas (1) Henry Hub (1) December 31, 2019 $ 55.85 $ 2.578 December 31, 2018 65.56 3.100 December 31, 2017 51.34 2.976 (1) Unweighted average of the first day of the 12‑months ended spot price, adjusted by lease or field for quality, transportation fees and market differentials. The Company’s net book value of oil and natural gas properties at March 31, June 30, and September 30, 2019 (Predecessor) exceeded the ceiling amount and the Company recorded full cost ceiling test impairments before income taxes of $275.2 million, $664.4 million and $45.6 million, respectively, for the periods. The ceiling test impairments during 2019 (Predecessor) were driven by the transfers of unevaluated property to the full cost pool that occurred during the year, as discussed above, and decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculations. The Company’s net book value of oil and natural gas properties in 2018 and 2017 (Predecessor) did not exceed the ceiling amount. Full cost ceiling test impairments are recorded in “Full cost ceiling impairment” in the Company’s consolidated statements of operations and in “Accumulated depletion” in the Company’s consolidated balance sheets. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties to the full cost pool, capital spending, and other factors will determine the Company’s ceiling test calculation and impairment analyses in future periods. Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. If the El Halcón and Williston Divestitures were accounted for as adjustments of capitalized costs with no gain or loss recognized, the adjustments would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of the oil and natural gas properties associated with the El Halcón Divestiture of $235.7 million for the year ended December 31, 2017 (Predecessor). The Company recognized an initial gain on the sale of the Williston Assets of $485.9 million during the year ended December 31, 2017 (Predecessor). This gain was reduced by $7.2 million during the year ended December 31, 2018 (Predecessor) as the result of customary post-closing adjustments. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. The gain (loss) was recorded in “Gain (loss) on sale of oil and natural gas properties,” on the Company’s consolidated statements of operations.

LONG TERM DEBT

LONG TERM DEBT	12 Months Ended
	Dec. 31, 2019
LONG TERM DEBT
LONG TERM DEBT	8. LONG‑TERM DEBT Long‑term debt as of December 31, 2019 (Successor) and 2018 (Predecessor) consisted of the following (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Successor senior revolving credit facility $ 144,000 $ — 6.75% senior notes due 2025 (1) — 613,105 $ 144,000 $ 613,105 (1) The Company’s 6.75% senior notes due 2025 were cancelled on October 8, 2019 upon emergence from chapter 11 bankruptcy. Amount includes a $7.2 million unamortized discount at December 31, 2018 (Predecessor) associated with the 2025 Notes. Amount includes a $5.4 million unamortized premium at December 31, 2018 (Predecessor) associated with the Additional 2025 Notes. Additionally, these amounts are net of $10.1 million unamortized debt issuance costs at December 31, 2018 (Predecessor). Successor Senior Revolving Credit Facility On the Effective Date, the Company entered into a senior secured revolving credit agreement, as amended on November 21, 2019, (the Senior Credit Agreement) with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the DIP Facility and the Predecessor Credit Agreement, both discussed below. The Senior Credit Agreement provides for a $750.0 million senior secured reserve‑based revolving credit facility with a current borrowing base of $240.0 million. A portion of the Senior Credit Agreement, in the amount of $50.0 million, is available for the issuance of letters of credit. The maturity date of the Senior Credit Agreement is October 8, 2024. The first redetermination will be in the spring of 2020 and redeterminations will occur semi-annually thereafter, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bear interest at specified margins over the base rate of 1.00% to 2.00% for ABR-based loans or at specified margins over LIBOR of 2.00% to 3.00% for Eurodollar-based loans, which margins may be increased one-time by not more than 50 basis points per annum if necessary in order to successfully syndicate the Senior Credit Agreement, which is currently in process. These margins fluctuate based on the Company’s utilization of the facility. The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Credit Agreement without premium or penalty, except with respect to any break funding payments which may be payable pursuant to the terms of the Senior Credit Agreement. The Company may be required to make mandatory prepayments of the outstanding borrowings under the Senior Credit Agreement in connection with certain borrowing base deficiencies, including deficiencies which may arise in connection with a borrowing base redetermination, an asset disposition or swap terminations attributable in the aggregate to more than ten percent (10%) of the then-effective borrowing base. Amounts outstanding under the Senior Credit Agreement are guaranteed by the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Company and its subsidiaries. The Senior Credit Agreement contains certain events of default, including non-payment; breaches of representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Credit Agreement also contains certain financial covenants, including maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) of not greater than 3.50 to 1.00 and (ii) a Current Ratio (as defined in the Senior Credit Agreement) of not less than 1.00 to 1.00, both commencing with the fiscal quarter ending March 31, 2020. As of December 31, 2019, there were no financial covenants in effect under the Senior Credit Agreement. At December 31, 2019 (Successor), the Company had $144.0 million indebtedness outstanding, approximately $2.3 million letters of credit outstanding and approximately $93.7 million of borrowing capacity available under the Senior Credit Agreement. On November 21, 2019 (Successor), the Company entered into the First Amendment to the Senior Credit Agreement which, among other things, (i) reduced the borrowing base to $240.0 million and (ii) limited the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) as of the last day of each fiscal quarter, commencing with the fiscal quarter ending March 31, 2020, of not greater than 3.50 to 1.00. Debtor-in-Possession Financing In connection with the chapter 11 proceedings and pursuant to an order of the Bankruptcy Court dated August 9, 2019 (the Interim Order), the Predecessor Company entered into a Junior Secured Debtor-In-Possession Credit Agreement (the DIP Credit Agreement) with the Unsecured Senior Noteholders party thereto from time to time as lenders (the DIP Lenders) and Wilmington Trust, National Association, as administrative agent. Under the DIP Credit Agreement, the DIP Lenders made available a $35.0 million debtor-in-possession junior secured term credit facility (the DIP Facility), of which $25.0 million was extended as an initial loan and the remainder of which was drawn on September 5, 2019 (Predecessor). The DIP Facility was refinanced by the Senior Credit Agreement upon emergence from chapter 11 bankruptcy. The Predecessor Company used the proceeds of the DIP Facility to, among other things, (i) provide working capital and other general corporate purposes, including to finance capital expenditures and make certain interest payments as and to the extent set forth in the Interim Order and/or the final order, as applicable, of the Bankruptcy Court and in accordance with the Predecessor Company’s budget delivered pursuant to the DIP Credit Agreement, (ii) pay fees and expenses related to the transactions contemplated by the DIP Credit Agreement in accordance with such budget and (iii) cash collateralize any letters of credit. The DIP Loans bore interest at a rate per annum equal to (i) adjusted LIBOR plus an applicable margin of 5.50% or (ii) an alternative base rate plus an applicable margin of 4.50%, in each case, as selected by the Company. The DIP Facility was secured by (i) a junior secured perfected security interest on all assets that secured the Predecessor Credit Agreement (defined below) and (ii) a senior secured perfected security interest on all unencumbered assets of the Company and any subsidiary guarantors. The security interests and liens were further subject to certain carve-outs and permitted liens, as set forth in the DIP Credit Agreement. The DIP Credit Agreement contained certain customary (i) representations and warranties; (ii) affirmative and negative covenants, including delivery of financial statements; conduct of business; reserve reports; title information; indebtedness; liens; dividends and distributions; investments; sale or discount of receivables; mergers; sale of properties; termination of swap agreements; transactions with affiliates; negative pledges; dividend restrictions; gas imbalances; take-or-pay or other prepayments and swap agreements; and (iii) events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; dismissal (or conversion to chapter 7) of the chapter 11 proceedings; and failure to satisfy certain bankruptcy milestones. Predecessor Senior Revolving Credit Facility On September 7, 2017, the Predecessor Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Predecessor Credit Agreement) by and among the Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions party thereto, as lenders. Pursuant to the Predecessor Credit Agreement, the lenders party thereto agreed to provide the Company with a $1.0 billion senior secured reserve-based revolving credit facility with a borrowing base of $225.0 million as of October 1, 2019 (Predecessor). The maturity date of the Predecessor Credit Agreement was September 7, 2022. The borrowing base was redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base took into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Predecessor Credit Agreement bore interest at specified margins over the base rate of 1.75% to 2.75% for ABR-based loans or at specified margins over LIBOR of 2.75% to 3.75% for Eurodollar-based loans. These margins fluctuated based on the Company’s utilization of the facility. The Predecessor Credit Agreement was refinanced by the Senior Credit Agreement upon emergence from chapter 11 bankruptcy. 6.75% Senior Notes On February 16, 2017, the Predecessor Company issued $850.0 million aggregate principal amount of 6.75% senior notes due 2025 (the 2025 Notes) in a private placement exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (Securities Act), Rule 144A and Regulation S, and applicable state securities laws. The 2025 Notes were issued at par and bore interest at a rate of 6.75% per annum, payable semi‑annually on February 15 and August 15 of each year. The maturity date of the 2025 Notes was February 15, 2025. Proceeds from the private placement were approximately $834.1 million after deducting initial purchasers’ discounts and commissions and offering expenses. The Company used a portion of the net proceeds from the private placement to fund the repurchase and redemption of the then outstanding 8.625% senior secured second lien notes (the 2020 Second Lien Notes), and for general corporate purposes. Upon repurchase and redemption of the 2020 Second Lien Notes during the three months ended March 31, 2017, the Predecessor Company recorded a loss on extinguishment of debt of approximately $56.9 million, representing a $30.9 million loss on the repurchase for the tender premium paid and a $26.0 million loss on the write-off of the discount on the notes. The loss was recorded in “Gain (loss) on extinguishment of debt” on the consolidated statement of operations. On July 25, 2017, the Predecessor Company concluded a consent solicitation of the holders of the 2025 Notes (the Consent Solicitation) and obtained consents to amend the indenture governing the 2025 Notes from approximately 99% of the holders of the 2025 Notes. As supplemented, the indenture governing the 2025 Notes exempted, among other things, the Williston Divestiture from certain provisions triggered upon a sale of “all or substantially all of the assets” of the Company. Consenting holders of the 2025 Notes received a consent fee of 2.0% of principal, or $16.9 million. The Company recorded the $16.9 million consent fees paid as a discount on the 2025 Notes. On September 7, 2017, the Predecessor Company commenced an offer to purchase for cash up to $425.0 million of the $850.0 million outstanding aggregate principal amount of its 2025 Notes at 103.0% of principal plus accrued and unpaid interest. The consummation of the Williston Divestiture constituted a “Williston Sale” under the indenture governing the 2025 Notes, and the Company was required to make an offer to all holders of the 2025 Notes to purchase for cash an aggregate principal amount up to $425.0 million of the 2025 Notes. The offer to purchase expired on October 6, 2017, with notes representing in excess of $425.0 million of principal amount validly tendered. As a result, on October 10, 2017, the Predecessor Company repurchased approximately $425.0 million principal amount of the 2025 Notes on a pro rata basis at 103.0% of par plus accrued and unpaid interest of approximately $4.1 million. The Company recognized a loss on the extinguishment of debt of approximately $28.9 million, representing a $12.8 million loss on the repurchase for the tender premium paid, an $8.3 million loss on the write-off of the discount, and a $7.8 million loss on the write-off of the debt issuance costs on the notes repurchased. The loss was recorded in “Gain (loss) on extinguishment of debt” on the consolidated statements of operations. On February 15, 2018, the Predecessor Company issued an additional $200.0 million aggregate principal amount of its 2025 Notes at a price to the initial purchasers of 103.0% of par (the Additional 2025 Notes). The net proceeds from the sale of the Additional 2025 Notes were approximately $202.4 million after deducting initial purchasers’ premiums, commissions and estimated offering expenses. The proceeds were used to fund the cash consideration for the acquisition of the West Quito Draw Properties, discussed further in Note 6, "Acquisitions and Divestitures,” and for general corporate purposes, including to fund the Company’s 2018 drilling program. On the Petition Date, the 2025 Notes represented " Liabilities subject to compromise " and the corresponding discount of $6.6 million and premium of $4.9 million were written-off to " Reorganization items, net " on the consolidated statements of operations. On October 8, 2019, upon emergence from chapter 11 bankruptcy, the 2025 Notes were cancelled. The Company discontinued recording interest on the 2025 Notes as of the Petition Date. The contractual interest expense not accrued or recorded in the consolidated statement of operations was approximately $7.1 million, representing interest expense from the Petition Date through the Effective Date. Refer to Note 2, “ Reorganization ” for further details. Debt Maturities Aggregate maturities required on long-term debt at December 31, 2019 (Successor) due in future years are as follows (in thousands, excluding discounts, premiums and debt issuance costs): 2020 $ — 2021 — 2022 — 2023 — 2024 144,000 Thereafter — Total $ 144,000 Debt Issuance Costs The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. During the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company expensed to “Reorganization items, net” $9.3 million of debt issuance costs associated with its 2025 Notes, which were cancelled upon emergence from chapter 11 bankruptcy. During the period, the Company also expensed to “Interest expense and other” $0.7 million of debt issuance costs associated with its Predecessor Credit Agreement. At December 31, 2019 (Successor) and 2018 (Predecessor), the Company had zero and $11.1 million of unamortized debt issuance costs, respectively. The debt issuance costs for the Company’s Predecessor Credit Agreement were presented in “Funds in escrow and other ” within total assets on the consolidated balance sheet, and the debt issuance costs for the Predecessor Company’s senior unsecured debt were presented in “Long-term debt, net” within total liabilities on the consolidated balance sheet.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2019
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	9. FAIR VALUE MEASUREMENTS Pursuant to ASC 820, Fair Value Measurement (ASC 820), the Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. ASC 820 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 (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. As required by ASC 820, a financial instrument’s level within the fair value hierarchy is 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 fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2019 (Successor) and 2018 (Predecessor) (in thousands): Successor December 31, 2019 Level 1 Level 2 Level 3 Total Assets Assets from derivative contracts $ — $ 5,219 $ — $ 5,219 Liabilities Liabilities from derivative contracts $ — $ 12,923 $ — $ 12,923 Predecessor December 31, 2018 Level 1 Level 2 Level 3 Total Assets Assets from derivative contracts $ — $ 69,717 $ — $ 69,717 Liabilities Liabilities from derivative contracts $ — $ 12,907 $ — $ 12,907 Derivative contracts listed above as Level 2 include fixed-price swaps, collars, puts, calls, basis swaps and WTI NYMEX rolls that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 10, “Derivative and Hedging Activities,” for additional discussion of derivatives. The Company’s derivative contracts are with major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance. The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments . The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents and restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short‑term nature. The estimated fair value of the Company’s Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates. The following table presents the estimated fair values of the Company’s fixed interest rate, long‑term debt instruments as of December 31, 2019 (Successor) and 2018 (Predecessor) (excluding discounts, premiums and debt issuance costs) (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Principal Estimated Principal Estimated Debt Amount Fair Value Amount Fair Value 6.75% senior notes (1) $ — $ — $ 625,005 $ 458,210 (1) The 6.75% senior notes were cancelled on October 8, 2019 upon emergence from chapter 11 bankruptcy. The fair value of the Company’s fixed interest debt instruments was calculated using Level 1 criteria. The fair value of the Company’s senior notes is based on quoted market prices from trades of such debt. On the Effective Date, the Company emerged from chapter 11 bankruptcy and adopted fresh-start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh-start accounting, the Company’s assets, liabilities and warrants were recorded at their fair values as of the fresh-start reporting date, October 1, 2019. See Note 3, “Fresh-start Accounting,” for a detailed discussion of the fair value approaches used by the Company. On February 28, 2017 (Predecessor), the Company closed the Pecos County Acquisition and recorded the assets acquired and liabilities assumed at their acquisition date fair values. See Note 6, "Acquisitions and Divestitures,” for a discussion of the fair value approaches used by the Company and the classification of the estimates within the fair value hierarchy. The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non‑recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 11, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.

DERIVATIVE AND HEDGING ACTIVITI

DERIVATIVE AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2019
DERIVATIVE AND HEDGING ACTIVITIES
DERIVATIVE AND HEDGING ACTIVITIES	10. DERIVATIVE AND HEDGING ACTIVITIES The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. In accordance with the Company’s policy, it generally hedges a substantial, but varying, portion of anticipated oil, natural gas and natural gas liquids production for future periods. Derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company’s hedge policies and objectives may change significantly as its operational profile changes. The Company does not enter into derivative contracts for speculative trading purposes. It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of December 31, 2019 (Successor), the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s Senior Credit Agreement or are uncollateralized trades. The Company’s crude oil, natural gas and natural gas liquids derivative positions at any point in time may consist of fixed-price swaps, costless put/call collars, basis swaps and WTI NYMEX rolls. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price. Basis swaps effectively lock in a price differential between regional prices (i.e. Midland) where the product is sold and the relevant pricing index under which the oil production is hedged (i.e. Cushing). WTI NYMEX roll agreements account for pricing adjustments to the trade month versus the delivery month for contract pricing. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations. All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of December 31, 2019 (Successor) and 2018 (Predecessor) (in thousands): Derivatives not designated Asset derivative contracts Liability derivative contracts as hedging contracts under Successor Predecessor Successor Predecessor ASC 815 Balance sheet location December 31, 2019 December 31, 2018 Balance sheet location December 31, 2019 December 31, 2018 Commodity contracts Current assets - assets from derivative contracts $ 4,995 $ 57,280 Current liabilities - liabilities from derivative contracts $ (8,069) $ (3,768) Commodity contracts Other noncurrent assets - assets from derivative contracts 224 12,437 Other noncurrent liabilities - liabilities from derivative contracts (4,854) (9,139) Total derivatives not designated as hedging contracts under ASC 815 $ 5,219 $ 69,717 $ (12,923) $ (12,907) The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations (in thousands): Amount of gain or (loss) recognized in income on derivative contracts for the Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 Derivatives not designated as hedging Location of gain or (loss) recognized in through through Years Ended December 31, contracts under ASC 815 income on derivative contracts December 31, 2019 October 1, 2019 2018 2017 Commodity contracts: Unrealized gain (loss) on commodity contracts Other income (expenses) - net gain (loss) on derivative contracts $ (18,681) $ (45,834) $ 84,274 $ (16,468) Realized gain (loss) on commodity contracts Other income (expenses) - net gain (loss) on derivative contracts 1,989 11,502 8,351 17,759 Total net gain (loss) on derivative contracts $ (16,692) $ (34,332) $ 92,625 $ 1,291 At December 31, 2019 (Successor) and 2018 (Predecessor), the Company had the following open crude oil and natural gas derivative contracts: Successor December 31, 2019 Floors Ceilings Basis Differential Volume in Weighted Weighted Weighted Mmbtu's/ Price / Average Price / Average Price / Average Period Instrument Commodity Bbl's Price Range Price Price Range Price Price Range Price January 2020 - June 2020 Fixed-Price Swap Crude Oil 182,000 $ 55.74 $ 55.74 $ — $ — $ — $ — January 2020 - September 2020 Fixed-Price Swap Natural Gas 1,186,000 2.61 2.61 January 2020 - December 2020 Fixed-Price Swap Crude Oil 732,000 55.68 - 60.00 57.84 January 2020 - December 2020 Fixed-Price Swap Natural Gas 2,928,000 2.55 - 2.57 2.56 January 2020 - December 2020 Collar Crude Oil 549,000 50.00 50.00 70.00 70.00 January 2020 - December 2020 Call Crude Oil 2,342,400 70.00 70.00 January 2020 - December 2020 Put Crude Oil 915,000 55.00 55.00 January 2020 - December 2020 Basis Swap Crude Oil 1,464,000 0.67 - 0.85 0.72 January 2020 - December 2020 WTI NYMEX Roll Crude Oil 366,000 0.37 0.37 February 2020 - December 2020 WTI NYMEX Roll Crude Oil 1,340,000 0.41 - 0.54 0.44 April 2020 - December 2020 Basis Swap Crude Oil 275,000 0.75 0.75 January 2021 - December 2021 Fixed-Price Swap Crude Oil 1,460,000 50.70 - 52.80 51.91 January 2021 - December 2021 Fixed-Price Swap Natural Gas 2,190,000 2.47 - 2.48 2.47 January 2021 - December 2021 Basis Swap Crude Oil 1,460,000 0.82 - 0.95 0.85 January 2021 - December 2021 WTI NYMEX Roll Crude Oil 1,460,000 0.13 - 0.14 0.14 January 2022 - December 2022 Fixed-Price Swap Crude Oil 1,460,000 51.50 51.50 January 2022 - December 2022 Basis Swap Crude Oil 1,460,000 0.85 - 0.95 0.88 January 2022 - December 2022 WTI NYMEX Roll Crude Oil 2,555,000 (0.02) - 0.00 (0.01) Predecessor December 31, 2018 Floors Ceilings Basis Differential Volume in Weighted Weighted Weighted Mmbtu's/ Price / Average Price / Average Price / Average Period Instrument Commodity Bbl's Price Range Price Price Range Price Price Range Price January 2019 - March 2019 Calls Crude Oil 1,350,000 $ — $ — $ 62.64 $ 62.64 $ — $ — January 2019 - March 2019 Calls Crude Oil (1,350,000) 58.64 58.64 January 2019 - March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019 - June 2019 Collars Crude Oil 181,000 51.00 51.00 56.00 56.00 January 2019 - September 2019 Basis Swap Crude Oil 546,000 (6.20) - (7.60) (6.90) January 2019 - December 2019 Fixed-Price Swap Natural Gas Liquids 1,460,000 29.08 - 30.15 29.33 January 2019 - December 2019 Collars Crude Oil 3,650,000 50.00 - 58.00 53.87 55.20 - 63.00 60.07 January 2019 - December 2019 Collars Natural Gas 8,760,000 2.52 - 2.70 2.60 3.00 - 3.10 3.01 January 2019 - December 2019 Basis Swap Crude Oil 2,448,000 (0.98) - (6.50) (2.80) January 2019 - December 2019 Basis Swap Natural Gas 9,307,500 (1.05) - (1.40) (1.18) January 2019 - December 2019 WTI NYMEX Roll Crude Oil 1,825,000 0.35 0.35 April 2019 - June 2019 Collars Crude Oil 91,000 50.00 50.00 55.00 55.00 April 2019 - December 2019 Collars Crude Oil 275,000 55.00 55.00 62.85 62.85 July 2019 - December 2019 Collars Crude Oil 552,000 50.00 - 55.00 53.00 55.00 - 69.00 61.00 July 2019 - December 2019 Basis Swap Crude Oil 460,000 (2.40) - (6.50) (5.68) October 2019 - December 2019 Fixed-Price Swap Natural Gas Liquids 92,000 32.50 32.50 October 2019 - December 2019 Collars Crude Oil 92,000 51.00 51.00 56.00 56.00 October 2019 - December 2019 Basis Swap Crude Oil 460,000 3.45 - 4.00 3.72 January 2020 - December 2020 Collars Crude Oil 549,000 50.00 50.00 70.00 70.00 January 2020 - December 2020 Calls Crude Oil 2,342,400 70.00 70.00 January 2020 - December 2020 Puts Crude Oil 915,000 55.00 55.00 January 2020 - December 2020 Basis Swap Crude Oil 3,294,000 2.00 - 4.00 2.95 The Company presents the fair value of its derivative contracts at the gross amounts in the consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts at December 31, 2019 (Successor) and 2018 (Predecessor) (in thousands): Derivative Assets Derivative Liabilities Successor Predecessor Successor Predecessor Offsetting of Derivative Assets and Liabilities December 31, 2019 December 31, 2018 December 31, 2019 December 31, 2018 Gross amounts presented in the consolidated balance sheet $ 5,219 $ 69,717 $ (12,923) $ (12,907) Amounts not offset in the consolidated balance sheet (4,557) (10,263) 4,557 10,263 Net amount $ 662 $ 59,454 $ (8,366) $ (2,644) The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. The filing of the voluntary petitions for relief under chapter 11 of the Bankruptcy Code described in Note 2, " Reorganization ," constituted an event of default under the Company's derivatives contracts that gave the counterparties the option to terminate such contracts. Certain parties elected to terminate their contracts in August 2019 (Predecessor) and the Company received approximately $0.1 million to settle a portion of the outstanding positions while other positions were novated for fees totaling $0.5 million. The remaining derivative contracts, including the novated positions, were secured on a super-priority pari passu basis with the Company's Predecessor Credit Agreement during the bankruptcy process and remain in place following the Company's chapter 11 bankruptcy.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2019
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS	11. ASSET RETIREMENT OBLIGATIONS The Company records an asset retirement obligation (ARO) on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and accretion” expense in the consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis. The Company recorded the following activity related to its ARO liability (inclusive of the current portion) (in thousands): Liability for asset retirement obligations as of December 31, 2017 (Predecessor) $ 4,368 Liabilities settled and divested (1) (590) Additions 988 Acquisitions (1) 2,465 Accretion expense 329 Revisions in estimated cash flows (646) Liability for asset retirement obligations as of December 31, 2018 (Predecessor) $ 6,914 Liabilities settled and divested (1) (229) Additions 354 Accretion expense 307 Revisions in estimated cash flows 2,807 Liability for asset retirement obligations as of October 1, 2019 (Predecessor) $ 10,153 Fair Value Adjustment $ — Liability for asset retirement obligations as of October 1, 2019 (Successor) $ 10,153 Additions 293 Accretion expense 144 Liability for asset retirement obligations as of December 31, 2019 (Successor) $ 10,590 (1) See Note 6, “Acquisitions and Divestitures,” for additional information on the Company’s acquisition and divestiture activities.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2019
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES	12. COMMITMENTS AND CONTINGENCIES Commitments As of December 31, 2019 (Successor), the Company has an active drilling rig commitment of approximately $3.2 million that will be incurred during 2020. Termination of the active drilling rig commitment would require an early termination penalty of $2.6 million, which would be in lieu of paying the active drilling rig commitment of $3.2 million. As of December 31, 2019 (Successor), the Company has purchase commitments related to equipment of approximately $8.2 million that will be incurred during 2020. The Company has entered into various long-term gathering, transportation and sales contracts with respect to its oil and natural gas production from the Delaware Basin in West Texas. As of December 31, 2019 (Successor), the Company had in place three long-term crude oil contracts and 14 long-term natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from this area for periods ranging from one to twenty years from the date of first production. Contingencies On February 26, 2019 (Predecessor), a subsidiary of the Company was ordered to pay $9,107,054 in a judgment entered by The Court of Common Pleas of Mercer County, Pennsylvania in a litigation matter captioned Vodenichar, et al., v. Halcón Energy Properties, Inc. et al., No. 2013‑0512, arising from a dispute over whether the subsidiary complied with the terms of a letter of intent related to the leasing of acreage. The Court of Common Pleas of Mercer County, Pennsylvania marked the judgment as satisfied on February 3, 2020 (Successor) and the Company considers this contingency resolved. In addition to the matter described above, from time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of our business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company’s consolidated operating results, financial position or cash flows.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2019
INCOME TAXES
INCOME TAXES	14. INCOME TAXES Income tax benefit (provision) for the indicated periods is comprised of the following (in thousands): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through Years Ended December 31, December 31, 2019 October 1, 2019 2018 2017 Current: Federal $ — $ — $ — $ 5,000 State — — — — — — — 5,000 Deferred: Federal — 95,791 (95,791) — State — — — — — 95,791 (95,791) — Total income tax benefit (provision) $ — $ 95,791 $ (95,791) $ 5,000 The actual income tax benefit (provision) differs from the expected income tax benefit (provision) as computed by applying the United States federal corporate income tax rate of 21% for the period from October 2, 2019 through December 31, 2019 (Successor), the period from January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor) and 35% for the year ended December 31, 2017 (Predecessor), as follows (in thousands): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through Years Ended December 31, December 31, 2019 October 1, 2019 2018 2017 Expected tax benefit (provision) $ 2,196 $ 262,888 $ (29,767) $ (185,740) State income tax expense, net of federal benefit — — — (2,587) Stock-based compensation — (6,093) (350) — Change in state rate — — — (10,121) Capital loss — 271,248 — — Increase (reduction) in deferred tax asset — (9,287) (201,903) 95,907 Change in valuation allowance and related items (1,506) (186,851) 136,432 392,846 Attribute reduction (229,385) — — Tax Cuts and Jobs Act of 2017 — — — (280,874) Permanent adjustments (690) (7,241) (203) — Other — 512 — (4,431) Total income tax benefit (provision) $ — $ 95,791 $ (95,791) $ 5,000 The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Deferred noncurrent income tax assets: Net operating loss carry-forwards $ 46,382 $ 204,751 Built in loss adjustment Section 382 142,285 88,835 Capital loss carryforward 74,848 — Stock-based compensation expense — 8,509 Asset retirement obligations 2,224 1,011 Book-tax differences in property basis 200,478 — Unrealized hedging transactions 1,618 — Disallowed interest Section 163(j) 7,722 3,370 Basis difference in debt 2,142 — Operating lease liability 666 — Other 991 1,917 Gross deferred noncurrent income tax assets 479,356 308,393 Valuation allowance (478,690) (290,333) Deferred noncurrent income tax assets $ 666 $ 18,060 Deferred noncurrent income tax liabilities: Basis difference in debt $ — $ (5,507) Book-tax differences in property basis — (96,414) Unrealized hedging transactions — (11,930) Lease right of use (666) — Deferred noncurrent income tax liabilities $ (666) $ (113,851) Net noncurrent deferred income tax assets (liabilities) $ — $ (95,791) The Company emerged from Chapter 11 Bankruptcy on October 8, 2019. Under the Plan, a substantial portion of the Company’s pre-petition debt securities were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (CODI) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in bankruptcy may exclude CODI from taxable income but must first reduce its tax attributes by the amount any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from chapter 11 bankruptcy proceedings, U.S. CODI was approximately $524.8 million, which reduced the value of the Company’s net operating losses and capital losses on January 1, 2020. The deferred tax balances disclosed above reflect the estimated impact of the attribute reduction on January 1, 2020. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The Company's emergence from chapter 11 bankruptcy proceedings is considered a change in ownership for purposes of IRC Section 382. The limitation under the IRC is based on the value of the corporation as of the emergence date. The ownership changes and resulting annual limitation resulted in the expiration of approximately $454.2 million of net operating losses generated prior to the emergence date. The expiration of these tax attributes was fully offset by a corresponding decrease in the Company's U.S. valuation allowance, which results in no net tax provision. An additional ownership change was experienced in December 2018 (Predecessor). This ownership change and resulting annual limitation generated the estimated expiration of approximately $891.5 million of net operating loss. The expiration of these tax attributes was partially offset by a corresponding decrease in the Company’s U.S. valuation allowance, which resulted in a $95.8 million deferred tax expense placing the Company in a net deferred tax liability position. The amount of U.S. consolidated NOLs available as of December 31, 2019 (Successor) after attribute reduction is estimated to be approximately $675.1 million, but the amount after attribute reduction and the Section 382 limitation is $220.0 million.. Of this amount, $103.2 million is subject to the 20 year carryforward period and will expire in 2037. The remaining $117.7 million may be carried forward indefinitely but in part subject to a Section 382 limitation. The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. The Company evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment. As a result of the Company’s analysis, it was concluded that as of December 31, 2019 (Successor), a valuation allowance should continue to be applied against the Company’s net deferred tax asset. The Company recorded a valuation allowance as of December 31, 2019 (Successor) of $478.7 million, an increase of $188.4 million from December 31, 2018 (Predecessor). The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized. ASC 740, Income Taxes (ASC 740) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more‑likely‑than‑not to be sustained upon examination by taxing authorities. The Company has no unrecognized tax benefits for the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor), the years ended December 31, 2018 (Predecessor). Generally, the Company’s income tax years 2016 through 2019 remain open for federal purposes and are subject to examination by Federal tax authorities. The Company's income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statue expiration period for federal purposes. The Company recognizes interest and penalties accrued to unrecognized benefits in “Interest expense and other” in its consolidated statements of operations. For the period of October 2, 2019 through December 31, 2019 (Successor), the period of January 1, 2019 through October 1, 2019 (Predecessor), the years ended December 31, 2018 (Predecessor), the Company recognized no interest and penalties.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2019
EARNINGS PER SHARE
EARNINGS PER SHARE	15. EARNINGS PER SHARE On October 8, 2019, upon emergence from chapter 11 bankruptcy, the Predecessor Company’s equity was cancelled and new equity was issued. Refer to Note 2, “Reorganization,” for further details. The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through Years Ended December 31, December 31, 2019 October 1, 2019 2018 2017 Basic: Net income (loss) available to common stockholders $ (10,460) $ (1,156,053) $ 45,959 $ 487,679 Weighted average basic number of common shares outstanding 16,204 158,925 157,011 132,763 Basic net income (loss) per common share $ (0.65) $ (7.27) $ 0.29 $ 3.67 Diluted: Net income (loss) available to common stockholders $ (10,460) $ (1,156,053) $ 45,959 $ 487,679 Weighted average basic number of common shares outstanding 16,204 158,925 157,011 132,763 Common stock equivalent shares representing shares issuable upon: Exercise of Predecessor stock options — Anti-dilutive Anti-dilutive Anti-dilutive Exercise of Predecessor warrants — Anti-dilutive Anti-dilutive Anti-dilutive Conversion of Predecessor preferred stock — — — Anti-dilutive Vesting of Predecessor restricted shares — Anti-dilutive 284 813 Exercise of Successor Series A Warrants Anti-dilutive — — — Exercise of Successor Series B Warrants Anti-dilutive — — — Exercise of Successor Series C Warrants Anti-dilutive — — — Weighted average diluted number of common shares outstanding 16,204 158,925 157,295 133,576 Diluted net income (loss) per common share $ (0.65) $ (7.27) $ 0.29 $ 3.65 Common stock equivalents, including warrants, totaling 6.9 million shares for the period of October 2, 2019 through December 31, 2019 (Successor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss. Common stock equivalents, including stock options, restricted shares and warrants totaling 14.1 million shares for the period of January 1, 2019 through October 1, 2019 (Predecessor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss. Common stock equivalents, including stock options, restricted shares and warrants totaling 13.1 million shares for the year ended December 31, 2018 (Predecessor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive. Common stock equivalents, including stock options, restricted shares, warrants, and preferred stock totaling 17.1 million shares for the year ended December 31, 2017 (Predecessor) were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive. On February 20, 2020 the Successor Company granted under the 2020 Plan stock options and restricted stock units to purchase or receive an aggregate of 1.3 million shares of common stock.

ADDITIONAL FINANCIAL STATEMENT

ADDITIONAL FINANCIAL STATEMENT INFORMATION	12 Months Ended
	Dec. 31, 2019
ADDITIONAL FINANCIAL STATEMENT INFORMATION
ADDITIONAL FINANCIAL STATEMENT INFORMATION	16. ADDITIONAL FINANCIAL STATEMENT INFORMATION Certain balance sheet amounts are comprised of the following (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Accounts receivable, net: Oil, natural gas and natural gas liquids revenues $ 36,367 $ 26,432 Joint interest accounts 10,145 7,369 Other 1,992 1,917 $ 48,504 $ 35,718 Prepaids and other: Prepaids $ 2,093 $ 3,503 Income tax receivable 1,250 1,250 Funds in escrow 4,000 — Other 36 35 $ 7,379 $ 4,788 Funds in escrow and other: Funds in escrow $ 580 $ 570 Other 123 1,611 $ 703 $ 2,181 Accounts payable and accrued liabilities: Trade payables $ 36,038 $ 68,959 Accrued oil and natural gas capital costs 22,781 41,461 Revenues and royalties payable 25,457 20,526 Accrued interest expense 604 16,971 Accrued employee compensation 2,947 3,421 Accrued lease operating expenses 9,230 6,292 Other 276 218 $ 97,333 $ 157,848

SUMMARY OF SIGNIFICANT EVENTS_2

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2019
SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation Battalion Oil Corporation (Battalion or the Company) is the successor reporting company to Halcón Resources Corporation (Halcón). On January 21, 2020, Battalion filed a Certificate of Amendment to the Company’s Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Halcón Resources Corporation to Battalion Oil Corporation. Battalion is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids‑rich oil and natural gas assets in the United States. The consolidated financial statements include the accounts of all majority‑owned, controlled subsidiaries. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. Allocation of capital is made across the Company’s entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. The Company has evaluated events and transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements.
Emergence from Voluntary Reorganization under Chapter 11	Emergence From Voluntary Reorganization Under Chapter 11 On August 7, 2019 (the Petition Date), the Company and its subsidiaries filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (the Bankruptcy Court) to pursue a prepackaged plan of reorganization (the Plan). The Company’s chapter 11 proceedings were administered under the caption In re Halcón Resources Corporation, et al. (Case No. 19-34446). On September 24, 2019, the Bankruptcy Court entered an order confirming the Plan and on October 8, 2019, the Plan became effective (the Effective Date) and the Company emerged from chapter 11 bankruptcy. See Note 2, “ Reorganization, ” for further details on the Company’s chapter 11 bankruptcy and the Plan. Upon emergence from chapter 11 bankruptcy, the Company adopted fresh-start accounting in accordance with provisions of the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852) which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. The Company elected to apply fresh-start accounting effective October 1, 2019, to coincide with the timing of its normal fourth quarter reporting period, which resulted in the Company becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2019 and October 8, 2019 were immaterial and use of an accounting convenience date of October 1, 2019 was appropriate. As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2019 (Successor) and related reorganization adjustments and fresh-start adjustments are included in the accompanying statement of operations for the period from January 1, 2019 through October 1, 2019 (Predecessor). Upon the adoption of fresh-start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh-start reporting date. As a result of the adoption of fresh-start accounting, the Company’s consolidated financial statements subsequent to October 1, 2019 are not comparable to its consolidated financial statements prior to, and including, October 1, 2019. See Note 3, “Fresh-start Accounting,” for further details on the impact of fresh-start accounting on the Company’s consolidated financial statements. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to October 1, 2019. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, October 1, 2019.
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 requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, fair value estimates, including estimates of Reorganization Value, Enterprise Value and the fair value of assets and liabilities recorded as a result of the adoption of fresh-start accounting, plus the estimated fair values of assets acquired and liabilities assumed in connection with the Pecos County Acquisition and the fair value of assets sold in connection with the Williston Divestiture and the El Halcón Divestiture (see Note 6, “Acquisitions and Divestitures,” for information on the Pecos County Acquisition, the Williston Divestiture and the El Halcón Divestiture), including the gains on sales recorded, and income taxes. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. Amounts in the consolidated balance sheets included in cash, cash equivalents and restricted cash on the Company’s consolidated statement of cash flows are as follows: Successor Predecessor December 31, 2019 December 31, 2018 Cash and cash equivalents $ 5,701 $ 46,866 Restricted cash 4,574 — Total cash, cash equivalents and restricted cash $ 10,275 $ 46,866 Restricted Cash consists of funds related to payments prescribed under the Plan that are held in an interest-bearing escrow account.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. As of December 31, 2019 (Successor) and 2018 (Predecessor), allowances for doubtful accounts were approximately $0.1 million and $0.2 million, respectively.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company uses the full cost method of accounting for its investment in oil and natural gas properties as prescribed by the United States Securities and Exchange Commission (SEC). Accordingly, all costs incurred in the acquisition, exploration and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, treating equipment and gathering support facilities, dry holes, geophysical costs, and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on estimated proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company reviews its unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The Company determines capitalized interest, when applicable, by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The Company’s accounting policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization.
Other Operating Property and Equipment	Other Operating Property and Equipment Other operating property and equipment additions are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: buildings, twenty years; automobiles and computers, three years; computer software, fixtures, furniture and equipment, the lesser of lease term or five years; trailers, seven years; heavy equipment, eight to ten years and leasehold improvements, lease term. Land and artwork are not depreciated. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. Refer to Note 3, “ Fresh-start Accounting,” for a discussion of the valuation approach used to record other operating property and equipment at fair value as of October 1, 2019. Refer to Note 6, “Acquisitions and Divestitures,” for a discussion of other operating property and equipment acquired and divested. The Company reviews its other operating property and equipment for impairment in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate other operating property and equipment for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its other operating property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods.
Concentrations of Credit Risk	Concentrations of Credit Risk The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts. For the combined periods of October 2, 2019 through December 31, 2019 (Successor), and January 1, 2019 through October 1, 2019 (Predecessor), two individual purchasers of our production, Western Refining Inc. and Sunoco Inc., each accounted for more than 10% of total sales, collectively representing 80% of our total sales for the period. For the year ended December 31, 2018 (Predecessor), two individual purchasers of the Company’s production, Sunoco, Inc. and Western Refining, Inc., each accounted for more than 10% of total sales, collectively representing 77% of the Company’s total sales for the year. In 2017 (Predecessor), two individual purchasers of the Company’s production, Crestwood Midstream Partners and Suncor Energy Marketing, Inc., each accounted for more than 10% of total sales, collectively representing 58% of the Company’s total sales for the year. The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected.
Risk Management Activities	Risk Management Activities The Company follows ASC 815, Derivatives and Hedging (ASC 815). From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted oil, natural gas, and natural gas liquids production. The Company recognized all derivative instruments as either assets or liabilities in the consolidated balance sheets at fair value. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark‑to‑market valuation of these positions, as well as payments and receipts on settled contracts, in “ Net gain (loss) on derivative contracts ” on the consolidated statements of operations.
Income Taxes	Income Taxes The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets. The Company follows ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the consolidated financial statements. The evaluation of a tax position in accordance with ASC 740 is a two‑step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement. The Company has no liability for unrecognized tax benefits as of December 31, 2019 (Successor) and 2018 (Predecessor). Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2019 (Successor), 2018 (Predecessor) and 2017 (Predecessor). In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months. The Company includes interest and penalties relating to uncertain tax positions within “ Interest expense and other ” on the Company’s consolidated statements of operations. Refer to Note 14, “ Income Taxes, ” for more details. Generally, the Company’s income tax years 2016 through 2019 remain open for federal purposes and are subject to examination by Federal tax authorities. No claims were filed with respect to any historical income tax periods that caused any challenge to the Plan. The Company’s income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statue expiration period for federal purposes. Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates.
Asset Retirement Obligations	Asset Retirement Obligations ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells, treating equipment and gathering support facilities. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, treating equipment and gathering support facilities as these obligations are incurred.
Leases	Leases Effective January 1, 2019 (Predecessor), the Company accounts for leases in accordance with ASC 842, Leases (ASC 842). The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of identified asset for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset, and (2) the customer has the right to control the use of the identified asset. The Company leases equipment and office space pursuant to net operating leases. Operating leases where the Company is the lessee are included in “Operating lease right of use assets” and “Operating lease liabilities” on the consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the unpaid lease payments at the lease commencement date. Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments. ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The incremental borrowing rate for a lease is the rate of interest the Company would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. Additionally, the Company applies a portfolio approach to determine the discount rate (the incremental borrowing rate for leases with similar characteristics). The Company uses the implicit rate when readily determinable. The lease term includes the noncancellable period of the lease plus any additional periods covered by either a lessee option to extend (or not to terminate) the lease that the lessee is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. Lease payments included in the measurement of the lease asset or liability comprise the following, when applicable: fixed payments (including in‑substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if the lessee is reasonably certain to exercise. The right of use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For the Company’s operating leases, the right of use asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight‑line basis over the lease term. Variable lease payments associated with the Company’s leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as “Gathering and other” or “General and administrative” in the consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases. The Company has lease agreements which include lease and nonlease components and the Company has elected to combine lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. The Company determines whether the lease or nonlease component is the predominant component on a case‑by‑case basis. The Company reviews its right of use assets for impairment in accordance with ASC 360. ASC 360 requires the Company to evaluate right of use assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. The Company monitors for events or changes in circumstances that would require a reassessment of a lease. When a reassessment results in the remeasurement of a lease liability, an adjustment is made to the carrying amount of the corresponding right of use asset unless doing so would reduce the carrying amount of the right of use asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative right of use asset balance is recorded in the consolidated statements of operations. The Company elected not to recognize right of use assets and lease liabilities for all short‑term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short‑term leases as an expense on a straight‑line basis over the lease term. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases.
Restructuring	Restructuring During 2019 (both in Successor and Predecessor periods), senior executives of the Company resigned from their positions. These were considered terminations without cause under their respective employment agreements, which entitled them to certain benefits. Additionally during the third quarter of 2019 (Predecessor), the Company made the decision to consolidate into one corporate office located in Houston, Texas in an effort to improve efficiencies and go forward costs. The transition includes both severance and relocation costs as well as incremental costs associated with hiring new employees to replace key positions. Consequently, for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company incurred approximately $1.2 million and $15.1 million, respectively, in costs which were recorded in “Restructuring” on the consolidated statements of operations.
401(k) Plan	401(k) Plan The Company sponsors a 401(k) tax deferred savings plan, whereby the Company matches a portion of employees’ contributions in cash. Participation in the plan is voluntary and all employees of the Company who are 18 years of age are eligible to participate. The Company provided matching contributions of $0.2 million and $1.1 million for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor), respectively. The Company provided matching contributions of $1.5 million and $2.2 million for the years ended December 31, 2018 and 2017 (Predecessor), respectively. The Company matches employee contributions dollar-for-dollar on the first 10% of an employee’s pre‑tax earnings, subject to individual IRS limitations.
Related Party Transactions	Related Party Transactions Crude Oil Gathering Agreement On July 27, 2018 (Predecessor), a subsidiary of the Company entered into a crude oil gathering agreement with SCM Crude, LLC (SCM) pursuant to which the Company agreed to dedicate, for a term of 15 years, production of crude oil from its currently owned, or later acquired, acreage in designated areas in Ward and Winkler Counties, Texas (excluding certain specific wells) for the receipt, gathering and transportation on a gathering system to be designed, engineered and constructed by SCM. For the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company recorded revenue $101.6 million and $13.0 million, respectively, from SCM under the crude oil gathering agreement. As of December 31, 2018 (Predecessor), the Company recorded a $10.9 million receivable from SCM for its crude oil sales. Certain funds under the control of Ares Management LLC (Ares) are the majority owners and controlling parties of SCM. Ares also controls other funds which owned in excess of ten percent (10%) of the common stock of the Company prior to the Effective Date of the Plan. No Ares fund that was a stockholder of the Company had an interest in SCM but one of the Company’s former directors, who is employed by Ares, also serves on the board of directors of SCM’s parent company. As of the Effective Date, SCM is no longer a related party to the Successor Company. Gas Purchase and Processing Agreement On November 16, 2017 (Predecessor), a subsidiary of the Company entered into a gas purchase and processing agreement with Salt Creek Midstream, LLC (Salt Creek) pursuant to which the Company agreed to dedicate for a term of 15 years, all production from its acreage in Ward County, Texas (that is not otherwise previously dedicated) and certain sections in Winkler County, Texas to a natural gas gathering pipeline and processing facilities to be constructed by Salt Creek. For the period of January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company recorded revenue of $6.0 million and $0.4 million, respectively, from Salt Creek under the gas purchase and processing agreement. As of December 31, 2018 (Predecessor), the Company had no receivables outstanding from Salt Creek. Certain funds under the control of Ares are the majority owners and controlling parties of Salt Creek. Ares also controls other funds which owned in excess of ten percent (10%) of the stock of the Company prior to the Effective Date of the Plan. No Ares fund that was a stockholder of the Company had an interest in Salt Creek but one of the Company’s former directors, who is employed by Ares, also serves on the board of directors of Salt Creek. As of the Effective Date, Salt Creek is no longer a related party to the Successor Company. Pipeline Testing Services In February 2019 (Predecessor), the Company entered into an agreement with Cima Inspection LLC (Cima), a company specializing in advanced, non-destructive methods of testing pipes and tubing, pursuant to which Cima will inspect various Company gathering and transportation assets. One of the Company's former directors (as of the Effective Date of the Plan) owns a minority interest in Cima and serves as its chief executive officer. For the period of January 1, 2019 through October 1, 2019 (Predecessor), the Company incurred charges of approximately $0.9 million for services provided by Cima. As of the Effective Date, Cima is no longer a related party to the Successor Company. Charter of Aircraft In the ordinary course of business, the Company occasionally chartered a private aircraft for business use. The Company’s former Chairman, Chief Executive Officer and President indirectly owns an aircraft that the Company chartered from time to time. During 2018 and a portion of 2017 (Predecessor), fees for the use of the Company’s former Chairman, Chief Executive Officer and President’s aircraft by the Company were based upon comparable costs that the Company would have incurred in chartering the same type and size of aircraft from an independent third party utilizing data from several independent third party aircraft leasing companies. In the first quarter of 2019 (Predecessor), the Company terminated all charter arrangements with the Company’s former Chairman, Chief Executive Officer and President relating to the use of his aircraft. During the period of January 1, 2019 to October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor), the Company paid approximately $0.2 million and $0.9 million, respectively, related to use of the aircraft indirectly owned by the Company’s former Chairman, Chief Executive Officer and President during 2018. As of December 31, 2018 (Predecessor), the Company recorded a $0.2 million payable to the Company’s former Chairman, Chief Executive Officer and President.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842) (ASU 2016-02). For public business entities, ASU 2016-02 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. The FASB issued ASU 2016-02 to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The Company adopted ASU 2016-02 effective January 1, 2019 using the modified retrospective approach as of the adoption date. See “Leases” above and Note 4, “Leases,” below for further details. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326) (ASU 2016-13), which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. ASU 2016-13 will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted. The Company adopted ASU 2016-13 effective January 1, 2020 using the modified retrospective approach as of the adoption date. The adoption will not have a material impact on the Company’s operating results, financial position or disclosures. In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (ASU 2019-12) as part of their simplification initiative. ASU 2019-12 simplifies the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance. ASU 2019-12 is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. The Company is currently evaluating the effects of ASU 2019-12, but does not believe that it will have a material impact on its operating results, financial position or disclosures

SUMMARY OF SIGNIFICANT EVENTS_3

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2019
SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES
Schedule Of Cash, Cash Equivalents And Restricted Cash	Successor Predecessor December 31, 2019 December 31, 2018 Cash and cash equivalents $ 5,701 $ 46,866 Restricted cash 4,574 — Total cash, cash equivalents and restricted cash $ 10,275 $ 46,866

FRESH-START ACCOUNTING (Tables)

FRESH-START ACCOUNTING (Tables)	12 Months Ended
	Dec. 31, 2019
FRESH-START ACCOUNTING
Schedule of Enterprise value to estimated fair value of the Successor's common stock	The following table reconciles the Company’s Enterprise Value to the estimated fair value of the Successor’s common stock as of October 1, 2019 (in thousands): October 1, 2019 Enterprise Value $ 441,583 Plus: Cash 15,546 Less: Fair value of debt (130,000) Less: Fair value of warrants (7,336) Fair Value of Successor common stock $ 319,793
Schedule of Enterprise Value to its Reorganization Value	The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of October 1, 2019 (in thousands): October 1, 2019 Enterprise Value $ 441,583 Plus: Cash 15,546 Plus: Current liabilities 122,134 Plus: Lease liabilities 3,395 Plus: Noncurrent asset retirement obligation 10,153 Plus: Other noncurrent liabilities 1,625 Reorganization Value of Successor assets $ 594,436
Schedule of reorganization balance sheet and fresh-start accounting adjustments	Amounts included in the table below are rounded to thousands. As of October 1, 2019 Predecessor Reorganization Fresh-Start Successor Current assets: Cash and cash equivalents $ 17,009 $ (1,463) (1) $ — $ 15,546 Accounts receivable, net 37,826 — — 37,826 Assets from derivative contracts 15,310 — — 15,310 Restricted cash — 13,839 (2) — 13,839 Prepaids and other 14,642 7,110 (3) (11,462) (11) 10,290 Total current assets 84,787 19,486 (11,462) 92,811 Oil and natural gas properties (full cost method): Evaluated 2,155,288 — (1,774,924) (12)(13) 380,364 Unevaluated 438,365 — (329,411) (13) 108,954 Gross oil and natural gas properties 2,593,653 — (2,104,335) 489,318 Less - accumulated depletion (1,709,719) — 1,709,719 (13) — Net oil and natural gas properties 883,934 — (394,616) 489,318 Other operating property and equipment: Other operating property and equipment 203,373 — (199,718) (12)(14) 3,655 Less - accumulated depreciation (14,416) — 14,416 (14) — Net other operating property and equipment 188,957 — (185,302) 3,655 Other noncurrent assets: Assets from derivative contracts 4,120 — — 4,120 Operating lease right of use assets 3,694 — (300) (15) 3,394 Funds in escrow and other 1,138 — — 1,138 Total assets $ 1,166,630 $ 19,486 $ (591,680) $ 594,436 Current liabilities: Accounts payable and accrued liabilities $ 112,578 $ 2,727 (4) $ — $ 115,305 Liabilities from derivative contracts 6,829 — — 6,829 Current portion of long-term debt, net 258,234 (258,234) (5) — — Operating lease liabilities 1,337 — (424) (15) 913 Total current liabilities 378,978 (255,507) (424) 123,047 Long-term debt, net — 130,000 (6) — 130,000 Liabilities subject to compromise 625,005 (625,005) (7) — — Other noncurrent liabilities: Liabilities from derivative contracts 1,625 — — 1,625 Asset retirement obligations 10,153 — — 10,153 Operating lease liabilities 2,438 — 44 (15) 2,482 Commitments and contingencies Stockholders' equity: Common Stock (Predecessor) 16 (16) (8) — — Common Stock (Successor) — 2 (9) — 2 Additional paid-in capital (Predecessor) 1,087,441 (1,087,441) (8) — — Additional paid-in capital (Successor) — 327,127 (9) — 327,127 Retained earnings (accumulated deficit) (939,026) 1,530,326 (10) (591,300) (16) — Total stockholders' equity 148,431 769,998 (591,300) 327,129 Total liabilities and stockholders' equity $ 1,166,630 $ 19,486 $ (591,680) $ 594,436 Reorganization adjustments 1) The table below details cash payments as of October 1, 2019, pursuant to the terms of the Plan described in Note 2, “ Reorganization, ” (in thousands): Sources: Proceeds from Senior Noteholder Rights Offering $ 150,150 Proceeds from Senior Credit Agreement 130,000 Proceeds from Existing Equity Interests Rights Offering 5,779 Total Sources $ 285,929 Uses: Payment of Predecessor Credit Agreement principal, accrued interest, and fees $ (226,580) Payment of DIP Facility principal and accrued interest (35,174) Funding of professional fee escrow and cash collateral account (13,839) Payment of debt issuance costs on Senior Credit Agreement (8,764) Payment of professional fees and other (3,035) Total Uses $ (287,392) Total Sources and Uses $ (1,463) 2) Reflects the funding of an escrow account for professional fees associated with the chapter 11 bankruptcy and an account to cash collateralize the Predecessor Company’s outstanding letters of credit. 3) Represents $10.2 million in debt issuance costs related to the Senior Credit Agreement, partially offset by the release of $3.1 million in fees paid to the Company’s restructuring advisors prior to the emergence from chapter 11 bankruptcy. 4) Represents $7.7 million in fees to be paid to the Company’s restructuring advisors subsequent to the Company’s emergence from chapter 11 bankruptcy, partially offset by payments of i) payments of accrued interest and fees on the Predecessor Credit Agreement and the DIP Facility of $3.5 million and ii) professional fees associated with the chapter 11 bankruptcy of $1.5 million. 5) On the Emergence Date, in accordance with the Plan, the Company repaid the principal outstanding on the Predecessor Credit Agreement of $223.2 million and the DIP Facility of $35.0 million using proceeds from the Equity Rights Offerings and borrowings under the Senior Credit Agreement. 6) Reflects the initial borrowing on the Senior Credit Agreement. 7) Liabilities subject to compromise were as follows (in thousands): 6.75% senior notes due 2025 $ 625,005 Liabilities subject to compromise 625,005 Discount on shares issued per the Senior Noteholder Subscription Rights Offering (67,840) Issuance of common stock to Class 4 claimholders (75,388) Gain on settlement of liabilities subject to compromise $ 481,777 8) Reflects the cancellation of Predecessor common stock and additional paid-in capital. 9) The following table reconciles reorganization adjustments made to Successor common stock and additional paid-in capital (in thousands): Par value of 16,203,940 shares of new common stock issued to holders of senior note claims and existing equity interest claims (valued at $19.74 per share) $ 2 Fair Value of warrants issued to holder of the Existing Equity Interests (1) 7,336 Additional paid-in-capital (Successor) 322,294 Equity issuance costs associated with Equity Rights Offering (2,503) Total change in Successor common stock and additional paid-in capital $ 327,129 (1) The fair value of the warrants was estimated using a Binomial Lattice model with the following assumptions: implied stock price of the Successor Company of $19.74; initial strike price per share of $40.17, $48.28, and $60.45, for Series A, B, and C warrants, respectively, increased each month at an annualized rate of 6.75%; expected volatility of 45%; and risk free interest rate using the USD Yield Curve at each time-step in the lattice. 10) The table below reflects the cumulative effect of the adjustments discussed above (in thousands): Gain on settlement of liabilities subject to compromise $ 481,777 Success fees incurred upon emergence (8,376) Fair value of equity issued to Predecessor common stockholders (7,449) Fair value of warrants issued to Predecessor common stockholders (7,336) Issuance of common stock to backstop commitment parties (13,079) Other (2,668) Cancellation of Predecessor Company equity 1,087,457 Net impact to retained earnings (accumulated deficit) $ 1,530,326 Fresh-start accounting adjustments 11) Adjustment reflects the write-off of debt issuance costs associated with the Senior Credit Agreement of $10.2 million and the write-off of prepaid expenses related to $1.2 million of premiums for the Predecessor Company’s directors and officers’ insurance policy. 12) Includes the reclassification of treating equipment and gathering support facilities from “Other operating property and equipment” to “Oil and natural gas properties, evaluated.” The Successor Company’s policy of accounting for its treating equipment and gathering support facilities identifies these assets as part of the Company’s full cost pool due to their supporting nature to the Company’s oil and natural gas operations. 13) Reflects the adjustment to fair value of the Company’s oil and natural gas properties and unproved acreage, as well as the elimination of accumulated depletion. In estimating the fair value of its oil and natural gas properties, the Company used a combination of the income and market approaches. For purposes of estimating the fair value of the Company’s proved reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company’s reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 10.0%. The proved reserve locations were limited to wells expected to be drilled in the Company’s five year development plan. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $71.51 per barrel of oil, $3.37 per MMBtu of natural gas and $29.50 per barrel of natural gas liquids. Base pricing was derived from an average of forward strip prices and analysts’ estimated prices. In estimating the fair value of the Company’s unproved acreage, a market approach was used in which a review of recent transactions involving properties in the same geographical location indicated the fair value of the Company’s unproved acreage from a market participant perspective. 14) Reflects the adjustment to fair value of the Company’s other operating property and equipment, as well as the elimination of accumulated depreciation. For purposes of estimating the fair value of its other operating property and equipment, the Company used a combination of the market and cost approaches. A market approach was relied upon to value land and vehicles, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and age of the assets. 15) Upon adoption of fresh start accounting, the Company’s lease obligations were recalculated using the incremental borrowing rate applicable to the Company upon emergence from chapter 11 bankruptcy and commensurate with its new capital structure. The incremental borrowing rate used decreased from 4.83% in the Predecessor period to 3.70% in the Successor period. Additionally represents the removal of right-of-use assets and lease liabilities associated with the Company’s compressors, as the remaining contract term of the compressor leases were less than one year as of the Effective Date. See Note 4, “Leases,” for details associated with the Company’s short-term lease costs. 16) Reflects the cumulative effect of the fresh-start accounting adjustments discussed above.
Schedule of net cash payments pursuant to the terms of the Reorganization Plan	1) The table below details cash payments as of October 1, 2019, pursuant to the terms of the Plan described in Note 2, “ Reorganization, ” (in thousands): Sources: Proceeds from Senior Noteholder Rights Offering $ 150,150 Proceeds from Senior Credit Agreement 130,000 Proceeds from Existing Equity Interests Rights Offering 5,779 Total Sources $ 285,929 Uses: Payment of Predecessor Credit Agreement principal, accrued interest, and fees $ (226,580) Payment of DIP Facility principal and accrued interest (35,174) Funding of professional fee escrow and cash collateral account (13,839) Payment of debt issuance costs on Senior Credit Agreement (8,764) Payment of professional fees and other (3,035) Total Uses $ (287,392) Total Sources and Uses $ (1,463)
Summary of liabilities subject to compromise	1) Liabilities subject to compromise were as follows (in thousands): 6.75% senior notes due 2025 $ 625,005 Liabilities subject to compromise 625,005 Discount on shares issued per the Senior Noteholder Subscription Rights Offering (67,840) Issuance of common stock to Class 4 claimholders (75,388) Gain on settlement of liabilities subject to compromise $ 481,777
Schedule Of Reconciliation Of Reorganization Adjustments Made To Common Stock And Additional Paid In Capital	1) The following table reconciles reorganization adjustments made to Successor common stock and additional paid-in capital (in thousands): Par value of 16,203,940 shares of new common stock issued to holders of senior note claims and existing equity interest claims (valued at $19.74 per share) $ 2 Fair Value of warrants issued to holder of the Existing Equity Interests (1) 7,336 Additional paid-in-capital (Successor) 322,294 Equity issuance costs associated with Equity Rights Offering (2,503) Total change in Successor common stock and additional paid-in capital $ 327,129
Schedule of cumulative effect of the reorganization adjustments	1) The table below reflects the cumulative effect of the adjustments discussed above (in thousands): Gain on settlement of liabilities subject to compromise $ 481,777 Success fees incurred upon emergence (8,376) Fair value of equity issued to Predecessor common stockholders (7,449) Fair value of warrants issued to Predecessor common stockholders (7,336) Issuance of common stock to backstop commitment parties (13,079) Other (2,668) Cancellation of Predecessor Company equity 1,087,457 Net impact to retained earnings (accumulated deficit) $ 1,530,326
Schedule of the net reorganization items	The following table summarizes the net reorganization items (in thousands): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through December 31, 2019 October 1, 2019 Gain on settlement of liabilities subject to compromise $ — $ 481,777 Fresh start adjustments — (591,300) Gain on adjustment of prepetition liabilities subject to compromise to the allowed claims amount — 20,274 Write-off debt discount/premium and debt issuance costs — (10,953) Reorganization professional fees and other (3,298) (16,922) Gain (loss) on reorganization items $ (3,298) $ (117,124)

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2019
Schedule of Company's leases	The table below summarizes the Company’s leases for the period of October 2, 2019 through December 31, 2019 (Successor) and the period of January 1, 2019 through October 1, 2019 (Predecessor) (in thousands, except years and discount rate): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through December 31, 2019 October 1, 2019 Lease cost Operating lease costs $ 260 $ 1,932 Short-term lease costs 4,408 12,262 Variable lease costs 215 1,210 Total lease costs $ 4,883 $ 15,404 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 254 $ 1,936 Right-of-use assets obtained in exchange for new operating lease liabilities 3,394 5,462 Weighted-average remaining lease term - operating leases 3.5 years 3.7 years Weighted-average discount rate - operating leases 3.70 % 4.83 %
Schedule of future minimum lease payments associated with the Company’s non-cancellable operating leases for office space and equipment	Future minimum lease payments associated with the Company’s non-cancellable operating leases for office space and equipment as of December 31, 2019 (Successor), are presented in the table below (in thousands): Successor December 31, 2019 2020 $ 1,022 2021 876 2022 574 2023 585 2024 345 Thereafter — Total operating lease payments 3,402 Less: discount to present value 232 Total operating lease liabilities 3,170 Less: current operating lease liabilities 923 Noncurrent operating lease liabilities $ 2,247
Schedule of future obligations, including variable nonlease components, associated with the Company's non-cancellable operating leases for office space and equipment	Prior to the adoption of ASC 842, future obligations, including variable nonlease components, associated with the Company’s non-cancellable operating leases for office space and equipment as of December 31, 2018 (Predecessor), are presented in the table below (in thousands): Predecessor December 31, 2018 2019 $ 3,792 2020 2,350 2021 1,899 2022 968 2023 999 Thereafter 599 Total operating lease payments $ 10,607
Accounting Standards Update 2016-02 Leases
Schedule of impact of adoption on the Company’s unaudited condensed consolidated balance sheet	The table below details the impact of adoption on the Company’s unaudited condensed consolidated balance sheet as of January 1, 2019 (Predecessor) (in thousands): Predecessor December 31, 2018 Impact of adoption January 1, 2019 Other noncurrent assets: Operating lease right of use assets $ — $ 5,462 $ 5,462 Current liabilities: Accounts payable and accrued liabilities $ 157,848 $ (85) $ 157,763 Operating lease liabilities — 2,103 2,103 Other noncurrent liabilities: Operating lease liabilities — 3,444 3,444

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables)	12 Months Ended
	Dec. 31, 2019
OPERATING REVENUES
Schedule of disaggregation of revenues by major product	The following table disaggregates the Company’s revenues by major product, in order to depict how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company’s single basin operations, for the periods indicated (in thousands): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through Years Ended December 31, December 31, 2019 October 1, 2019 2018 2017 Operating revenues: Oil, natural gas and natural gas liquids sales: Oil $ 58,325 $ 145,024 $ 199,601 $ 340,674 Natural gas 1,719 107 6,791 16,194 Natural gas liquids 5,071 13,229 19,137 18,969 Total oil, natural gas and natural gas liquids sales 65,115 158,360 225,529 375,837 Other 467 743 1,080 2,128 Total operating revenues $ 65,582 $ 159,103 $ 226,609 $ 377,965 (1) The Company adopted ASC 606, “Revenue from Contracts with Customers” effective January 1, 2018 (Predecessor) using the modified retrospective approach under which prior period amounts have not been adjusted.

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2019
ACQUISITIONS AND DIVESTITURES
Summary of the consideration paid for acquisition and the estimated values of assets acquired and liabilities assumed	The following table summarizes the consideration paid to acquire the Pecos County Assets, as well as the estimated values of assets acquired and liabilities assumed as of the acquisition date (in thousands): Cash consideration paid to Samson at closing (1) $ 703,865 Less: Post-effective closing date adjustments (2) (4,677) Final consideration transferred $ 699,188 Plus: Estimated Fair Value of Liabilities Assumed: Current liabilities $ 839 Asset retirement obligations 2,116 Amount attributable to liabilities assumed 2,955 Total purchase price plus liabilities assumed $ 702,143 Estimated Fair Value of Assets Acquired: Evaluated oil and natural gas properties (3)(4) $ 188,275 Unevaluated oil and natural gas properties (3)(4) 487,489 Gas gathering and other operating assets (5) 26,379 Amount attributable to assets acquired $ 702,143 (1) Represents amount of cash consideration, adjusted for customary closing items, for the purchase of the Pecos County Assets funded by the issuance of approximately $400.1 million of new 8% automatically convertible preferred stock and borrowings under the Predecessor Credit Agreement. (2) In accordance with the purchase agreement, the effective date of the acquisition was November 1, 2016 (Predecessor) and therefore revenues, expenses and related capital expenditures from November 1, 2016 through February 28, 2017 (Predecessor), the closing date of the Pecos County Acquisition, have been reflected as adjustments to the purchase price consideration. (3) In estimating the fair value of the Pecos County Assets’ oil and natural gas properties, the Company used an income approach. For purposes of estimating the fair value of the proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Pecos County Assets’ estimated reserves risked by reserve category and discounted using a weighted average cost of capital rate of 10.0% for proved reserves and 12.0% for probable and possible reserves. The proved reserve locations were limited to wells expected to be drilled in the Company’s five-year development plan. This estimation includes the use of unobservable inputs, such as estimated future production, oil and natural gas revenues and expenses. The use of these unobservable inputs results in the fair value estimate of the Pecos County Assets being classified as Level 3. (4) Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $76.10 per barrel of oil, $4.14 per Mcf of natural gas and $29.48 per barrel of oil equivalent of natural gas liquids, after adjustment for transportation fees and regional price differentials. Base pricing was derived from an average of forward strip prices and research analysts’ estimated prices. (5) In estimating the fair value of the Pecos County Assets’ other operating property and equipment, the Company used a combination of the cost and market approaches. A market approach was relied upon to value the land, heavy equipment and vehicles, and in this valuation approach, recent transactions of similar assets were utilized to determine the value from a market participant perspective. For the remaining other operating assets, a cost approach was used. The estimation of fair value under the cost approach was based on current replacement costs of the assets, less depreciation based on the estimated economic useful lives of the assets and age of the assets.
Schedule of pro forma financial information	Amounts included in the table below are rounded to thousands, except per share amounts. Predecessor Year Ended December 31, 2017 (Unaudited) Revenue $ 385,867 Net income (loss) 542,724 Net income (loss) available to common stockholders 494,717 Pro forma net income (loss) per share of common stock: Basic $ 3.73 Diluted $ 3.70

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2019
OIL AND NATURAL GAS PROPERTIES
Schedule of oil and natural gas properties	Oil and natural gas properties as of December 31, 2019 (Successor) and 2018 (Predecessor) consisted of the following (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Subject to depletion $ 420,609 $ 1,470,509 Not subject to depletion: Exploration and extension wells in progress — 23,536 Other capital costs: Incurred in 2019 (1) 105,009 — Incurred in 2018 — 310,113 Incurred in 2017 — 638,269 Incurred in 2016 and prior — — Total not subject to depletion 105,009 971,918 Gross oil and natural gas properties 525,618 2,442,427 Less accumulated depletion (19,474) (639,951) Net oil and natural gas properties $ 506,144 $ 1,802,476 In 2019, with the adoption of fresh-start accounting, the Company’s unevaluated properties were recorded at fair value.
Schedule of the Company's Oil and Natural Gas prices used in the calculation of the ceiling test value of the Company's reserves	West Texas (1) Henry Hub (1) December 31, 2019 $ 55.85 $ 2.578 December 31, 2018 65.56 3.100 December 31, 2017 51.34 2.976 (1) Unweighted average of the first day of the 12‑months ended spot price, adjusted by lease or field for quality, transportation fees and market differentials.

LONG TERM DEBT (Tables)

LONG TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2019
LONG TERM DEBT
Schedule of debt	Long‑term debt as of December 31, 2019 (Successor) and 2018 (Predecessor) consisted of the following (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Successor senior revolving credit facility $ 144,000 $ — 6.75% senior notes due 2025 (1) — 613,105 $ 144,000 $ 613,105 (1) The Company’s 6.75% senior notes due 2025 were cancelled on October 8, 2019 upon emergence from chapter 11 bankruptcy. Amount includes a $7.2 million unamortized discount at December 31, 2018 (Predecessor) associated with the 2025 Notes. Amount includes a $5.4 million unamortized premium at December 31, 2018 (Predecessor) associated with the Additional 2025 Notes. Additionally, these amounts are net of $10.1 million unamortized debt issuance costs at December 31, 2018 (Predecessor).
Schedule of aggregate maturities required on long-term debt	Aggregate maturities required on long-term debt at December 31, 2019 (Successor) due in future years are as follows (in thousands, excluding discounts, premiums and debt issuance costs): 2020 $ — 2021 — 2022 — 2023 — 2024 144,000 Thereafter — Total $ 144,000

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
FAIR VALUE MEASUREMENTS
Schedule of fair value of the Company's financial assets and liabilities	The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2019 (Successor) and 2018 (Predecessor) (in thousands): Successor December 31, 2019 Level 1 Level 2 Level 3 Total Assets Assets from derivative contracts $ — $ 5,219 $ — $ 5,219 Liabilities Liabilities from derivative contracts $ — $ 12,923 $ — $ 12,923 Predecessor December 31, 2018 Level 1 Level 2 Level 3 Total Assets Assets from derivative contracts $ — $ 69,717 $ — $ 69,717 Liabilities Liabilities from derivative contracts $ — $ 12,907 $ — $ 12,907
Schedule of the estimated fair values of the Company's fixed interest rate debt instruments	The following table presents the estimated fair values of the Company’s fixed interest rate, long‑term debt instruments as of December 31, 2019 (Successor) and 2018 (Predecessor) (excluding discounts, premiums and debt issuance costs) (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Principal Estimated Principal Estimated Debt Amount Fair Value Amount Fair Value 6.75% senior notes (1) $ — $ — $ 625,005 $ 458,210

DERIVATIVE AND HEDGING ACTIVI_2

DERIVATIVE AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2019
DERIVATIVE AND HEDGING ACTIVITIES
Summary of location and fair value of derivative contracts	The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of December 31, 2019 (Successor) and 2018 (Predecessor) (in thousands): Derivatives not designated Asset derivative contracts Liability derivative contracts as hedging contracts under Successor Predecessor Successor Predecessor ASC 815 Balance sheet location December 31, 2019 December 31, 2018 Balance sheet location December 31, 2019 December 31, 2018 Commodity contracts Current assets - assets from derivative contracts $ 4,995 $ 57,280 Current liabilities - liabilities from derivative contracts $ (8,069) $ (3,768) Commodity contracts Other noncurrent assets - assets from derivative contracts 224 12,437 Other noncurrent liabilities - liabilities from derivative contracts (4,854) (9,139) Total derivatives not designated as hedging contracts under ASC 815 $ 5,219 $ 69,717 $ (12,923) $ (12,907)
Summary of the location and amounts of the Company's realized and unrealized gains and losses on derivative contracts	The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations (in thousands): Amount of gain or (loss) recognized in income on derivative contracts for the Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 Derivatives not designated as hedging Location of gain or (loss) recognized in through through Years Ended December 31, contracts under ASC 815 income on derivative contracts December 31, 2019 October 1, 2019 2018 2017 Commodity contracts: Unrealized gain (loss) on commodity contracts Other income (expenses) - net gain (loss) on derivative contracts $ (18,681) $ (45,834) $ 84,274 $ (16,468) Realized gain (loss) on commodity contracts Other income (expenses) - net gain (loss) on derivative contracts 1,989 11,502 8,351 17,759 Total net gain (loss) on derivative contracts $ (16,692) $ (34,332) $ 92,625 $ 1,291
Schedule of open derivative contracts	At December 31, 2019 (Successor) and 2018 (Predecessor), the Company had the following open crude oil and natural gas derivative contracts: Successor December 31, 2019 Floors Ceilings Basis Differential Volume in Weighted Weighted Weighted Mmbtu's/ Price / Average Price / Average Price / Average Period Instrument Commodity Bbl's Price Range Price Price Range Price Price Range Price January 2020 - June 2020 Fixed-Price Swap Crude Oil 182,000 $ 55.74 $ 55.74 $ — $ — $ — $ — January 2020 - September 2020 Fixed-Price Swap Natural Gas 1,186,000 2.61 2.61 January 2020 - December 2020 Fixed-Price Swap Crude Oil 732,000 55.68 - 60.00 57.84 January 2020 - December 2020 Fixed-Price Swap Natural Gas 2,928,000 2.55 - 2.57 2.56 January 2020 - December 2020 Collar Crude Oil 549,000 50.00 50.00 70.00 70.00 January 2020 - December 2020 Call Crude Oil 2,342,400 70.00 70.00 January 2020 - December 2020 Put Crude Oil 915,000 55.00 55.00 January 2020 - December 2020 Basis Swap Crude Oil 1,464,000 0.67 - 0.85 0.72 January 2020 - December 2020 WTI NYMEX Roll Crude Oil 366,000 0.37 0.37 February 2020 - December 2020 WTI NYMEX Roll Crude Oil 1,340,000 0.41 - 0.54 0.44 April 2020 - December 2020 Basis Swap Crude Oil 275,000 0.75 0.75 January 2021 - December 2021 Fixed-Price Swap Crude Oil 1,460,000 50.70 - 52.80 51.91 January 2021 - December 2021 Fixed-Price Swap Natural Gas 2,190,000 2.47 - 2.48 2.47 January 2021 - December 2021 Basis Swap Crude Oil 1,460,000 0.82 - 0.95 0.85 January 2021 - December 2021 WTI NYMEX Roll Crude Oil 1,460,000 0.13 - 0.14 0.14 January 2022 - December 2022 Fixed-Price Swap Crude Oil 1,460,000 51.50 51.50 January 2022 - December 2022 Basis Swap Crude Oil 1,460,000 0.85 - 0.95 0.88 January 2022 - December 2022 WTI NYMEX Roll Crude Oil 2,555,000 (0.02) - 0.00 (0.01) Predecessor December 31, 2018 Floors Ceilings Basis Differential Volume in Weighted Weighted Weighted Mmbtu's/ Price / Average Price / Average Price / Average Period Instrument Commodity Bbl's Price Range Price Price Range Price Price Range Price January 2019 - March 2019 Calls Crude Oil 1,350,000 $ — $ — $ 62.64 $ 62.64 $ — $ — January 2019 - March 2019 Calls Crude Oil (1,350,000) 58.64 58.64 January 2019 - March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019 - June 2019 Collars Crude Oil 181,000 51.00 51.00 56.00 56.00 January 2019 - September 2019 Basis Swap Crude Oil 546,000 (6.20) - (7.60) (6.90) January 2019 - December 2019 Fixed-Price Swap Natural Gas Liquids 1,460,000 29.08 - 30.15 29.33 January 2019 - December 2019 Collars Crude Oil 3,650,000 50.00 - 58.00 53.87 55.20 - 63.00 60.07 January 2019 - December 2019 Collars Natural Gas 8,760,000 2.52 - 2.70 2.60 3.00 - 3.10 3.01 January 2019 - December 2019 Basis Swap Crude Oil 2,448,000 (0.98) - (6.50) (2.80) January 2019 - December 2019 Basis Swap Natural Gas 9,307,500 (1.05) - (1.40) (1.18) January 2019 - December 2019 WTI NYMEX Roll Crude Oil 1,825,000 0.35 0.35 April 2019 - June 2019 Collars Crude Oil 91,000 50.00 50.00 55.00 55.00 April 2019 - December 2019 Collars Crude Oil 275,000 55.00 55.00 62.85 62.85 July 2019 - December 2019 Collars Crude Oil 552,000 50.00 - 55.00 53.00 55.00 - 69.00 61.00 July 2019 - December 2019 Basis Swap Crude Oil 460,000 (2.40) - (6.50) (5.68) October 2019 - December 2019 Fixed-Price Swap Natural Gas Liquids 92,000 32.50 32.50 October 2019 - December 2019 Collars Crude Oil 92,000 51.00 51.00 56.00 56.00 October 2019 - December 2019 Basis Swap Crude Oil 460,000 3.45 - 4.00 3.72 January 2020 - December 2020 Collars Crude Oil 549,000 50.00 50.00 70.00 70.00 January 2020 - December 2020 Calls Crude Oil 2,342,400 70.00 70.00 January 2020 - December 2020 Puts Crude Oil 915,000 55.00 55.00 January 2020 - December 2020 Basis Swap Crude Oil 3,294,000 2.00 - 4.00 2.95
Schedule of potential effects of master netting arrangements on the fair value of derivative contracts	The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts at December 31, 2019 (Successor) and 2018 (Predecessor) (in thousands): Derivative Assets Derivative Liabilities Successor Predecessor Successor Predecessor Offsetting of Derivative Assets and Liabilities December 31, 2019 December 31, 2018 December 31, 2019 December 31, 2018 Gross amounts presented in the consolidated balance sheet $ 5,219 $ 69,717 $ (12,923) $ (12,907) Amounts not offset in the consolidated balance sheet (4,557) (10,263) 4,557 10,263 Net amount $ 662 $ 59,454 $ (8,366) $ (2,644)

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2019
ASSET RETIREMENT OBLIGATIONS
Schedule of activity related to ARO liability	The Company recorded the following activity related to its ARO liability (inclusive of the current portion) (in thousands): Liability for asset retirement obligations as of December 31, 2017 (Predecessor) $ 4,368 Liabilities settled and divested (1) (590) Additions 988 Acquisitions (1) 2,465 Accretion expense 329 Revisions in estimated cash flows (646) Liability for asset retirement obligations as of December 31, 2018 (Predecessor) $ 6,914 Liabilities settled and divested (1) (229) Additions 354 Accretion expense 307 Revisions in estimated cash flows 2,807 Liability for asset retirement obligations as of October 1, 2019 (Predecessor) $ 10,153 Fair Value Adjustment $ — Liability for asset retirement obligations as of October 1, 2019 (Successor) $ 10,153 Additions 293 Accretion expense 144 Liability for asset retirement obligations as of December 31, 2019 (Successor) $ 10,590 See Note 6, “Acquisitions and Divestitures,” for additional information on the Company’s acquisition and divestiture activities.

STOCKHOLDERS' EQUITY (Tables)

STOCKHOLDERS' EQUITY (Tables)	12 Months Ended
	Dec. 31, 2019
STOCKHOLDERS' EQUITY
Schedule of the stock option transactions	Number Weighted Aggregate (1) (In thousands) Weighted Average Outstanding at December 31, 2016 (Predecessor) 5,319,400 $ 9.22 $ 631 9.7 Granted 1,790,605 7.72 Exercised — — Forfeited (374,102) 8.82 Outstanding at December 31, 2017 (Predecessor) 6,735,903 $ 8.84 $ 29 8.9 Granted 1,206,800 5.65 Exercised (41,667) 7.75 29 Forfeited (432,110) 8.68 Outstanding at December 31, 2018 (Predecessor) 7,468,926 $ 8.34 $ — 8.1 Granted — — Exercised — — Forfeited (5,182,238) 8.38 Cancelled (2) (2,286,688) 8.26 Outstanding at October 1, 2019 (Predecessor) — $ — $ — — Outstanding at October 1, 2019 (Successor) — Granted — Exercised — Forfeited — Outstanding at December 31, 2019 (Successor) — $ — $ — — (1) The period end intrinsic value of stock options was calculated as the amount by which the closing market price on December 31, 2018, 2017 and 2016 (Predecessor) of the underlying stock exceeded the exercise price of the option. The intrinsic value of stock options exercised during the year ended December 31, 2018 (Predecessor) was calculated as the amount by which the market price at the time of exercise of the underlying stock exceeded the exercise price of the option. (2) Immediately prior to emergence from chapter 11 bankruptcy, all outstanding options under the 2016 Plan were cancelled.
Schedule of assumptions used in calculating fair value of the Company's stock-based compensation	Predecessor Years Ended December 31, 2018 2017 Weighted average value per option granted during the period $ 2.92 $ 4.36 Assumptions : Stock price volatility (1) 52.08 % 60.18 % Risk free rate of return 2.63 % 1.94 % Expected term 6 years 6 years (1) Due to the Predecessor Company’s limited historical data, expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available.
Schedule of the restricted stock transactions	The following table sets forth the restricted stock transactions for the periods indicated: Number of Weighted Aggregate (1) (In thousands) Unvested outstanding shares at December 31, 2016 (Predecessor) 1,738,077 $ 9.06 $ 16,234 Granted 2,022,432 7.07 Vested (2,516,647) 8.39 Forfeited (498,355) 7.41 Unvested outstanding shares at December 31, 2017 (Predecessor) 745,507 $ 7.05 $ 5,643 Granted 2,326,961 5.47 Vested (537,411) 5.89 Forfeited (262,164) 6.29 Unvested outstanding shares at December 31, 2018 (Predecessor) 2,272,893 $ 5.80 $ 3,864 Granted 4,163,348 1.29 Vested (1,611,465) 4.65 Accelerated vesting (2) (2,724,086) 2.07 Forfeited (2,100,690) 2.58 Unvested outstanding shares at October 1, 2019 (Predecessor) — $ — $ — Unvested outstanding shares at October 1, 2019 (Successor) — Granted — Vested — Forfeited — Unvested outstanding shares at December 31, 2019 (Successor) — $ — $ — (1) The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2018, 2017 and 2016 (Predecessor) of the underlying stock multiplied by the number of restricted shares. The total fair value of shares vested was $1.8 million, $2.0 million and $16.1 million for the period of January 1, 2019 through October 1, 2019 (Predecessor), the years ended December 31, 2018 and 2017 (Predecessor), respectively. Immediately prior to emergence from chapter 11 bankruptcy, all outstanding unvested restricted stock under the 2016 Plan was vested

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2019
INCOME TAXES
Schedule of income tax benefit (provision)	Income tax benefit (provision) for the indicated periods is comprised of the following (in thousands): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through Years Ended December 31, December 31, 2019 October 1, 2019 2018 2017 Current: Federal $ — $ — $ — $ 5,000 State — — — — — — — 5,000 Deferred: Federal — 95,791 (95,791) — State — — — — — 95,791 (95,791) — Total income tax benefit (provision) $ — $ 95,791 $ (95,791) $ 5,000
Schedule of differences between the actual income tax benefit (provision) and the expected income tax benefit (provision)	The actual income tax benefit (provision) differs from the expected income tax benefit (provision) as computed by applying the United States federal corporate income tax rate of 21% for the period from October 2, 2019 through December 31, 2019 (Successor), the period from January 1, 2019 through October 1, 2019 (Predecessor) and the year ended December 31, 2018 (Predecessor) and 35% for the year ended December 31, 2017 (Predecessor), as follows (in thousands): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through Years Ended December 31, December 31, 2019 October 1, 2019 2018 2017 Expected tax benefit (provision) $ 2,196 $ 262,888 $ (29,767) $ (185,740) State income tax expense, net of federal benefit — — — (2,587) Stock-based compensation — (6,093) (350) — Change in state rate — — — (10,121) Capital loss — 271,248 — — Increase (reduction) in deferred tax asset — (9,287) (201,903) 95,907 Change in valuation allowance and related items (1,506) (186,851) 136,432 392,846 Attribute reduction (229,385) — — Tax Cuts and Jobs Act of 2017 — — — (280,874) Permanent adjustments (690) (7,241) (203) — Other — 512 — (4,431) Total income tax benefit (provision) $ — $ 95,791 $ (95,791) $ 5,000
Schedule of components of net deferred income tax assets (liabilities)	The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Deferred noncurrent income tax assets: Net operating loss carry-forwards $ 46,382 $ 204,751 Built in loss adjustment Section 382 142,285 88,835 Capital loss carryforward 74,848 — Stock-based compensation expense — 8,509 Asset retirement obligations 2,224 1,011 Book-tax differences in property basis 200,478 — Unrealized hedging transactions 1,618 — Disallowed interest Section 163(j) 7,722 3,370 Basis difference in debt 2,142 — Operating lease liability 666 — Other 991 1,917 Gross deferred noncurrent income tax assets 479,356 308,393 Valuation allowance (478,690) (290,333) Deferred noncurrent income tax assets $ 666 $ 18,060 Deferred noncurrent income tax liabilities: Basis difference in debt $ — $ (5,507) Book-tax differences in property basis — (96,414) Unrealized hedging transactions — (11,930) Lease right of use (666) — Deferred noncurrent income tax liabilities $ (666) $ (113,851) Net noncurrent deferred income tax assets (liabilities) $ — $ (95,791)

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2019
EARNINGS PER SHARE
Schedule of calculation of earnings (loss) per share	The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts): Successor Predecessor Period from Period from October 2, 2019 January 1, 2019 through through Years Ended December 31, December 31, 2019 October 1, 2019 2018 2017 Basic: Net income (loss) available to common stockholders $ (10,460) $ (1,156,053) $ 45,959 $ 487,679 Weighted average basic number of common shares outstanding 16,204 158,925 157,011 132,763 Basic net income (loss) per common share $ (0.65) $ (7.27) $ 0.29 $ 3.67 Diluted: Net income (loss) available to common stockholders $ (10,460) $ (1,156,053) $ 45,959 $ 487,679 Weighted average basic number of common shares outstanding 16,204 158,925 157,011 132,763 Common stock equivalent shares representing shares issuable upon: Exercise of Predecessor stock options — Anti-dilutive Anti-dilutive Anti-dilutive Exercise of Predecessor warrants — Anti-dilutive Anti-dilutive Anti-dilutive Conversion of Predecessor preferred stock — — — Anti-dilutive Vesting of Predecessor restricted shares — Anti-dilutive 284 813 Exercise of Successor Series A Warrants Anti-dilutive — — — Exercise of Successor Series B Warrants Anti-dilutive — — — Exercise of Successor Series C Warrants Anti-dilutive — — — Weighted average diluted number of common shares outstanding 16,204 158,925 157,295 133,576 Diluted net income (loss) per common share $ (0.65) $ (7.27) $ 0.29 $ 3.65

ADDITIONAL FINANCIAL STATEMEN_2

ADDITIONAL FINANCIAL STATEMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2019
ADDITIONAL FINANCIAL STATEMENT INFORMATION
Schedule of additional financial statement information, balance sheet	Certain balance sheet amounts are comprised of the following (in thousands): Successor Predecessor December 31, 2019 December 31, 2018 Accounts receivable, net: Oil, natural gas and natural gas liquids revenues $ 36,367 $ 26,432 Joint interest accounts 10,145 7,369 Other 1,992 1,917 $ 48,504 $ 35,718 Prepaids and other: Prepaids $ 2,093 $ 3,503 Income tax receivable 1,250 1,250 Funds in escrow 4,000 — Other 36 35 $ 7,379 $ 4,788 Funds in escrow and other: Funds in escrow $ 580 $ 570 Other 123 1,611 $ 703 $ 2,181 Accounts payable and accrued liabilities: Trade payables $ 36,038 $ 68,959 Accrued oil and natural gas capital costs 22,781 41,461 Revenues and royalties payable 25,457 20,526 Accrued interest expense 604 16,971 Accrued employee compensation 2,947 3,421 Accrued lease operating expenses 9,230 6,292 Other 276 218 $ 97,333 $ 157,848

SUMMARY OF SIGNIFICANT EVENTS_4

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)segment	Dec. 31, 2018USD ($)
Basis of Presentation and Principles of Consolidation
Number of operating segments | segment	1
Allowance for doubtful accounts | $	$ 0.1	$ 0.2

SUMMARY OF SIGNIFICANT EVENTS_5

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 02, 2019	Dec. 31, 2016
SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
Cash and cash equivalents	$ 15,546	$ 5,701	$ 15,546		$ 46,866		$ 15,546
Restricted cash		4,574
Total cash, cash equivalents and restricted cash	$ 29,385	$ 10,275	$ 29,385		$ 46,866	$ 424,071		$ 24

SUMMARY OF SIGNIFICANT EVENTS_6

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - Other Operating Property and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Oct. 02, 2019	Oct. 01, 2019	Dec. 31, 2018
Other operating property and equipment
Other operating property and equipment	$ 3,655	$ 3,655	$ 203,373	$ 130,251
Buildings
Other operating property and equipment
Estimated useful lives	20 years
Automobiles
Other operating property and equipment
Estimated useful lives	3 years
Computers
Other operating property and equipment
Estimated useful lives	3 years
Computer software
Other operating property and equipment
Estimated useful lives	5 years
Fixtures, furniture and equipment
Other operating property and equipment
Estimated useful lives	5 years
Trailers
Other operating property and equipment
Estimated useful lives	7 years
Heavy equipment | Minimum
Other operating property and equipment
Estimated useful lives	8 years
Heavy equipment | Maximum
Other operating property and equipment
Estimated useful lives	10 years

SUMMARY OF SIGNIFICANT EVENTS_7

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - Concentrations of Credit Risk (Details) - Revenue - Concentrations of Credit Risk - customer	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Concentrations of Credit Risk
Number of customers	2	2	2
Sunoco and Western Refining Inc.
Concentrations of Credit Risk
Percentage of concentration risk	80.00%	77.00%
Sunoco | Minimum
Concentrations of Credit Risk
Percentage of concentration risk	10.00%	10.00%
Western Refining | Minimum
Concentrations of Credit Risk
Percentage of concentration risk	10.00%	10.00%
Crestwood and Suncor
Concentrations of Credit Risk
Percentage of concentration risk			58.00%
Crestwood | Minimum
Concentrations of Credit Risk
Percentage of concentration risk			10.00%
Suncor | Minimum
Concentrations of Credit Risk
Percentage of concentration risk			10.00%

SUMMARY OF SIGNIFICANT EVENTS_8

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - Income Taxes (Details) - USD ($) $ in Millions	Oct. 01, 2019	Oct. 31, 2019	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES
Unrecognized Tax Benefits	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Interest or penalties recognized in the results of operations	$ 0	$ 0	0	$ 0	0	0
Interest or penalties recognized in the statement of financial position			$ 0		$ 0	$ 0

SUMMARY OF SIGNIFICANT EVENTS_9

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - Restructuring and Redeemable Noncontrolling Interest (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Dec. 31, 2019	Oct. 01, 2019
Restructuring
Severance Costs	$ 1.2	$ 15.1

SUMMARY OF SIGNIFICANT EVENT_10

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - 401 (k) Plan (Details) - USD ($) $ in Millions	1 Months Ended	2 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended
	Oct. 31, 2019	Dec. 31, 2019	Dec. 31, 2019	Oct. 01, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
401(k) Plan
Eligibility age for employees to participate in the plan					18 years
Company's matching contributions			$ 0.2	$ 1.1		$ 1.5	$ 2.2
Company's matching contributions dollar-for-dollar on employee's pre-tax earnings (as a percent)	10.00%	10.00%		10.00%		10.00%	10.00%

SUMMARY OF SIGNIFICANT EVENT_11

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - Related Party Transactions (Details) - USD ($) $ in Millions	Oct. 01, 2019	Jul. 27, 2018	Nov. 16, 2017	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018
Chairman, Chief Executive Officer and President
Related Party Transactions
Amount incurred				$ 0.2		$ 0.9
Chairman, Chief Executive Officer and President | Accounts payable and accrued liabilities
Related Party Transactions
Amount payable						0.2
Ares Management LLC | Halcon Resources Corporation
Related Party Transactions
Ownership interest (as a percent)		10.00%	10.00%
SCM Crude, LLC
Related Party Transactions
Term		15 years
Amount earned	$ 101.6				$ 101.6	13
Receivable from related party						10.9
Salt Creek Midstream, LLC
Related Party Transactions
Term			15 years
Amount earned				6		0.4
Receivable from related party						$ 0
Cima
Related Party Transactions
Amount incurred				$ 0.9

REORGANIZATION (Details)

REORGANIZATION (Details) - USD ($) $ in Millions	Aug. 02, 2019	Dec. 31, 2019	Oct. 08, 2019	Oct. 08, 2018	Oct. 07, 2017	Jul. 10, 2017	Feb. 16, 2017
Restructuring Support Agreement
Warrant term (in years)			3 years
8.625% senior secured second lien notes due 2020
Restructuring Support Agreement
Interest rate (as a percent)							8.625%
12.0% senior secured second lien notes due 2022
Restructuring Support Agreement
Interest rate (as a percent)					12.00%
6.75% senior notes due 2025
Restructuring Support Agreement
Interest rate (as a percent)	6.75%	6.75%	6.75%	6.75%		6.75%	6.75%
The Restructuring Support Agreement
Restructuring Support Agreement
Pro rate share of common stock that unsecured noteholders will receive	91.00%
Pro rate share of common stock that stockholders will receive	9.00%
Aggregate price of new common shares offered to unsecured senior noteholders	$ 150.2
Aggregate price of new common shares offered to existing common shareholders	$ 5.8
Price per share discount (as a percent)	26.00%
Assumed enterprise value	$ 425
Consideration to unsecured senior noteholders for backstop senior noteholders rights offering (as a percent)	6.00%
Cash payment percentage on termination of backstop agreement	6.00%
Warrant term (in years)	3 years
Percentage of cumulative warrants issued to new shares	30.00%
The Restructuring Support Agreement | Maximum
Restructuring Support Agreement
Threshold shares of common stock holding by existing stockholders will receive cash	2,000

FRESH-START ACCOUNTING - Enterp

FRESH-START ACCOUNTING - Enterprise to Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Oct. 02, 2019	Oct. 01, 2019	Dec. 31, 2018
Fresh-Start Adjustment
Enterprise Value			$ 441,583
Plus: Cash	$ 5,701	$ 15,546	15,546	$ 46,866
Less: Fair value of debt			(130,000)
Less: Fair value of warrants		$ (7,336)	(7,336)
Fair Value of Successor common stock			319,793
Minimum
Fresh-Start Adjustment
Enterprise Value			$ 425,000,000
Maximum
Fresh-Start Adjustment
Maximum percentage of voting shares of emerging entity to qualify for fresh-start accounting under ASC 852 (as a percent)			50.00%
Enterprise Value			$ 475,000,000

FRESH-START ACCOUNTING - Ente_2

FRESH-START ACCOUNTING - Enterprise to Reorg Values (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Oct. 02, 2019	Oct. 01, 2019	Dec. 31, 2018
FRESH-START ACCOUNTING
Enterprise Value			$ 441,583
Plus: Cash	$ 5,701	$ 15,546	15,546	$ 46,866
Plus: Current liabilities			122,134
Plus: Lease liabilities			3,395
Plus: Noncurrent asset retirement obligation			10,153
Plus: Other noncurrent liabilities			1,625
Reorganization Value of Successor assets			$ 594,436

FRESH-START ACCOUNTING - Balanc

FRESH-START ACCOUNTING - Balance sheet effects (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Oct. 02, 2019	Oct. 01, 2019	Sep. 30, 2019	Jan. 01, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents			$ 17,009
Cash and cash equivalents	$ 5,701	$ 15,546	15,546			$ 46,866
Accounts receivable, net	48,504	37,826	37,826			35,718
Assets from derivative contracts	4,995	15,310	15,310			57,280
Restricted cash		13,839
Prepaids and other	7,379	10,290	14,642			4,788
Total current assets	71,153	92,811	84,787			144,652
Oil and natural gas properties (full cost method):
Evaluated	420,609	380,364	2,155,288			1,470,509
Unevaluated	105,009	108,954	438,365			971,918
Gross oil and natural gas properties	525,618	489,318	2,593,653			2,442,427
Less - accumulated depletion	(19,474)		(1,709,719)			(639,951)
Net oil and natural gas properties	506,144	489,318	883,934			1,802,476
Other operating property and equipment:
Other operating property and equipment	3,655	3,655	203,373			130,251
Less - accumulated depreciation	(378)		(14,416)			(8,388)
Net other operating property and equipment	3,277	3,655	188,957			121,863
Other noncurrent assets:
Assets from derivative contracts	224	4,120	4,120			12,437
Operating lease right of use assets	3,165	3,394	3,694		$ 5,462
Funds in escrow and other	703	1,138	1,138			2,181
Other	123					1,611
Total assets	584,666	594,436	1,166,630			2,083,609
Current liabilities:
Accounts payable and accrued liabilities	97,333	115,305	112,578		157,763	157,848
Liabilities from derivative contracts	8,069	6,829	6,829			3,768
Current portion of long-term debt, net			258,234
Operating lease liabilities	923	913	1,337		2,103
Asset retirement obligations	109					126
Total current liabilities	106,434	123,047	378,978			161,742
Long-term debt, net	144,000	130,000				613,105
Liabilities subject to compromise			625,005
Other noncurrent liabilities:
Liabilities from derivative contracts	4,854	1,625	1,625			9,139
Asset retirement obligations	10,481	10,153	10,153			6,788
Operating lease liabilities	2,247	2,482	2,438		$ 3,444
Commitments and contingencies
Stockholders' equity:
Common stock	2	2	16			16
Additional paid-in capital	327,108	327,127	1,087,441			1,095,367
Retained earnings (accumulated deficit)	(10,460)		(939,026)			101,661
Total stockholders' equity	316,650	327,129	148,431	$ 30,477		1,197,044	$ 1,071,998	$ 112,688
Total liabilities and stockholders' equity	584,666	$ 594,436	1,166,630			$ 2,083,609
Reorganization Adjustments
Current assets:
Cash and cash equivalents			(1,463)
Restricted cash			13,839
Prepaids and other			7,110
Total current assets			19,486
Other noncurrent assets:
Total assets			19,486
Current liabilities:
Accounts payable and accrued liabilities			2,727
Current portion of long-term debt, net			(258,234)
Total current liabilities			(255,507)
Long-term debt, net			130,000
Liabilities subject to compromise			(625,005)
Other noncurrent liabilities:
Commitments and contingencies
Stockholders' equity:
Common stock	2		(16)
Additional paid-in capital	$ 327,127		(1,087,441)
Retained earnings (accumulated deficit)			1,530,326
Total stockholders' equity			769,998
Total liabilities and stockholders' equity			19,486
Fresh Start Adjustments
Current assets:
Prepaids and other			(11,462)
Total current assets			(11,462)
Oil and natural gas properties (full cost method):
Evaluated			(1,774,924)
Unevaluated			(329,411)
Gross oil and natural gas properties			(2,104,335)
Less - accumulated depletion			1,709,719
Net oil and natural gas properties			(394,616)
Other operating property and equipment:
Other operating property and equipment			(199,718)
Less - accumulated depreciation			14,416
Net other operating property and equipment			(185,302)
Other noncurrent assets:
Operating lease right of use assets			(300)
Total assets			(591,680)
Current liabilities:
Operating lease liabilities			(424)
Total current liabilities			(424)
Other noncurrent liabilities:
Operating lease liabilities			44
Commitments and contingencies
Stockholders' equity:
Retained earnings (accumulated deficit)			(591,300)
Total stockholders' equity			(591,300)
Total liabilities and stockholders' equity			$ (591,680)

FRESH-START ACCOUNTING - Net ca

FRESH-START ACCOUNTING - Net cash payments (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Dec. 31, 2018	Dec. 31, 2017
Sources:
Proceeds from Senior Credit Agreement	$ 130,000
Proceeds from Existing Equity Interests Rights Offering	5,779
Total Sources	285,929
Uses:
Payment of Predecessor Credit Agreement principal, accrued interest, and fees	(226,580)
Repayments of Debt	35,174
Funding of professional fee escrow and cash collateral account	(13,839)
Payment of debt issuance costs on Senior Credit Agreement	(8,764)
Debt issuance costs		$ (1,471)	$ (8,764)	$ (4,334)	$ (17,799)
Payment of professional fees and other	(3,035)
Total Uses	(287,392)
Total Sources and Uses	(1,463)
Debt Issuance Costs, Gross	10,200		10,200
Restructuring Advisor Fee Prepaid	3,100
Restructuring Advisor Fee Payable	7,700		$ 7,700
Payments Of Accrued Interest And Fees	3,500
Payments Of Professional Fees	1,500
Senior Noteholder Rights Offering
Sources:
Proceeds from Existing Equity Interests Rights Offering	150,150
Senior revolving credit facility
Uses:
Repayments of Debt	$ 223,200

FRESH-START ACCOUNTING - Liabil

FRESH-START ACCOUNTING - Liabilities subject to compromise (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Oct. 01, 2019	Dec. 31, 2019	Oct. 08, 2019	Aug. 02, 2019	Oct. 08, 2018	Jul. 10, 2017	Feb. 16, 2017
Liabilities Subject to Compromise
Liabilities subject to compromise	$ 625,005	$ 625,005
Discount on shares issued per the Senior Noteholder Subscription Rights Offering	(67,840)	(67,840)
Issuance of common stock to Class 4 claimholders	(75,388)	(75,388)
Gain on settlement of liabilities subject to compromise	481,777	481,777
Gain on settlement of liabilities subject to compromise	481,777	481,777
6.75% senior notes due 2025
Liabilities Subject to Compromise
Interest rate (as a percent)			6.75%	6.75%	6.75%	6.75%	6.75%	6.75%
Debt	625,005	625,005
Reorganization Adjustments
Liabilities Subject to Compromise
Liabilities subject to compromise	$ (625,005)	$ (625,005)
Reorganization Adjustments | 6.75% senior notes due 2025
Liabilities Subject to Compromise
Interest rate (as a percent)	6.75%	6.75%

FRESH-START ACCOUNTING - Adjust

FRESH-START ACCOUNTING - Adjustments Made To Successor Company Stock and Additional Paid-in Capital (Details) $ / shares in Units, $ in Thousands	Oct. 08, 2019	Oct. 02, 2019USD ($)$ / sharesshares	Dec. 31, 2019USD ($)shares	Oct. 01, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2019USD ($)	Feb. 09, 2018$ / shares	Dec. 31, 2016USD ($)	Sep. 09, 2016$ / shares
Fresh-Start Adjustment
Par value of 16,203,940 shares of new common stock issued to holders of senior note claims and existing equity interest claims (valued at $19.74per share) | $		$ 2	$ 2	$ 16	$ 16
Fair Value of warrants issued to holder of the Existing Equity Interests | $		7,336		7,336
Additional paid-in-capital (Successor) | $		322,294
Equity issuance costs | $		(2,503)	(19)	(2,503)	(3,044)	$ (11,919)
Total stockholders' equity | $		$ 327,129	$ 316,650	$ 148,431	$ 1,197,044	$ 1,071,998	$ 30,477		$ 112,688
Common stock, shares issued | shares		16,203,940	16,203,940
Share Price | $ / shares		$ 19.74						$ 6.90
Annualized Rate Of Increase To The Strike Price Of Warrants Issued	6.75	6.75
Warrants exercise price (in dollars per share) | $ / shares										$ 14.04
Measurement Input Implied Strike Price
Fresh-Start Adjustment
Warrants and Rights Outstanding, Measurement Input		19.74
Measurement Input, Initial Strike Price | Series A Warrants
Fresh-Start Adjustment
Warrants exercise price (in dollars per share) | $ / shares		$ 40.17
Measurement Input, Initial Strike Price | Series B Warrants
Fresh-Start Adjustment
Warrants exercise price (in dollars per share) | $ / shares		48.28
Measurement Input, Initial Strike Price | SeriesC Warrants [Member]
Fresh-Start Adjustment
Warrants exercise price (in dollars per share) | $ / shares		$ 60.45
Measurement Input, Price Volatility [Member]
Fresh-Start Adjustment
Warrants and Rights Outstanding, Measurement Input		45

FRESH-START ACCOUNTING - Effect

FRESH-START ACCOUNTING - Effect of reorganization adj cumulative (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Oct. 01, 2019	Oct. 02, 2019
Reorganization Items
Gain on settlement of liabilities subject to compromise	$ 481,777	$ 481,777
Success fees incurred upon emergence	(8,376)
Fair value of equity issued to Predecessor common stockholders	(7,449)	(7,449)
Less: Fair value of warrants	(7,336)	(7,336)	$ (7,336)
Issuance of common stock to backstop commitment parties	(13,079)
Cancellation of Predecessor Company equity		(30,477)
Reorganization Adjustments
Reorganization Items
Other reorganization adjustments	(2,668)
Cancellation of Predecessor Company equity	1,087,457
Net impact to retained earnings (accumulated deficit)	$ 1,530,326	$ 1,530,326

FRESH-START ACCOUNTING - FV adj

FRESH-START ACCOUNTING - FV adjustments to oil and natural gas properties (Details) $ in Millions	Oct. 01, 2019USD ($)	Dec. 31, 2019	Oct. 01, 2019$ / MMBTU$ / bbl
Oil and natural gas properties (full cost method):
Debt issuance cost expensed | $	$ 10.2
Write Off Of Prepaid Premium Expenses | $	$ 1.2
Incremental borrowing rate		3.70%	4.83%
Fresh Start Adjustments
Oil and natural gas properties (full cost method):
Weighted average cost of capital rate (as a percent)			10
Development plan in years			5 years
Weighted average commodity price of oil (in dollars per barrel) | $ / bbl			71.51
Weighted average commodity price of natural gas (in dollars per Mmbtu) | $ / MMBTU			3.37
Weighted average commodity price of natural gas liquids (in dollars per barrel) | $ / bbl			29.50

FRESH-START ACCOUNTING - Reorga

FRESH-START ACCOUNTING - Reorganization items (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019
Reorganization Items
Gain on settlement of liabilities subject to compromise	$ 481,777		$ 481,777
Fresh start adjustments			(591,300)
Gain on adjustment of pre-petition liabilities subject to compromise to the allowed claims amount			20,274
Write-off of debt discounts/premium and debt issuance costs			(10,953)
Reorganization professional fees and other		$ (3,298)	(16,922)
Gain (loss) on reorganization items		$ (3,298)	$ (117,124)

LEASES (Details)

LEASES (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 02, 2019	Jan. 01, 2019
Other noncurrent assets:
Operating lease right of use assets	$ 3,694	$ 3,165	$ 3,694				$ 3,394	$ 5,462
Current liabilities:
Accounts payable and accrued liabilities	112,578	97,333	112,578		$ 157,848		115,305	157,763
Operating lease liabilities	1,337	923	1,337				913	2,103
Other noncurrent liabilities:
Operating lease liabilities	$ 2,438	2,247	2,438				$ 2,482	3,444
Lease cost
Operating lease costs		260	1,932
Short-term lease costs		4,408	12,262
Variable lease costs		215	1,210
Total lease costs		4,883	15,404
Other information
Operating cash flows from operating leases		254	1,936
Right-of-use assets obtained in exchange for new operating lease liabilities		$ 3,394	$ 5,462
Weighted-average remaining lease term - operating leases	3 years 8 months 12 days	3 years 6 months	3 years 8 months 12 days
Weighted-average discount rate - operating leases	4.83%	3.70%	4.83%
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
Minimum
Other noncurrent liabilities:
Initial lease term	1 year	2 years	1 year
Maximum
Other noncurrent liabilities:
Initial lease term	4 years	5 years	4 years
As initially reported | Accounting Standards Update 2016-02 Leases
Current liabilities:
Accounts payable and accrued liabilities					$ 157,848
Increase (decrease) | Accounting Standards Update 2016-02 Leases
Other noncurrent assets:
Operating lease right of use assets								5,462
Current liabilities:
Accounts payable and accrued liabilities								(85)
Operating lease liabilities								2,103
Other noncurrent liabilities:
Operating lease liabilities								$ 3,444

LEASES - Reported under ASC 842

LEASES - Reported under ASC 842 and ASC 840 (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 02, 2019	Jan. 01, 2019
Future minimum lease payments for non-cancellable operating leases
2020		$ 1,022
2021		876
2022		574
2023		585
2024		345
Total operating lease payment		3,402
Less: discount to present value		232
Total operating lease liabilities		3,170
Less: current operating lease liabilities	$ 1,337	923	$ 1,337				$ 913	$ 2,103
Noncurrent operating lease liabilities	$ 2,438	$ 2,247	$ 2,438				$ 2,482	$ 3,444
Prior to the adoption of ASC 842, future obligations for non-cancellable operating leases
2019					$ 3,792
2020					2,350
2021					1,899
2022					968
2023					999
Thereafter					599
Total operating lease payments					$ 10,607
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor

OPERATING REVENUES - Revenue Re

OPERATING REVENUES - Revenue Recognition (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of operating revenue
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
Total oil, natural gas and natural gas liquids sales		$ 65,115	$ 158,360		$ 225,529	$ 375,837
Other		467	743		1,080	2,128
Total operating revenues		65,582	159,103		226,609	377,965
Oil
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		58,325	145,024		199,601	340,674
Oil
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		58,325	145,024		199,601	340,674
Natural gas
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		1,719	107		6,791	16,194
NGLs
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		5,071	$ 13,229		19,137	$ 18,969
Accounts receivable
Disaggregation of operating revenue
Due from contracts with customers		$ 36,400			$ 26,400

ACQUISITIONS AND DIVESTITURES -

ACQUISITIONS AND DIVESTITURES - West Quito Draw Properties (Details) - USD ($) $ in Millions	Feb. 06, 2018	Dec. 31, 2019	Oct. 08, 2019	Aug. 02, 2019	Oct. 08, 2018	Jul. 10, 2017	Feb. 16, 2017
West Quito Draw Properties
ACQUISITIONS AND DIVESTITURES
Purchase price	$ 198.5
6.75% senior notes due 2025
ACQUISITIONS AND DIVESTITURES
Interest rate (as a percent)		6.75%	6.75%	6.75%	6.75%	6.75%	6.75%

ACQUISITIONS AND DIVESTITURES-M

ACQUISITIONS AND DIVESTITURES-Monument Draw Assets (Details) - Ward County Assets - USD ($) $ in Millions	Jan. 09, 2018	Dec. 13, 2017	Jun. 15, 2017
ACQUISITIONS AND DIVESTITURES
Purchase price		$ 101.8
Southern Tract
ACQUISITIONS AND DIVESTITURES
Purchase price			$ 87.4
Northern Tract
ACQUISITIONS AND DIVESTITURES
Purchase price	$ 108.2

ACQUISITIONS AND DIVESTITURES-P

ACQUISITIONS AND DIVESTITURES-Pecos County Acquisition (Details) $ in Thousands	Dec. 13, 2017USD ($)	Feb. 28, 2017USD ($)$ / Mcf$ / Boe$ / bbl	Jan. 24, 2017	Jan. 18, 2017USD ($)	Dec. 31, 2019USD ($)	Oct. 02, 2019USD ($)	Oct. 01, 2019USD ($)	Dec. 31, 2018USD ($)	Nov. 01, 2017USD ($)
Estimated Fair Value of Assets Acquired:
Evaluated oil and natural gas properties (3)(4)					$ 420,609	$ 380,364	$ 2,155,288	$ 1,470,509
Gas gathering and other operating assets (5)					$ 3,655	$ 3,655	$ 203,373	$ 130,251
8% Convertible Preferred Stock
ACQUISITIONS AND DIVESTITURES.
Dividend rate (as a percent)			8.00%
Pecos County Assets
Consideration paid for acquisition and the estimated values of assets acquired and liabilities assumed
Cash consideration paid to Samson at closing (1)		$ 703,865
Less: Post-effective closing date adjustments (2)		(4,677)
Final consideration transferred		699,188		$ 699,200
Plus: Estimated Fair Value of Liabilities Assumed:
Current liabilities		839
Asset retirement obligations		2,116
Amount attributable to liabilities assumed		2,955
Total purchase price plus liabilities assumed		702,143
Estimated Fair Value of Assets Acquired:
Evaluated oil and natural gas properties (3)(4)		188,275
Unevaluated oil and natural gas properties (3)(4)		487,489
Gas gathering and other operating assets (5)		26,379
Amount attributable to assets acquired		$ 702,143
Additional disclosures
Goodwill									$ 0
Weighted average cost of capital rate (as a percent)		10
Weighted average cost of capital for probable and possible reserves rate (as a percent)		12
Development plan in years		5 years
Pecos County Assets | Crude oil
Additional disclosures
Weighted average commodity prices | $ / bbl		76.10
Pecos County Assets | Natural gas
Additional disclosures
Weighted average commodity prices | $ / Mcf		4.14
Pecos County Assets | NGLs
Additional disclosures
Weighted average commodity prices | $ / Boe		29.48
Pecos County Assets | 8% Convertible Preferred Stock
ACQUISITIONS AND DIVESTITURES.
Dividend rate (as a percent)		8.00%
Additional disclosures
Net proceeds expected to be received for common stock agreed to be purchased by third party		$ 400,100
Ward County Assets
Consideration paid for acquisition and the estimated values of assets acquired and liabilities assumed
Final consideration transferred	$ 101,800

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES-Pecos County Proforma (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Pro forma financial information
Net income (loss) available to common stockholders		$ (10,460)	$ (1,156,053)		$ 45,959	$ 487,679
Additional disclosures
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
Pecos County Assets
Pro forma financial information
Revenue						$ 385,867
Net income (loss)						542,724
Net income (loss) available to common stockholders						$ 494,717
Pro forma net income (loss) per share of common stock:
Basic (in dollars per share)						$ 3.73
Diluted (in dollars per share)						$ 3.70
Additional disclosures
Transaction costs and non-recurring charges						$ 1,000
Oil, natural gas and natural gas liquids sales related to properties acquired					$ 46,200	46,200
Net field operating income related to properties acquired						$ 5,900
Financial Designation, Predecessor and Successor [Fixed List]						Predecessor
Pecos County Assets | General and administrative
Additional disclosures
Non-recurring transaction costs						$ 1,000

ACQUISITIONS AND DIVESTITURES_3

ACQUISITIONS AND DIVESTITURES - Water Infrastructure Assets (Details) - Water Infrastructure Assets - USD ($) $ in Millions	Dec. 20, 2018	Dec. 31, 2018	Oct. 01, 2018
Purchase and Sale Agreement
ACQUISITIONS AND DIVESTITURES
Sale price of asset in cash	$ 210.9
Incentives payable per year if certain thresholds are met			$ 25
(Gain) loss on sale of Water Assets
ACQUISITIONS AND DIVESTITURES
Gain (loss) from sale of other operating property and equipment		$ 119

ACQUISITIONS AND DIVESTITURES_4

ACQUISITIONS AND DIVESTITURES - Divestitures (Details) $ in Thousands

Nov. 09, 2017USD ($)

Sep. 19, 2017USD ($)

Jul. 10, 2017USD ($)subsidiary

Jan. 24, 2017USD ($)

Jan. 01, 2017USD ($)

Dec. 31, 2019USD ($)

Oct. 01, 2019USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Oct. 08, 2019

Aug. 02, 2019

Oct. 08, 2018

Oct. 07, 2017

Sep. 07, 2017USD ($)

Feb. 16, 2017USD ($)

Divestitures

Increase (Decrease) In Gains On Disposition Of Water Assets

$ 500

$ 3,600

Proceeds received from sales of oil and natural gas assets

$ 1,247

$ 3,816

$ 2,003,894

Gain (loss) on extinguishment of debt

(114,931)

Proceeds received from sale of other operating property and equipment

$ 6

216,083

21,798

Gain (loss) from sale of other operating property and equipment

(7,235)

721,573

12.0% senior secured second lien notes due 2022

Divestitures

Interest rate (as a percent)

12.00%

Gain (loss) on extinguishment of debt

(29,200)

Loss on the repurchase for the make whole premium

23,000

Loss on the write-off of the discount on notes

6,200

6.75% senior notes due 2025

Divestitures

Repurchase amount of outstanding principal

$ 425,000

Aggregate principal amount drawn

$ 850,000

625,005

[1]

$ 850,000

$ 850,000

Interest rate (as a percent)

6.75%

6.75%

6.75%

6.75%

6.75%

6.75%

Gain (loss) on extinguishment of debt

(28,900)

Loss on the write-off of the discount on notes

8,300

Gain on sale of oil and natural gas assets

Divestitures

Gain (loss) from sale of other operating property and equipment

$ 0

$ 0

Williston Basin Assets

Divestitures

Gain (loss) from sale of other operating property and equipment

0

$ (7,200)

485,900

Williston Basin Assets | Property Plant And Equipment, Other

Divestitures

Proceeds received from sales of oil and natural gas assets

1,390,000

Proceeds received from sale of other operating property and equipment

$ 10,900

Williston Basin Assets | Disposal Group Disposed of by Sale

Divestitures

Ownership percentage disposed

100.00%

Number of subsidiaries | subsidiary

2

Proceeds received from sales of oil and natural gas assets

$ 1,400,000

El Halcon Assets

Divestitures

Gain (loss) from sale of other operating property and equipment

0

235,700

El Halcon Assets | Property Plant And Equipment, Other

Divestitures

Proceeds received from sales of oil and natural gas assets

484,100

Proceeds received from sale of other operating property and equipment

$ 10,200

El Halcon Assets | Gain on sale of oil and natural gas assets

Divestitures

Gain (loss) from sale of other operating property and equipment

$ 235,700

El Halcon Assets | Disposal Group Disposed of by Sale

Divestitures

Proceeds from sales of interests

$ 491,100

Non-operating owner | Williston Basin Assets

Divestitures

Proceeds from sales of interests

$ 103,400

Gain (loss) on sale

$ 0

[1]

The 6.75% senior notes were cancelled on October 8, 2019 upon emergence from chapter 11 bankruptcy.

OIL AND NATURAL GAS PROPERTIE_2

OIL AND NATURAL GAS PROPERTIES (Details) $ in Thousands	Oct. 01, 2019USD ($)	Jul. 10, 2017USD ($)	Jan. 24, 2017USD ($)	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Oct. 01, 2019USD ($)	Sep. 30, 2019	Dec. 31, 2019USD ($)$ / MMBTU$ / bbl	Dec. 31, 2018USD ($)$ / MMBTU$ / bbl	Dec. 31, 2017USD ($)$ / MMBTU$ / bbl	Oct. 02, 2019USD ($)
Oil and Natural Gas Properties
Subject to depletion	$ 2,155,288			$ 420,609				$ 2,155,288		$ 420,609	$ 1,470,509		$ 380,364
Not subject to depletion:
Exploration and extension wells in progress											23,536
Other capital costs:
Incurred in 2019				105,009						105,009
Incurred in 2018											310,113
Incurred in 2017											638,269
Total not subject to depletion	438,365			105,009				438,365		105,009	971,918		108,954
Gross oil and natural gas properties	2,593,653			525,618				2,593,653		525,618	2,442,427		489,318
Less accumulated depletion	(1,709,719)			(19,474)				(1,709,719)		(19,474)	(639,951)
Net oil and natural gas properties	883,934			$ 506,144				883,934		$ 506,144	$ 1,802,476		$ 489,318
Ceiling Limitation Disclosures
Oil And Natural Gas, Evaluated Properties, Fair Value Disclosure	380,400							380,400
Oil And Natural Gas, Unevaluated Properties, Fair Value Disclosure	$ 109,000							109,000
First day average of the (WTI) crude oil spot price (in dollars per barrel) | $ / bbl										55.85	65.56	51.34
First day average of the Henry Hub natural gas price (in dollars per Mmbtu) | $ / MMBTU										2.578	3.100	2.976
Amount of unevaluated property costs transferred to the full cost pool							$ 51,000
Gain (loss) from sale of other operating property and equipment											$ (7,235)	$ 721,573
Impairment of Oil and Gas Properties					$ 45,600	$ 664,400	$ 275,200	$ 985,190
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor			Successor				Predecessor	Predecessor		Predecessor	Predecessor
Williston Basin Assets
Ceiling Limitation Disclosures
Gain (loss) from sale of other operating property and equipment		$ 0									$ (7,200)	$ 485,900
El Halcon Assets
Ceiling Limitation Disclosures
Gain (loss) from sale of other operating property and equipment			$ 0									$ 235,700
Utica areas | Unevaluated Oil and Gas Leaseholds
Ceiling Limitation Disclosures
Amount of unevaluated property costs transferred to the full cost pool						$ 481,700

LONG TERM DEBT (Details)

LONG TERM DEBT (Details) - USD ($) $ in Thousands

Oct. 01, 2019

Dec. 31, 2019

Oct. 01, 2019

Sep. 30, 2019

Dec. 31, 2018

Dec. 31, 2017

Oct. 08, 2019

Aug. 02, 2019

Oct. 08, 2018

Oct. 07, 2017

Jul. 10, 2017

Feb. 16, 2017

Current and long-term debt

Financial Designation, Predecessor and Successor [Fixed List]

Predecessor

Successor

Predecessor

Predecessor

Predecessor

Predecessor

Debt

$ 144,000

$ 613,105

Unamortized debt issuance costs

$ 0

11,100

8.625% senior secured second lien notes due 2020

Current and long-term debt

Interest rate (as a percent)

8.625%

12.0% senior secured second lien notes due 2022

Current and long-term debt

Interest rate (as a percent)

12.00%

6.75% senior notes due 2025

Current and long-term debt

Debt

613,105

Interest rate (as a percent)

6.75%

6.75%

6.75%

6.75%

6.75%

6.75%

Unamortized discount

7,200

Additional 2025 Notes

Current and long-term debt

Unamortized debt issuance costs

10,100

Unamortized premium related to debt issued

$ 5,400

Successor Senior revolving credit facility

Current and long-term debt

Debt

$ 144,000

LONG TERM DEBT - Senior Facilit

LONG TERM DEBT - Senior Facility (Details) $ in Thousands	Nov. 21, 2019USD ($)	Oct. 08, 2019USD ($)	Sep. 07, 2017USD ($)item	Dec. 31, 2019USD ($)item	Oct. 01, 2019USD ($)	Dec. 31, 2018USD ($)
Current and long-term debt
Debt				$ 144,000		$ 613,105
Senior revolving credit facility
Current and long-term debt
Maximum borrowing capacity			$ 1,000
Current borrowing capacity					$ 225,000
Amount available for issuance of letters of credit		$ 50,000
Number of interim unscheduled redeterminations of borrowing base to which the company and lender each have the right | item			1
Number of consecutive semi-annual redeterminations between which the company and the lenders each have the right to one interim unscheduled redetermination of borrowing base | item			2
Debt Instrument, Threshold Total Net Indebtedness Leverage Ratio	3.50
Senior revolving credit facility | ABR-based | Minimum
Current and long-term debt
Applicable margin (as a percent)		1.00%	1.75%
Senior revolving credit facility | ABR-based | Maximum
Current and long-term debt
Applicable margin (as a percent)			2.75%
Senior revolving credit facility | LIBOR | Minimum
Current and long-term debt
Applicable margin (as a percent)			2.75%
Senior revolving credit facility | LIBOR | Maximum
Current and long-term debt
Applicable margin (as a percent)			3.75%
Successor Senior revolving credit facility
Current and long-term debt
Debt				144,000
Maximum borrowing capacity		$ 750,000,000
Current borrowing capacity	$ 240,000			$ 144,000
Number of interim unscheduled redeterminations of borrowing base to which the company and lender each have the right | item				1
Number of consecutive semi-annual redeterminations between which the company and the lenders each have the right to one interim unscheduled redetermination of borrowing base | item				2
Letters of credit outstanding				$ 2,300
Borrowing capacity available				$ 93,700
Successor Senior revolving credit facility | Minimum
Current and long-term debt
Current Ratio		1
Successor Senior revolving credit facility | ABR-based | Maximum
Current and long-term debt
Applicable margin (as a percent)		2.00%
Successor Senior revolving credit facility | LIBOR | Minimum
Current and long-term debt
Applicable margin (as a percent)		2.00%
Successor Senior revolving credit facility | LIBOR | Maximum
Current and long-term debt
Applicable margin (as a percent)		3.00%
First Amendment To Senior Revolving Credit Facility
Current and long-term debt
Current borrowing capacity	$ 240,000
Debt Instrument, Threshold Total Net Indebtedness Leverage Ratio	3.50

LONG TERM DEBT - Debtor in Poss

LONG TERM DEBT - Debtor in Possession Financing (Details) - DIP Credit Agreement - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Aug. 09, 2019
Current and long-term debt
Maximum borrowing capacity		$ 35
Extended Initial Loan Credit Facility	$ 25
LIBOR
Current and long-term debt
Interest added to applicable interest rate in effect (as a percent)	5.50%
ABR-based
Current and long-term debt
Interest added to applicable interest rate in effect (as a percent)	4.50%

LONG TERM DEBT - 6.75% Senior N

LONG TERM DEBT - 6.75% Senior Notes (Details) - USD ($) $ in Thousands	Aug. 07, 2019	Feb. 15, 2018	Oct. 10, 2017	Sep. 07, 2017	Jul. 25, 2017	Feb. 16, 2017	Mar. 31, 2017	Oct. 01, 2019	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2019	Oct. 08, 2019	Aug. 02, 2019	Oct. 08, 2018	Oct. 07, 2017	Jul. 10, 2017
Current and long-term debt
Accrued and unpaid interest			$ 4,100
Gains (Losses) on Extinguishment of Debt											$ (114,931)
Unamortized debt issuance costs									$ 11,100			$ 0
Write-off debt discounts/premium and debt issuance costs								$ 10,953
Interest expense not accrued	$ 7,100
12.0% senior secured second lien notes due 2022
Current and long-term debt
Interest rate (as a percent)																12.00%
Gains (Losses) on Extinguishment of Debt											(29,200)
Loss on the write-off of the discount on notes											6,200
6.75% senior notes due 2025
Current and long-term debt
Principal amount				$ 850,000		$ 850,000			625,005	[1]							$ 850,000
Interest rate (as a percent)						6.75%						6.75%	6.75%	6.75%	6.75%		6.75%
Net proceeds from issuance						$ 834,100
Redemption price of debt instrument (as a percent)			103.00%
Gains (Losses) on Extinguishment of Debt											(28,900)
Loss on the repurchase for the tender premium paid											12,800
Loss on the write-off of the discount on notes											8,300
Loss on write off of debt issuance costs									7,800		$ 7,800
Percentage of holders concluded a consent solicitation					99.00%
Percentage of consent fee paid					2.00%
Consent fee paid					$ 16,900
Principal amount repurchased			$ 425,000
Write-off debt discounts/premium and debt issuance costs	6,600
Additional 2025 Notes
Current and long-term debt
Principal amount		$ 200,000
Net proceeds from issuance		$ 202,400
Issue price as a percentage of par value		103.00%
Unamortized premium related to debt issued									5,400
Unamortized debt issuance costs									$ 10,100
Write-off of debt premium	$ 4,900
8.625% senior secured second lien notes due 2020
Current and long-term debt
Interest rate (as a percent)						8.625%
Gains (Losses) on Extinguishment of Debt							$ (56,900)
Loss on the repurchase for the tender premium paid							30,900
Loss on the write-off of the discount on notes							$ 26,000
Williston Basin Assets | 6.75% senior notes due 2025
Current and long-term debt
Redemption price of debt instrument (as a percent)				103.00%
Principal amount repurchased				$ 425,000
[1]	The 6.75% senior notes were cancelled on October 8, 2019 upon emergence from chapter 11 bankruptcy.

LONG TERM DEBT - Debt Maturitie

LONG TERM DEBT - Debt Maturities and Debt Issuance Costs (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Dec. 31, 2018	Dec. 31, 2017	Nov. 30, 2019
Debt maturities
2024						$ 144,000
Total						$ 144,000
Debt Issuance Costs
Payment of debt issuance costs on Senior Credit Agreement		$ 1,471	$ 8,764	$ 4,334	$ 17,799
Debt issuance cost expensed	$ 10,200
Unamortized debt issuance costs		$ 0		$ 11,100
6.75% senior notes due 2025 and the additional 2025 Notes | Reorganization Adjustments
Debt Issuance Costs
Debt issuance cost expensed			9,300
Senior revolving credit facility | Interest expense and other
Debt Issuance Costs
Debt issuance cost expensed			$ 700

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Assets
Asset transfers between levels					$ 0
Liabilities
Liability transfers between levels					0
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor		Predecessor	Predecessor
Total
Liabilities
Financial Designation, Predecessor and Successor [Fixed List]		Successor				Predecessor
Level 1
Liabilities
Financial Designation, Predecessor and Successor [Fixed List]		Successor
Level 2
Liabilities
Financial Designation, Predecessor and Successor [Fixed List]		Successor
Level 3
Liabilities
Financial Designation, Predecessor and Successor [Fixed List]		Successor
Recurring | Total
Assets
Receivables from derivative contracts		$ 5,219			5,219	$ 69,717
Liabilities
Liabilities from derivative contracts		12,923			12,923	12,907
Recurring | Level 2
Assets
Receivables from derivative contracts		5,219			5,219	69,717
Liabilities
Liabilities from derivative contracts		$ 12,923			$ 12,923	$ 12,907

FAIR VALUE MEASUREMENTS - Estim

FAIR VALUE MEASUREMENTS - Estimated FV (Details) - USD ($) $ in Thousands

Oct. 01, 2019

Dec. 31, 2019

Oct. 01, 2019

Sep. 30, 2019

Dec. 31, 2018

Dec. 31, 2017

Oct. 08, 2019

Aug. 02, 2019

Oct. 08, 2018

Oct. 07, 2017

Sep. 07, 2017

Jul. 10, 2017

Feb. 16, 2017

Fair value measurements

Financial Designation, Predecessor and Successor [Fixed List]

Predecessor

Successor

Predecessor

Predecessor

Predecessor

Predecessor

12.0% senior secured second lien notes due 2022

Fair value measurements

Interest rate (as a percent)

12.00%

6.75% senior notes due 2025

Fair value measurements

Interest rate (as a percent)

6.75%

6.75%

6.75%

6.75%

6.75%

6.75%

Principal amount

$ 625,005

[1]

$ 850,000

$ 850,000

$ 850,000

Total

Fair value measurements

Financial Designation, Predecessor and Successor [Fixed List]

Successor

Predecessor

Total | 6.75% senior notes due 2025

Fair value measurements

Estimated fair value of debt

[1]

$ 458,210

[1]

The 6.75% senior notes were cancelled on October 8, 2019 upon emergence from chapter 11 bankruptcy.

DERIVATIVE AND HEDGING ACTIVI_3

DERIVATIVE AND HEDGING ACTIVITIES - (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative and hedging activities
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
Asset derivative contracts		$ 5,219			$ 69,717
Liability derivative contracts		(12,923)			(12,907)
Derivatives not designated as hedging contracts
Derivative and hedging activities
Asset derivative contracts		5,219			69,717
Liability derivative contracts		(12,923)			(12,907)
Derivatives not designated as hedging contracts | Commodity contracts | Current assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts		4,995			57,280
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts		224			12,437
Derivatives not designated as hedging contracts | Commodity contracts | Current liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts		(8,069)			(3,768)
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts		$ (4,854)			$ (9,139)

DERIVATIVE AND HEDGING ACTIVI_4

DERIVATIVE AND HEDGING ACTIVITIES - Realized Unrealized (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative and hedging activities
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
Total net gain (loss) on derivative contracts		$ (16,692)	$ (34,332)		$ 92,625	$ 1,291
Derivatives not designated as hedging contracts | Commodity contracts | Other Income Expense
Derivative and hedging activities
Unrealized gain (loss) on commodity contracts		(18,681)	(45,834)		84,274	(16,468)
Realized gain (loss) on commodity contracts		1,989	11,502		8,351	17,759
Total net gain (loss) on derivative contracts		$ (16,692)	$ (34,332)		$ 92,625	$ 1,291

DERIVATIVE AND HEDGING ACTIVI_5

DERIVATIVE AND HEDGING ACTIVITIES - Open Contracts (Details)	Oct. 01, 2019	Dec. 31, 2019MMBTU$ / MMBTU$ / bblbbl	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2017
Derivative and hedging activities
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
July 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					552,000
July 2019 - December 2019 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					50
Ceilings (in dollars per Mmbtu's/Bbl's)					55
July 2019 - December 2019 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					55
Ceilings (in dollars per Mmbtu's/Bbl's)					69
July 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					53
Ceilings (in dollars per Mmbtu's/Bbl's)					61
July 2019 - December 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					460,000
July 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential					(2.40)
July 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential					(6.50)
July 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential					(5.68)
October 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					92,000
Floors (in dollars per Mmbtu's/Bbl's)					51
Ceilings (in dollars per Mmbtu's/Bbl's)					56
October 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					51
Ceilings (in dollars per Mmbtu's/Bbl's)					56
October 2019 - December 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					460,000
October 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential					3.45
October 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential					4
October 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential					3.72
October 2019 - December 2019 | Fixed Swap | NGLs
Derivative and hedging activities
Volume in Mmbtu's | MMBTU					92,000
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					32.50
October 2019 - December 2019 | Fixed Swap | NGLs | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					32.50
January 2020 - December 2020 | Fixed Swap | Natural gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		2.55
January 2020 - December 2020 | Fixed Swap | Natural gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		2.57
January 2019 - March 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					90,000
Floors (in dollars per Mmbtu's/Bbl's)					46.75
Ceilings (in dollars per Mmbtu's/Bbl's)					51.75
January 2019 - March 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					46.75
Ceilings (in dollars per Mmbtu's/Bbl's)					51.75
January 2019 - March 2019 | Call option | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					1,350,000
Ceilings (in dollars per Mmbtu's/Bbl's)					62.64
January 2019 - March 2019 | Call option | Crude oil | Weighted Average
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)					62.64
January 2019 - March 2019 | Call option | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					(1,350,000)
Ceilings (in dollars per Mmbtu's/Bbl's)					58.64
January 2019 - March 2019 | Call option | Crude oil | Weighted Average
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)					58.64
January 2019 - June 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					181,000
Floors (in dollars per Mmbtu's/Bbl's)					51
Ceilings (in dollars per Mmbtu's/Bbl's)					56
January 2019 - June 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					51
Ceilings (in dollars per Mmbtu's/Bbl's)					56
January 2019 - September 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					546,000
January 2019 - September 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential					(6.20)
January 2019 - September 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential					(7.60)
January 2019 - September 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential					(6.90)
January 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					3,650,000
January 2019 - December 2019 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					50
Ceilings (in dollars per Mmbtu's/Bbl's)					55.20
January 2019 - December 2019 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					58
Ceilings (in dollars per Mmbtu's/Bbl's)					63
January 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					53.87
Ceilings (in dollars per Mmbtu's/Bbl's)					60.07
January 2019 - December 2019 | Collars | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU					8,760,000
January 2019 - December 2019 | Collars | Natural gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					2.52
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					3
January 2019 - December 2019 | Collars | Natural gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					2.70
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					3.10
January 2019 - December 2019 | Collars | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					2.60
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					3.01
January 2019 - December 2019 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					2,448,000
January 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential					(0.98)
January 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential					(6.50)
January 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential					(2.80)
January 2019 - December 2019 | Basis Swap | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU					9,307,500
January 2019 - December 2019 | Basis Swap | Natural gas | Minimum
Derivative and hedging activities
Basis Differential | $ / MMBTU					(1.05)
January 2019 - December 2019 | Basis Swap | Natural gas | Maximum
Derivative and hedging activities
Basis Differential | $ / MMBTU					(1.40)
January 2019 - December 2019 | Basis Swap | Natural gas | Weighted Average
Derivative and hedging activities
Basis Differential | $ / MMBTU					(1.18)
January 2019 - December 2019 | WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					1,825,000
Floors (in dollars per Mmbtu's/Bbl's)					0.35
January 2019 - December 2019 | WTI NYMEX Roll | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					0.35
January 2019 - December 2019 | Fixed Swap | NGLs
Derivative and hedging activities
Volume in Mmbtu's | MMBTU					1,460,000
January 2019 - December 2019 | Fixed Swap | NGLs | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					29.08
January 2019 - December 2019 | Fixed Swap | NGLs | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					30.15
January 2019 - December 2019 | Fixed Swap | NGLs | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU					29.33
April 2019 - June 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					91,000
Floors (in dollars per Mmbtu's/Bbl's)					50
Ceilings (in dollars per Mmbtu's/Bbl's)					55
April 2019 - June 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					50
Ceilings (in dollars per Mmbtu's/Bbl's)					55
April 2019 - December 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl					275,000
Floors (in dollars per Mmbtu's/Bbl's)					55
Ceilings (in dollars per Mmbtu's/Bbl's)					62.85
April 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)					55
Ceilings (in dollars per Mmbtu's/Bbl's)					62.85
January 2020 - June 2020 | Fixed Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		182,000,000
Floors (in dollars per Mmbtu's/Bbl's)		55.74
January 2020 - June 2020 | Fixed Swap | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		55.74
January 2020 - September 2020 | Fixed Swap | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU		1,186,000
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		2.61
January 2020 - September 2020 | Fixed Swap | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		2.61
January 2020 - December 2020 [Member] | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		549,000,000			549,000
Floors (in dollars per Mmbtu's/Bbl's)		50			50
Ceilings (in dollars per Mmbtu's/Bbl's)		70			70
January 2020 - December 2020 [Member] | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		50			50
Ceilings (in dollars per Mmbtu's/Bbl's)		70			70
January 2020 - December 2020 [Member] | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,464,000,000			3,294,000
January 2020 - December 2020 [Member] | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential		0.67			2
January 2020 - December 2020 [Member] | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential		0.85			4
January 2020 - December 2020 [Member] | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		0.72			2.95
January 2020 - December 2020 [Member] | WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		366,000,000
Floors (in dollars per Mmbtu's/Bbl's)		0.37
January 2020 - December 2020 [Member] | WTI NYMEX Roll | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		0.37
January 2020 - December 2020 [Member] | Call option | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		2,342,400,000			2,342,400
Ceilings (in dollars per Mmbtu's/Bbl's)		70			70
January 2020 - December 2020 [Member] | Call option | Crude oil | Weighted Average
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)		70			70
January 2020 - December 2020 [Member] | Put options | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		915,000,000			915,000
Floors (in dollars per Mmbtu's/Bbl's)		55			55
January 2020 - December 2020 [Member] | Put options | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		55			55
January 2020 - December 2020 [Member] | Fixed Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		732,000,000
January 2020 - December 2020 [Member] | Fixed Swap | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		55.68
January 2020 - December 2020 [Member] | Fixed Swap | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		60
January 2020 - December 2020 [Member] | Fixed Swap | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		57.84
January 2020 - December 2020 [Member] | Fixed Swap | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU		2,928,000
January 2020 - December 2020 [Member] | Fixed Swap | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		2.56
February 2020 - December 2020 | WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,340,000,000
February 2020 - December 2020 | WTI NYMEX Roll | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		0.41
February 2020 - December 2020 | WTI NYMEX Roll | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		0.54
February 2020 - December 2020 | WTI NYMEX Roll | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		0.44
April 2020 - December 2020 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		275,000,000
Basis Differential		0.75
April 2020 - December 2020 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		0.75
January 2021 - December 2021 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,460,000,000
January 2021 - December 2021 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential		0.82
January 2021 - December 2021 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential		0.95
January 2021 - December 2021 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		0.85
January 2021 - December 2021 | WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,460,000,000
January 2021 - December 2021 | WTI NYMEX Roll | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		0.13
January 2021 - December 2021 | WTI NYMEX Roll | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		0.14
January 2021 - December 2021 | WTI NYMEX Roll | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		0.14
January 2021 - December 2021 | Fixed Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,460,000,000
January 2021 - December 2021 | Fixed Swap | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		50.70
January 2021 - December 2021 | Fixed Swap | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		52.80
January 2021 - December 2021 | Fixed Swap | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		51.91
January 2021 - December 2021 | Fixed Swap | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU		2,190,000
January 2021 - December 2021 | Fixed Swap | Natural gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		2.47
January 2021 - December 2021 | Fixed Swap | Natural gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		2.48
January 2021 - December 2021 | Fixed Swap | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		2.47
January 2022 - December 2022 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,460,000,000
January 2022 - December 2022 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential		0.85
January 2022 - December 2022 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential		0.95
January 2022 - December 2022 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		0.88
January 2022 - December 2022 | WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		2,555,000,000
January 2022 - December 2022 | WTI NYMEX Roll | Crude oil | Minimum
Derivative and hedging activities
Floor (in dollars per Mmbtu's/Bbl's)		(0.02)
January 2022 - December 2022 | WTI NYMEX Roll | Crude oil | Maximum
Derivative and hedging activities
Floor (in dollars per Mmbtu's/Bbl's)		0
January 2022 - December 2022 | WTI NYMEX Roll | Crude oil | Weighted Average
Derivative and hedging activities
Floor (in dollars per Mmbtu's/Bbl's)		(0.01)
January 2022 - December 2022 | Fixed Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,460,000,000
Floors (in dollars per Mmbtu's/Bbl's)		51.50
January 2022 - December 2022 | Fixed Swap | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		51.50

DERIVATIVE AND HEDGING ACTIVI_6

DERIVATIVE AND HEDGING ACTIVITIES - Netting Arrangements (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Aug. 31, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Assets
Gross Amounts Presented in the Consolidated Balance Sheet			$ 5,219			$ 69,717
Amounts Not Offset in the Consolidated Balance Sheet			(4,557)			(10,263)
Net Amount			662			59,454
Derivative Liabilities
Gross Amounts Presented in the Consolidated Balance Sheet			(12,923)			(12,907)
Amounts Not Offset in the Consolidated Balance Sheet			4,557			10,263
Net Amount			$ (8,366)			$ (2,644)
Amount received to settle outstanding positions		$ 100
Derivative contract novation fees.		$ 500
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor		Successor	Predecessor	Predecessor	Predecessor	Predecessor

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Activity related to ARO liability
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
Liability for asset retirement obligations at the beginning of the period		$ 10,153	$ 6,914	$ 6,914	$ 4,368
Liabilities settled and divested			(229)		(590)
Additions		293	354		988
Acquisitions					2,465
Accretion expense		144	307		329
Revisions in estimated cash flows			2,807		(646)
Liability for asset retirement obligations at the end of the period	$ 10,153	$ 10,590	$ 10,153		$ 6,914	$ 4,368

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Details)	Feb. 26, 2019USD ($)	Dec. 31, 2019USD ($)item
Drilling rig commitments
Obligations under drilling rig commitments
Non-cancelable termination penalties		$ 2,600,000
Drilling rig commitments		3,200,000
Purchase Commitments
Purchase commitments related to equipment
2020		$ 8,200,000
Gathering, transportation and sales | West Texas
Purchase commitments related to equipment
Number of long-term crude oil sales contracts to which the entity is committed | item		3
Gathering, transportation and sales | West Texas | Minimum
Purchase commitments related to equipment
Period of commitment for production from the date of first production		1 year
Gathering, transportation and sales | West Texas | Maximum
Purchase commitments related to equipment
Period of commitment for production from the date of first production		20 years
Litigation Against Vodenichar
Purchase commitments related to equipment
Litigation Settlement, Amount Awarded to Other Party	$ 9,107,054
Active Drilling Rig Commitment
Obligations under rig termination and stacking fees commitments
2020		$ 3,200,000

STOCKHOLDERS' EQUITY-Common sto

STOCKHOLDERS' EQUITY-Common stock and warrants (Details) $ / shares in Units, $ in Thousands	Oct. 08, 2019series$ / sharesshares	Oct. 02, 2019$ / shares	Feb. 09, 2018USD ($)$ / sharesshares	Apr. 06, 2017shares	Oct. 01, 2019USD ($)	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2019$ / sharesshares	Aug. 02, 2019	Sep. 09, 2016$ / sharesshares
Stockholders' equity
Shares issued	16,200,000		9,200,000	55,200,000
Common stock, par value (in dollars per share) | $ / shares	$ 0.0001		$ 0.0001			$ 0.0001	$ 0.0001
Share price (in dollars per share) | $ / shares		$ 19.74	$ 6.90
Proceeds from Issuance of Common Stock | $			$ 60,400		$ 155,929	$ 63,480
Number of warrants issued									4,700,000
Equivalent number shares of the warrants									4,700,000
Annualized Rate Of Increase To The Strike Price Of Warrants Issued	6.75	6.75
Exercise price (in dollars per share) | $ / shares									$ 14.04
Warrant term (in years)	3 years
Authorized shares of capital stock, after amendment of certificate of incorporation	101,000,000
Authorized shares of common stock, after amendment of certificate of incorporation	100,000,000					1,000,000,000	100,000,000
Number of series of warrants | series	3
Number of shares of common stock that can be purchased from warrants	1
Series A Warrants
Stockholders' equity
Warrants issued	1,798,322
Exercise price (in dollars per share) | $ / shares	$ 40.17						$ 40.51
Series B Warrants
Stockholders' equity
Warrants issued	2,247,985
Exercise price (in dollars per share) | $ / shares	$ 48.28						48.71
Series C Warrants
Stockholders' equity
Warrants issued	2,890,271
Exercise price (in dollars per share) | $ / shares	$ 60.45						$ 61.02
The Restructuring Support Agreement
Stockholders' equity
Warrant term (in years)								3 years
Convertible Preferred stock
Stockholders' equity
Preferred stock, par value (in dollars per share) | $ / shares	$ 0.0001
Authorized shares of preferred stock, after amendment of certificate of incorporation	1,000,000

STOCKHOLDERS' EQUITY - Preferre

STOCKHOLDERS' EQUITY - Preferred Stock and Non-Cash Preferred Stock Dividend (Details) - USD ($) $ / shares in Units, $ in Millions	Oct. 08, 2019	Feb. 09, 2018	Apr. 06, 2017	Feb. 27, 2017	Jan. 24, 2017	Jun. 30, 2017	Dec. 31, 2019	Oct. 02, 2019	Dec. 31, 2018	Mar. 16, 2017
Stockholders' equity
Shares issued	16,200,000	9,200,000	55,200,000
Share price (in dollars per share)		$ 6.90						$ 19.74
Par value of common stock (in dollars per share)	$ 0.0001	$ 0.0001					$ 0.0001		$ 0.0001
8% Convertible Preferred Stock
Stockholders' equity
Shares issued					5,518
Dividend rate (as a percent)					8.00%
Preferred stock, par value (in dollars per share)					$ 0.0001
Number of shares of common stock to be issued upon conversion					10,000
Proceeds from issuance of convertible preferred stock per share				$ 72,500
Gross proceeds from preferred stock offering				$ 400.1
Share price (in dollars per share)				$ 7.25	$ 8.12
Offering costs including placement agent fees				$ 11.9
Par value of common stock (in dollars per share)										$ 0.0001
Preferred dividend						$ 0
Conversion price (in dollars per share)					$ 0.87
Beneficial conversion proceeds					$ 48
Discount amortization period					65 months

STOCKHOLDERS' EQUITY - Incentiv

STOCKHOLDERS' EQUITY - Incentive Plans (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 29, 2020	Apr. 06, 2017
Restricted stock
Weighted average grant date fair value of the shares granted			$ 5,400
Number of Shares
Unvested outstanding shares at the beginning of the period (in shares)			2,272,893	2,272,893	2,272,893	745,507	1,738,077
Granted (in shares)			4,163,348			2,326,961	2,022,432
Vested (in shares)			(1,611,465)			(537,411)	(2,516,647)
Accelerated vesting (in shares)			(2,724,086)
Forfeited (in shares)			(2,100,690)			(262,164)	(498,355)
Unvested outstanding shares at the end of the period (in shares)						2,272,893	745,507	1,738,077
Weighted Average Grant Date fair Value Per Share
Unvested outstanding shares at the beginning of the period (in dollars per share)			$ 5.80	$ 5.80	$ 5.80	$ 7.05	$ 9.06
Granted (in dollars per share)			1.29			5.47	7.07
Vested (in dollars per share)			4.65			5.89	8.39
Accelerated vesting (in dollars per share)			2.07
Forfeited (in dollars per share)			$ 2.58			6.29	7.41
Unvested outstanding shares at the end of the period (in dollars per share)						$ 5.80	$ 7.05	$ 9.06
Aggregate Intrinsic Value
Aggregate Intrinsic Value at the beginning of the period (in dollars)			$ 3,864	$ 3,864	$ 3,864	$ 5,643	$ 16,234
Aggregate Intrinsic Value at the end of period (in dollars)						3,864	5,643	$ 16,234
Employees and non-employee directors
Number of Shares
Granted (in shares)		0
General and administrative
Stock-based compensation
Allocated share based compensation credit			$ 8,000
Compensation expense recorded		$ 0				$ 15,300	$ 36,800
Stock options
Number of Shares
Outstanding at the beginning of the period (in shares)			7,468,926	7,468,926	7,468,926	6,735,903	5,319,400
Granted (in shares)						1,206,800	1,790,605
Exercised (in shares)						(41,667)
Forfeited (in shares)			(5,182,238)			(432,110)	(374,102)
Cancelled (in shares)			(2,286,688)
Outstanding at the end of the period (in shares)						7,468,926	6,735,903	5,319,400
Weighted Average Exercise Price Per Share
Outstanding at the beginning of the period (in dollars per share)			$ 8.34	$ 8.34	$ 8.34	$ 8.84	$ 9.22
Granted (in dollars per share)						5.65	7.72
Exercised (in dollars per share)						7.75
Forfeited (in dollars per share)			8.38			8.68	8.82
Cancelled (in dollars per share)			$ 8.26
Outstanding at the end of the period (in dollars per share)						$ 8.34	$ 8.84	$ 9.22
Aggregate Intrinsic Value
Outstanding at the beginning of the period						$ 29	$ 631
Exercised						$ 29
Outstanding at the end of the period							$ 29	$ 631
Weighted Average Remaining Contractual Term
Outstanding at the end of the period						8 years 1 month 6 days	8 years 10 months 24 days	9 years 8 months 12 days
2016 Incentive Plan
Stock-based compensation
Incremental reduction to stock-based compensation expense			$ 9,500
2016 Incentive Plan | Common Stock
Stock-based compensation
Aggregate number of shares available										19,000,000
Maximum number of shares that remained reserved for issuance under the Plan						4,900,000
2016 Incentive Plan | Stock options
Stock-based compensation
Share Based Compensation Arrangements by Share Based Payment Award Options Annual Vesting Percentage.					33.33%
Vesting period					3 years
Expiration term					10 years
Weighted average remaining vesting period						10 months 24 days	1 year 2 months 12 days
Weighted average grant date fair value of the shares granted						$ 3,500	$ 7,800
Proceeds from stock options						300
Number of Shares
Granted (in shares)	0	0		0
Restricted stock
Unrecognized compensation expense stock option						$ 5,200	$ 13,000
2016 Incentive Plan | Restricted Stock
Stock-based compensation
Percentage of awards other than options vesting on the annual anniversary date of the grant					33.33%
Vesting period					3 years
Weighted average remaining vesting period						1 year 1 month 6 days	1 year 4 months 24 days
Unrecognized compensation expense other than options						$ 6,100	$ 3,200
Restricted stock
Weighted average grant date fair value of the shares granted						12,700	14,300
Additional Disclosures
Total fair value of shares vested			$ 1,800			$ 2,000	$ 16,100
2016 Incentive Plan | Restricted Stock | Non-employee director
Stock-based compensation
Vesting period					6 months
2020 Incentive Plan | Common Stock | Subsequent event
Stock-based compensation
Aggregate number of shares available									1,500,000

STOCKHOLDERS' EQUITY - Stock Op

STOCKHOLDERS' EQUITY - Stock Options (Details) - USD ($) $ in Millions	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stock-based compensation
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor		Predecessor	Predecessor
2016 Incentive Plan | Stock options
Stock-based compensation
Vesting period					3 years
Expiration term					10 years
Proceeds from exercise of stock options						$ 0.3
Unrecognized compensation expense stock option						$ 5.2	$ 13
Weighted average remaining vesting period						10 months 24 days	1 year 2 months 12 days
Weighted average grant date fair value of the shares granted						$ 3.5	$ 7.8

STOCKHOLDERS' EQUITY - Assumpti

STOCKHOLDERS' EQUITY - Assumptions (Details) - $ / shares	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
STOCKHOLDERS' EQUITY
Weighted average grant date fair value of grants					$ 2.92	$ 4.36
Assumptions:
Stock price volatility (as a percent)					52.08%	60.18%
Risk free rate of return (as a percent)					2.63%	1.94%
Expected term					6 years	6 years
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor

STOCKHOLDERS' EQUITY - Restrict

STOCKHOLDERS' EQUITY - Restricted Stock (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2019	Oct. 01, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stock-based compensation
Number of shares granted		4,163,348		2,326,961	2,022,432
Weighted average grant date fair value of the shares granted		$ 5.4
Employees and non-employee directors
Stock-based compensation
Number of shares granted	0
2016 Incentive Plan | Restricted Stock
Stock-based compensation
Vesting period			3 years
Percentage of awards other than options vesting on the annual anniversary date of the grant			33.33%
Weighted average grant date fair value of the shares granted				$ 12.7	$ 14.3
Unrecognized compensation expense other than options				$ 6.1	$ 3.2
Weighted average remaining vesting period				1 year 1 month 6 days	1 year 4 months 24 days
2016 Incentive Plan | Restricted Stock | Non-employee director
Stock-based compensation
Vesting period			6 months

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2018	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current:
Federal								$ 5,000
Total current income tax benefit (provision)								5,000
Deferred:
Federal				$ 95,791			$ (95,791)
Total deferred income tax benefit (provision)				95,791			(95,791)
Total income tax benefit (provision)		$ (95,800)		95,791		$ 0	$ (95,791)	$ 5,000
Differences between the actual income tax benefit (provision) and the expected income tax benefit (provision)
Federal statutory rate (as a percent)	21.00%		21.00%		21.00%		21.00%	35.00%
Expected tax benefit (provision)			$ 2,196	262,888			$ (29,767)	$ (185,740)
State income tax expense, net of federal benefit								(2,587)
Stock-based compensation				(6,093)			(350)
Change in state rate								(10,121)
Capital loss				(271,248)
Increase (reduction) in deferred tax asset				(9,287)			(201,903)	95,907
Change in valuation allowance and related items			(1,506)	(186,851)			136,432	392,846
Attribute reduction				(229,385)
Tax Cuts and Jobs Act of 2017								(280,874)
Permanent adjustments			(690)	(7,241)			(203)
Other				512				(4,431)
Total income tax benefit (provision)		(95,800)		$ 95,791		0	(95,791)	$ 5,000
Deferred noncurrent income tax assets:
Net operating loss carry-forwards		204,751	46,382			46,382	204,751
Net operating loss limitation under IRC Section 382						220,000
Built in loss adjustment Section 382		88,835	142,285			142,285	88,835
Capital loss carryforward			74,848			74,848
Stock-based compensation expense		8,509					8,509
Asset retirement obligations		1,011	2,224			2,224	1,011
Book-tax differences in property basis			200,478			200,478
Unrealized hedging transactions			1,618			1,618
Disallowed interest Section 163(j)		3,370	7,722			7,722	3,370
Basis difference in debt			2,142			2,142
Operating lease liability			666			666
Other		1,917	991			991	1,917
Gross deferred noncurrent income tax assets		308,393	479,356			479,356	308,393
Valuation allowance		(290,333)	(478,690)			(478,690)	(290,333)
Deferred noncurrent income tax assets		18,060	666			666	18,060
Deferred noncurrent income tax liabilities:
Basis difference in debt		(5,507)					(5,507)
Book-tax differences in property basis		(96,414)					(96,414)
Unrealized hedging transactions		(11,930)					(11,930)
Net current deferred income tax assets (liabilities)		(113,851)	(666)			(666)	(113,851)
Net current deferred income tax assets (liabilities)		$ (95,791)					$ (95,791)
Market value of equity upon emergence from bankruptcy			$ 524,800			$ 524,800
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor		Successor	Predecessor	Predecessor		Predecessor	Predecessor

INCOME TAXES - Operating loss c

INCOME TAXES - Operating loss carryforward (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Oct. 31, 2019	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
INCOME TAXES
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor				Successor	Predecessor	Predecessor		Predecessor	Predecessor
Expiration of net operating losses	$ 454,200		$ 891,500			$ 454,200			$ 891,500
Deferred tax expense			95,800			(95,791)		$ 0	95,791	$ (5,000)
Net operating loss carryforwards				$ 675,100	$ 675,100			675,100
Net operating loss carryforward subject expiration in 2037				103,200	103,200			$ 103,200
Carryforward period of NOLs that will expire in 2037								20 years
Net operating carryforward not subject to expiration				117,700	117,700			$ 117,700
Valuation allowance			290,333	478,690	478,690			478,690	290,333
Decrease in valuation allowance								188,400
Unrecognized tax benefits	0	$ 0	$ 0	0	$ 0	$ 0	$ 0	$ 0	$ 0	0
Open tax year (in years)									3 years
Interest and penalties	$ 0	$ 0		$ 0			$ 0		$ 0	$ 0

EARNINGS PER SHARE (Details)

EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Feb. 20, 2020	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017
Basic:
Net income (loss) available to common stockholders			$ (10,460)	$ (1,156,053)		$ 45,959	$ 487,679
Weighted average basic number of common shares outstanding			16,204	158,925		157,011	132,763
Basic net income (loss) per share of common share (in dollars per share)			$ (0.65)	$ (7.27)		$ 0.29	$ 3.67
Diluted:
Net income (loss) available to common stockholders			$ (10,460)	$ (1,156,053)		$ 45,959	$ 487,679
Weighted average basic number of common shares outstanding			16,204	158,925		157,011	132,763
Common stock equivalent shares representing shares included upon Vesting of restricted shares						284	813
Weighted average diluted number of common shares outstanding			16,204	158,925		157,295	133,576
Diluted net income (loss) per share of common stock (in dollars per share)			$ (0.65)	$ (7.27)		$ 0.29	$ 3.65
Common stock equivalents excluded from computation of diluted earnings per share of common stock because of anti-dilutive effect			6,900	14,100		13,100	17,100
Financial Designation, Predecessor and Successor [Fixed List]		Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor
Subsequent event
Diluted:
Purchase or receive an aggregate	1,300

ADDITIONAL FINANCIAL STATEMEN_3

ADDITIONAL FINANCIAL STATEMENT INFORMATION (Details) - USD ($) $ in Thousands	Oct. 01, 2019	Dec. 31, 2019	Oct. 01, 2019	Sep. 30, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 02, 2019	Jan. 01, 2019
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		$ 36,367			$ 26,432
Joint interest accounts		10,145			7,369
Other		1,992			1,917
Total	$ 37,826	48,504	$ 37,826		35,718		$ 37,826
Prepaids and other:
Prepaids		2,093			3,503
Income tax receivable		1,250			1,250
Funds in escrow		4,000
Other		36			35
Total	14,642	7,379	14,642		4,788		10,290
Funds in escrow and other:
Funds in escrow		580			570
Other		123			1,611
Total	1,138	703	1,138		2,181		1,138
Accounts payable and accrued liabilities:
Trade payables		36,038			68,959
Accrued oil and natural gas capital costs		22,781			41,461
Revenues and royalties payable		25,457			20,526
Accrued interest expense		604			16,971
Accrued employee compensation		2,947			3,421
Accrued lease operating expenses		9,230			6,292
Other		276			218
Total	$ 112,578	$ 97,333	$ 112,578		$ 157,848		$ 115,305	$ 157,763
Financial Designation, Predecessor and Successor [Fixed List]	Predecessor	Successor	Predecessor	Predecessor	Predecessor	Predecessor