Battalion Oil (BATL) 10-K 12 Mar 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Mar. 04, 2019	Jun. 30, 2018
Document and Entity Information
Entity Registrant Name	HALCON RESOURCES CORP
Entity Central Index Key	0001282648
Document Type	10-K
Document Period End Date	Dec. 31, 2018
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 Filer Category	Accelerated Filer
Entity Public Float			$ 589.9
Entity Common Stock, Shares Outstanding		160,261,776
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017
Oil, natural gas and natural gas liquids sales:
Other	$ 802		$ 1,080	$ 2,128
Total operating revenues	153,362		226,609	377,965
Production:
Lease operating	22,382		25,075	61,743
Workover and other	10,510		8,574	21,739
Taxes other than income	12,364		12,787	30,757
Gathering and other	14,677		60,090	40,783
Restructuring			128	7,535
General and administrative	41,395		62,056	111,351
Depletion, depreciation and accretion	46,899		77,527	110,207
Full cost ceiling impairment	420,934
(Gain) loss on sale of oil and natural gas properties			7,235	(721,573)
Gain on sale of oil and natural gas assets			(119,003)
Total operating expenses	569,161		134,469	(337,458)
Income (loss) from operations	(415,799)		92,140	715,423
Other income (expenses):
Net gain (loss) on derivative contracts	(27,740)		92,625	1,291
Interest expense and other, net	(28,861)		(43,015)	(71,097)
Reorganization items	(2,049)
Gain (loss) on extinguishment of debt				(114,931)
Total other income (expenses)	(58,650)		49,610	(184,737)
Income (loss) before income taxes	(474,449)		141,750	530,686
Income tax benefit (provision)	(4,744)		(95,791)	5,000
Net income (loss)	(479,193)		45,959	535,686
Non-cash preferred dividend				(48,007)
Preferred dividends and accretion on redeemable noncontrolling interest	(791)
Net income (loss) available to common stockholders	$ (479,984)		$ 45,959	$ 487,679
Net income (loss) per share of common stock:
Basic (in dollars per share)	$ (5.26)		$ 0.29	$ 3.67
Diluted (in dollars per share)	$ (5.26)		$ 0.29	$ 3.65
Weighted average common shares outstanding:
Basic (in shares)	91,228		157,011	132,763
Diluted (in shares)	91,228		157,295	133,576
Total oil, natural gas and natural gas liquids sales
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	$ 152,560		$ 225,529	$ 375,837
Oil
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	139,786		199,601	340,674
Natural gas
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	6,756		6,791	16,194
Natural gas liquids
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales	$ 6,018		$ 19,137	$ 18,969
Predecessor
Oil, natural gas and natural gas liquids sales:
Other		$ 1,339
Total operating revenues		266,843
Production:
Lease operating		50,032
Workover and other		22,507
Taxes other than income		24,453
Gathering and other		29,279
Restructuring		5,168
General and administrative		83,641
Depletion, depreciation and accretion		120,555
Full cost ceiling impairment		754,769
Other operating property and equipment impairment		28,056
Total operating expenses		1,118,460
Income (loss) from operations		(851,617)
Other income (expenses):
Net gain (loss) on derivative contracts		(17,998)
Interest expense and other, net		(122,249)
Reorganization items		913,722
Gain (loss) on extinguishment of debt		81,434
Total other income (expenses)		854,909
Income (loss) before income taxes		3,292
Income tax benefit (provision)		8,666
Net income (loss)		11,958
Series A preferred dividends		8,847
Preferred dividends and accretion on redeemable noncontrolling interest		(35,905)
Net income (loss) available to common stockholders		$ (32,794)
Net income (loss) per share of common stock:
Basic (in dollars per share)		$ (0.27)
Diluted (in dollars per share)		$ (0.27)
Weighted average common shares outstanding:
Basic (in shares)		120,513
Diluted (in shares)		120,513
Predecessor | Total oil, natural gas and natural gas liquids sales
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales		$ 265,504
Predecessor | Oil
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales		248,064
Predecessor | Natural gas
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales		9,511
Predecessor | Natural gas liquids
Oil, natural gas and natural gas liquids sales:
Total oil, natural gas and natural gas liquids sales		$ 7,929

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS $ in Thousands	Dec. 31, 2018USD ($)
Current assets:
Cash and cash equivalents	$ 46,866
Accounts receivable	35,718
Receivables from derivative contracts	57,280
Prepaids and other	4,788
Total current assets	144,652
Oil and natural gas properties (full cost method):
Evaluated	1,470,509
Unevaluated	971,918
Gross oil and natural gas properties	2,442,427
Less - accumulated depletion	(639,951)
Net oil and natural gas properties	1,802,476
Other operating property and equipment:
Other operating property and equipment	130,251
Less - accumulated depreciation	(8,388)
Net other operating property and equipment	121,863
Other noncurrent assets:
Receivables from derivative contracts	12,437
Funds in escrow and other	2,181
Total assets	2,083,609
Current liabilities:
Accounts payable and accrued liabilities	157,848
Liabilities from derivative contracts	3,768
Current portion of asset retirement obligation	126
Total current liabilities	161,742
Long-term debt, net	613,105
Other noncurrent liabilities:
Liabilities from derivative contracts	9,139
Asset retirement obligations	6,788
Deferred income taxes	95,791
Commitments and contingencies (Note 11)
Stockholders' equity:
Common stock: 1,000,000,000 shares of $0.0001 par value authorized; 160,612,852 and 149,379,491 shares issued and outstanding as of December 31, 2018 and 2017, respectively	16
Additional paid-in capital	1,095,367
Retained earnings (accumulated deficit)	101,661
Total stockholders' equity	1,197,044
Total liabilities and stockholders' equity	$ 2,083,609

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Stockholders' equity:
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, par value (in dollars per share)	$ 0.0001	$ 0.0001
Common stock, shares issued	160,612,852	149,379,491
Common stock, shares outstanding	160,612,852	149,379,491

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Preferred Stock	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)	Total
Balances (Predecessor) at Dec. 31, 2015		$ 12	$ 3,283,097	$ (3,230,695)	$ 52,414
Balances (in shares) (Predecessor) at Dec. 31, 2015	245	122,524
Increase (Decrease) in Stockholders' Equity
Net income (loss) | Predecessor				11,958	11,958
Conversion of preferred stock (in shares) | Predecessor	(23)	724
Preferred dividends on redeemable noncontrolling interest | Predecessor				(9,329)	(9,329)
Accretion of redeemable noncontrolling interest | Predecessor				(26,576)	(26,576)
Cash payment to Preferred Holders | Predecessor			(11,100)		(11,100)
Reverse stock split rounding (in shares) | Predecessor		5
Offering costs | Predecessor			(10)		(10)
Long-term incentive plan forfeitures (in shares) | Predecessor		(517)
Reduction in shares to cover individuals' tax withholding | Predecessor			(176)		(176)
Reduction in shares to cover individuals' tax withholding (in shares) | Predecessor		(498)
Stock-based compensation | Predecessor			4,995		4,995
Cancellation of Predecessor equity | Predecessor		$ (12)	(3,254,630)	3,254,642
Cancellation of Predecessor equity (in shares) | Predecessor	(222)	(122,238)
Issuance of Successor common stock and warrants		$ 9	571,114		571,123
Issuance of Successor common stock and warrants (in shares)		90,000
Balances (Predecessor) at Sep. 09, 2016		$ 12	3,254,630	(3,254,642)	(933,139)
Balances at Sep. 09, 2016		$ 9	571,114		571,123
Balances (in shares) (Predecessor) at Sep. 09, 2016	222	122,238
Balances (in shares) at Sep. 09, 2016		90,000
Increase (Decrease) in Stockholders' Equity
Fair value of equity issued to Predecessor common stockholders | Predecessor			(22,176)		(22,176)
Fair value of equity issued to Predecessor common stockholders					554,432
Net income (loss)				(479,193)	(479,193)
Preferred dividends on redeemable noncontrolling interest				(791)	(791)
Long-term incentive plan grants (in shares)		2,991
Stock-based compensation			21,549		21,549
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
Offering 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
Net income (loss)				45,959	45,959
Common stock issuance		$ 1	63,479		63,480
Common stock issuance (in shares)		9,200
Offering costs			(3,044)		(3,044)
Stock option exercises			323		323
Stock option exercises (in shares)		42
Long-term incentive plan grants		$ 2,327
Long-term incentive plan forfeitures		(262)
Reduction in shares to cover individuals' tax withholding		(73)	(301)		(301)
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

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income (loss)	$ (479,193)		$ 45,959	$ 535,686
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	46,899		77,527	110,207
Full cost ceiling impairment	420,934
(Gain) loss on sale of oil and natural gas properties			7,235	(721,573)
Gain on sale of oil and natural gas assets			(119,003)
Deferred income tax provision (benefit)			95,791
Stock-based compensation, net	21,519		15,266	36,757
Unrealized loss (gain) on derivative contracts	112,449		(84,274)	16,468
Amortization and write-off of deferred loan costs			1,405	1,795
Amortization of discount and premium	2,506		288	2,597
Reorganization items	(15,963)			(739)
Loss (gain) on extinguishment of debt				114,931
Accrued settlements on derivative contracts	(18,498)		10	24
Other expense (income)	79		(1,618)	(3,355)
Change in assets and liabilities:
Accounts receivable	(20,459)		378	103,166
Prepaids and other	857		5,840	(3,688)
Accounts payable and accrued liabilities	32,006		22,351	(77,685)
Net cash provided by (used in) operating activities	103,136		67,155	114,591
Cash flows from investing activities:
Oil and natural gas capital expenditures	(61,389)		(475,685)	(331,257)
Proceeds received from sales of oil and natural gas assets	888		3,816	2,003,894
Acquisition of oil and natural gas properties	(70)		(333,857)	(1,018,546)
Acquisition of other operating property and equipment				(25,538)
Other operating property and equipment capital expenditures	(750)		(116,995)	(53,214)
Proceeds received from sale of other operating property and equipment			216,083	21,798
Funds held in escrow and other	(1,721)		153	1,455
Net cash provided by (used in) investing activities	(63,042)		(706,485)	598,592
Cash flows from financing activities:
Proceeds from borrowings	115,000		438,000	1,349,000
Repayments of borrowings	(159,000)		(232,000)	(1,922,826)
Cash payments to Noteholders and Preferred Holders	(10,013)			(83,653)
Debt issuance costs			(4,334)	(17,799)
Preferred stock issued				400,055
Common stock issued			63,480
Offering costs and other			(3,021)	(13,913)
Net cash provided by (used in) financing activities	(54,013)		262,125	(289,136)
Net increase (decrease) in cash and cash equivalents	(13,919)		(377,205)	424,047
Cash and cash equivalents at beginning of period	13,943		424,071	24
Cash and cash equivalents at end of period	24	$ 13,943	46,866	424,071
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	3,605		37,526	90,835
Cash paid (refunded) for income taxes	5,000		(5,000)	1,250
Cash paid for reorganization items	18,012			739
Disclosure of non-cash investing and financing activities:
Asset retirement obligations	513		2,217	(29,313)
Accretion of non-cash preferred dividend				48,007
Preferred dividends on redeemable noncontrolling interest paid-in-kind	791
Accrued debt issuance costs			$ (90)	$ 90
Predecessor
Cash flows from operating activities:
Net income (loss)		11,958
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion		120,555
Full cost ceiling impairment		754,769
Other operating property and equipment impairment		28,056
Stock-based compensation, net		4,876
Unrealized loss (gain) on derivative contracts		263,732
Amortization and write-off of deferred loan costs		6,371
Amortization of discount and premium		1,515
Reorganization items		(929,084)
Loss (gain) on extinguishment of debt		(81,434)
Other expense (income)		(4,233)
Change in assets and liabilities:
Accounts receivable		47,920
Prepaids and other		(4,329)
Accounts payable and accrued liabilities		(45,324)
Net cash provided by (used in) operating activities		175,348
Cash flows from investing activities:
Oil and natural gas capital expenditures		(226,741)
Proceeds received from sales of oil and natural gas assets		(407)
Acquisition of oil and natural gas properties		124
Other operating property and equipment capital expenditures		(950)
Proceeds received from sale of other operating property and equipment		138
Funds held in escrow and other		62
Net cash provided by (used in) investing activities		(227,774)
Cash flows from financing activities:
Proceeds from borrowings		886,000
Repayments of borrowings		(727,648)
Cash payments to Noteholders and Preferred Holders		(97,521)
Debt issuance costs		(1,977)
Offering costs and other		(511)
Net cash provided by (used in) financing activities		58,343
Net increase (decrease) in cash and cash equivalents		5,917
Cash and cash equivalents at beginning of period	$ 13,943	8,026
Cash and cash equivalents at end of period		13,943
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest		139,930
Cash paid for reorganization items		15,362
Disclosure of non-cash investing and financing activities:
Accrued capitalized interest		(23,966)
Asset retirement obligations		939
Preferred dividends on redeemable noncontrolling interest paid-in-kind		9,329
Accretion of redeemable noncontrolling interest		26,576
Accrued debt issuance costs		$ 1,176

SUMMARY OF SIGNIFICANT EVENTS A

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2018
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 Halcón Resources Corporation (Halcón or the Company) 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 July 27, 2016 (the Petition Date), the Company and certain of its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a joint prepackaged plan of reorganization (the Plan). On September 8, 2016, the Bankruptcy Court entered an order confirming the Plan and on September 9, 2016, the Plan became effective (the Effective Date) and the Halcón Entities emerged from chapter 11 bankruptcy. The Company’s subsidiary, HK TMS, LLC which was divested on September 30, 2016, was not part of the chapter 11 bankruptcy filings. See Note 2, “Reorganization,” for further details on the Company’s chapter 11 bankruptcy and the Plan and Note 5, “Acquisitions and Divestitures,” for further details on the divestiture of HK TMS, LLC. 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. 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 September 9, 2016 are not comparable to its consolidated financial statements prior to, and including, September 9, 2016. 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 September 9, 2016. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016. 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 5, “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 that are 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 and Cash Equivalents 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. 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, 2018 and 2017, allowances for doubtful accounts were approximately $0.2 million and $0.7 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, 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: gas gathering systems, thirty years, gas treating systems and 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. 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 September 9, 2016. Refer to Note 5, “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. For the period from January 1, 2016 through September 9, 2016, the Company recorded a non-cash impairment charge of $28.1 million related to $32.8 million gross investments in gas gathering infrastructure that were deemed non-economical due to a shift in exploration, drilling and developmental plans in a low commodity price environment. This impairment was recorded in “Other operating property and equipment impairment” in the Company’s consolidated statements of operations and in “Other operating property and equipment” in the Company’s consolidated balance sheets. In accordance with ASC 820, Fair Value Measurements and Disclosures (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 estimate of the fair value of the Company’s gas gathering systems was based on an income approach that estimated future cash flows associated with those assets over the remaining asset lives. This estimation includes the use of unobservable inputs, such as estimated future production, gathering and compression revenues and operating expenses. The use of these unobservable inputs results in the fair value estimate of the Company’s gas gathering systems being classified as Level 3. 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 year ended December 31, 2018, 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 period. In 2017 and 2016, 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 each 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, when derivative contracts are available at terms (or prices) acceptable to the Company, it may hedge a portion of its forecasted oil, natural gas, and natural gas liquids production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction. 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, 2018 and 2017. 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, 2018, 2017 and 2016. 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, net ” on the Company’s consolidated statements of operations. Refer to Note 13, “ Income Taxes, ” for more details. Generally, the Company’s income tax years 2015 through 2018 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. 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 and other operating property and equipment. 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 and other operating property and equipment as these obligations are incurred. Restructuring The Company had reductions in its workforce in conjunction with its divestiture activities in 2017 and the decrease in drilling and developmental activities planned for 2016. Consequently, for the years ended December 31, 2018 and 2017, and the period from January 1, 2016 through September 9, 2016, the Company incurred approximately $0.1 million, $7.5 million and $5.2 million, respectively, in severance costs and accelerated stock-based compensation expense related to the termination of certain employees. These costs were recorded in “ Restructuring ” on the consolidated statements of operations. Redeemable Noncontrolling Interest On June 16, 2014, funds and accounts managed by affiliates of Apollo Global Management (Apollo) contributed $150 million in cash to HK TMS, a Delaware limited liability company, which was then wholly owned by the Company and held all of the Company’s acreage in the Tuscaloosa Marine Shale (TMS) formation, located in Mississippi and Louisiana, in exchange for the issuance by HK TMS of 150,000 preferred shares. Holders of the HK TMS preferred shares were to receive quarterly cash dividends of 8% cumulative perpetual per annum, subject to HK TMS’ option to pay such dividends “in-kind” through the issuance of additional preferred shares. The preferred shares were expected to be automatically redeemed and cancelled when the holders received cash dividends and distributions on the preferred shares equating to the greater of a 12% annual rate of return plus principal and 1.25 times their investment plus applicable fees (the Redemption Price), subject to adjustment under certain circumstances. On September 30, 2016, certain wholly-owned subsidiaries of the Company executed an Assignment and Assumption Agreement with an affiliate of Apollo pursuant to which 100% of the common shares in HK TMS (the Membership Interests) were assigned to Apollo (the HK TMS Divestiture). In exchange for the assignment, Apollo assumed all obligations relating to such Membership Interests. See Note 5, “ Acquisitions and Divestitures ,” for further information regarding the HK TMS Divestiture. The preferred shares were classified as “ Redeemable noncontrolling interest ” and included in “ Mezzanine equity ” between total liabilities and stockholders’ equity on the consolidated balance sheets pursuant to ASC 480-10-S99-3A. The preferred shares were considered probable of becoming redeemable and therefore were accreted up to the estimated required redemption value. The accretion was presented as a deemed dividend and recorded in “ Redeemable noncontrolling interest ” on the consolidated balance sheets and within “ Preferred dividends and accretion on redeemable noncontrolling interest ” on the consolidated statements of operations. In accordance with ASC 480-10-S99-3A, an adjustment to the carrying amount presented in mezzanine equity was recognized as charges against retained earnings and reduced income available to common stockholders in the calculation of earnings per share. For the period of September 10, 2016 through September 30, 2016 and January 1, 2016 through September 9, 2016, HK TMS issued 791 and 9,329 additional preferred shares to Apollo for dividends paid-in-kind, respectively. These dividends were presented within “ Preferred dividends and accretion on redeemable noncontrolling interest ” on the consolidated statements of operations. HK TMS was not included in the chapter 11 bankruptcy filings or the Restructuring Support Agreement discussed in Note 2, “ Reorganization .” 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 $1.5 million and $2.2 million for the years ended December 31, 2018 and 2017, respectively. The Company provided matching contributions of $0.8 million and $2.0 million for the period September 10, 2016 through December 31, 2016 and the period January 1, 2016 through September 9, 2016, 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, 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. The gathering system is expected to be operational by February 28, 2019. Beginning in the fourth quarter of 2018, the Company began selling its crude oil to SCM while the gathering system is under construction. For the year ended December 31, 2018, the Company received $13.0 million and recorded a $10.9 million receivable from SCM for its crude oil sales. The agreement with SCM was the culmination of a lengthy process during which the Company analyzed the most effective method of gathering and transportation of its future oil production in these areas. During the course of its investigation, the Company considered a variety of alternatives and solicited and received numerous third party proposals. The Company received and evaluated proposals from eleven companies covering some or all of its oil production in the region and determined that among the proposals it received, SCM’s was superior for economic and strategic reasons. Because certain funds under the control of Ares Management LLC (Ares) are the majority owners and controlling parties of SCM, the Audit Committee of the board of directors of the Company and the disinterested members of the Company’s board of directors evaluated and approved (in a vote that excluded the Company director who is employed by Ares) the process by which the Company determined the SCM proposal to be superior to other alternatives, as well as the principal terms of the agreement, in accordance with applicable Company policies, including its Code of Conduct and Corporate Governance Guidelines (copies of which are available through the Company’s website at www.halconresources.com ) and the Company’s procedures for the review and approval of transactions with related parties. Ares also controls other funds which own in excess of ten percent (10%) of the common stock of the Company. No Ares fund that is a stockholder of the Company has an interest in SCM but one of the Company’s directors, who is employed by Ares, also serves on the board of directors of SCM’s parent company. Gas Purchase and Processing Agreement On November 16, 2017, 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. The facilities were completed and placed in service in May 2018. For the year ended December 31, 2018, the Company received $0.4 million from Salt Creek under the gas purchase and processing agreement. The agreement with Salt Creek was the culmination of a lengthy process during which the Company investigated the most efficient method of gathering, processing and marketing its future natural gas production in these areas. During the course of its investigation, the Company considered the construction of Company owned gas gathering and processing facilities, Company owned high pressure pipeline to a third-party processing plant and solicited and received proposals from numerous third parties for long-term gathering and processing options. The Company received proposals from eight midstream companies, determined that third party options were more attractive from a variety of business perspectives, and that among the proposals it received, Salt Creek’s was superior. Certain funds under the control of Ares are the majority owners and controlling parties of Salt Creek. Ares also controls other funds which own in excess of ten percent (10%) of the stock of the Company. No Ares fund that is a stockholder of the Company has an interest in Salt Creek but one of the Company’s directors, who is employed by Ares, and is a director of the Company, also serves on the board of directors of Salt Creek. Due to these relationships, prior to entering into the gas purchase and processing agreement, the process by which the Company determined the Salt Creek proposal to be superior to other alternatives, as well as the terms of the agreement, were evaluated and approved in advance by the Audit Committee of the Company and the disinterested members of the Company’s board of directors, in a vote that excluded the Company director who is employed by Ares in accordance with applicable Company policies, including its Code of Conduct and Corporate Governance Guidelines (copies of which are available through the Company’s website at www.halconresources.com ), and the Company’s procedures for the review and approval of transactions with related parties. Charter of Aircraft In the ordinary course of its business, the Company occasionally charters a private aircraft for business use. Floyd C. Wilson, Halcón’s former Chairman, Chief Executive Officer and President, owns an aircraft which the Company has chartered from time to time. For a portion of 2017, Mr. Wilson’s aircraft was managed by an independent air charter company unaffiliated with both Mr. Wilson and Halcón. The aircraft in the air charter company’s fleet are available to the public for charter based upon a standard fee schedule established by the air charter company, with the fees dependent primarily upon the type and size of the aircraft utilized and the duration of the flight. Because the air charter company established fees for the use of the aircraft in its fleet, Mr. Wilson did not receive any greater benefit from Halcón’s charter of the aircraft indirectly owned by him than he would have if any third party were to charter the aircraft. During the course of 2017, Mr. Wilson terminated the independent air charter company and removed his aircraft from the charter company’s fleet, pending his search for a new charter company to manage his aircraft. During the search period for a new charter company, fees for the use of Mr. Wilson’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. The terms for this use were evaluated and approved by the Audit Committee of the Company, and subsequently by the disinterested members of the Company’s board of directors upon the recommendation of the Audit Committee, in accordance with the Company’s procedures for the review and approval of transactions with related parties. During the year ended December 31, 2018, the Company paid approximately $0.9 million to Mr. Wilson for the Company’s use of the aircraft. As of December 31, 2018, the Company recorded a $0.2 million payable to Mr. Wilson. The payable is recorded in “ Accounts payable and accrued liabilities ,” on the Company’s unaudited condensed consolidated balance sheet. The Company has terminated all charter arrangements with Mr. Wilson relating to the use of his aircraft. Recently Issued Accounting Pronouncements In January 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). For public business entities, ASU 2017-01 is effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2017. The amendments in this ASU should be applied prospectively on or after the effective date. The ASU was issued to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The Company applied the provisions of ASU 2017-01 to the acquisition of the West Quito Draw Properties and the divestiture of the Water Assets, which are discussed further in Note 5, “ Acquisitions and Divestitures .” In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) (ASU 2016-15). For public business entities, ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. The areas for simplification in this ASU involve addressing eight specific classification issues in the statement of cash flows. An entity should apply the amendments in this AS

REORGANIZATION

REORGANIZATION	12 Months Ended
	Dec. 31, 2018
REORGANIZATION
REORGANIZATION	2. REORGANIZATION On June 9, 2016, the Halcón Entities entered into a restructuring support agreement (the Restructuring Support Agreement) with certain holders of the Company’s 13% senior secured third lien notes due 2022 (the Third Lien Noteholders), the Company’s 8.875% senior unsecured notes due 2021, 9.25% senior unsecured notes due 2022 and 9.75% senior unsecured notes due 2020 (collectively, the Unsecured Noteholders), the holder of the Company’s 8% senior unsecured convertible note due 2020 (the Convertible Noteholder), and certain holders of the Company’s 5.75% Series A Convertible Perpetual Preferred Stock. On July 27, 2016, the Halcón Entities filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware to effect an accelerated prepackaged bankruptcy restructuring as contemplated in the Restructuring Support Agreement. On September 8, 2016, the Bankruptcy Court entered an order confirming the Company’s plan of reorganization and on September 9, 2016, the Halcón Entities emerged from chapter 11 bankruptcy. Upon emergence, pursuant to the terms of the Plan, the following significant transactions occurred: · the Predecessor Company’s financing facility was refinanced and replaced with a debtor-in-possession senior-secured, super-priority revolving credit facility, which was subsequently converted into the Senior Credit Agreement (refer to Note 7, “ Long-term Debt ” for credit agreement definitions and further details regarding the Senior Credit Agreement); · the Predecessor Company’s Second Lien Notes (consisting of $700.0 million in aggregate principal amount outstanding of 8.625% senior secured notes due 2020 and $112.8 million in aggregate principal amount outstanding of 12% senior secured notes due 2022) were unimpaired and reinstated; · the Predecessor Company’s Third Lien Notes were cancelled and the Third Lien Noteholders received their pro rata share of 76.5% of the common stock of reorganized Halcón, together with a cash payment of $33.8 million, and accrued and unpaid interest on their notes through May 15, 2016, which interest was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims; · the Predecessor Company’s Unsecured Notes were cancelled and the Unsecured Noteholders received their pro rata share of 15.5% of the common stock of reorganized Halcón, together with a cash payment of $37.6 million and warrants to purchase 4% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), and accrued and unpaid interest on their notes through May 15, 2016, which interest was paid prior to the chapter 11 bankruptcy filing, in full and final satisfaction of their claims; · the Predecessor Company’s Convertible Note was cancelled and the Convertible Noteholder received 4% of the common stock of reorganized Halcón, together with a cash payment of $15.0 million and warrants to purchase 1% of the common stock of reorganized Halcón (with a four year term and an exercise price of $14.04 per share), in full and final satisfaction of their claims; · the general unsecured claims were unimpaired and paid in full in the ordinary course; · all outstanding shares of the Predecessor Company’s Series A Preferred Stock were cancelled and the Preferred Holders received their pro rata share of $11.1 million in cash, in full and final satisfaction of their interests; and · all of the Predecessor Company’s outstanding shares of common stock were cancelled and the common stockholders received their pro rata share of 4% of the common stock of reorganized Halcón, in full and final satisfaction of their interests. Each of the foregoing percentages of equity in the reorganized Company were as of September 9, 2016 and subject to dilution from the exercise of the warrants described above, awards under the management incentive plan and other future issuances of equity securities. See Note 7, “Long-term Debt,” and Note 12, “Stockholders’ Equity,” for further information regarding the Company’s Successor and Predecessor debt and equity instruments.

FRESH-START ACCOUNTING

FRESH-START ACCOUNTING	12 Months Ended
	Dec. 31, 2018
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 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 may 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 application 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 value 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 at the Effective Date was below the midpoint of the Court approved range of $1.6 billion to $1.8 billion, primarily reflecting the decline in forward commodity prices during the period between the Company’s analysis performed in advance of the July 2016 chapter 11 bankruptcy filing and the Effective Date. 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 September 9, 2016. The Company’s principal assets are its oil and natural gas properties. For purposes of estimating the fair value of the Company’s proved, probable and possible 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 10.5% for proved reserves and 12.5% 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. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 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 analysts’ estimated prices. In estimating the fair value of the Company’s unproved acreage that was not included in the valuation of probable and possible reserves, 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 September 9, 2016 (in thousands): September 9, 2016 Enterprise Value $ 1,618,888 Plus: Cash 13,943 Less: Fair value of debt (1,016,160) Less: Fair value of redeemable noncontrolling interest (41,070) Less: Fair value of other long-term liabilities (4,478) Less: Fair value of warrants (16,691) Fair Value of Successor common stock $ 554,432 The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of September 9, 2016 (in thousands): September 9, 2016 Enterprise Value $ 1,618,888 Plus: Cash 13,943 Plus: Current liabilities 178,639 Plus: Noncurrent asset retirement obligation 32,156 Reorganization Value of Successor assets $ 1,843,626 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 and liabilities. Amounts included in the table below are rounded to thousands. As of September 9, 2016 Predecessor Reorganization Fresh-Start Successor Company Adjustments Adjustments Company Current assets: Cash and cash equivalents $ 111,464 $ (97,521) (1) $ — $ 13,943 Accounts receivable 116,859 — — 116,859 Receivables from derivative contracts 97,648 — — 97,648 Restricted cash 17,164 — — 17,164 Prepaids and other 8,961 — (1,332) (7) 7,629 Total current assets 352,096 (97,521) (1,332) 253,243 Oil and natural gas properties (full cost method): Evaluated 7,712,003 — (6,497,874) (8) 1,214,129 Unevaluated 1,193,259 — (861,144) (8) 332,115 Gross oil and natural gas properties 8,905,262 — (7,359,018) 1,546,244 Less—accumulated depletion (6,803,231) — 6,803,231 (8) — Net oil and natural gas properties 2,102,031 — (555,787) 1,546,244 Other operating property and equipment: Other operating property and equipment 100,079 — (62,008) (9) 38,071 Less—accumulated depreciation (24,154) — 24,154 (9) — Net other operating property and equipment 75,925 — (37,854) 38,071 Other noncurrent assets: Receivables from derivative contracts 4,431 — — 4,431 Funds in escrow and other 1,610 — 27 (10) 1,637 Total assets $ 2,536,093 $ (97,521) $ (594,946) $ 1,843,626 Current liabilities: Accounts payable and accrued liabilities $ 160,000 $ 13,688 (2) $ — $ 173,688 Liabilities from derivative contracts 102 — — 102 Other 414 — 4,435 (11)(12) 4,849 Total current liabilities 160,516 13,688 4,435 178,639 Long-term debt, net 1,031,114 — (14,954) (13) 1,016,160 Liabilities subject to compromise 2,007,703 (2,007,703) (3) — — Other noncurrent liabilities: Liabilities from derivative contracts 525 — — 525 Asset retirement obligations 48,955 — (16,799) (12) 32,156 Other 528 — 3,425 (11)(14) 3,953 Commitments and contingencies Mezzanine equity: Redeemable noncontrolling interest 219,891 — (178,821) (14) 41,070 Stockholders' equity: Preferred stock (Predecessor) — — (4) — — Common Stock (Predecessor) 12 (12) (4) — — Common Stock (Successor) — 9 (5) — 9 Additional paid-in capital (Predecessor) 3,287,906 (3,287,906) (4) — — Additional paid-in capital (Successor) — 571,114 (5) — 571,114 Retained earnings (accumulated deficit) (4,221,057) 4,613,289 (6) (392,232) (15) — Total stockholders' equity (933,139) 1,896,494 (392,232) 571,123 Total liabilities and stockholders' equity $ 2,536,093 $ (97,521) $ (594,946) $ 1,843,626 Reorganization adjustments 1) The table below details cash payments as of September 9, 2016, pursuant to the terms of the Plan described in Note 2, “Reorganization,” (in thousands): Payment to Third Lien Noteholders $ 33,826 Payment to Unsecured Noteholders 37,595 Payment to Convertible Noteholder 15,000 Payment to Preferred Holders 11,100 Total Uses $ 97,521 2) In connection with the chapter 11 bankruptcy, the Company modified and rejected certain office lease arrangements and paid approximately $3.4 million for these modifications and rejections subsequent to the emergence from chapter 11 bankruptcy. This amount also reflects $10.3 million paid to the Company’s restructuring advisors subsequent to the emergence from chapter 11 bankruptcy. 3) Liabilities subject to compromise were as follows (in thousands): 13.0% senior secured third lien notes due 2022 $ 1,017,970 9.25% senior notes due 2022 37,194 8.875% senior notes due 2021 297,193 9.75% senior notes due 2020 315,535 8.0% convertible note due 2020 289,669 Accrued interest 46,715 Office lease modification and rejection fees 3,427 Liabilities subject to compromise 2,007,703 Fair value of equity and warrants issued to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder (548,947) Cash payments to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder (86,421) Office lease modification and rejection fees (3,427) Gain on settlement of Liabilities subject to compromise $ 1,368,908 4) Reflects the cancellation of Predecessor equity, as follows (in thousands): Predecessor Company stock $ 3,287,918 Fair value of equity issued to Predecessor common stockholders (22,176) Cash payment to Preferred Holders (11,100) Cancellation of Predecessor Company equity $ 3,254,642 5) Reflects the issuance of Successor equity. In accordance with the Plan, the Successor Company issued 3.6 million shares of common stock to the Predecessor Company’s existing common stockholders, 68.8 million shares of common stock to the Third Lien Noteholders, 14.0 million shares of common stock to the Unsecured Noteholders, and 3.6 million shares of common stock to the Convertible Noteholder. This amount is subject to dilution by warrants issued to the Unsecured Noteholders and the Convertible Noteholder totaling 4.7 million shares with an exercise price of $14.04 per share and a term of four years. The fair value of the warrants was estimated at $3.52 per share using a Black-Scholes-Merton valuation model. 6) The table below reflects the cumulative effect of the reorganization adjustments discussed above (in thousands): Gain on settlement of Liabilities subject to compromise $ 1,368,908 Accrued reorganization items (10,261) Cancellation of Predecessor Company equity 3,254,642 Net impact to retained earnings (accumulated deficit) $ 4,613,289 Fresh-start accounting adjustments 7) Reflects the reclassification of tubulars and well equipment to “Oil and natural gas properties.” 8) 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, probable and possible 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 10.5% for proved reserves and 12.5% 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. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 per barrel 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 analysts’ estimated prices. In estimating the fair value of the Company’s unproved acreage that was not included in the valuation of probable and possible reserves, 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. 9) In estimating the fair value of its other operating property and equipment, the Company used a combination of the income, cost, and market approaches. For purposes of estimating the fair value of its gas gathering assets, an income approach was used that estimated future cash flows associated with the assets over the remaining useful lives. The valuation included such inputs as estimated future production, gathering and compression revenues, and operating expenses that were discounted at a weighted average cost of capital rate of 9.5%. For purposes of estimating the fair value of its other operating assets, the Company used a combination of the market and cost approaches. A market approach was relied upon to value land and computer equipment, 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. 10) Reflects the adjustment of the Company’s equity method investment in SBE Partners, L.P. to fair value based on an income approach, which calculated the discounted cash flows of the Company’s share of the partnership’s interest in oil and gas estimated proved reserves. The anticipated cash flows of the reserve were risked by reserve category and discounted at 10.5%. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 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 analysts’ estimated prices. 11) Records an intangible liability of approximately $8.3 million, $4.5 million of which was recorded as current, to adjust the Company’s active rig contract to fair value at September 9, 2016. The intangible liability will be amortized over the remaining life of the contract. 12) Reflects the adjustment of asset retirement obligations to fair value using estimated plugging and abandonment costs as of September 9, 2016, adjusted for inflation and then discounted at the appropriate credit-adjusted risk free rate ranging from 5.5% to 6.6% depending on the life of the well. The fair value of asset retirement obligations was estimated at $32.5 million, approximately $0.3 million of which was recorded as current. 13) Reflects the adjustment of the 2020 Second Lien Notes and the 2022 Second Lien Notes to fair value. The fair value estimate was based on quoted market prices from trades of such debt on September 9, 2016. 14) Reflects the adjustment of the Company’s redeemable noncontrolling interest and related embedded derivative of HK TMS to fair value. The fair value of the redeemable noncontrolling interest was estimated at $41.1 million and the embedded derivative was estimated at zero. For purposes of estimating the fair values, an income approach was used that estimated fair value based on the anticipated cash flows associated with HK TMS proved reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 12.5%. The value of the redeemable noncontrolling interest was further reduced by a probability factor of the potential assignment of the common shares of HK TMS to Apollo, which occurred subsequent to the fresh-start date. Refer to Note 5, “ Acquisitions and Divestitures, ” for further information regarding the HK TMS Divestiture on September 30, 2016. 15) 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 ” in the Company’s consolidated statements of operations. The following table summarizes the net reorganization items (in thousands): Successor Predecessor Period from Period from September 10, 2016 January 1, 2016 through through December 31, 2016 September 9, 2016 Gain on settlement of Liabilities subject to compromise $ — $ 1,368,908 Fresh start adjustments — (392,232) Reorganization professional fees and other (2,049) (30,287) Write-off debt discounts/premiums and debt issuance costs — (32,667) Gain (loss) on reorganization items $ (2,049) $ 913,722

OPERATING REVENUES

OPERATING REVENUES	12 Months Ended
	Dec. 31, 2018
OPERATING REVENUES
OPERATING REVENUES	4. OPERATING REVENUES Adoption of ASC 606, Revenue from Contracts with Customers On January 1, 2018, the Company adopted ASC 606 using the modified retrospective approach applied to all contracts as of the date of adoption. Reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported under the accounting standards in effect for those periods. The adoption of ASC 606 resulted in offsetting changes to revenues and expenses associated with certain natural gas gathering and processing agreements, and therefore there was no cumulative effect of applying ASC 606 to the opening balance of “ Retained earnings (accumulated deficit) .” The net impact of adopting ASC 606 for the year ended December 31, 2018 was a decrease of $1.1 million to “ Natural gas ” and an offsetting decrease of $1.1 million to “ Gathering and other ,” on the consolidated statements of operations. These changes result from principal versus agent considerations under ASC 606 for the Company’s natural gas gathering and processing arrangements in place with midstream companies. 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 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, the Company is the principal and the midstream entity is the agent in the sale transaction with the third party purchaser of processed commodities. In these instances, 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 as “ Gathering and other .” 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 $26.4 million and $24.1 million as of December 31, 2018 and 2017, respectively, as “ Accounts receivable ” on the unaudited condensed 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 September 10, 2016 January 1, 2016 Years Ended December 31, through through 2018 2017 (1) December 31, 2016 (1) September 9, 2016 (1) Operating revenues: Oil, natural gas and natural gas liquids sales: Oil $ 199,601 $ 340,674 $ 139,786 $ 248,064 Natural gas 6,791 16,194 6,756 9,511 Natural gas liquids 19,137 18,969 6,018 7,929 Total oil, natural gas and natural gas liquids sales 225,529 375,837 152,560 265,504 Other 1,080 2,128 802 1,339 Total operating revenues $ 226,609 $ 377,965 $ 153,362 $ 266,843 (1) As noted above, prior period amounts have not been adjusted under the modified retrospective method of adoption. 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 transportation costs and other 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, and therefore any fees incurred to gather or process the natural gas are presented separately as “ Gathering and other .” 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 .” 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, 2018
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES	5. ACQUISITIONS AND DIVESTITURES Acquisitions West Quito Draw Properties On February 6, 2018, 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, and the Company closed the transaction on April 4, 2018. The Company funded the cash consideration for the acquisition of the West Quito Draw Properties with the net proceeds from the issuance of the Additional 2025 Notes and common stock, which are discussed in Note 7, “ Long-term Debt ,” and Note 12, “ Stockholders’ Equity ,” respectively. Monument Draw Assets (Ward and Winkler Counties, Texas) On December 9, 2016, the Company entered into an agreement with a private company, pursuant to which the Company acquired the rights to purchase acreage in the Monument Draw area of the Delaware Basin, located in Ward and Winkler Counties, Texas (the Ward County Assets) prospective for the Wolfcamp and Bone Spring formations for an initial purchase price of $11,000 per acre. The Ward County Assets are divided into two tracts (the Southern Tract and the Northern Tract) with separate options for each tract. The agreement was subsequently amended on June 14, 2017 to increase the purchase price of the Southern Tract and the Northern Tract acreage, from $11,000 per acre to $13,000 per acre, for rights to additional depths in the acreage under option. Pursuant to the terms of the agreement, on June 15, 2017, the Company purchased the Southern Tract acreage for approximately $87.4 million and on January 9, 2018, the Company purchased the Northern Tract acreage for approximately $108.2 million. Acquisition of Additional Properties in Monument Draw (Ward and Winkler Counties, Texas) On December 13, 2017, 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. Hackberry Draw Assets (Pecos and Reeves Counties, Texas) On January 18, 2017, Halcón Energy Properties, Inc., 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. The transaction had an effective date of November 1, 2016. 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 Senior Credit Agreement. Refer to Note 12, “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 liabilites 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 Senior Credit Agreement. (2) In accordance with the purchase agreement, the effective date of the acquisition was November 1, 2016 and therefore revenues, expenses and related capital expenditures from November 1, 2016 through February 28, 2017, 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, the period of September 10, 2016 through December 31, 2016 and the period of January 1, 2016 through September 9, 2016 as though the Pecos County Acquisition had been completed as of the beginning of the comparable prior annual reporting period, or January 1, 2016. The pro forma combined results of operations for the year ended December 31, 2017, the period of September 10, 2016 through September 30, 2016 and the period of January 1, 2016 through September 9, 2016 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. Successor Predecessor Period from Period from September 10, 2016 January 1, 2016 Year ended through through December 31, 2017 December 31, 2016 September 9, 2016 (Unaudited) (Unaudited) (Unaudited) Revenue $ 385,867 $ 166,499 $ 288,902 Net income (loss) 542,724 (475,580) 16,513 Net income (loss) available to common stockholders 494,717 (476,371) (28,239) Pro forma net income (loss) per share of common stock: Basic $ 3.73 $ (5.22) $ (0.23) Diluted $ 3.70 $ (5.22) $ (0.23) 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, 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 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 for all periods presented in the above table. Divestitures Water Infrastructure Assets On December 20, 2018, 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 $214.1 million in cash (the Water Infrastructure Divestiture). The effective date of the transaction was October 1, 2018. Additional incentive payments of up to $25.0 million per year for the next five years are 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. The Company’s ability to achieve the incentive thresholds will be driven by, among other things, its development program which will consider future market conditions and is subject to change. 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 are no drilling or throughput commitments associated with the Water Infrastructure Divestiture. The Purchaser will receive a current 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. 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. ” Williston Basin Non-Operated Assets On September 19, 2017, 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 and the transaction closed on November 9, 2017. 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, 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 and the transaction closed on September 7, 2017. The Company used the net proceeds from the sale to repay borrowings outstanding under its Senior 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 7, “ Long-term Debt ”), redeem all of its 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 6, “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. This gain was reduced by $7.2 million during the year ended December 31, 2018 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, 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 and the transaction closed on March 9, 2017. The Company used the net proceeds from the sale to repay borrowings outstanding under its Senior 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. 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. HK TMS, LLC On September 30, 2016, certain wholly-owned subsidiaries of the Company executed an Assignment and Assumption Agreement with an affiliate of Apollo pursuant to which Apollo acquired one hundred percent (100%) of the Membership Interests of HK TMS, which transaction is referred to as the HK TMS Divestiture. HK TMS was previously a wholly-owned subsidiary and held all of the Company’s oil and natural gas properties prospective for the TMS formation. In exchange for the assignment of the Membership Interests, Apollo assumed all obligations relating to the Membership Interests.

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	12 Months Ended
	Dec. 31, 2018
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES	6. OIL AND NATURAL GAS PROPERTIES Oil and natural gas properties as of December 31, 2018 and 2017 consisted of the following (in thousands): December 31, 2018 December 31, 2017 Subject to depletion $ 1,470,509 $ 877,316 Not subject to depletion: Exploration and extension wells in progress 23,536 5,298 Other capital costs: Incurred in 2018 310,113 — Incurred in 2017 638,269 760,488 Incurred in 2016 — — Incurred in 2015 and prior — — Total not subject to depletion 971,918 765,786 Gross oil and natural gas properties 2,442,427 1,643,102 Less accumulated depletion (639,951) (570,155) Net oil and natural gas properties $ 1,802,476 $ 1,072,947 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, 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. 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. In March 2016, the Company transferred the remaining unevaluated Utica and TMS properties of approximately $330.4 million and $74.8 million, respectively, to the full cost pool. For the quarter ended March 31, 2016, management concluded that it was no longer probable that capital would be available or approved to continue exploratory drilling activities in the Company’s Utica or TMS acreage positions in advance of the related lease expirations due to the Company’s evaluation of strategic alternatives to reduce its debt and preserve liquidity in light of continued low commodity prices, together with a reduction of the Company’s exploration department and the Company’s intent to expend capital only on its most economical and proven areas. 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 Predecessor Company determined capitalized interest by multiplying the Predecessor 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 capitalized interest amounts were recorded as additions to unevaluated oil and natural gas properties on the consolidated balance sheets. As the costs excluded were transferred to the full cost pool, the associated capitalized interest was also transferred to the full cost pool. For the period from January 1, 2016 through September 9, 2016, the Predecessor Company capitalized interest costs of $68.2 million. The Successor Company’s policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization. The ceiling test value of the Company’s reserves was calculated based on the following prices: West Texas Intermediate Henry Hub (per barrel) (1) (per MMBtu) (1) December 31, 2018 $ 65.56 $ 3.100 December 31, 2017 51.34 2.976 December 31, 2016 42.75 2.481 (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 in 2018 and 2017 did not exceed the ceiling amount. The Company’s net book value of oil and natural gas properties at March 31, June 30 and September 30, 2016 exceeded the ceiling amount. The Company recorded full cost ceiling test impairments before income taxes of $420.9 million ($268.1 million after taxes, before valuation allowance) for the period of September 10, 2016 through September 30, 2016 and $754.8 million ($478.2 million after taxes, before valuation allowance) for the six months ended June 30, 2016. The impairment at September 30, 2016 reflects the differences between the first day of the month average prices for the preceding twelve months required by Regulation S-X, Rule 4-10 and ASC 932 in calculating the ceiling test and the forward-looking prices required by ASC 852 to estimate the fair value of the Company’s oil and natural gas properties on the fresh-start reporting date of September 9, 2016. The ceiling test impairments at March 31, 2016 and June 30, 2016, were driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculations since December 31, 2015. The impairment at March 31, 2016 also reflects the transfer of the remaining unevaluated Utica and TMS properties, as discussed above. The Company recorded the full cost ceiling test impairments 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 actual ceiling test calculation and impairment analyses in future periods.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2018
LONG-TERM DEBT
LONG-TERM DEBT	7. LONG‑TERM DEBT Long‑term debt as of December 31, 2018 and 2017 consisted of the following (in thousands): December 31, 2018 December 31, 2017 Senior revolving credit facility $ — $ — 6.75% senior notes due 2025 (1) 613,105 409,168 $ 613,105 $ 409,168 (1) On February 15, 2018, the Company issued an additional $200.0 million aggregate principal amount of its 2025 Notes at 103.0% of par. Amount includes a $7.2 million and $8.1 million unamortized discount at December 31, 2018 and 2017, respectively, associated with the 2025 Notes. Amount includes a $5.4 million unamortized premium at December 31, 2018, associated with the Additional 2025 Notes. Additionally, these amounts are net of $10.1 million and $7.7 million unamortized debt issuance costs at December 31, 2018 and 2017, respectively. Refer to “6.75% Senior Notes” below for further details. Senior Revolving Credit Facility On September 7, 2017, the Company entered into an Amended and Restated Senior Secured Revolving Credit Agreement (the Senior 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 Senior 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 current borrowing base of $275.0 million. The maturity date of the Senior Credit Agreement is September 7, 2022. The borrowing base will be 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 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 1.25% to 2.25% for ABR-based loans or at specified margins over LIBOR of 2.25% to 3.25% for Eurodollar-based loans. 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). Amounts outstanding under the Senior Credit Agreement are guaranteed by certain of 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 representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy. The Senior Credit Agreement also contains certain financial covenants, including the maintenance of (i) a Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement), which was recently revised by the H2S Consent, Severance and Office Payments Consent and Seventh Amendment, as discussed below, and (ii) a Current Ratio (as defined in the Senior Credit Agreement) not to be less than 1.00 to 1.00. At December 31, 2018, under the then effective borrowing base of $275.0 million, the Company had no indebtedness outstanding, approximately $1.0 million letters of credit outstanding and approximately $274.0 million of borrowing capacity available under the Senior Credit Agreement. On February 28, 2019, the lenders party to the Senior Credit Agreement issued a consent (the Severance and Office Payments Consent) to the Company whereby Severance Payments and Office Payments (as defined in the Severance and Office Payments Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2019. On February 15, 2019, the Company entered into the Seventh Amendment (the Seventh Amendment) to the Senior Credit Agreement which, among other things, provides for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amends the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA to be (a) 5.00 to 1.0 for the fiscal quarter ending March 31, 2019, (b) 4.75 to 1.0 for the fiscal quarter ending June 30, 2019, (c) 4.5 to 1.0 for the fiscal quarter ending September 30, 2019, (d) 4.25 to 1.0 for the fiscal quarter ending December 31, 2019, and (e) 4.0 to 1.0 for the fiscal quarter ending March 31, 2020 and any fiscal quarter thereafter. On November 16, 2018, the Company entered into the Sixth Amendment (the Sixth Amendment) to the Senior Credit Agreement, which, among other things, provided for (i) provisions allowing for optional increases in the maximum Credit Amount (as defined in the Credit Agreement) by the Company and the lenders party thereto. The Sixth Amendment also established the borrowing base at $350.0 million following the closing of the sale of the Water Assets; however, the Company and the lenders agreed to reduce the Aggregate Maximum Credit Amounts (as defined in the Credit Agreement) to $275.0 million, thereby effectively limiting the amount available to the Company to borrow under the Credit Agreement to $275.0 million. On November 7, 2018, the Company entered into the Fifth Amendment (the Fifth Amendment) to the Senior Credit Agreement which, among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018, March 31, 2019, June 30, 2019 and September 30, 2019 and (ii) amended the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of (a) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (b) 4.25 to 1.0 for the fiscal quarter ending December 31, 2018 and (c) 4.0 to 1.0 for the fiscal quarter ending March 31, 2019 and any fiscal quarter thereafter. On November 6, 2018, the lenders party to the Senior Credit Agreement issued a consent (the H2S Consent) to the Company whereby H2S Expenses (as defined in the H2S Consent) may exceed the maximum level allowed for adding back non-recurring expenses and charges in the definition of EBITDA (as defined in the Senior Credit Agreement) when calculating the ratio of Consolidated Total Net Debt to EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending September 30, 2018, December 31, 2018 and March 31, 2019. On July 12, 2018, the Company entered into the Fourth Amendment (the Fourth Amendment) to the Senior Credit Agreement which provided for an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA (as defined in the Senior Credit Agreement) of (i) 4.75 to 1.0 for the fiscal quarter ending September 30, 2018, (ii) 5.0 to 1.0 for the fiscal quarters ending December 31, 2018, March 31, 2019 and June 30, 2019, (iii) 4.25 to 1.0 for the fiscal quarter ending September 30, 2019 and (iv) 4.0 to 1.0 for the fiscal quarter ending December 31, 2019 and any fiscal quarter thereafter; provided, however, that if the Company consummated a sale of all or a material portion of its midstream assets, then the ratio of Consolidated Total Net Debt to EBITDA would be reduced to 4.0 to 1.0 for each fiscal quarter ending after the fiscal quarter in which such sale was consummated. On May 1, 2018, the Company entered into the Third Amendment (the Third Amendment) to the Senior Credit Agreement which provided for an assignment and reallocation of the Maximum Credit Amounts (as defined in the Senior Credit Agreement) among certain of the lender financial institutions. The Third Amendment did not adjust the aggregate Maximum Credit Amounts, which remained at $1.0 billion. On February 2, 2018, the Company entered into the Second Amendment (the Second Amendment) to the Senior 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. The Second Amendment among other things, provided for (i) the use of annualized financial data in determining EBITDA (as defined in the Senior Credit Agreement) for the fiscal quarters ending June 30, 2018, September 30, 2018 and December 31, 2018, (ii) an increase in the ratio of Consolidated Total Net Debt (as defined in the Senior Credit Agreement) to EBITDA of 4.50 to 1.00 for the fiscal quarter ending June 30, 2018, and a ratio of 4.00 to 1.00 for any fiscal quarter thereafter, (iii) a waiver of compliance with the covenant relating to the Total Net Indebtedness Leverage Ratio (as defined in the Senior Credit Agreement) for the fiscal quarter ending March 31, 2018, and (iv) a waiver of the automatic reduction to the borrowing base that would have otherwise resulted due to the issuance of the Additional 2025 Notes (defined below). After giving effect to the H2S Consent and the Fifth Amendment, at December 31, 2018, the Company was in compliance with the financial covenants under the Senior Credit Agreement. 6.75% Senior Notes On February 16, 2017, the Company issued $850.0 million aggregate principal amount of new 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 bear interest at a rate of 6.75% per annum, payable semi‑annually on February 15 and August 15 of each year. The 2025 Notes will mature on 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 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 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. The 2025 Notes are governed by an Indenture, dated as of February 16, 2017 (as supplemented, the February 2017 Indenture) by and among the Company, the Guarantors and U.S. Bank National Association, as Trustee, which contains affirmative and negative covenants that, among other things, limit the ability of the Company and the Guarantors to incur indebtedness; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The February 2017 Indenture also contains customary events of default. Upon the occurrence of certain events of default, the Trustee or the holders of the 2025 Notes may declare all outstanding 2025 Notes to be due and payable immediately. The 2025 Notes are jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis by the Company’s existing wholly‑owned subsidiaries. Halcón, the issuer of the 2025 Notes, has no material independent assets or operations apart from the assets and operations of its subsidiaries. In connection with the sale of the 2025 Notes, on February 16, 2017, the Company, the Guarantors and J.P. Morgan Securities LLC, on behalf of itself and as representative of the initial purchasers, entered into a Registration Rights Agreement (the 2017 Registration Rights Agreement) pursuant to which the Company agreed to, among other things, use reasonable best efforts to file a registration statement under the Securities Act and complete an exchange offer for the 2025 Notes within 365 days after closing. The Company completed the exchange offer for the 2025 Notes on February 1, 2018. On July 25, 2017, the Company concluded a consent solicitation of the holders of the 2025 Notes (the Consent Solicitation) and obtained consents to amend the February 2017 Indenture from approximately 99% of the holders of the 2025 Notes. As supplemented, the February 2017 Indenture 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 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 February 2017 Indenture, 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 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 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 5 , " Acquisitions and Divestitures , ” and for general corporate purposes, including to fund the Company’s 2018 drilling program. These notes were issued under the February 2017 Indenture. The Additional 2025 Notes are treated as a single class with, and have the same terms as, the 2025 Notes, except that the Additional 2025 Notes will initially be subject to transfer restrictions and have the benefit of certain registration rights and provisions for the payment of additional interest in the event of a breach with respect to such registration rights pursuant to the terms of a Registration Rights Agreement, entered into on February 15, 2018 (the 2018 Registration Rights Agreement). Pursuant to the 2018 Registration Rights Agreement the Company agreed to, among other things, use reasonable best efforts to file a registration statement under the Securities Act and complete an exchange offer for the 2025 Notes within 180 days after closing. The Company completed the exchange offer for the Additional 2025 Notes on May 17, 2018. The remaining unamortized discount on the 2025 Notes was $7.2 million at December 31, 2018. The unamortized premium on the Additional 2025 Notes was $5.4 million at December 31, 2018. Debt Maturities Aggregate maturities required on long-term debt at December 31, 2018 due in future years are as follows (in thousands, excluding discounts, premiums and debt issuance costs): 2019 $ — 2020 — 2021 — 2022 — 2023 — Thereafter 625,005 Total $ 625,005 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 year ended December 31, 2018, the Company capitalized approximately $4.2 million of debt issuance costs related to the Senior Credit Agreement and the Additional 2025 Notes. At December 31, 2018 and 2017, the Company had $11.1 million and $8.3 million, respectively of unamortized debt issuance costs. The debt issuance costs for the Company’s Senior Credit Agreement are presented in “Funds in escrow and other” and the debt issuance costs for the Company’s senior unsecured debt are presented in ”Long-term debt, net” on the consolidated balance sheets.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2018
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	8. FAIR VALUE MEASUREMENTS Pursuant to 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, 2018 and 2017 (in thousands): December 31, 2018 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 69,717 $ — $ 69,717 Liabilities Liabilities from derivative contracts $ — $ 12,907 $ — $ 12,907 December 31, 2017 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 677 $ — $ 677 Liabilities Liabilities from derivative contracts $ — $ 26,999 $ — $ 26,999 Derivative contracts listed above as Level 2 include collars, puts, calls, fixed-price swaps and basis swaps 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 markets prices and implied volatility factors related to changes in the forward curves. See Note 9, “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 and cash equivalents, 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, 2018 and 2017 (excluding discounts, premiums and debt issuance costs) (in thousands): December 31, 2018 December 31, 2017 Principal Estimated Principal Estimated Debt Amount Fair Value Amount Fair Value 6.75% senior notes $ 625,005 $ 458,210 $ 425,005 $ 443,790 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 February 28, 2017, the Company closed the Pecos County Acquisition and recorded the assets acquired and liabilities assumed at their acquisition date fair values. See Note 5, “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. On September 9, 2016, 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 and liabilities were recorded at their fair values as of the fresh-start reporting date, September 9, 2016. See Note 3, “Fresh-start Accounting,” for a detailed discussion of the fair value approaches used by the Company. For the period from January 1, 2016 through September 9, 2016, the Predecessor Company recorded a non-cash impairment charge of $28.1 million related to its gas gathering infrastructure. See Note 1, “Financial Statement Presentation,” for a discussion of the valuation approach used and the classification of the estimate 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; consequently, the Company has designated these liabilities as Level 3. See Note 10, “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, 2018
DERIVATIVE AND HEDGING ACTIVITIES
DERIVATIVE AND HEDGING ACTIVITIES	9. 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. Derivative contracts are utilized to hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil, natural gas and natural gas liquids production. When derivative contracts are available at terms (or prices) acceptable to the Company, 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 and/or commodities prices change. 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 institutions deemed by management as competitive market makers. As of December 31, 2018, 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, basis swaps and costless put/call “collars.” 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. 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). 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. The Company has elected to not 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. At December 31, 2018, the Company had 86 open commodity derivative contracts summarized in the following tables: nine natural gas collar arrangements, seven natural gas basis swaps, six natural gas liquids swaps, 26 crude oil basis swaps, 31 crude oil collar arrangements, two crude oil puts, four crude oil calls and one crude oil WTI NYMEX roll. At December 31, 2017, the Company had 34 open commodity derivative contracts summarized in the following tables: three natural gas collar arrangements, 12 crude oil basis swaps and 19 crude oil collar arrangements. 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, 2018 and 2017 (in thousands): Derivatives not designated Asset derivative contracts Liability derivative contracts as hedging contracts under December 31, December 31, December 31, December 31, ASC 815 Balance sheet location 2018 2017 Balance sheet location 2018 2017 Commodity contracts Current assets—receivables from derivative contracts $ 57,280 $ 677 Current liabilities—liabilities from derivative contracts $ (3,768) $ (19,248) Commodity contracts Other noncurrent assets—receivables from derivative contracts 12,437 — Other noncurrent liabilities—liabilities from derivative contracts (9,139) (7,751) Total derivatives not designated as hedging contracts under ASC 815 $ 69,717 $ 677 $ (12,907) $ (26,999) 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 September 10, 2016 January 1, 2016 Derivatives not designated as hedging Location of gain or (loss) recognized in Years Ended December 31, through through contracts under ASC 815 income on derivative contracts 2018 2017 December 31, 2016 September 9, 2016 Commodity contracts: Unrealized gain (loss) on commodity contracts Other income (expenses)—net gain (loss) on derivative contracts $ 84,274 $ (16,468) $ (112,449) $ (263,732) Realized gain (loss) on commodity contracts Other income (expenses)—net gain (loss) on derivative contracts 8,351 17,759 84,709 245,734 Total net gain (loss) on derivative contracts $ 92,625 $ 1,291 $ (27,740) $ (17,998) At December 31, 2018 and 2017, the Company had the following open crude oil and natural gas derivative contracts: 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 Janaury 2019—March 2019 Calls Crude Oil 1,350,000 $ — — $ — $ — 62.64 $ 62.64 Janaury 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 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 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 Swap Natural Gas Liquids 1,460,000 29.08 - 30.15 29.33 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 Basis Swap Crude Oil 460,000 (2.40) - (6.50) (5.68) July 2019—December 2019 Collars Crude Oil 552,000 50.00 - 55.00 53.00 55.00 - 69.00 61.00 October 2019—December 2019 Basis Swap Crude Oil 460,000 3.45 - 4.00 3.72 October 2019—December 2019 Collars Crude Oil 92,000 — 51.00 51.00 — 56.00 56.00 October 2019—December 2019 Swap Natural Gas Liquids 92,000 — 32.50 32.50 January 2020—December 2020 Basis Swap Crude Oil 3,294,000 2.00 - 4.00 2.95 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 — — — December 31, 2017 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 2018—December 2018 Basis Swap Crude Oil 2,555,000 $ — — $ — $ — — $ — $ (1.05) - (1.50) $ (1.29) January 2018—December 2018 Collars Crude Oil 2,920,000 45.00 - 53.00 49.29 50.00 - 60.00 56.82 January 2018—December 2018 Collars Natural Gas 2,737,500 3.00 - 3.03 3.01 3.22 - 3.38 3.30 April 2018—December 2018 Basis Swap Crude Oil 275,000 — - — — — - — — — - (1.15) (1.15) April 2018—December 2018 Collars Crude Oil 275,000 46.75 46.75 51.75 51.75 July 2018—December 2018 Basis Swap Crude Oil 1,012,000 (0.98) - (1.18) (1.12) July 2018—December 2018 Collars Crude Oil 184,000 48.50 48.50 53.50 53.50 October 2018—December 2018 Collars Crude Oil 92,000 50.65 50.65 55.65 55.65 January 2019—March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019—December 2019 Basis Swap Crude Oil 4,380,000 (0.50) - (1.33) (1.02) January 2019—December 2019 Collars Crude Oil 1,825,000 50.00 - 51.00 50.24 55.00 - 57.30 55.70 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, 2018 and 2017 (in thousands): Derivative Assets Derivative Liabilities December 31, December 31, December 31, December 31, Offsetting of Derivative Assets and Liabilities 2018 2017 2018 2017 Gross amounts presented in the consolidated balance sheet $ 69,717 $ 677 $ (12,907) $ (26,999) Amounts not offset in the consolidated balance sheet (10,263) (231) 10,263 231 Net amount $ 59,454 $ 446 $ (2,644) $ (26,768) 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.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2018
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS	10. 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. For other operating property and equipment, the Company records an ARO when the system is placed in service and it can reasonably estimate the fair value of an obligation to perform site reclamation and other necessary work when it is required. The Company records the ARO liability on the consolidated balance sheets and capitalizes a portion of the cost in “Oil and natural gas properties” or “Other operating property and equipment” 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 or straight-line 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, 2016 $ 32,375 Liabilities settled and divested (1) (33,796) Additions 592 Acquisitions (1) 3,109 Accretion expense 1,306 Revisions in estimated cash flows 782 Liability for asset retirement obligations as of December 31, 2017 $ 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 $ 6,914 (1) See Note 5, “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, 2018
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES	11. COMMITMENTS AND CONTINGENCIES Commitments The Company leases corporate office space in Houston, Texas and Denver, Colorado. Rent expense was approximately $3.7 million and $3.9 million for the years ended December 31, 2018 and 2017, respectively. Rent expense was approximately $1.4 million for the period of September 10, 2016 through December 31, 2016 and $5.9 million for the period of January 1, 2016 through September 9, 2016. Approximate future minimum lease payments for subsequent annual periods for all non-cancelable operating leases as of December 31, 2018 are as follows (in thousands): 2019 $ 3,792 2020 2,350 2021 1,899 2022 968 2023 999 Thereafter 599 Total $ 10,607 As of December 31, 2018, the Company has the following active drilling rig commitments (in thousands): 2019 $ 4,973 2020 — 2021 — 2022 — 2023 — Thereafter — Total $ 4,973 As of December 31, 2018, termination of the Company's active drilling rig commitments would require early termination penalties of $4.7 million, which would be in lieu of paying the remaining active drilling rig commitments of $5.0 million. As of December 31, 2018, the Company has the following rig termination and stacking fees commitments (in thousands): 2019 $ 781 2020 3,000 2021 — 2022 — 2023 — Thereafter — Total $ 3,781 As of December 31, 2018, the Company has the following purchase commitments related to equipment (in thousands): 2019 $ 20,233 2020 — 2021 — 2022 — 2023 — Thereafter — Total $ 20,233 The Company has entered into various long-term gathering, transportation and sales contracts with respect to production from the Delaware Basin in West Texas. As of December 31, 2018, the Company had in place three long‑term crude oil contracts and ten 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. The sales prices under these contracts are based on posted market rates. Contingencies 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 its 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.

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2018
STOCKHOLDERS' EQUITY
STOCKHOLDERS' EQUITY	12. STOCKHOLDERS’ EQUITY Preferred Stock and Non-Cash Preferred Stock Dividend On January 24, 2017 (the Commitment Date), the Company entered into a stock purchase agreement with certain accredited investors to sell, in a private placement exempt from registration requirements of the Securities Act pursuant to Section 4(a)(2), approximately 5,518 shares of 8% Automatically Convertible Preferred Stock, par value $0.0001 per share (the Preferred Stock), each share of which was convertible into 10,000 shares of common stock. Also on January 24, 2017, the Company received an executed written consent in lieu of a stockholders’ meeting authorizing and approving the conversion of the Preferred Stock into common stock. On February 27, 2017, the Company filed with the Delaware Secretary of State a Certificate of Designation, Preferences, Rights and Limitations of the Preferred Stock (the Certificate of Designation), which created the series of preferred stock issued by the Company on that same date. The Company issued the Preferred Stock at $72,500 per share. Gross proceeds were approximately $400.1 million, or $7.25 per share of common stock. The Company incurred approximately $11.9 million in expenses associated with this offering, including placement agent fees. On March 16, 2017, the Company mailed a definitive information statement to its stockholders notifying them that a majority of its stockholders had consented to the issuance of common stock, par value $0.0001 per share, upon the conversion of the Preferred Stock. The Preferred Stock automatically converted into 55.2 million shares of common stock on April 6, 2017 in accordance with the terms of the Certificate of Designation. No cash dividends were paid on the Preferred Stock since, pursuant to the terms of the Certificate of Designation of the Preferred Stock, conversion occurred prior to June 1, 2017. The Company agreed to file a registration statement to register the resale of shares of common stock issuable upon conversion of the Preferred Stock and to pay penalties in the event such registration was not effective by June 27, 2017. The Company filed such registration statement on March 3, 2017 and it was declared effective by the SEC on April 7, 2017. In accordance with ASC Topic 470, Debt (ASC 470), the Company determined that the conversion feature in the Preferred Stock represented a beneficial conversion feature. The fair value of the Company’s common stock of $8.12 per share on the Commitment Date was greater than the conversion price of $7.25 per share of common stock, representing a beneficial conversion feature of $0.87 per share of common stock, or approximately $48.0 million in aggregate. Under ASC 470, $48.0 million (the intrinsic value of the beneficial conversion feature) of the proceeds received from the issuance of the Preferred Stock was allocated to “Additional paid‑in capital,” creating a discount on the Preferred Stock (the Discount). The Discount is required to be amortized on a non‑cash basis over the approximate 65-month period between the issuance date and the required redemption date of July 28, 2022, or fully amortized upon an accelerated date of redemption or conversion, and recorded as a preferred dividend. The Discount was fully amortized and a non‑cash preferred dividend was recorded upon the conversion date of April 6, 2017. The Discount amortization is reflected in “Non‑cash preferred dividend” in the consolidated statements of operations. The preferred dividend was charged against additional paid‑in capital since no retained earnings were available. Common Stock On September 9, 2016, upon emergence from chapter 11 bankruptcy, all existing shares of Predecessor common stock were cancelled and the Successor Company issued approximately 90.0 million shares of common stock to the Predecessor Company's existing common stockholders, Third Lien Noteholders, Unsecured Noteholders, and the Convertible Noteholder. Refer to Note 2, "Reorganization," for further details. Also on September 9, 2016, the Successor Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for (i) the total number of shares of all classes of capital stock that the Successor Company has the authority to issue is 1,001,000,000 of which 1,000,000,000 shares are common stock, par value $0.0001 per share and 1,000,000 shares are preferred stock, par value $0.0001 per share, (ii) a classified board structure, (iii) the right of removal of directors with or without cause by stockholders, and (iv) a restriction on the Successor Company from issuing any non-voting equity securities in violation of Section 1123(a)(6) of chapter 11 of title 11 of the United States Code. On February 9, 2018, the Company sold 9.2 million shares of common stock, par value $0.0001 per share, in a public offering at a price of $6.90 per share. The net proceeds to the Company from the offering were approximately $60.4 million, after deducting the underwriters’ discounts and offering expenses. The Company used the net proceeds, together with the net proceeds from the issuance of the Additional 2025 Notes, to fund the cash consideration for the acquisition of the West Quito Draw Properties, and for general corporate purposes, including funding the Company’s 2018 drilling program. Warrants On September 9, 2016, the Company issued 4.7 million new warrants. The warrants can be exercised to purchase 4.7 million shares of the Company's common stock at an exercise price of $14.04 per share. The holders are entitled to exercise the warrants in whole or in part at any time prior to expiration on September 9, 2020. Incentive Plans On September 9, 2016, the Company’s board of directors adopted the 2016 Long-Term Incentive Plan (the Plan). An aggregate of 10.0 million shares of the Company’s common stock were available for grant pursuant to awards under the Plan. On April 6, 2017, Amendment No. 1 to the Plan to increase, by 9.0 million shares, the maximum number of shares of common stock that may be issued thereunder, i.e., a maximum of 19.0 million shares, became effective, which was 20 calendar days following the date the Company mailed an information statement to all stockholders of record notifying them of approval of the amendment by written consent of holders of a majority of the Company’s outstanding stock. As of December 31, 2018 and 2017, a maximum of 4.9 million and 7.7 million shares, respectively of the Company’s common stock remained reserved for issuance under the Plan. The Company accounts for stock-based payment accruals under authoritative guidance on stock compensation. The guidance requires all stock-based payments to employees and directors, including grants of stock options and restricted stock, to be recognized in the financial statements based on their fair values. The Company has elected not to apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited. For the years ended December 31, 2018 and 2017, the Company recognized $15.3 million and $36.8 million of stock-based compensation expense, respectively. For the period from September 10, 2016 through December 31, 2016 and the period from January 1, 2016 through September 9, 2016 the Company recognized $21.5 million and $4.9 million, respectively, of stock-based compensation expense. Stock-based compensation expense is recorded as a component of “General and administrative” on the consolidated statements of operations. Stock Options From time to time, the Company grants stock options under the Plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. These awards typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant and expire ten years from the grant date. Immediately prior to emergence from chapter 11 bankruptcy, all outstanding stock options under the Predecessor incentive plan were cancelled. Refer to Note 2, “Reorganization,” for further details. The weighted average grant date fair value of options granted during the year ended December 31, 2018 was $3.5 million. During the year ended December 31, 2018, the Company received $0.3 million from the exercise of stock options. At December 31, 2018, the Company had $5.2 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average vesting period of 0.9 years. The weighted average grant date fair value of options granted during the year ended December 31, 2017 was $7.8 million. At December 31, 2017, the Company had $13.0 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average vesting period of 1.2 years. The weighted average grant date fair value of options granted during the period from September 10, 2016 through December 31, 2016 was $32.3 million. No options were granted during the period January 1, 2016 through September 9, 2016. At December 31, 2016, the Company had $26.5 million of unrecognized compensation expense related to non-vested stock options to be recognized over a weighted-average period of 1.7 years. The following table sets forth the stock option transactions for the periods indicated: Weighted Aggregate Weidhted Average Average Intrinsic Remaining Exercise Price Value (1) Contractual Life Number Per Share (In thousands) (Years) Outstanding at December 31, 2015 (Predecessor) 4,860,133 $ 17.80 $ — 8.4 Granted — — Exercised — — Forfeited (695,302) 21.17 Cancelled (2) (4,164,831) 17.23 Outstanding at September 9, 2016 (Predecessor) — $ — $ — — Outstanding at September 9, 2016 (Successor) — $ — $ — — Granted 5,319,400 9.22 Exercised — — Forfeited — — Outstanding at December 31, 2016 (Successor) 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 (Successor) 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 (Successor) 7,468,926 $ 8.34 $ — 8.1 (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 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 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. No stock options were exercised during the year ended December 31, 2017 or 2016. (2) Immediately prior to emergence from chapter 11 bankruptcy, all outstanding options under the Predecessor incentive plan were cancelled. Options outstanding at December 31, 2018 consisted of the following: Outstanding Exercisable (1) Weighted Average Weighted Average Weighted Average Remaining Weighted Average Aggregate Remaining Range of Grant Exercise Price Contractual Life Exercise Price Intrinsic Contractual Life Prices Per Share Number per Share (Years ) Number per Share Value (Years ) $5.65 - $7.75 2,783,493 $ 6.85 8.7 — $ — $ — — $8.93 - $9.24 4,685,433 9.23 7.7 — — — — (1) At December 31, 2018, none of the Company’s options were exercisable due to service performance conditions or option exercise prices above the current market value of the underlying stock. The assumptions used in calculating the Black-Scholes-Merton valuation model fair value of the Company’s stock options for the years ended December 31, 2018 and 2017 and the period from September 10, 2016 through December 31, 2016 are set forth in the following table: Successor Period from September 10, 2016 Years Ended December 31, through 2018 2017 December 31, 2016 Weighted average value per option granted during the period $ 2.92 $ 4.36 $ 6.07 Assumptions: Stock price volatility (1) 52.08 % 60.18 % 56.29 % Risk free rate of return 2.63 % 1.94 % 1.34 % Expected term 6 years 6 years 6 years (1) Due to the Company’s limited historical data, expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available. Restricted Stock From time to time, the Company grants shares of restricted stock to employees and non-employee directors of the Company. Employee shares typically vest over a three year period at a rate of one-third on the annual anniversary date of the grant, and the non-employee directors' shares vest six months from the date of grant. Certain shares granted under the Plan specifically related to the Company’s emergence from chapter 11 bankruptcy vested on or before September 30, 2017. Immediately prior to emergence from chapter 11 bankruptcy, all outstanding unvested restricted stock awards granted under the Predecessor Incentive Plan were vested. Refer to Note 2, "Reorganization," for further details. The weighted average grant date fair value of shares granted during the year ended December 31, 2018 was $12.7 million. At December 31, 2018, the Company had $6.1 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average vesting period of 1.1 years. The weighted average grant date fair value of shares granted during the year ended December 31, 2017 was $14.3 million. At December 31, 2017, the Company had $3.2 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average vesting period of 1.4 years. The weighted average grant date fair value of shares granted during the period from September 10, 2016 through December 31, 2016 was $27.3 million. No restricted shares were granted from the period January 1, 2016 through September 9, 2016. At December 31, 2016, the Company had $11.5 million of unrecognized compensation expense related to non-vested restricted stock awards to be recognized over a weighted-average period of 0.9 years. The following table sets forth the restricted stock transactions for the periods indicated: Weighted Aggregate Average Grant Intrinsic Number of Date Fair Value Value (1) Shares Per Share (In thousands) Unvested outstanding shares at December 31, 2015 (Predecessor) 2,870,405 $ 7.55 $ 3,617 Granted — — Vested (436,256) 18.50 Accelerated vesting (2) (1,917,072) 5.39 Forfeited (517,077) 6.31 Unvested outstanding shares at September 9, 2016 (Predecessor) — $ — $ — Unvested shares outstanding at September 9, 2016 (Successor) — $ — $ — Granted 2,991,202 9.14 Vested (1,253,125) 9.24 Forfeited — — Unvested outstanding shares at December 31, 2016 (Successor) 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 (Successor) 745,507 $ 7.05 $ 5,643 Granted 2,326,961 5.47 Vested (537,411) 5.89 Forfeited (262,164) 6.29 Unvested shares outstanding at December 31, 2018 (Successor) 2,272,893 $ 5.80 $ 3,864 (1) The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2018, 2017 and 2016 of the underlying stock multiplied by the number of restricted shares. The total fair value of shares vested was $2.0 million, $16.1 million, $11.6 million and $0.9 million for the years ended December 31, 2018 and 2017, the period from September 10, 2016 through December 31, 2016, and the period from January 1, 2016 through September 9, 2016, respectively. (2) Immediately prior to emergence from chapter 11 bankruptcy, all outstanding unvested restricted stock under the Predecessor incentive plan were vested.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2018
INCOME TAXES
INCOME TAXES	13. INCOME TAXES Income tax benefit (provision) for the indicated periods is comprised of the following (in thousands): Successor Predecessor Period from Period from September 10, 2016 January 1, 2016 Years Ended December 31, through through 2018 2017 December 31, 2016 September 9, 2016 Current: Federal $ — $ 5,000 $ (5,000) $ 8,666 State — — 256 — — 5,000 (4,744) 8,666 Deferred: Federal (95,791) — 52,223 (22,491) State — — (52,223) 22,491 — — — — Total income tax benefit (provision) $ (95,791) $ 5,000 $ (4,744) $ 8,666 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 year ended December 31, 2018 and 35% for each of the prior periods, as follows (in thousands): Successor Predecessor Period from Period from September 10, 2016 January 1, 2016 Years Ended December 31, through through 2018 2017 December 31, 2016 September 9, 2016 Expected tax benefit (provision) $ (29,767) $ (185,740) $ 166,057 $ (1,152) State income tax expense, net of federal benefit — (2,587) 6,243 (43) Stock-based compensation (350) — — (14,803) Net operating loss limitation under IRC Section 382 — — (161,704) — TMS Divestiture — — (157,767) — Adjustments attributable to reorganization — — — 275,460 Change in state rate — (10,121) — — Debt related costs — — — (4,089) Cancellation of indebtedness income — — — 103,268 Increase (reduction) in deferred tax asset (201,903) 95,907 — 14,645 Change in valuation allowance and related items 136,432 392,846 202,592 (263,211) IRC section 108 attribute reduction — — (56,483) (101,342) Tax Cuts and Jobs Act of 2017 — (280,874) — — Permanent adjustments (203) — — — Other — (4,431) (3,682) (67) Total income tax benefit (provision) $ (95,791) $ 5,000 $ (4,744) $ 8,666 The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands): December 31, 2018 December 31, 2017 Deferred noncurrent income tax assets: Net operating loss carry-forwards $ 204,751 $ 205,570 Built in loss adjustment Section 382 88,835 90,897 Stock-based compensation expense 8,509 5,501 Asset retirement obligations 1,011 963 Book-tax differences in property basis — 125,309 Unrealized hedging transactions — 5,901 Disallowed interest Section 163(j) 3,370 — Other 1,917 — Gross deferred noncurrent income tax assets 308,393 434,141 Valuation allowance (290,333) (426,765) Deferred noncurrent income tax assets $ 18,060 $ 7,376 Deferred noncurrent income tax liabilities: Basis difference in debt $ (5,507) $ (6,366) Book-tax differences in property basis (96,414) — Unrealized hedging transactions (11,930) — Other — (1,010) Deferred noncurrent income tax liabilities $ (113,851) $ (7,376) Net noncurrent deferred income tax assets (liabilities) $ (95,791) $ — On December 22, 2017, the Tax Cuts and Job Act of 2017 (the Act) was signed into law making significant changes to the Internal Revenue Code of 1986, as amended (the IRC). Changes include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017, imposes significant additional limitations on the deductibility of interest and net operating losses, allows for the expensing of certain capital expenditures, and limits the deductibility of certain types of executive compensation. The Company for the year ended December 31, 2017 calculated its best estimate of the impact of the Act in its year-end income statement provision in accordance with its understanding of the Act and guidance available as of the date of this filing and as a result have recorded a $280.9 million income tax provision primarily related to the decrease in the corporate tax rate offset by a corresponding decrease in the Company’s valuation allowance for no net overall impact to the Company’s income tax provision for the year ended December 31, 2017. On December 22, 2017, Staff Accounting Bulletin No. 118 (SAB 118) was issued to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Act. In accordance with SAB 118, the Company has determined that the $280.9 million income tax provision and corresponding decrease in the Company’s valuation allowance was a provisional amount and a reasonable estimate at December 31, 2017. Any subsequent adjustments to these amounts will be recorded to current tax benefit (provision) in the quarter of 2018 when the analysis is complete. The accounting is now complete and there were no material changes. The Company emerged from chapter 11 bankruptcy on September 9, 2016. 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 a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of 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 $844.7 million, which reduced the value of the Company’s U.S. net operating losses (NOLs) and other assets on January 1, 2017. The Company also had various state NOL carryforwards that were subject to reduction as a result of the CODI being excluded from taxable income. 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 $750.0 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. 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 results in a $95.8 million deferred tax expense as the Company is now in a net deferred tax liability position. The amount of U.S. consolidated NOLs available as of December 31, 2018 after attribute reduction and Section 382 limitation is estimated to be approximately $975 million. Of this amount, $129.3 million is subject to the 20 year carryforward period and will expire in 2037. The remaining $845.7 million may be carried forward indefinitely but subject to a Section 382 limitation. The Company has recognized a tax benefit for approximately $81.6 million of the NOL’s based on the expected reversal of existing temporary differences and amount of the annual Section 382 limit. 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, 2018, 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, 2018 of $290.3 million, a decrease of $136.4 million from December 31, 2017. 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 years ended December 31, 2018 and 2017, the period of September 10, 2016 through December 31, 2016, the period of January 1, 2016 through September 9, 2016. Generally, the Company’s income tax years 2015 through 2018 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, net” in its consolidated statements of operations. For the years ended December 31, 2018 and 2017, the period of September 10, 2016 through December 31, 2016, and the period of January 1, 2016 through September 9, 2016, the Company recognized no interest and penalties.

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2018
EARNINGS PER COMMON SHARE
EARNINGS PER SHARE	14. EARNINGS PER SHARE On September 9, 2016, 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 September 10, 2016 January 1, 2016 Years Ended December 31, through through 2018 2017 December 31, 2016 September 9, 2016 Basic: Net income (loss) available to common stockholders $ 45,959 $ 487,679 $ (479,984) $ (32,794) Weighted average basic number of common shares outstanding 157,011 132,763 91,228 120,513 Basic net income (loss) per common share $ 0.29 $ 3.67 $ (5.26) $ (0.27) Diluted: Net income (loss) available to common stockholders $ 45,959 $ 487,679 $ (479,984) $ (32,794) Weighted average basic number of common shares outstanding 157,011 132,763 91,228 120,513 Common stock equivalent shares representing shares issuable upon: Exercise of stock options Anti-dilutive Anti-dilutive Anti-dilutive Anti-dilutive Exercise of February 2012 Warrants — — — Anti-dilutive Exercise of warrants Anti-dilutive Anti-dilutive Anti-dilutive — Vesting of restricted shares 284 813 Anti-dilutive Anti-dilutive Vesting of performance units — — — — Conversion of preferred stock — Anti-dilutive — — Conversion of Convertible Note — — — Anti-dilutive Conversion of Series A Preferred Stock — — — Anti-dilutive Weighted average diluted number of common shares outstanding 157,295 133,576 91,228 120,513 Diluted net income (loss) per common share $ 0.29 $ 3.65 $ (5.26) $ (0.27) Common stock equivalents, including stock options, restricted shares and warrants totaling 13.1 million shares for the year ended December 31, 2018 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 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 and warrants totaling 11.2 million shares for the period from September 10, 2016 through December 31, 2016 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, warrants, convertible debt and preferred stock totaling 43.6 million shares for the period from January 1, 2016 through September 9, 2016 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.

ADDITIONAL FINANCIAL STATEMENT

ADDITIONAL FINANCIAL STATEMENT INFORMATION	12 Months Ended
	Dec. 31, 2018
ADDITIONAL FINANCIAL STATEMENT INFORMATION
ADDITIONAL FINANCIAL STATEMENT INFORMATION	15. ADDITIONAL FINANCIAL STATEMENT INFORMATION Certain balance sheet amounts are comprised of the following (in thousands): December 31, 2018 December 31, 2017 Accounts receivable: Oil, natural gas and natural gas liquids revenues $ 26,432 $ 24,110 Joint interest accounts 7,369 2,249 Other 1,917 10,057 $ 35,718 $ 36,416 Prepaids and other: Prepaids $ 3,503 $ 4,324 Income tax receivable 1,250 6,250 Other 35 54 $ 4,788 $ 10,628 Funds in escrow and other: Funds in escrow $ 570 $ 563 Other 1,611 1,128 $ 2,181 $ 1,691 Accounts payable and accrued liabilities: Trade payables $ 68,959 $ 35,688 Accrued oil and natural gas capital costs 41,461 50,743 Revenues and royalties payable 20,526 20,256 Accrued interest expense 16,971 10,985 Accrued employee compensation 3,421 9,805 Accrued lease operating expenses 6,292 2,024 Other 218 1,586 $ 157,848 $ 131,087

SUMMARY OF SIGNIFICANT EVENTS_2

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2018
SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation Halcón Resources Corporation (Halcón or the Company) 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 July 27, 2016 (the Petition Date), the Company and certain of its subsidiaries (the Halcón Entities) filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court in the District of Delaware (the Bankruptcy Court) to pursue a joint prepackaged plan of reorganization (the Plan). On September 8, 2016, the Bankruptcy Court entered an order confirming the Plan and on September 9, 2016, the Plan became effective (the Effective Date) and the Halcón Entities emerged from chapter 11 bankruptcy. The Company’s subsidiary, HK TMS, LLC which was divested on September 30, 2016, was not part of the chapter 11 bankruptcy filings. See Note 2, “Reorganization,” for further details on the Company’s chapter 11 bankruptcy and the Plan and Note 5, “Acquisitions and Divestitures,” for further details on the divestiture of HK TMS, LLC. 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. 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 September 9, 2016 are not comparable to its consolidated financial statements prior to, and including, September 9, 2016. 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 September 9, 2016. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, September 9, 2016.
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 5, “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 that are 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 and Cash Equivalents	Cash and Cash Equivalents 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.
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, 2018 and 2017, allowances for doubtful accounts were approximately $0.2 million and $0.7 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, 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: gas gathering systems, thirty years, gas treating systems and 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. 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 September 9, 2016. Refer to Note 5, “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. For the period from January 1, 2016 through September 9, 2016, the Company recorded a non-cash impairment charge of $28.1 million related to $32.8 million gross investments in gas gathering infrastructure that were deemed non-economical due to a shift in exploration, drilling and developmental plans in a low commodity price environment. This impairment was recorded in “Other operating property and equipment impairment” in the Company’s consolidated statements of operations and in “Other operating property and equipment” in the Company’s consolidated balance sheets. In accordance with ASC 820, Fair Value Measurements and Disclosures (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 estimate of the fair value of the Company’s gas gathering systems was based on an income approach that estimated future cash flows associated with those assets over the remaining asset lives. This estimation includes the use of unobservable inputs, such as estimated future production, gathering and compression revenues and operating expenses. The use of these unobservable inputs results in the fair value estimate of the Company’s gas gathering systems being classified as Level 3.
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 year ended December 31, 2018, 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 period. In 2017 and 2016, 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 each 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, when derivative contracts are available at terms (or prices) acceptable to the Company, it may hedge a portion of its forecasted oil, natural gas, and natural gas liquids production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction. 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, 2018 and 2017. 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, 2018, 2017 and 2016. 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, net ” on the Company’s consolidated statements of operations. Refer to Note 13, “ Income Taxes, ” for more details. Generally, the Company’s income tax years 2015 through 2018 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. 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 and other operating property and equipment. 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 and other operating property and equipment as these obligations are incurred.
Restructuring	Restructuring The Company had reductions in its workforce in conjunction with its divestiture activities in 2017 and the decrease in drilling and developmental activities planned for 2016. Consequently, for the years ended December 31, 2018 and 2017, and the period from January 1, 2016 through September 9, 2016, the Company incurred approximately $0.1 million, $7.5 million and $5.2 million, respectively, in severance costs and accelerated stock-based compensation expense related to the termination of certain employees. These costs were recorded in “ Restructuring ” on the consolidated statements of operations.
Redeemable Noncontrolling Interest	Redeemable Noncontrolling Interest On June 16, 2014, funds and accounts managed by affiliates of Apollo Global Management (Apollo) contributed $150 million in cash to HK TMS, a Delaware limited liability company, which was then wholly owned by the Company and held all of the Company’s acreage in the Tuscaloosa Marine Shale (TMS) formation, located in Mississippi and Louisiana, in exchange for the issuance by HK TMS of 150,000 preferred shares. Holders of the HK TMS preferred shares were to receive quarterly cash dividends of 8% cumulative perpetual per annum, subject to HK TMS’ option to pay such dividends “in-kind” through the issuance of additional preferred shares. The preferred shares were expected to be automatically redeemed and cancelled when the holders received cash dividends and distributions on the preferred shares equating to the greater of a 12% annual rate of return plus principal and 1.25 times their investment plus applicable fees (the Redemption Price), subject to adjustment under certain circumstances. On September 30, 2016, certain wholly-owned subsidiaries of the Company executed an Assignment and Assumption Agreement with an affiliate of Apollo pursuant to which 100% of the common shares in HK TMS (the Membership Interests) were assigned to Apollo (the HK TMS Divestiture). In exchange for the assignment, Apollo assumed all obligations relating to such Membership Interests. See Note 5, “ Acquisitions and Divestitures ,” for further information regarding the HK TMS Divestiture. The preferred shares were classified as “ Redeemable noncontrolling interest ” and included in “ Mezzanine equity ” between total liabilities and stockholders’ equity on the consolidated balance sheets pursuant to ASC 480-10-S99-3A. The preferred shares were considered probable of becoming redeemable and therefore were accreted up to the estimated required redemption value. The accretion was presented as a deemed dividend and recorded in “ Redeemable noncontrolling interest ” on the consolidated balance sheets and within “ Preferred dividends and accretion on redeemable noncontrolling interest ” on the consolidated statements of operations. In accordance with ASC 480-10-S99-3A, an adjustment to the carrying amount presented in mezzanine equity was recognized as charges against retained earnings and reduced income available to common stockholders in the calculation of earnings per share. For the period of September 10, 2016 through September 30, 2016 and January 1, 2016 through September 9, 2016, HK TMS issued 791 and 9,329 additional preferred shares to Apollo for dividends paid-in-kind, respectively. These dividends were presented within “ Preferred dividends and accretion on redeemable noncontrolling interest ” on the consolidated statements of operations. HK TMS was not included in the chapter 11 bankruptcy filings or the Restructuring Support Agreement discussed in Note 2, “ Reorganization .”
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 $1.5 million and $2.2 million for the years ended December 31, 2018 and 2017, respectively. The Company provided matching contributions of $0.8 million and $2.0 million for the period September 10, 2016 through December 31, 2016 and the period January 1, 2016 through September 9, 2016, 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, 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. The gathering system is expected to be operational by February 28, 2019. Beginning in the fourth quarter of 2018, the Company began selling its crude oil to SCM while the gathering system is under construction. For the year ended December 31, 2018, the Company received $13.0 million and recorded a $10.9 million receivable from SCM for its crude oil sales. The agreement with SCM was the culmination of a lengthy process during which the Company analyzed the most effective method of gathering and transportation of its future oil production in these areas. During the course of its investigation, the Company considered a variety of alternatives and solicited and received numerous third party proposals. The Company received and evaluated proposals from eleven companies covering some or all of its oil production in the region and determined that among the proposals it received, SCM’s was superior for economic and strategic reasons. Because certain funds under the control of Ares Management LLC (Ares) are the majority owners and controlling parties of SCM, the Audit Committee of the board of directors of the Company and the disinterested members of the Company’s board of directors evaluated and approved (in a vote that excluded the Company director who is employed by Ares) the process by which the Company determined the SCM proposal to be superior to other alternatives, as well as the principal terms of the agreement, in accordance with applicable Company policies, including its Code of Conduct and Corporate Governance Guidelines (copies of which are available through the Company’s website at www.halconresources.com ) and the Company’s procedures for the review and approval of transactions with related parties. Ares also controls other funds which own in excess of ten percent (10%) of the common stock of the Company. No Ares fund that is a stockholder of the Company has an interest in SCM but one of the Company’s directors, who is employed by Ares, also serves on the board of directors of SCM’s parent company. Gas Purchase and Processing Agreement On November 16, 2017, 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. The facilities were completed and placed in service in May 2018. For the year ended December 31, 2018, the Company received $0.4 million from Salt Creek under the gas purchase and processing agreement. The agreement with Salt Creek was the culmination of a lengthy process during which the Company investigated the most efficient method of gathering, processing and marketing its future natural gas production in these areas. During the course of its investigation, the Company considered the construction of Company owned gas gathering and processing facilities, Company owned high pressure pipeline to a third-party processing plant and solicited and received proposals from numerous third parties for long-term gathering and processing options. The Company received proposals from eight midstream companies, determined that third party options were more attractive from a variety of business perspectives, and that among the proposals it received, Salt Creek’s was superior. Certain funds under the control of Ares are the majority owners and controlling parties of Salt Creek. Ares also controls other funds which own in excess of ten percent (10%) of the stock of the Company. No Ares fund that is a stockholder of the Company has an interest in Salt Creek but one of the Company’s directors, who is employed by Ares, and is a director of the Company, also serves on the board of directors of Salt Creek. Due to these relationships, prior to entering into the gas purchase and processing agreement, the process by which the Company determined the Salt Creek proposal to be superior to other alternatives, as well as the terms of the agreement, were evaluated and approved in advance by the Audit Committee of the Company and the disinterested members of the Company’s board of directors, in a vote that excluded the Company director who is employed by Ares in accordance with applicable Company policies, including its Code of Conduct and Corporate Governance Guidelines (copies of which are available through the Company’s website at www.halconresources.com ), and the Company’s procedures for the review and approval of transactions with related parties. Charter of Aircraft In the ordinary course of its business, the Company occasionally charters a private aircraft for business use. Floyd C. Wilson, Halcón’s former Chairman, Chief Executive Officer and President, owns an aircraft which the Company has chartered from time to time. For a portion of 2017, Mr. Wilson’s aircraft was managed by an independent air charter company unaffiliated with both Mr. Wilson and Halcón. The aircraft in the air charter company’s fleet are available to the public for charter based upon a standard fee schedule established by the air charter company, with the fees dependent primarily upon the type and size of the aircraft utilized and the duration of the flight. Because the air charter company established fees for the use of the aircraft in its fleet, Mr. Wilson did not receive any greater benefit from Halcón’s charter of the aircraft indirectly owned by him than he would have if any third party were to charter the aircraft. During the course of 2017, Mr. Wilson terminated the independent air charter company and removed his aircraft from the charter company’s fleet, pending his search for a new charter company to manage his aircraft. During the search period for a new charter company, fees for the use of Mr. Wilson’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. The terms for this use were evaluated and approved by the Audit Committee of the Company, and subsequently by the disinterested members of the Company’s board of directors upon the recommendation of the Audit Committee, in accordance with the Company’s procedures for the review and approval of transactions with related parties. During the year ended December 31, 2018, the Company paid approximately $0.9 million to Mr. Wilson for the Company’s use of the aircraft. As of December 31, 2018, the Company recorded a $0.2 million payable to Mr. Wilson. The payable is recorded in “ Accounts payable and accrued liabilities ,” on the Company’s unaudited condensed consolidated balance sheet. The Company has terminated all charter arrangements with Mr. Wilson relating to the use of his aircraft.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements In January 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). For public business entities, ASU 2017-01 is effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2017. The amendments in this ASU should be applied prospectively on or after the effective date. The ASU was issued to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions of assets or businesses. The Company applied the provisions of ASU 2017-01 to the acquisition of the West Quito Draw Properties and the divestiture of the Water Assets, which are discussed further in Note 5, “ Acquisitions and Divestitures .” In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230) (ASU 2016-15). For public business entities, ASU 2016-15 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. The areas for simplification in this ASU involve addressing eight specific classification issues in the statement of cash flows. An entity should apply the amendments in this ASU using a retrospective transition method. The Company adopted ASU 2016-15 effective January 1, 2018. The adoption of ASU 2016-15 did not have an impact on the Company’s consolidated statement of cash flows. In February 2016, the FASB issued ASU 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. In January 2018, ASU 2016-02 was updated with ASU No. 2018-01, Leases (Topic 842)—Land Easement Practical Expedient for Transition to Topic 842, which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. An entity that does not elect this practical expedient should evaluate all existing or expired land easements in connection with the adoption of the new lease requirements in Topic 842 to assess whether they meet the definition of a lease. In July 2018, ASU 2016-02 was updated with ASU No. 2018-11, Targeted Improvements to ASC 842 (ASU 2018-11), which provides entities with relief from the costs of implementing certain aspects of the new leasing standard. Specifically, under the amendments in ASU 2018-11, (1) entities may elect not to recast the comparative periods presented when transitioning to ASC 842 and (2) lessors may elect not to separate lease and nonlease components when certain conditions are met. Before ASU 2018-11 was issued, transition to the new lease standard required application of the new guidance at the beginning of the earliest comparative period presented in the financial statements. The Company adopted ASU 2016-02 effective January 1, 2019 using the modified retrospective approach as of the adoption date. The Company is substantially complete with its initial lease population and with development of accounting policies and procedures to address the provisions of ASU 2016-02. In addition, the Company implemented an accounting software solution to facilitate compliance with the new lease accounting requirements. ASU 2016-02 provides a number of optional practical expedients for transition, as well as ongoing accounting, and the Company has chosen to elect many of the practical expedients available under the new standard, including the expedients related to short-term lease recognition exemption and land easements. The most significant effects of the adoption of ASU 2016-02 relate to 1) the recognition of right-of-use assets and lease liabilities on the consolidated balance sheets (that are not recognized under historical lease accounting guidance) and 2) new disclosures regarding the Company’s leasing activities. As of December 31, 2018, the Company had approximately $15.6 million of contractual obligations related to its non-cancelable operating leases and drilling contracts and certain of these contractual obligations will be recorded on the Company’s consolidated balance sheet under ASU 2016-02. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 states that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard provides five steps an entity should apply in determining its revenue recognition. In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), which provides further clarification on the principal versus agent evaluation. The Company adopted ASC 606 effective January 1, 2018 using the modified retrospective approach. See Note 4, “ Operating Revenues ,” for further details.

FRESH-START ACCOUNTING (Tables)

FRESH-START ACCOUNTING (Tables)	12 Months Ended
	Dec. 31, 2018
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 September 9, 2016 (in thousands): September 9, 2016 Enterprise Value $ 1,618,888 Plus: Cash 13,943 Less: Fair value of debt (1,016,160) Less: Fair value of redeemable noncontrolling interest (41,070) Less: Fair value of other long-term liabilities (4,478) Less: Fair value of warrants (16,691) Fair Value of Successor common stock $ 554,432
Schedule of Enterprise Value to its Reorganization Value	The following table reconciles the Company’s Enterprise Value to its Reorganization Value as of September 9, 2016 (in thousands): September 9, 2016 Enterprise Value $ 1,618,888 Plus: Cash 13,943 Plus: Current liabilities 178,639 Plus: Noncurrent asset retirement obligation 32,156 Reorganization Value of Successor assets $ 1,843,626
Schedule of reorganization balance sheet and fresh-start accounting adjustments	Amounts included in the table below are rounded to thousands. As of September 9, 2016 Predecessor Reorganization Fresh-Start Successor Company Adjustments Adjustments Company Current assets: Cash and cash equivalents $ 111,464 $ (97,521) (1) $ — $ 13,943 Accounts receivable 116,859 — — 116,859 Receivables from derivative contracts 97,648 — — 97,648 Restricted cash 17,164 — — 17,164 Prepaids and other 8,961 — (1,332) (7) 7,629 Total current assets 352,096 (97,521) (1,332) 253,243 Oil and natural gas properties (full cost method): Evaluated 7,712,003 — (6,497,874) (8) 1,214,129 Unevaluated 1,193,259 — (861,144) (8) 332,115 Gross oil and natural gas properties 8,905,262 — (7,359,018) 1,546,244 Less—accumulated depletion (6,803,231) — 6,803,231 (8) — Net oil and natural gas properties 2,102,031 — (555,787) 1,546,244 Other operating property and equipment: Other operating property and equipment 100,079 — (62,008) (9) 38,071 Less—accumulated depreciation (24,154) — 24,154 (9) — Net other operating property and equipment 75,925 — (37,854) 38,071 Other noncurrent assets: Receivables from derivative contracts 4,431 — — 4,431 Funds in escrow and other 1,610 — 27 (10) 1,637 Total assets $ 2,536,093 $ (97,521) $ (594,946) $ 1,843,626 Current liabilities: Accounts payable and accrued liabilities $ 160,000 $ 13,688 (2) $ — $ 173,688 Liabilities from derivative contracts 102 — — 102 Other 414 — 4,435 (11)(12) 4,849 Total current liabilities 160,516 13,688 4,435 178,639 Long-term debt, net 1,031,114 — (14,954) (13) 1,016,160 Liabilities subject to compromise 2,007,703 (2,007,703) (3) — — Other noncurrent liabilities: Liabilities from derivative contracts 525 — — 525 Asset retirement obligations 48,955 — (16,799) (12) 32,156 Other 528 — 3,425 (11)(14) 3,953 Commitments and contingencies Mezzanine equity: Redeemable noncontrolling interest 219,891 — (178,821) (14) 41,070 Stockholders' equity: Preferred stock (Predecessor) — — (4) — — Common Stock (Predecessor) 12 (12) (4) — — Common Stock (Successor) — 9 (5) — 9 Additional paid-in capital (Predecessor) 3,287,906 (3,287,906) (4) — — Additional paid-in capital (Successor) — 571,114 (5) — 571,114 Retained earnings (accumulated deficit) (4,221,057) 4,613,289 (6) (392,232) (15) — Total stockholders' equity (933,139) 1,896,494 (392,232) 571,123 Total liabilities and stockholders' equity $ 2,536,093 $ (97,521) $ (594,946) $ 1,843,626 Reorganization adjustments 1) The table below details cash payments as of September 9, 2016, pursuant to the terms of the Plan described in Note 2, “Reorganization,” (in thousands): Payment to Third Lien Noteholders $ 33,826 Payment to Unsecured Noteholders 37,595 Payment to Convertible Noteholder 15,000 Payment to Preferred Holders 11,100 Total Uses $ 97,521 2) In connection with the chapter 11 bankruptcy, the Company modified and rejected certain office lease arrangements and paid approximately $3.4 million for these modifications and rejections subsequent to the emergence from chapter 11 bankruptcy. This amount also reflects $10.3 million paid to the Company’s restructuring advisors subsequent to the emergence from chapter 11 bankruptcy. 3) Liabilities subject to compromise were as follows (in thousands): 13.0% senior secured third lien notes due 2022 $ 1,017,970 9.25% senior notes due 2022 37,194 8.875% senior notes due 2021 297,193 9.75% senior notes due 2020 315,535 8.0% convertible note due 2020 289,669 Accrued interest 46,715 Office lease modification and rejection fees 3,427 Liabilities subject to compromise 2,007,703 Fair value of equity and warrants issued to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder (548,947) Cash payments to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder (86,421) Office lease modification and rejection fees (3,427) Gain on settlement of Liabilities subject to compromise $ 1,368,908 4) Reflects the cancellation of Predecessor equity, as follows (in thousands): Predecessor Company stock $ 3,287,918 Fair value of equity issued to Predecessor common stockholders (22,176) Cash payment to Preferred Holders (11,100) Cancellation of Predecessor Company equity $ 3,254,642 5) Reflects the issuance of Successor equity. In accordance with the Plan, the Successor Company issued 3.6 million shares of common stock to the Predecessor Company’s existing common stockholders, 68.8 million shares of common stock to the Third Lien Noteholders, 14.0 million shares of common stock to the Unsecured Noteholders, and 3.6 million shares of common stock to the Convertible Noteholder. This amount is subject to dilution by warrants issued to the Unsecured Noteholders and the Convertible Noteholder totaling 4.7 million shares with an exercise price of $14.04 per share and a term of four years. The fair value of the warrants was estimated at $3.52 per share using a Black-Scholes-Merton valuation model. 6) The table below reflects the cumulative effect of the reorganization adjustments discussed above (in thousands): Gain on settlement of Liabilities subject to compromise $ 1,368,908 Accrued reorganization items (10,261) Cancellation of Predecessor Company equity 3,254,642 Net impact to retained earnings (accumulated deficit) $ 4,613,289 Fresh-start accounting adjustments 7) Reflects the reclassification of tubulars and well equipment to “Oil and natural gas properties.” 8) 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, probable and possible 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 10.5% for proved reserves and 12.5% 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. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 per barrel 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 analysts’ estimated prices. In estimating the fair value of the Company’s unproved acreage that was not included in the valuation of probable and possible reserves, 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. 9) In estimating the fair value of its other operating property and equipment, the Company used a combination of the income, cost, and market approaches. For purposes of estimating the fair value of its gas gathering assets, an income approach was used that estimated future cash flows associated with the assets over the remaining useful lives. The valuation included such inputs as estimated future production, gathering and compression revenues, and operating expenses that were discounted at a weighted average cost of capital rate of 9.5%. For purposes of estimating the fair value of its other operating assets, the Company used a combination of the market and cost approaches. A market approach was relied upon to value land and computer equipment, 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. 10) Reflects the adjustment of the Company’s equity method investment in SBE Partners, L.P. to fair value based on an income approach, which calculated the discounted cash flows of the Company’s share of the partnership’s interest in oil and gas estimated proved reserves. The anticipated cash flows of the reserve were risked by reserve category and discounted at 10.5%. Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $72.30 per barrel of oil, $3.50 per MMBtu of natural gas and $12.00 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 analysts’ estimated prices. 11) Records an intangible liability of approximately $8.3 million, $4.5 million of which was recorded as current, to adjust the Company’s active rig contract to fair value at September 9, 2016. The intangible liability will be amortized over the remaining life of the contract. 12) Reflects the adjustment of asset retirement obligations to fair value using estimated plugging and abandonment costs as of September 9, 2016, adjusted for inflation and then discounted at the appropriate credit-adjusted risk free rate ranging from 5.5% to 6.6% depending on the life of the well. The fair value of asset retirement obligations was estimated at $32.5 million, approximately $0.3 million of which was recorded as current. 13) Reflects the adjustment of the 2020 Second Lien Notes and the 2022 Second Lien Notes to fair value. The fair value estimate was based on quoted market prices from trades of such debt on September 9, 2016. 14) Reflects the adjustment of the Company’s redeemable noncontrolling interest and related embedded derivative of HK TMS to fair value. The fair value of the redeemable noncontrolling interest was estimated at $41.1 million and the embedded derivative was estimated at zero. For purposes of estimating the fair values, an income approach was used that estimated fair value based on the anticipated cash flows associated with HK TMS proved reserves, risked by reserve category and discounted using a weighted average cost of capital rate of 12.5%. The value of the redeemable noncontrolling interest was further reduced by a probability factor of the potential assignment of the common shares of HK TMS to Apollo, which occurred subsequent to the fresh-start date. Refer to Note 5, “ Acquisitions and Divestitures, ” for further information regarding the HK TMS Divestiture on September 30, 2016. 15) 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	The table below details cash payments as of September 9, 2016, pursuant to the terms of the Plan described in Note 2, “Reorganization,” (in thousands): Payment to Third Lien Noteholders $ 33,826 Payment to Unsecured Noteholders 37,595 Payment to Convertible Noteholder 15,000 Payment to Preferred Holders 11,100 Total Uses $ 97,521
Schedule of Liabilities subject to compromise, settled	Liabilities subject to compromise were as follows (in thousands): 13.0% senior secured third lien notes due 2022 $ 1,017,970 9.25% senior notes due 2022 37,194 8.875% senior notes due 2021 297,193 9.75% senior notes due 2020 315,535 8.0% convertible note due 2020 289,669 Accrued interest 46,715 Office lease modification and rejection fees 3,427 Liabilities subject to compromise 2,007,703 Fair value of equity and warrants issued to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder (548,947) Cash payments to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder (86,421) Office lease modification and rejection fees (3,427) Gain on settlement of Liabilities subject to compromise $ 1,368,908
Schedule of cancellation of predecessor equity	Reflects the cancellation of Predecessor equity, as follows (in thousands): Predecessor Company stock $ 3,287,918 Fair value of equity issued to Predecessor common stockholders (22,176) Cash payment to Preferred Holders (11,100) Cancellation of Predecessor Company equity $ 3,254,642
Schedule of cumulative effect of the reorganization adjustments	The table below reflects the cumulative effect of the reorganization adjustments discussed above (in thousands): Gain on settlement of Liabilities subject to compromise $ 1,368,908 Accrued reorganization items (10,261) Cancellation of Predecessor Company equity 3,254,642 Net impact to retained earnings (accumulated deficit) $ 4,613,289
Schedule of the net reorganization items	The following table summarizes the net reorganization items (in thousands): Successor Predecessor Period from Period from September 10, 2016 January 1, 2016 through through December 31, 2016 September 9, 2016 Gain on settlement of Liabilities subject to compromise $ — $ 1,368,908 Fresh start adjustments — (392,232) Reorganization professional fees and other (2,049) (30,287) Write-off debt discounts/premiums and debt issuance costs — (32,667) Gain (loss) on reorganization items $ (2,049) $ 913,722

OPERATING REVENUES (Tables)

OPERATING REVENUES (Tables)	12 Months Ended
	Dec. 31, 2018
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 September 10, 2016 January 1, 2016 Years Ended December 31, through through 2018 2017 (1) December 31, 2016 (1) September 9, 2016 (1) Operating revenues: Oil, natural gas and natural gas liquids sales: Oil $ 199,601 $ 340,674 $ 139,786 $ 248,064 Natural gas 6,791 16,194 6,756 9,511 Natural gas liquids 19,137 18,969 6,018 7,929 Total oil, natural gas and natural gas liquids sales 225,529 375,837 152,560 265,504 Other 1,080 2,128 802 1,339 Total operating revenues $ 226,609 $ 377,965 $ 153,362 $ 266,843 (1) As noted above, prior period amounts have not been adjusted under the modified retrospective method of adoption.

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2018
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 liabilites 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 Senior Credit Agreement. (2) In accordance with the purchase agreement, the effective date of the acquisition was November 1, 2016 and therefore revenues, expenses and related capital expenditures from November 1, 2016 through February 28, 2017, 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. Successor Predecessor Period from Period from September 10, 2016 January 1, 2016 Year ended through through December 31, 2017 December 31, 2016 September 9, 2016 (Unaudited) (Unaudited) (Unaudited) Revenue $ 385,867 $ 166,499 $ 288,902 Net income (loss) 542,724 (475,580) 16,513 Net income (loss) available to common stockholders 494,717 (476,371) (28,239) Pro forma net income (loss) per share of common stock: Basic $ 3.73 $ (5.22) $ (0.23) Diluted $ 3.70 $ (5.22) $ (0.23)

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2018
OIL AND NATURAL GAS PROPERTIES
Schedule of oil and natural gas properties	Oil and natural gas properties as of December 31, 2018 and 2017 consisted of the following (in thousands): December 31, 2018 December 31, 2017 Subject to depletion $ 1,470,509 $ 877,316 Not subject to depletion: Exploration and extension wells in progress 23,536 5,298 Other capital costs: Incurred in 2018 310,113 — Incurred in 2017 638,269 760,488 Incurred in 2016 — — Incurred in 2015 and prior — — Total not subject to depletion 971,918 765,786 Gross oil and natural gas properties 2,442,427 1,643,102 Less accumulated depletion (639,951) (570,155) Net oil and natural gas properties $ 1,802,476 $ 1,072,947
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 Intermediate Henry Hub (per barrel) (1) (per MMBtu) (1) December 31, 2018 $ 65.56 $ 3.100 December 31, 2017 51.34 2.976 December 31, 2016 42.75 2.481 (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, 2018
LONG-TERM DEBT
Schedule of debt	Long‑term debt as of December 31, 2018 and 2017 consisted of the following (in thousands): December 31, 2018 December 31, 2017 Senior revolving credit facility $ — $ — 6.75% senior notes due 2025 (1) 613,105 409,168 $ 613,105 $ 409,168 (1) On February 15, 2018, the Company issued an additional $200.0 million aggregate principal amount of its 2025 Notes at 103.0% of par. Amount includes a $7.2 million and $8.1 million unamortized discount at December 31, 2018 and 2017, respectively, associated with the 2025 Notes. Amount includes a $5.4 million unamortized premium at December 31, 2018, associated with the Additional 2025 Notes. Additionally, these amounts are net of $10.1 million and $7.7 million unamortized debt issuance costs at December 31, 2018 and 2017, respectively. Refer to “6.75% Senior Notes” below for further details.
Schedule of aggregate maturities required on long-term debt	Aggregate maturities required on long-term debt at December 31, 2018 due in future years are as follows (in thousands, excluding discounts, premiums and debt issuance costs): 2019 $ — 2020 — 2021 — 2022 — 2023 — Thereafter 625,005 Total $ 625,005

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 (in thousands): December 31, 2018 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 69,717 $ — $ 69,717 Liabilities Liabilities from derivative contracts $ — $ 12,907 $ — $ 12,907 December 31, 2017 Level 1 Level 2 Level 3 Total Assets Receivables from derivative contracts $ — $ 677 $ — $ 677 Liabilities Liabilities from derivative contracts $ — $ 26,999 $ — $ 26,999
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, 2018 and 2017 (excluding discounts, premiums and debt issuance costs) (in thousands): December 31, 2018 December 31, 2017 Principal Estimated Principal Estimated Debt Amount Fair Value Amount Fair Value 6.75% senior notes $ 625,005 $ 458,210 $ 425,005 $ 443,790

DERIVATIVE AND HEDGING ACTIVI_2

DERIVATIVE AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 (in thousands): Derivatives not designated Asset derivative contracts Liability derivative contracts as hedging contracts under December 31, December 31, December 31, December 31, ASC 815 Balance sheet location 2018 2017 Balance sheet location 2018 2017 Commodity contracts Current assets—receivables from derivative contracts $ 57,280 $ 677 Current liabilities—liabilities from derivative contracts $ (3,768) $ (19,248) Commodity contracts Other noncurrent assets—receivables from derivative contracts 12,437 — Other noncurrent liabilities—liabilities from derivative contracts (9,139) (7,751) Total derivatives not designated as hedging contracts under ASC 815 $ 69,717 $ 677 $ (12,907) $ (26,999)
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 September 10, 2016 January 1, 2016 Derivatives not designated as hedging Location of gain or (loss) recognized in Years Ended December 31, through through contracts under ASC 815 income on derivative contracts 2018 2017 December 31, 2016 September 9, 2016 Commodity contracts: Unrealized gain (loss) on commodity contracts Other income (expenses)—net gain (loss) on derivative contracts $ 84,274 $ (16,468) $ (112,449) $ (263,732) Realized gain (loss) on commodity contracts Other income (expenses)—net gain (loss) on derivative contracts 8,351 17,759 84,709 245,734 Total net gain (loss) on derivative contracts $ 92,625 $ 1,291 $ (27,740) $ (17,998)
Schedule of open derivative contracts	At December 31, 2018 and 2017, the Company had the following open crude oil and natural gas derivative contracts: 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 Janaury 2019—March 2019 Calls Crude Oil 1,350,000 $ — — $ — $ — 62.64 $ 62.64 Janaury 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 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 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 Swap Natural Gas Liquids 1,460,000 29.08 - 30.15 29.33 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 Basis Swap Crude Oil 460,000 (2.40) - (6.50) (5.68) July 2019—December 2019 Collars Crude Oil 552,000 50.00 - 55.00 53.00 55.00 - 69.00 61.00 October 2019—December 2019 Basis Swap Crude Oil 460,000 3.45 - 4.00 3.72 October 2019—December 2019 Collars Crude Oil 92,000 — 51.00 51.00 — 56.00 56.00 October 2019—December 2019 Swap Natural Gas Liquids 92,000 — 32.50 32.50 January 2020—December 2020 Basis Swap Crude Oil 3,294,000 2.00 - 4.00 2.95 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 — — — December 31, 2017 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 2018—December 2018 Basis Swap Crude Oil 2,555,000 $ — — $ — $ — — $ — $ (1.05) - (1.50) $ (1.29) January 2018—December 2018 Collars Crude Oil 2,920,000 45.00 - 53.00 49.29 50.00 - 60.00 56.82 January 2018—December 2018 Collars Natural Gas 2,737,500 3.00 - 3.03 3.01 3.22 - 3.38 3.30 April 2018—December 2018 Basis Swap Crude Oil 275,000 — - — — — - — — — - (1.15) (1.15) April 2018—December 2018 Collars Crude Oil 275,000 46.75 46.75 51.75 51.75 July 2018—December 2018 Basis Swap Crude Oil 1,012,000 (0.98) - (1.18) (1.12) July 2018—December 2018 Collars Crude Oil 184,000 48.50 48.50 53.50 53.50 October 2018—December 2018 Collars Crude Oil 92,000 50.65 50.65 55.65 55.65 January 2019—March 2019 Collars Crude Oil 90,000 46.75 46.75 51.75 51.75 January 2019—December 2019 Basis Swap Crude Oil 4,380,000 (0.50) - (1.33) (1.02) January 2019—December 2019 Collars Crude Oil 1,825,000 50.00 - 51.00 50.24 55.00 - 57.30 55.70
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, 2018 and 2017 (in thousands): Derivative Assets Derivative Liabilities December 31, December 31, December 31, December 31, Offsetting of Derivative Assets and Liabilities 2018 2017 2018 2017 Gross amounts presented in the consolidated balance sheet $ 69,717 $ 677 $ (12,907) $ (26,999) Amounts not offset in the consolidated balance sheet (10,263) (231) 10,263 231 Net amount $ 59,454 $ 446 $ (2,644) $ (26,768)

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2016 $ 32,375 Liabilities settled and divested (1) (33,796) Additions 592 Acquisitions (1) 3,109 Accretion expense 1,306 Revisions in estimated cash flows 782 Liability for asset retirement obligations as of December 31, 2017 $ 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 $ 6,914 (1) See Note 5, “Acquisitions and Divestitures,” for additional information on the Company’s acquisition and divestiture activities.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2018
COMMITMENTS AND CONTINGENCIES
Schedule of approximate future minimum lease payments for subsequent annual periods for all non-cancelable operating leases	Approximate future minimum lease payments for subsequent annual periods for all non-cancelable operating leases as of December 31, 2018 are as follows (in thousands): 2019 $ 3,792 2020 2,350 2021 1,899 2022 968 2023 999 Thereafter 599 Total $ 10,607
Schedule of commitments	As of December 31, 2018, the Company has the following active drilling rig commitments (in thousands): 2019 $ 4,973 2020 — 2021 — 2022 — 2023 — Thereafter — Total $ 4,973
Schedule of rig termination and stacking fees commitments	As of December 31, 2018, the Company has the following rig termination and stacking fees commitments (in thousands): 2019 $ 781 2020 3,000 2021 — 2022 — 2023 — Thereafter — Total $ 3,781
Schedule of purchase commitments related to equipment	As of December 31, 2018, the Company has the following purchase commitments related to equipment (in thousands): 2019 $ 20,233 2020 — 2021 — 2022 — 2023 — Thereafter — Total $ 20,233

STOCKHOLDERS' EQUITY (Tables)

STOCKHOLDERS' EQUITY (Tables)	12 Months Ended
	Dec. 31, 2018
STOCKHOLDERS' EQUITY
Schedule of the stock option transactions	Weighted Aggregate Weidhted Average Average Intrinsic Remaining Exercise Price Value (1) Contractual Life Number Per Share (In thousands) (Years) Outstanding at December 31, 2015 (Predecessor) 4,860,133 $ 17.80 $ — 8.4 Granted — — Exercised — — Forfeited (695,302) 21.17 Cancelled (2) (4,164,831) 17.23 Outstanding at September 9, 2016 (Predecessor) — $ — $ — — Outstanding at September 9, 2016 (Successor) — $ — $ — — Granted 5,319,400 9.22 Exercised — — Forfeited — — Outstanding at December 31, 2016 (Successor) 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 (Successor) 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 (Successor) 7,468,926 $ 8.34 $ — 8.1 (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 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 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. No stock options were exercised during the year ended December 31, 2017 or 2016. (2) Immediately prior to emergence from chapter 11 bankruptcy, all outstanding options under the Predecessor incentive plan were cancelled.
Schedule of outstanding options by exercise price range	Options outstanding at December 31, 2018 consisted of the following: Outstanding Exercisable (1) Weighted Average Weighted Average Weighted Average Remaining Weighted Average Aggregate Remaining Range of Grant Exercise Price Contractual Life Exercise Price Intrinsic Contractual Life Prices Per Share Number per Share (Years ) Number per Share Value (Years ) $5.65 - $7.75 2,783,493 $ 6.85 8.7 — $ — $ — — $8.93 - $9.24 4,685,433 9.23 7.7 — — — — (1) At December 31, 2018, none of the Company’s options were exercisable due to service performance conditions or option exercise prices above the current market value of the underlying stock.
Schedule of assumptions used in calculating fair value of the Company's stock-based compensation	Successor Period from September 10, 2016 Years Ended December 31, through 2018 2017 December 31, 2016 Weighted average value per option granted during the period $ 2.92 $ 4.36 $ 6.07 Assumptions: Stock price volatility (1) 52.08 % 60.18 % 56.29 % Risk free rate of return 2.63 % 1.94 % 1.34 % Expected term 6 years 6 years 6 years (1) Due to the 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: Weighted Aggregate Average Grant Intrinsic Number of Date Fair Value Value (1) Shares Per Share (In thousands) Unvested outstanding shares at December 31, 2015 (Predecessor) 2,870,405 $ 7.55 $ 3,617 Granted — — Vested (436,256) 18.50 Accelerated vesting (2) (1,917,072) 5.39 Forfeited (517,077) 6.31 Unvested outstanding shares at September 9, 2016 (Predecessor) — $ — $ — Unvested shares outstanding at September 9, 2016 (Successor) — $ — $ — Granted 2,991,202 9.14 Vested (1,253,125) 9.24 Forfeited — — Unvested outstanding shares at December 31, 2016 (Successor) 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 (Successor) 745,507 $ 7.05 $ 5,643 Granted 2,326,961 5.47 Vested (537,411) 5.89 Forfeited (262,164) 6.29 Unvested shares outstanding at December 31, 2018 (Successor) 2,272,893 $ 5.80 $ 3,864 (1) The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2018, 2017 and 2016 of the underlying stock multiplied by the number of restricted shares. The total fair value of shares vested was $2.0 million, $16.1 million, $11.6 million and $0.9 million for the years ended December 31, 2018 and 2017, the period from September 10, 2016 through December 31, 2016, and the period from January 1, 2016 through September 9, 2016, respectively. (2) Immediately prior to emergence from chapter 11 bankruptcy, all outstanding unvested restricted stock under the Predecessor incentive plan were vested.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2018
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 September 10, 2016 January 1, 2016 Years Ended December 31, through through 2018 2017 December 31, 2016 September 9, 2016 Current: Federal $ — $ 5,000 $ (5,000) $ 8,666 State — — 256 — — 5,000 (4,744) 8,666 Deferred: Federal (95,791) — 52,223 (22,491) State — — (52,223) 22,491 — — — — Total income tax benefit (provision) $ (95,791) $ 5,000 $ (4,744) $ 8,666
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 year ended December 31, 2018 and 35% for each of the prior periods, as follows (in thousands): Successor Predecessor Period from Period from September 10, 2016 January 1, 2016 Years Ended December 31, through through 2018 2017 December 31, 2016 September 9, 2016 Expected tax benefit (provision) $ (29,767) $ (185,740) $ 166,057 $ (1,152) State income tax expense, net of federal benefit — (2,587) 6,243 (43) Stock-based compensation (350) — — (14,803) Net operating loss limitation under IRC Section 382 — — (161,704) — TMS Divestiture — — (157,767) — Adjustments attributable to reorganization — — — 275,460 Change in state rate — (10,121) — — Debt related costs — — — (4,089) Cancellation of indebtedness income — — — 103,268 Increase (reduction) in deferred tax asset (201,903) 95,907 — 14,645 Change in valuation allowance and related items 136,432 392,846 202,592 (263,211) IRC section 108 attribute reduction — — (56,483) (101,342) Tax Cuts and Jobs Act of 2017 — (280,874) — — Permanent adjustments (203) — — — Other — (4,431) (3,682) (67) Total income tax benefit (provision) $ (95,791) $ 5,000 $ (4,744) $ 8,666
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): December 31, 2018 December 31, 2017 Deferred noncurrent income tax assets: Net operating loss carry-forwards $ 204,751 $ 205,570 Built in loss adjustment Section 382 88,835 90,897 Stock-based compensation expense 8,509 5,501 Asset retirement obligations 1,011 963 Book-tax differences in property basis — 125,309 Unrealized hedging transactions — 5,901 Disallowed interest Section 163(j) 3,370 — Other 1,917 — Gross deferred noncurrent income tax assets 308,393 434,141 Valuation allowance (290,333) (426,765) Deferred noncurrent income tax assets $ 18,060 $ 7,376 Deferred noncurrent income tax liabilities: Basis difference in debt $ (5,507) $ (6,366) Book-tax differences in property basis (96,414) — Unrealized hedging transactions (11,930) — Other — (1,010) Deferred noncurrent income tax liabilities $ (113,851) $ (7,376) Net noncurrent deferred income tax assets (liabilities) $ (95,791) $ —

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2018
EARNINGS PER COMMON 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 September 10, 2016 January 1, 2016 Years Ended December 31, through through 2018 2017 December 31, 2016 September 9, 2016 Basic: Net income (loss) available to common stockholders $ 45,959 $ 487,679 $ (479,984) $ (32,794) Weighted average basic number of common shares outstanding 157,011 132,763 91,228 120,513 Basic net income (loss) per common share $ 0.29 $ 3.67 $ (5.26) $ (0.27) Diluted: Net income (loss) available to common stockholders $ 45,959 $ 487,679 $ (479,984) $ (32,794) Weighted average basic number of common shares outstanding 157,011 132,763 91,228 120,513 Common stock equivalent shares representing shares issuable upon: Exercise of stock options Anti-dilutive Anti-dilutive Anti-dilutive Anti-dilutive Exercise of February 2012 Warrants — — — Anti-dilutive Exercise of warrants Anti-dilutive Anti-dilutive Anti-dilutive — Vesting of restricted shares 284 813 Anti-dilutive Anti-dilutive Vesting of performance units — — — — Conversion of preferred stock — Anti-dilutive — — Conversion of Convertible Note — — — Anti-dilutive Conversion of Series A Preferred Stock — — — Anti-dilutive Weighted average diluted number of common shares outstanding 157,295 133,576 91,228 120,513 Diluted net income (loss) per common share $ 0.29 $ 3.65 $ (5.26) $ (0.27)

ADDITIONAL FINANCIAL STATEMEN_2

ADDITIONAL FINANCIAL STATEMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2018
ADDITIONAL FINANCIAL STATEMENT INFORMATION
Schedule of additional financial statement information, balance sheet	Certain balance sheet amounts are comprised of the following (in thousands): December 31, 2018 December 31, 2017 Accounts receivable: Oil, natural gas and natural gas liquids revenues $ 26,432 $ 24,110 Joint interest accounts 7,369 2,249 Other 1,917 10,057 $ 35,718 $ 36,416 Prepaids and other: Prepaids $ 3,503 $ 4,324 Income tax receivable 1,250 6,250 Other 35 54 $ 4,788 $ 10,628 Funds in escrow and other: Funds in escrow $ 570 $ 563 Other 1,611 1,128 $ 2,181 $ 1,691 Accounts payable and accrued liabilities: Trade payables $ 68,959 $ 35,688 Accrued oil and natural gas capital costs 41,461 50,743 Revenues and royalties payable 20,526 20,256 Accrued interest expense 16,971 10,985 Accrued employee compensation 3,421 9,805 Accrued lease operating expenses 6,292 2,024 Other 218 1,586 $ 157,848 $ 131,087

SUMMARY OF SIGNIFICANT EVENTS_3

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)segment	Dec. 31, 2017USD ($)
Basis of Presentation and Principles of Consolidation
Number of operating segments | segment	1
Allowance for doubtful accounts | $	$ 0.2	$ 0.7

SUMMARY OF SIGNIFICANT EVENTS_4

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Details) - Other Operating Property and Equipment (Details) - USD ($) $ in Thousands	8 Months Ended	12 Months Ended
	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017
Other operating property and equipment
Property, Plant and Equipment, Other, Gross	$ 38,071	$ 130,251	$ 101,282
Predecessor
Other operating property and equipment
Non-cash impairment charge	28,056
Property, Plant and Equipment, Other, Gross	100,079
Other operating property and equipment
Other operating property and equipment
Estimated useful lives		30 years
Other operating property and equipment | Predecessor
Other operating property and equipment
Non-cash impairment charge	28,100
Property, Plant and Equipment, Other, Gross	$ 32,800
Water disposal and recycling facilities
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_5

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Details) - Concentrations of Credit Risk (Details) - Revenue - Concentrations of Credit Risk - customer	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Concentrations of Credit Risk
Number of customers	2	2	2
Sunoco and Western Refining Inc.
Concentrations of Credit Risk
Percentage of concentration risk	77.00%
Sunoco | Minimum
Concentrations of Credit Risk
Percentage of concentration risk	10.00%
Western Refining | Minimum
Concentrations of Credit Risk
Percentage of concentration risk	10.00%
Crestwood and Suncor
Concentrations of Credit Risk
Percentage of concentration risk		58.00%	58.00%
Crestwood | Minimum
Concentrations of Credit Risk
Percentage of concentration risk		10.00%	10.00%
Suncor | Minimum
Concentrations of Credit Risk
Percentage of concentration risk		10.00%	10.00%

SUMMARY OF SIGNIFICANT EVENTS_6

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES (Details) - Income Taxes (Details) - USD ($) $ in Millions	Sep. 09, 2016	Jan. 31, 2016	Aug. 31, 2016	Mar. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Unrecognized Tax Benefits						$ 0	$ 0	$ 0	$ 0
Interest or penalties recognized in the results of operations						0	0	0
Interest or penalties recognized in the statement of financial position							$ 0	$ 0
Predecessor
Unrecognized Tax Benefits	$ 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

SUMMARY OF SIGNIFICANT EVENTS_7

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - Restructuring and Redeemable Noncontrolling Interest (Details)	Jun. 16, 2014USD ($)shares	Sep. 30, 2016shares	Sep. 09, 2016USD ($)shares	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Restructuring
Severance Costs			$ 5,200,000	$ 100,000	$ 7,500,000
HK TMS | Preferred Stock
Redeemable Noncontrolling Interest
Proceeds received on sale of preferred shares	$ 150,000,000
Dividend rate (as a percent)	8.00%
Rate of return on preferred shares (as a percent)	12.00%
Multiple factor on investment	1.25
Additional preferred shares issued for dividends paid-in-kind | shares		791	9,329
HK TMS | Preferred Stock | Apollo
Redeemable Noncontrolling Interest
Initial Preferred Shares issued | shares	150,000
HK TMS | Preferred Stock
Redeemable Noncontrolling Interest
Ownership percentage in subsidiaries	100.00%

SUMMARY OF SIGNIFICANT EVENTS_8

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - 401 (k) Plan (Details) - USD ($) $ in Millions	4 Months Ended	8 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 09, 2016	Sep. 30, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2015
401(k) Plan
Eligibility age for employees to participate in the plan				18 years
Company's matching contributions	$ 0.8	$ 2		$ 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%

SUMMARY OF SIGNIFICANT EVENTS_9

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - Related Party Transactions (Details) - USD ($) $ in Millions	Jul. 27, 2018	Nov. 16, 2017	Dec. 31, 2018
Chairman, Chief Executive Officer and President
Related Party Transactions
Amount paid for charter of aircraft			$ 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%
Salt Creek Midstream, LLC
Related Party Transactions
Term		15 years
Amount received			0.4
SCM Crude, LLC
Related Party Transactions
Term	15 years
Amount received			13
Receivable from related party			$ 10.9

SUMMARY OF SIGNIFICANT EVENT_10

SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES - Recently Issued Accounting Pronouncements (Details) $ in Millions	Dec. 31, 2018USD ($)
Non-cancelable leases and drilling contracts
Recently Issued Accounting Pronouncements
Contractual obligations related to non-cancelable leases and drilling contracts	$ 15.6

REORGANIZATION (Details)

REORGANIZATION (Details) $ / shares in Units, $ in Thousands	Sep. 09, 2017USD ($)$ / shares	Sep. 09, 2016USD ($)$ / shares	Jun. 09, 2016	May 15, 2016USD ($)$ / shares	Sep. 09, 2016USD ($)$ / shares	Oct. 07, 2017	Feb. 16, 2017	Dec. 21, 2015USD ($)	May 01, 2015USD ($)
Restructuring Support Agreement
Exercise price (in dollars per share) | $ / shares		$ 14.04			$ 14.04
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%
Predecessor
Restructuring Support Agreement
Interest rate (as a percent)			13.00%
Cash Payments Made To Preferred Holders					$ 11,100
Predecessor | 8.625% senior secured second lien notes due 2020
Restructuring Support Agreement
Interest rate (as a percent)									8.625%
Principal amount									$ 700,000
Predecessor | 12.0% senior secured second lien notes due 2022
Restructuring Support Agreement
Interest rate (as a percent)								12.00%
Principal amount								$ 112,800
Predecessor | 9.25% senior notes due 2022
Restructuring Support Agreement
Interest rate (as a percent)			9.25%
Predecessor | 8.875% senior notes due 2021
Restructuring Support Agreement
Interest rate (as a percent)			8.875%
Predecessor | 9.75% senior notes due 2020
Restructuring Support Agreement
Interest rate (as a percent)			9.75%
Predecessor | 8.0% convertible note due 2020
Restructuring Support Agreement
Interest rate (as a percent)			8.00%
Predecessor | Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | Common Stock
Restructuring Support Agreement
Pro-forma equity of reorganized Entity (as a percent)		4			4
Predecessor | Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | Series A Preferred Stock
Restructuring Support Agreement
Dividend rate (as a percent)			5.75%
Cash Payments Made To Preferred Holders		$ 11,100
Predecessor | Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | 13.0% senior secured third lien notes due 2022
Restructuring Support Agreement
Pro-forma equity of reorganized Entity (as a percent)				76.50
Cash payment to noteholders				$ 33,800
Predecessor | Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | 8.0% convertible note due 2020
Restructuring Support Agreement
Pro-forma equity of reorganized Entity (as a percent)	4
Cash payment to noteholders	$ 15,000
Warrants to purchase shares of pro-forma equity of reorganized Halcon (as a percent)	1.00%
Exercise price (in dollars per share) | $ / shares	$ 14.04
Extension term	4 years
Predecessor | Restructuring of indebtedness and capitalization | The Restructuring Support Agreement | Senior Unsecured Notes Held by Certain Holders
Restructuring Support Agreement
Pro-forma equity of reorganized Entity (as a percent)				15.5
Cash payment to noteholders				$ 37,600
Warrants to purchase shares of pro-forma equity of reorganized Halcon (as a percent)				4.00%
Warrant term				4 years
Exercise price (in dollars per share) | $ / shares				$ 14.04

FRESH-START ACCOUNTING (Details

FRESH-START ACCOUNTING (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2015
Fresh-Start Adjustment
Enterprise Value				$ 1,618,888
Plus: Cash	$ 46,866	$ 424,071	$ 24	13,943
Less: Fair value of debt				(1,016,160)
Less: Fair value of redeemable noncontrolling interest				(41,070)
Less: Fair value of other long-term liabilities				(4,478)
Less: Fair value of warrants				(16,691)
Fair Value of Successor common stock				554,432
Minimum
Fresh-Start Adjustment
Enterprise Value				1,600,000
Maximum
Fresh-Start Adjustment
Enterprise Value				1,800,000
Predecessor
Fresh-Start Adjustment
Plus: Cash				13,943	$ 8,026
Fair Value of Successor common stock				$ (22,176)
Predecessor | 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%

FRESH-START ACCOUNTING-Enterpri

FRESH-START ACCOUNTING-Enterprise to Reorg Values (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 09, 2016
FRESH-START ACCOUNTING
Enterprise Value				$ 1,618,888
Plus: Cash	$ 46,866	$ 424,071	$ 24	13,943
Plus: Current liabilities				178,639
Plus: Noncurrent asset retirement obligation				32,156
Reorganization Value of Successor assets				$ 1,843,626

FRESH-START ACCOUNTING-Balance

FRESH-START ACCOUNTING-Balance sheet effects (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Sep. 09, 2017	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 46,866	$ 424,071		$ 24	$ 13,943
Accounts receivable	35,718	36,416			116,859
Receivables from derivative contracts	57,280	677			97,648
Restricted cash					17,164
Prepaids and other	4,788	10,628			7,629
Total current assets	144,652	471,792			253,243
Oil and natural gas properties (full cost method):
Evaluated	1,470,509	877,316			1,214,129
Unevaluated	971,918	765,786			332,115
Gross oil and natural gas properties	2,442,427	1,643,102			1,546,244
Less - accumulated depletion	(639,951)	(570,155)
Net oil and natural gas properties	1,802,476	1,072,947			1,546,244
Other operating property and equipment:
Other operating property and equipment	130,251	101,282			38,071
Less - accumulated depreciation	(8,388)	(4,092)
Net other operating property and equipment	121,863	97,190			38,071
Other noncurrent assets:
Receivables from derivative contracts	12,437				4,431
Funds in escrow and other	2,181	1,691			1,637
Total assets	2,083,609	1,643,620			1,843,626
Current liabilities:
Accounts payable and accrued liabilities	157,848	131,087			173,688
Liabilities from derivative contracts	3,768	19,248			102
Other					4,849
Current portion of asset retirement obligation	126
Total current liabilities	161,742	150,335			178,639
Long-term debt, net	613,105	409,168			1,016,160
Liabilities subject to compromise					2,007,703
Other noncurrent liabilities:
Liabilities from derivative contracts	9,139	7,751			525
Asset retirement obligations	6,788	4,368			32,156
Other					3,953
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest					41,070
Stockholders' equity:
Common stock	16	15			9
Additional paid-in capital	1,095,367	1,016,281			571,114
Retained earnings (accumulated deficit)	101,661	55,702
Total stockholders' equity	1,197,044	1,071,998		$ 112,688	571,123
Total liabilities and stockholders' equity	$ 2,083,609	$ 1,643,620			1,843,626
Reorganization Adjustments
Current assets:
Cash and cash equivalents					(97,521)
Total current assets					(97,521)
Other noncurrent assets:
Total assets					(97,521)
Current liabilities:
Accounts payable and accrued liabilities					13,688
Total current liabilities					13,688
Liabilities subject to compromise					(2,007,703)
Other noncurrent liabilities:
Commitments and contingencies
Stockholders' equity:
Common stock					9
Additional paid-in capital					571,114
Retained earnings (accumulated deficit)					4,613,289
Total stockholders' equity					1,896,494
Total liabilities and stockholders' equity					(97,521)
Fresh Start Adjustments
Current assets:
Prepaids and other					(1,332)
Total current assets					(1,332)
Oil and natural gas properties (full cost method):
Evaluated					(6,497,874)
Unevaluated					(861,144)
Gross oil and natural gas properties					(7,359,018)
Less - accumulated depletion					6,803,231
Net oil and natural gas properties					(555,787)
Other operating property and equipment:
Other operating property and equipment					(62,008)
Less - accumulated depreciation					24,154
Net other operating property and equipment					(37,854)
Other noncurrent assets:
Funds in escrow and other					27
Total assets					(594,946)
Current liabilities:
Other					4,435
Total current liabilities					4,435
Long-term debt, net					(14,954)
Other noncurrent liabilities:
Asset retirement obligations					(16,799)
Other					3,425
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest					(178,821)
Stockholders' equity:
Retained earnings (accumulated deficit)					(392,232)
Total stockholders' equity					(392,232)
Total liabilities and stockholders' equity					(594,946)
Predecessor
Current assets:
Cash and cash equivalents					111,464
Cash and cash equivalents					13,943	$ 8,026
Accounts receivable					116,859
Receivables from derivative contracts					97,648
Restricted cash					17,164
Prepaids and other					8,961
Total current assets					352,096
Oil and natural gas properties (full cost method):
Evaluated					7,712,003
Unevaluated					1,193,259
Gross oil and natural gas properties					8,905,262
Less - accumulated depletion					(6,803,231)
Net oil and natural gas properties					2,102,031
Other operating property and equipment:
Other operating property and equipment					100,079
Less - accumulated depreciation					(24,154)
Net other operating property and equipment					75,925
Other noncurrent assets:
Receivables from derivative contracts					4,431
Funds in escrow and other					1,610
Total assets					2,536,093
Current liabilities:
Accounts payable and accrued liabilities					160,000
Liabilities from derivative contracts					102
Other					414
Total current liabilities					160,516
Long-term debt, net					1,031,114
Liabilities subject to compromise					2,007,703
Other noncurrent liabilities:
Liabilities from derivative contracts					525
Asset retirement obligations					48,955
Other					528
Commitments and contingencies
Mezzanine equity:
Redeemable noncontrolling interest					219,891
Stockholders' equity:
Common stock					12
Additional paid-in capital					3,287,906
Retained earnings (accumulated deficit)					(4,221,057)
Total stockholders' equity					(933,139)	$ 52,414
Total liabilities and stockholders' equity					2,536,093
Predecessor | Reorganization Adjustments
Stockholders' equity:
Common stock					(12)
Additional paid-in capital					(3,287,906)
Total stockholders' equity					$ 3,287,918

FRESH-START ACCOUNTING-Net cash

FRESH-START ACCOUNTING-Net cash payments (Details) $ in Thousands	Sep. 09, 2016USD ($)
Uses:
Payment to settle debt	$ (86,421)
Reorganization Adjustments
Uses:
Total Uses	97,521
Reorganization Adjustments | Series A Preferred Stock
Uses:
Cash payment to Preferred holders	11,100
Reorganization Adjustments | 13.0% senior secured third lien notes due 2022
Uses:
Payment to settle debt	33,826
Reorganization Adjustments | 8.0% convertible note due 2020
Uses:
Payment to settle debt	15,000
Reorganization Adjustments | Senior Unsecured Notes Held by Certain Holders
Uses:
Payment to settle debt	$ 37,595

FRESH-START ACCOUNTING-Liabilit

FRESH-START ACCOUNTING-Liabilities subject to compromise (Details) - USD ($) $ in Thousands	Sep. 09, 2016	Sep. 30, 2016
Liabilities subject to compromise
Accrued interest	$ 46,715
Office lease modification and rejection fees	3,427
Liabilities subject to compromise, Total	2,007,703
Fair value of equity and warrants issued to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder	(548,947)
Cash payments to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder	(86,421)
Office lease modification and rejection fees	(3,427)
Gain on settlement of Liabilities subject to compromise	1,368,908
13.0% senior secured third lien notes due 2022
Liabilities subject to compromise
Debt	1,017,970
9.25% senior notes due 2022
Liabilities subject to compromise
Debt	37,194
8.875% senior notes due 2021
Liabilities subject to compromise
Debt	297,193
9.75% senior notes due 2020
Liabilities subject to compromise
Debt	315,535
8.0% convertible note due 2020
Liabilities subject to compromise
Debt	289,669
Reorganization Adjustments
Fresh-Start Adjustment
Payments for amended certain office lease arrangements		$ 3,400
Restructuring Advisor fees		$ 10,300
Liabilities subject to compromise
Liabilities subject to compromise, Total	$ (2,007,703)
Reorganization Adjustments | 13.0% senior secured third lien notes due 2022
Liabilities subject to compromise
Interest rate (as a percent)	13.00%
Cash payments to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder	$ 33,826
Reorganization Adjustments | 9.25% senior notes due 2022
Liabilities subject to compromise
Interest rate (as a percent)	9.25%
Reorganization Adjustments | 8.875% senior notes due 2021
Liabilities subject to compromise
Interest rate (as a percent)	8.875%
Reorganization Adjustments | 9.75% senior notes due 2020
Liabilities subject to compromise
Interest rate (as a percent)	9.75%
Reorganization Adjustments | 8.0% convertible note due 2020
Liabilities subject to compromise
Interest rate (as a percent)	8.00%
Cash payments to Third Lien Noteholders, Unsecured Noteholders and Convertible Noteholder	$ 15,000

FRESH-START ACCOUNTING-Cancella

FRESH-START ACCOUNTING-Cancellation of predecessor equity (Details) - USD ($) $ in Thousands	Sep. 09, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cancellation of predecessor equity
Company Stock	$ (571,123)	$ (571,123)	$ (1,197,044)	$ (1,071,998)	$ (112,688)
Fair value of equity issued to Predecessor common stockholders	554,432	554,432
Predecessor
Cancellation of predecessor equity
Company Stock	933,139	933,139				$ (52,414)
Fair value of equity issued to Predecessor common stockholders	(22,176)	(22,176)
Cash payment to Preferred Holders		(11,100)
Reorganization Adjustments
Cancellation of predecessor equity
Company Stock	(1,896,494)	(1,896,494)
Reorganization Adjustments | Predecessor
Cancellation of predecessor equity
Company Stock	(3,287,918)	(3,287,918)
Fair value of equity issued to Predecessor common stockholders	(22,176)	$ (22,176)
Cash payment to Preferred Holders	(11,100)
Cancellation of Predecessor Company equity	$ 3,254,642

FRESH-START ACCOUNTING-Successo

FRESH-START ACCOUNTING-Successor equity (Details) - $ / shares shares in Millions	Feb. 09, 2018	Apr. 06, 2017	Sep. 09, 2016
Stockholders' equity
Shares issued	9.2	55.2	90
Equivalent number shares of the warrants			4.7
Exercise price (in dollars per share)			$ 14.04
Warrants Issued to Former Holders of Unsecured and Convertible Notes
Stockholders' equity
Exercise price (in dollars per share)			$ 14.04
Exercise or expiration period			4 years
Reorganization Adjustments | Warrants Issued to Former Holders of Unsecured and Convertible Notes
Stockholders' equity
Fair Value price of Warrants (in dollars per share)			$ 3.52
Reorganization Adjustments | 8.0% convertible note due 2020
Stockholders' equity
Shares issued			3.6
Reorganization Adjustments | Senior Unsecured Notes Held by Certain Holders
Stockholders' equity
Shares issued			14
Reorganization Adjustments | Common Stock
Stockholders' equity
Shares issued			3.6
Reorganization Adjustments | Common Stock | 13.0% senior secured third lien notes due 2022
Stockholders' equity
Shares issued			68.8

FRESH-START ACCOUNTING-Effect o

FRESH-START ACCOUNTING-Effect of reorganization adj cumulative (Details) $ in Thousands	Sep. 09, 2016USD ($)	Sep. 09, 2016USD ($)
Cumulative effect of the reorganization adjustments
Gain on settlement of Liabilities subject to compromise	$ 1,368,908
Predecessor
Cumulative effect of the reorganization adjustments
Gain on settlement of Liabilities subject to compromise		$ 1,368,908
Predecessor | Reorganization Adjustments
Cumulative effect of the reorganization adjustments
Accrued reorganization items	(10,261)	(10,261)
Cancellation of Predecessor Company equity	3,254,642
Net impact to retained earnings (accumulated deficit)	$ 4,613,289	$ 4,613,289

FRESH-START ACCOUNTING-FV adjus

FRESH-START ACCOUNTING-FV adjustments to oil and natural gas properties (Details) - Fresh Start Adjustments	Sep. 09, 2016$ / MMBTU$ / bbl
Oil and natural gas properties (full cost method):
Weighted average cost of capital rate (as a percent)	10.50
Weighted average cost of capital for probable and possible reserves rate (as a percent)	12.5
Development plan in years	5 years
Weighted average commodity price of oil (in dollars per barrel)	72.30
Weighted average commodity price of natural gas (in dollars per Mmbtu) | $ / MMBTU	3.50
Weighted average commodity price of natural gas liquids (in dollars per barrel)	12

FRESH-START ACCOUNTING-FV adj_2

FRESH-START ACCOUNTING-FV adjustments to other operating properties (Details) $ in Thousands	Sep. 09, 2016USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Other operating property and equipment:
Asset retirement obligations		$ 6,914	$ 4,368	$ 32,375
Fresh Start Adjustments
Other operating property and equipment:
Weighted average cost of capital rate (as a percent)	10.50
Asset retirement obligations	$ 32,500
Fair value of asset retirement obligation current	300
Fair value of redeemable noncontrolling interest	41,100
Fair Value of embedded derivative	$ 0
Fresh Start Adjustments | Embedded Derivative
Other operating property and equipment:
Weighted average cost of capital rate (as a percent)	12.5
Fresh Start Adjustments | Minimum
Other operating property and equipment:
Risk free rate (as a percent)	5.50%
Fresh Start Adjustments | Maximum
Other operating property and equipment:
Risk free rate (as a percent)	6.60%
Fresh Start Adjustments | Drilling rig commitments
Other operating property and equipment:
Intangible liability for rig contract	$ 8,300
Intangible current liability for rig contract	$ 4,500
Fresh Start Adjustments | Other operating property and equipment
Other operating property and equipment:
Weighted average cost of capital rate (as a percent)	9.5

FRESH-START ACCOUNTING-Reorgani

FRESH-START ACCOUNTING-Reorganization items (Details) - USD ($) $ in Thousands	Sep. 09, 2016	Dec. 31, 2016	Sep. 09, 2016
Reorganization Items
Gain on settlement of Liabilities subject to compromise	$ 1,368,908
Reorganization professional fees and other		$ (2,049)
Gain (loss) on reorganization items		$ (2,049)
Predecessor
Reorganization Items
Gain on settlement of Liabilities subject to compromise			$ 1,368,908
Fresh start adjustments			(392,232)
Reorganization professional fees and other			(30,287)
Write-off of debt discounts/premium and debt issuance costs			(32,667)
Gain (loss) on reorganization items			$ 913,722

OPERATING REVENUES - Adoption o

OPERATING REVENUES - Adoption of ASC 606, Revenue from Contracts with Customers (Details) - USD ($) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Operating revenues
Gathering and other expense	$ (14,677)	$ (60,090)	$ (40,783)
Adjustments due to ASU 201409 | ASU 201409
Operating revenues
Cumulative effect of applying ASC 606		0
Oil, natural gas and natural gas liquids sales		1,100
Gathering and other expense		$ 1,100

OPERATING REVENUES - Revenue Re

OPERATING REVENUES - Revenue Recognition (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of operating revenue
Other	$ 802		$ 1,080	$ 2,128
Total operating revenues	153,362		226,609	377,965
Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Other	802			2,128
Total operating revenues	153,362			377,965
Total oil, natural gas and natural gas liquids sales
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	152,560		225,529	375,837
Total oil, natural gas and natural gas liquids sales | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	152,560			375,837
Oil
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	139,786		199,601	340,674
Oil | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	139,786			340,674
Natural gas
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	6,756		6,791	16,194
Natural gas | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	6,756			16,194
Natural gas liquids
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	6,018		19,137	18,969
Natural gas liquids | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales	$ 6,018			18,969
Accounts receivable
Disaggregation of operating revenue
Due from contracts with customers			$ 26,400	$ 24,100
Predecessor
Disaggregation of operating revenue
Other		$ 1,339
Total operating revenues		266,843
Predecessor | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Other		1,339
Total operating revenues		266,843
Predecessor | Total oil, natural gas and natural gas liquids sales
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		265,504
Predecessor | Total oil, natural gas and natural gas liquids sales | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		265,504
Predecessor | Oil
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		248,064
Predecessor | Oil | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		248,064
Predecessor | Natural gas
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		9,511
Predecessor | Natural gas | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		9,511
Predecessor | Natural gas liquids
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		7,929
Predecessor | Natural gas liquids | Calculated under Revenue Guidance in Effect before Topic 606
Disaggregation of operating revenue
Total oil, natural gas and natural gas liquids sales		$ 7,929

OPERATING REVENUES - Revenue _2

OPERATING REVENUES - Revenue Recognition - Practical Expedients (Details)	12 Months Ended
	Dec. 31, 2018
OPERATING REVENUES
Practical Expedients	true

ACQUISITIONS AND DIVESTITURES -

ACQUISITIONS AND DIVESTITURES - West Quito Draw Properties (Details) $ in Millions	Feb. 06, 2018USD ($)
West Quito Draw Properties
ACQUISITIONS AND DIVESTITURES
Purchase price	$ 198.5

ACQUISITIONS AND DIVESTITURES-M

ACQUISITIONS AND DIVESTITURES-Monument Draw Assets (Details) $ in Millions	Jan. 09, 2018USD ($)	Dec. 13, 2017USD ($)	Jun. 15, 2017USD ($)	Dec. 09, 2016item$ / a	Jun. 14, 2017$ / a
ACQUISITIONS AND DIVESTITURES
Number of tracts | item				2
Ward County Texas Assets
ACQUISITIONS AND DIVESTITURES
Purchase price		$ 101.8
Southern Tract | Ward County Texas Assets
ACQUISITIONS AND DIVESTITURES
Price per Acre | $ / a				11,000	13,000
Purchase price			$ 87.4
Northern Tract | Ward County Texas Assets
ACQUISITIONS AND DIVESTITURES
Price per Acre | $ / a				11,000	13,000
Purchase price	$ 108.2

ACQUISITIONS AND DIVESTITURES-P

ACQUISITIONS AND DIVESTITURES-Pecos County Consideration (Details) $ in Thousands	Dec. 13, 2017USD ($)	Feb. 28, 2017USD ($)$ / Mcf$ / Boe$ / bbl	Jan. 24, 2017	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Nov. 01, 2017USD ($)	Sep. 09, 2016USD ($)
Estimated Fair Value of Assets Acquired:
Evaluated oil and natural gas properties				$ 1,470,509	$ 877,316		$ 1,214,129
Other operating property and equipment				$ 130,251	$ 101,282		$ 38,071
8% Convertible Preferred Stock
Additional disclosures
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		$ 703,865
Less: Post-effective closing date adjustments		(4,677)
Final estimated 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		188,275
Unevaluated oil and natural gas properties		487,489
Other operating property and equipment		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 | Natural gas liquids
Additional disclosures
Weighted average commodity prices | $ / Boe		29.48
Pecos County Assets | 8% Convertible Preferred Stock
Additional disclosures
Net proceeds received		$ 400,100
Dividend rate (as a percent)		8.00%
Ward County Texas Assets
Consideration paid for acquisition and the estimated values of assets acquired and liabilities assumed
Final estimated consideration transferred	$ 101,800

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES-Pecos County Proforma (Details) - USD ($) $ / shares in Units, $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017
Pro forma financial information
Net income (loss) available to common stockholders	$ (479,984)		$ 45,959	$ 487,679
Predecessor
Pro forma financial information
Net income (loss) available to common stockholders		$ (32,794)
Pecos County Assets
Pro forma financial information
Revenue	166,499			385,867
Net income (loss)	(475,580)			542,724
Net income (loss) available to common stockholders	$ (476,371)			$ 494,717
Pro forma net income (loss) per share of common stock:
Basic (in dollars per share)	$ (5.22)			$ 3.73
Diluted (in dollars per share)	$ (5.22)			$ 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
Net field operating income related to properties acquired				5,900
Pecos County Assets | General and administrative
Additional disclosures
Non-recurring transaction costs				$ 1,000
Pecos County Assets | Predecessor
Pro forma financial information
Revenue		288,902
Net income (loss)		16,513
Net income (loss) available to common stockholders		$ (28,239)
Pro forma net income (loss) per share of common stock:
Basic (in dollars per share)		$ (0.23)
Diluted (in dollars per share)		$ (0.23)

ACQUISITIONS AND DIVESTITURES_3

ACQUISITIONS AND DIVESTITURES - Water Infrastructure Assets (Details) - USD ($) $ in Thousands	Dec. 20, 2018	Oct. 01, 2018	Dec. 31, 2018
ACQUISITIONS AND DIVESTITURES
Gain (loss) from sale of other operating property and equipment			$ 119,003
Water Infrastructure Assets | Purchase and Sale Agreement
ACQUISITIONS AND DIVESTITURES
Sale price of asset in cash	$ 214,100
Incentives payable per year if certain thresholds are met		$ 25,000
Deferred period of sale price based on certain thresholds		5 years
(Gain) loss on sale of Water Assets | Water Infrastructure Assets | Purchase and Sale Agreement
ACQUISITIONS AND DIVESTITURES
Gain (loss) from sale of other operating property and equipment			$ 119,000

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, 2016USD ($)

Sep. 09, 2016USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Oct. 07, 2017

Sep. 07, 2017USD ($)

Feb. 16, 2017USD ($)

Sep. 30, 2016

Jun. 09, 2016

Dec. 21, 2015USD ($)

Divestitures

Proceeds received from sales of oil and natural gas assets

$ 888

$ 3,816

$ 2,003,894

Gain (loss) on extinguishment of debt

(114,931)

Proceeds received from sale of other operating property and equipment

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

$ 425,005

$ 850,000

$ 850,000

Interest rate (as a percent)

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 | Other operating property and equipment

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

El Halcon Assets | Other operating property and equipment

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

Companys Existing Wholly Owned Subsidiaries Other Than HK TMS | HK TMS

Divestitures

Ownership percentage in subsidiaries

100.00%

Non-operating owner | Williston Basin Assets

Divestitures

Proceeds from sales of interests

$ 103,400

Gain (loss) on sale

$ 0

Predecessor

Divestitures

Interest rate (as a percent)

13.00%

Proceeds received from sales of oil and natural gas assets

$ (407)

Gain (loss) on extinguishment of debt

81,434

Proceeds received from sale of other operating property and equipment

$ 138

Predecessor | 12.0% senior secured second lien notes due 2022

Divestitures

Aggregate principal amount drawn

$ 112,800

Interest rate (as a percent)

12.00%

OIL AND NATURAL GAS PROPERTIE_2

OIL AND NATURAL GAS PROPERTIES (Details) $ in Thousands	1 Months Ended		4 Months Ended	6 Months Ended	8 Months Ended	12 Months Ended
	Sep. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)	Jun. 30, 2016USD ($)	Sep. 09, 2016USD ($)	Dec. 31, 2018USD ($)$ / MMBTU$ / bbl	Dec. 31, 2017USD ($)$ / MMBTU$ / bbl	Dec. 31, 2016$ / MMBTU$ / bbl
Oil and Natural Gas Properties
Subject to depletion					$ 1,214,129	$ 1,470,509	$ 877,316
Not subject to depletion:
Exploration and extension wells in progress						23,536	5,298
Other capital costs:
Incurred in 2018						310,113
Incurred in 2017						638,269	760,488
Gross oil and natural gas properties					1,546,244	2,442,427	1,643,102
Less - accumulated depletion						(639,951)	(570,155)
Net oil and natural gas properties					1,546,244	$ 1,802,476	$ 1,072,947
Ceiling Limitation Disclosures
Full cost ceiling impairment	$ 420,900		$ 420,934
Full cost ceiling impairment, after tax	$ 268,100
Predecessor
Oil and Natural Gas Properties
Subject to depletion					7,712,003
Other capital costs:
Gross oil and natural gas properties					8,905,262
Less - accumulated depletion					(6,803,231)
Net oil and natural gas properties					2,102,031
Ceiling Limitation Disclosures
First day average of the (WTI) crude oil spot price (in dollars per barrel) | $ / bbl						65.56	51.34	42.75
First day average of the Henry Hub natural gas price (in dollars per Mmbtu) | $ / MMBTU						3.100	2.976	2.481
Full cost ceiling impairment				$ 754,800	754,769
Full cost ceiling impairment, after tax				$ 478,200
Predecessor | Unevaluated Oil and Gas Leaseholds
Other capital costs:
Interest costs capitalized					$ 68,200
Predecessor | Tuscaloosa Marine Shale
Other capital costs:
Amount of unevaluated property costs transferred to the full cost pool		$ 74,800
Utica areas | Predecessor | Unevaluated Oil and Gas Leaseholds
Other capital costs:
Amount of unevaluated property costs transferred to the full cost pool		$ 330,400

LONG-TERM DEBT (Details)

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

Feb. 15, 2018

Dec. 31, 2018

Dec. 31, 2017

Oct. 10, 2017

Oct. 07, 2017

Sep. 07, 2017

Jul. 10, 2017

Feb. 16, 2017

Sep. 09, 2016

Jun. 09, 2016

Dec. 21, 2015

May 01, 2015

Current and long-term debt

Principal amount outstanding, net

$ 613,105

$ 409,168

$ 1,016,160

Predecessor

Current and long-term debt

Principal amount outstanding, net

$ 1,031,114

Interest rate (as a percent)

13.00%

8.625% senior secured second lien notes due 2020

Current and long-term debt

Interest rate (as a percent)

8.625%

8.625% senior secured second lien notes due 2020 | Predecessor

Current and long-term debt

Interest rate (as a percent)

8.625%

Principal amount

$ 700,000

12.0% senior secured second lien notes due 2022

Current and long-term debt

Interest rate (as a percent)

12.00%

12.0% senior secured second lien notes due 2022 | Predecessor

Current and long-term debt

Interest rate (as a percent)

12.00%

Principal amount

$ 112,800

6.75% senior notes due 2025

Current and long-term debt

Principal amount outstanding, net

$ 613,105

$ 409,168

Interest rate (as a percent)

6.75%

6.75%

6.75%

6.75%

Unamortized discount

$ 7,200

$ 8,100

Principal amount

625,005

425,005

$ 850,000

$ 850,000

$ 850,000

Principal amount repurchased

$ 425,000

Additional 2025 Notes

Current and long-term debt

Principal amount

$ 200,000

Unamortized debt issuance costs

10,100

7,700

Issue price as a percentage of par value

103.00%

Unamortized premium related to debt issued

5,400

Senior revolving credit facility

Current and long-term debt

Unamortized debt issuance costs

$ 11,100

$ 8,300

LONG-TERM DEBT - Senior Facilit

LONG-TERM DEBT - Senior Facility (Details) $ in Millions	Sep. 07, 2017USD ($)item	Feb. 15, 2019	Dec. 31, 2018USD ($)	Nov. 16, 2018USD ($)	Nov. 07, 2018	Jul. 12, 2018	May 01, 2018USD ($)	Feb. 02, 2018
Senior revolving credit facility
Current and long-term debt
Maximum borrowing capacity	$ 1,000
Current borrowing capacity	$ 275		$ 275
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
Amount outstanding			0
Letters of credit outstanding			1
Borrowing capacity available			$ 274
Senior revolving credit facility | Minimum
Current and long-term debt
Current Ratio	1
Senior revolving credit facility | ABR - based | Minimum
Current and long-term debt
Applicable margin (as a percent)	1.25%
Senior revolving credit facility | ABR - based | Maximum
Current and long-term debt
Applicable margin (as a percent)	2.25%
Senior revolving credit facility | LIBOR | Minimum
Current and long-term debt
Applicable margin (as a percent)	2.25%
Senior revolving credit facility | LIBOR | Maximum
Current and long-term debt
Applicable margin (as a percent)	3.25%
Seventh Amendment to Senior Credit Agreement | Fiscal quarter ending March 31, 2019
Current and long-term debt
Total Net Debt to EBITDA ratio		5
Seventh Amendment to Senior Credit Agreement | Fiscal quarter ending June 30, 2019
Current and long-term debt
Total Net Debt to EBITDA ratio		4.75
Seventh Amendment to Senior Credit Agreement | Fiscal quarter ending September 30, 2019
Current and long-term debt
Total Net Debt to EBITDA ratio		4.5
Seventh Amendment to Senior Credit Agreement | Fiscal quarter ending December 31, 2019
Current and long-term debt
Total Net Debt to EBITDA ratio		4.25
Seventh Amendment to Senior Credit Agreement | Fiscal quarter ending March 31, 2020 and any fiscal quarter thereafter
Current and long-term debt
Total Net Debt to EBITDA ratio		4
Sixth Amendment To Senior Credit Agreement
Current and long-term debt
Maximum borrowing capacity				$ 350
Current borrowing capacity				$ 275
Fifth Amendment to Senior Credit Agreement | Fiscal quarter ending September 30, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio					4.75
Fifth Amendment to Senior Credit Agreement | Fiscal quarter ending December 31, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio					4.25
Fifth Amendment to Senior Credit Agreement | Fiscal quarter ending March 31, 2019 and any fiscal quarter thereafter
Current and long-term debt
Total Net Debt to EBITDA ratio					4
Fourth Amendment to the Senior Credit Agreement | Fiscal quarter ending September 30, 2019
Current and long-term debt
Total Net Debt to EBITDA ratio						4.25
Fourth Amendment to the Senior Credit Agreement | Fiscal quarter ending September 30, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio						4.75
Fourth Amendment to the Senior Credit Agreement | Fiscal quarters ending December 31, 2018, March 31, 2019 and June 30, 2019
Current and long-term debt
Total Net Debt to EBITDA ratio						5
Fourth Amendment to the Senior Credit Agreement | Fiscal quarter ending December 31, 2019 and any fiscal quarter thereafter
Current and long-term debt
Total Net Debt to EBITDA ratio						4
Fourth Amendment to the Senior Credit Agreement | Each fiscal quarter ending after the fiscal quarter in which such sale is consummated
Current and long-term debt
Total Net Debt to EBITDA ratio						4
Third Amendment to the Senior Credit Agreement
Current and long-term debt
Maximum borrowing capacity							$ 1,000
Second Amendment to Senior Credit Agreement | Fiscal quarter ending June 30, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio								4.50
Second Amendment to Senior Credit Agreement | Fiscal quarter after June 30, 2018
Current and long-term debt
Total Net Debt to EBITDA ratio								4

LONG-TERM DEBT - 6.75% Senior N

LONG-TERM DEBT - 6.75% Senior Notes (Details) - USD ($) $ in Thousands

Feb. 15, 2018

Oct. 10, 2017

Sep. 07, 2017

Jul. 25, 2017

Feb. 16, 2017

Mar. 31, 2017

Sep. 09, 2016

Dec. 31, 2018

Dec. 31, 2017

Oct. 07, 2017

Jul. 10, 2017

Jun. 09, 2016

Dec. 21, 2015

May 01, 2015

Current and long-term debt

Accrued interest expense

$ 16,971

$ 10,985

Accrued and unpaid interest

$ 4,100

Gains (Losses) on Extinguishment of Debt

(114,931)

Predecessor

Current and long-term debt

Interest rate (as a percent)

13.00%

Gains (Losses) on Extinguishment of Debt

$ 81,434

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

12.0% senior secured second lien notes due 2022 | Predecessor

Current and long-term debt

Principal amount

$ 112,800

Interest rate (as a percent)

12.00%

6.75% senior notes due 2025

Current and long-term debt

Principal amount

$ 850,000

$ 850,000

$ 625,005

$ 425,005

$ 850,000

Interest rate (as a percent)

6.75%

6.75%

6.75%

6.75%

Net proceeds from issuance

$ 834,100

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

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

Unamortized discount

$ 7,200

$ 8,100

9.75% senior notes due 2020 | Predecessor

Current and long-term debt

Interest rate (as a percent)

9.75%

8.875% senior notes due 2021 | Predecessor

Current and long-term debt

Interest rate (as a percent)

8.875%

9.25% senior notes due 2022 | Predecessor

Current and long-term debt

Interest rate (as a percent)

9.25%

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%

Period within which to complete exchange offer after closing

180 days

Unamortized premium related to debt issued

$ 5,400

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

8.625% senior secured second lien notes due 2020 | Predecessor

Current and long-term debt

Principal amount

$ 700,000

Interest rate (as a percent)

8.625%

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

LONG-TERM DEBT - Debt Maturitie

LONG-TERM DEBT - Debt Maturities and Debt Issuance Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Sep. 07, 2017	Jul. 10, 2017	Feb. 16, 2017
Debt maturities
Thereafter		$ 625,005
Total		625,005
Debt Issuance Costs
Costs associated with the issuance of debt capitalized	$ 4,334	17,799
6.75% senior notes due 2025
Debt maturities
Aggregate principal amount drawn	625,005	425,005	$ 850,000	$ 850,000	$ 850,000
Senior revolving credit facility and additional 2025 notes
Debt Issuance Costs
Costs associated with the issuance of debt capitalized	4,200
Senior revolving credit facility
Debt Issuance Costs
Unamortized debt issuance costs	$ 11,100	$ 8,300

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Assets
Asset transfers between levels	$ 0
Liabilities
Liability transfers between levels		$ 0
Recurring | Total
Assets
Receivables from derivative contracts	69,717	677
Liabilities
Liabilities from derivative contracts	12,907	26,999
Recurring | Level 2
Assets
Receivables from derivative contracts	69,717	677
Liabilities
Liabilities from derivative contracts	$ 12,907	$ 26,999

FAIR VALUE MEASUREMENTS - Estim

FAIR VALUE MEASUREMENTS - Estimated FV (Details) - USD ($) $ in Thousands	8 Months Ended
	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Oct. 07, 2017	Sep. 07, 2017	Jul. 10, 2017	Feb. 16, 2017	Jun. 09, 2016	Dec. 21, 2015	May 01, 2015
8.625% senior secured second lien notes due 2020
Fair value measurements
Interest rate (as a percent)							8.625%
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%
Principal amount		$ 625,005	$ 425,005		$ 850,000	$ 850,000	$ 850,000
Total | 6.75% senior notes due 2025
Fair value measurements
Estimated fair value of debt		$ 458,210	$ 443,790
Predecessor
Fair value measurements
Interest rate (as a percent)								13.00%
Non-cash impairment charge	$ 28,056
Predecessor | 8.625% senior secured second lien notes due 2020
Fair value measurements
Interest rate (as a percent)										8.625%
Principal amount										$ 700,000
Predecessor | 12.0% senior secured second lien notes due 2022
Fair value measurements
Interest rate (as a percent)									12.00%
Principal amount									$ 112,800

DERIVATIVE AND HEDGING ACTIVI_3

DERIVATIVE AND HEDGING ACTIVITIES - (Details) $ in Thousands	Dec. 31, 2018USD ($)item	Dec. 31, 2017USD ($)item
Derivative and hedging activities
Asset derivative contracts | $	$ 69,717	$ 677
Liability derivative contracts | $	(12,907)	(26,999)
Derivatives not designated as hedging contracts
Derivative and hedging activities
Asset derivative contracts | $	69,717	677
Liability derivative contracts | $	$ (12,907)	$ (26,999)
Derivatives not designated as hedging contracts | Commodity contracts
Derivative and hedging activities
Number of open commodity derivative contracts	86	34
Derivatives not designated as hedging contracts | Commodity contracts | Current assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts | $	$ 57,280	$ 677
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent assets - receivables from derivative contracts
Derivative and hedging activities
Asset derivative contracts | $	12,437
Derivatives not designated as hedging contracts | Commodity contracts | Current liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts | $	(3,768)	(19,248)
Derivatives not designated as hedging contracts | Commodity contracts | Other noncurrent liabilities - liabilities from derivative contracts
Derivative and hedging activities
Liability derivative contracts | $	$ (9,139)	$ (7,751)
Derivatives not designated as hedging contracts | Commodity contracts | Collars | Natural gas
Derivative and hedging activities
Number of open commodity derivative contracts	9	3
Derivatives not designated as hedging contracts | Commodity contracts | Collars | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	31	19
Derivatives not designated as hedging contracts | Commodity contracts | Basis Swap | Natural gas
Derivative and hedging activities
Number of open commodity derivative contracts	7
Derivatives not designated as hedging contracts | Commodity contracts | Basis Swap | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	26	12
Derivatives not designated as hedging contracts | Commodity contracts | Swaps | Natural gas liquids
Derivative and hedging activities
Number of open commodity derivative contracts	6
Derivatives not designated as hedging contracts | Commodity contracts | Put options | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	2
Derivatives not designated as hedging contracts | Commodity contracts | Call option | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	4
Derivatives not designated as hedging contracts | Commodity contracts | WTI NYMEX Roll | Crude oil
Derivative and hedging activities
Number of open commodity derivative contracts	1

DERIVATIVE AND HEDGING ACTIVI_4

DERIVATIVE AND HEDGING ACTIVITIES - Realized Unrealized (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017
Derivative and hedging activities
Total net gain (loss) on derivative contracts	$ (27,740)		$ 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	(112,449)		84,274	(16,468)
Realized gain (loss) on commodity contracts	84,709		8,351	17,759
Total net gain (loss) on derivative contracts	$ (27,740)		$ 92,625	$ 1,291
Predecessor
Derivative and hedging activities
Total net gain (loss) on derivative contracts		$ (17,998)
Predecessor | Derivatives not designated as hedging contracts | Commodity contracts | Other Income Expense
Derivative and hedging activities
Unrealized gain (loss) on commodity contracts		(263,732)
Realized gain (loss) on commodity contracts		245,734
Total net gain (loss) on derivative contracts		$ (17,998)

DERIVATIVE AND HEDGING ACTIVI_5

DERIVATIVE AND HEDGING ACTIVITIES - Open Contracts (Details) - Commodity contracts	Dec. 31, 2018MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2017MMBTU$ / MMBTU$ / bblbbl
January 2018 - December 2018 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		2,555,000
January 2018 - December 2018 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential		(1.05)
January 2018 - December 2018 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential		(1.50)
January 2018 - December 2018 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		(1.29)
January 2018 - December 2018 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		2,920,000
January 2018 - December 2018 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		45
Ceilings (in dollars per Mmbtu's/Bbl's)		50
January 2018 - December 2018 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		53
Ceilings (in dollars per Mmbtu's/Bbl's)		60
January 2018 - December 2018 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		49.29
Ceilings (in dollars per Mmbtu's/Bbl's)		56.82
January 2018 - December 2018 | Collars | Natural gas
Derivative and hedging activities
Volume in Mmbtu's | MMBTU		2,737,500
January 2018 - December 2018 | Collars | Natural gas | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.22
January 2018 - December 2018 | Collars | Natural gas | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.03
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.38
January 2018 - December 2018 | Collars | Natural gas | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.01
Ceilings (in dollars per Mmbtu's/Bbl's) | $ / MMBTU		3.30
April 2018 - December 2018 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		275,000
Basis Differential		(1.15)
April 2018 - December 2018 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		(1.15)
April 2018 - December 2018 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		275,000
April 2018 - December 2018 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		46.75
Ceilings (in dollars per Mmbtu's/Bbl's)		51.75
April 2018 - December 2018 | 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
July 2018 - December 2018 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		1,012,000
July 2018 - December 2018 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential		(0.98)
July 2018 - December 2018 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential		(1.18)
July 2018 - December 2018 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential		(1.12)
July 2018 - December 2018 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		184,000
July 2018 - December 2018 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		48.50
Ceilings (in dollars per Mmbtu's/Bbl's)		53.50
July 2018 - December 2018 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		48.50
Ceilings (in dollars per Mmbtu's/Bbl's)		53.50
October 2018 - December 2018 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl		92,000
October 2018 - December 2018 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		50.65
Ceilings (in dollars per Mmbtu's/Bbl's)		55.65
October 2018 - December 2018 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)		50.65
Ceilings (in dollars per Mmbtu's/Bbl's)		55.65
January 2019 - March 2019 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	90,000	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 | Minimum
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 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	46.75	46.75
Ceilings (in dollars per Mmbtu's/Bbl's)	51.75	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 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	2,448,000	4,380,000
January 2019 - December 2019 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Basis Differential	(0.98)	(0.50)
January 2019 - December 2019 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Basis Differential	(6.50)	(1.33)
January 2019 - December 2019 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Basis Differential	(2.80)	(1.02)
January 2019 - December 2019 | Basis Swap | Natural gas
Derivative and hedging activities
Volume in Bbl's | bbl	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 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	3,650,000	1,825,000
January 2019 - December 2019 | Collars | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	50	50
Ceilings (in dollars per Mmbtu's/Bbl's)	55.20	55
January 2019 - December 2019 | Collars | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	58	51
Ceilings (in dollars per Mmbtu's/Bbl's)	63	57.30
January 2019 - December 2019 | Collars | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	53.87	50.24
Ceilings (in dollars per Mmbtu's/Bbl's)	60.07	55.70
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)	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 | Swaps | Natural gas liquids
Derivative and hedging activities
Volume in Mmbtu's | MMBTU	1,460,000
January 2019 - December 2019 | Swaps | Natural gas liquids | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	29.08
January 2019 - December 2019 | Swaps | Natural gas liquids | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	30.15
January 2019 - December 2019 | Swaps | Natural gas liquids | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	29.33
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
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
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)
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
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 | 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 | Swaps | Natural gas liquids
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 | Swaps | Natural gas liquids | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's) | $ / MMBTU	32.50
January 2020 - December 2020 | Basis Swap | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	3,294,000
January 2020 - December 2020 | Basis Swap | Crude oil | Minimum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	2
January 2020 - December 2020 | Basis Swap | Crude oil | Maximum
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	4
January 2020 - December 2020 | Basis Swap | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	2.95
January 2020 - December 2020 | Collars | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	549,000
Floors (in dollars per Mmbtu's/Bbl's)	50
Ceilings (in dollars per Mmbtu's/Bbl's)	70
January 2020 - December 2020 | 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)	70
January 2020 - December 2020 | Call option | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	2,342,400
Ceilings (in dollars per Mmbtu's/Bbl's)	70
January 2020 - December 2020 | Call option | Crude oil | Weighted Average
Derivative and hedging activities
Ceilings (in dollars per Mmbtu's/Bbl's)	70
January 2020 - December 2020 | Put options | Crude oil
Derivative and hedging activities
Volume in Bbl's | bbl	915,000
Floors (in dollars per Mmbtu's/Bbl's)	55
January 2020 - December 2020 | Put options | Crude oil | Weighted Average
Derivative and hedging activities
Floors (in dollars per Mmbtu's/Bbl's)	55

DERIVATIVE AND HEDGING ACTIVI_6

DERIVATIVE AND HEDGING ACTIVITIES - Netting Arrangements (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative Assets
Gross Amounts Presented in the Consolidated Balance Sheet	$ 69,717	$ 677
Amounts Not Offset in the Consolidated Balance Sheet	(10,263)	(231)
Net Amount	59,454	446
Derivative Liabilities
Gross Amounts Presented in the Consolidated Balance Sheet	(12,907)	(26,999)
Amounts Not Offset in the Consolidated Balance Sheet	10,263	231
Net Amount	$ (2,644)	$ (26,768)

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Activity related to ARO liability
Liability for asset retirement obligations at the beginning of the period	$ 4,368	$ 32,375
Liabilities settled and divested	(590)	(33,796)
Additions	988	592
Acquisitions	2,465	3,109
Accretion expense	329	1,306
Revisions in estimated cash flows	(646)	782
Liability for asset retirement obligations at the end of the period	$ 6,914	$ 4,368

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details) $ in Thousands	1 Months Ended	4 Months Ended	8 Months Ended	12 Months Ended
	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Sep. 09, 2016USD ($)	Dec. 31, 2018USD ($)item	Dec. 31, 2017USD ($)
Commitments and contingencies
Rent expense		$ 1,400	$ 5,900	$ 3,700	$ 3,900
Approximate future minimum lease payments for all non-cancelable operating leases
2018				3,792
2019				2,350
2020				1,899
2021				968
2022				999
Thereafter				599
Total				10,607
Obligations under rig termination and stacking fees commitments
2019				781
2020				3,000
Total				3,781
Purchase commitments related to equipment
2019				20,233
Total				20,233
Drilling rig commitments
Obligation under contractual commitments
2018				4,973
Total				4,973
Non-cancelable termination penalties				4,700
Drilling rig commitments				$ 5,000
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
Number of long-term natural gas sales contracts to which the entity is committed | item				10
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
Reorganization Adjustments
Commitments and contingencies
Payments for amended certain office lease arrangements	$ 3,400

STOCKHOLDERS' EQUITY - Preferre

STOCKHOLDERS' EQUITY - Preferred Stock and Non-Cash Preferred Stock Dividend (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 09, 2018	Apr. 06, 2017	Feb. 27, 2017	Jan. 24, 2017	Sep. 09, 2016	Jun. 30, 2017	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Mar. 16, 2017
Stockholders' equity
Shares issued	9,200,000	55,200,000			90,000,000
Share price (in dollars per share)	$ 6.90
Offering costs including placement agent fees								$ 3,044	$ 11,919
Par value of common stock (in dollars per share)	$ 0.0001				$ 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			$ 400,100
Share price (in dollars per share)			$ 7.25	$ 8.12
Offering costs including placement agent fees			$ 11,900
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				$ 48,000
Discount amortization period				65 months
Predecessor
Stockholders' equity
Offering costs including placement agent fees							$ 10

STOCKHOLDERS' EQUITY-Common sto

STOCKHOLDERS' EQUITY-Common stock and warrants (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 09, 2018	Apr. 06, 2017	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017
Stockholders' equity
Shares issued	9,200,000	55,200,000	90,000,000
Authorized shares of common stock, after amendment of certificate of incorporation			1,000,000,000	1,000,000,000	1,000,000,000
Common stock, par value (in dollars per share)	$ 0.0001		$ 0.0001	$ 0.0001	$ 0.0001
Share price (in dollars per share)	$ 6.90
Number of warrants issued			4,700,000
Equivalent number shares of the warrants			4,700,000
Exercise price (in dollars per share)			$ 14.04
Additional paid-in capital			$ 571,114	$ 1,095,367	$ 1,016,281
Authorized shares of capital stock, after amendment of certificate of incorporation			1,001,000,000
Net proceeds issuance of common stock	$ 60,400			$ 63,480
Warrants Issued to Former Holders of Unsecured and Convertible Notes
Stockholders' equity
Exercise price (in dollars per share)			$ 14.04
Preferred stock
Stockholders' equity
Preferred stock, par value (in dollars per share)			$ 0.0001
Authorized shares of preferred stock, after amendment of certificate of incorporation			1,000,000
Predecessor
Stockholders' equity
Additional paid-in capital			$ 3,287,906

STOCKHOLDERS' EQUITY - Incentiv

STOCKHOLDERS' EQUITY - Incentive Plans (Details) - USD ($) $ / shares in Units, $ in Thousands	Apr. 06, 2017	Dec. 31, 2015	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
General and administrative
Stock-based compensation
Compensation expense recorded			$ 21,500		$ 15,300	$ 36,800
Stock options
Stock-based compensation
Grant date weighted average price (in dollars per share)			$ 9.22		$ 8.34	$ 8.84	$ 9.22
Weighted average grant date fair value of grants			$ 6.07		$ 2.92	$ 4.36
Number of Shares
Outstanding at the beginning of the period (in shares)					6,735,903	5,319,400
Granted (in shares)			5,319,400		1,206,800	1,790,605
Exercised (in shares)					(41,667)	0	0
Forfeited (in shares)					(432,110)	(374,102)
Outstanding at the end of the period (in shares)			5,319,400		7,468,926	6,735,903	5,319,400
Weighted Average Exercise Price Per Share
Granted (in dollars per share)			$ 9.22		$ 5.65	$ 7.72
Exercised (in dollars per share)					7.75
Forfeited (in dollars per share)					$ 8.68	$ 8.82
Aggregate Intrinsic Value
Outstanding at the beginning of the period					$ 29	$ 631
Outstanding at the end of the period			$ 631			$ 29	$ 631
Weighted Average Remaining Contractual Term
Outstanding at the end of the period			9 years 8 months 12 days		8 years 1 month 6 days	8 years 10 months 24 days
Assumptions:
Weighted average grant date fair value of grants			$ 6.07		$ 2.92	$ 4.36
Stock price volatility (as a percent)			56.29%		52.08%	60.18%
Risk free rate of return (as a percent)			1.34%		2.63%	1.94%
Expected term			5 years		6 years	6 years
Aggregate Intrinsic Value
Exercised					$ 29
Predecessor | General and administrative
Stock-based compensation
Compensation expense recorded				$ 4,900
Predecessor | Stock options
Stock-based compensation
Grant date weighted average price (in dollars per share)		$ 17.80
Number of Shares
Outstanding at the beginning of the period (in shares)				4,860,133			4,860,133
Granted (in shares)				0
Exercised (in shares)
Forfeited (in shares)				(695,302)
Cancelled (in shares)				4,164,831
Outstanding at the end of the period (in shares)		4,860,133
Weighted Average Exercise Price Per Share
Granted (in dollars per share)
Exercised (in dollars per share)
Forfeited (in dollars per share)				21.17
Cancelled (in dollars per share)				$ 17.23
Weighted Average Remaining Contractual Term
Outstanding at the end of the period		8 years 4 months 24 days
Predecessor | Restricted Stock
Number of Shares
Granted other than options (in shares)				0
2006 Long-Term Incentive Plan | Predecessor | Restricted Stock
Number of Shares
Unvested outstanding shares at the beginning of the period (in shares)				2,870,405			2,870,405
Vested (in shares)				(436,256)
Accelerated vesting (in shares)				(1,917,072)
Forfeited (in shares)				(517,077)
Unvested outstanding shares at the end of the period (in shares)		2,870,405
Weighted Average Grant Date fair Value Per Share
Unvested outstanding shares at the beginning of the period (in dollars per share)				$ 7.55			$ 7.55
Vested (in dollars per share)				18.50
Accelerated vesting (in dollars per share)				5.39
Forfeited (in dollars per share)				$ 6.31
Unvested outstanding shares at the end of the period (in dollars per share)		$ 7.55
Aggregate Intrinsic Value
Aggregate Intrinsic Value at the beginning of the period (in dollars)				$ 3,617			$ 3,617
Aggregate Intrinsic Value at the end of period (in dollars)		$ 3,617
2016 Incentive Plan | Common Stock
Stock-based compensation
Aggregate number of shares available	19,000,000			10,000,000
Maximum number of shares that remained reserved for issuance under the Plan					4,900,000	7,700,000
Increase in shares available for issuance	9,000,000
Number of calculation days for which shares will be available for issuance.	20 days
2016 Incentive Plan | Stock options
Stock-based compensation
Weighted average remaining vesting period			1 year 8 months 12 days		10 months 24 days	1 year 2 months 12 days
Weighted average grant date fair value of the shares granted			$ 32,300		$ 3,500	$ 7,800
Proceeds from stock options					300
Restricted stock
Unrecognized compensation expense stock option			$ 26,500		$ 5,200	$ 13,000	26,500
2016 Incentive Plan | Stock options | Employee
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
2016 Incentive Plan | Restricted Stock
Stock-based compensation
Weighted average remaining vesting period			10 months 24 days		1 year 1 month 6 days	1 year 4 months 24 days
Unrecognized compensation expense other than options			$ 11,500		$ 6,100	$ 3,200	$ 11,500
Restricted stock
Weighted average grant date fair value of the shares granted			$ 27,300		$ 12,700	$ 14,300
Number of Shares
Unvested outstanding shares at the beginning of the period (in shares)					745,507	1,738,077
Granted (in shares)			2,991,202		2,326,961	2,022,432
Vested (in shares)			(1,253,125)		(537,411)	(2,516,647)
Forfeited (in shares)					(262,164)	(498,355)
Unvested outstanding shares at the end of the period (in shares)			1,738,077		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)					$ 7.05	$ 9.06
Granted (in dollars per share)			$ 9.14		5.47	7.07
Vested (in dollars per share)			9.24		5.89	8.39
Forfeited (in dollars per share)					6.29	7.41
Unvested outstanding shares at the end of the period (in dollars per share)			$ 9.06		$ 5.80	$ 7.05	$ 9.06
Aggregate Intrinsic Value
Aggregate Intrinsic Value at the beginning of the period (in dollars)					$ 5,643	$ 16,234
Aggregate Intrinsic Value at the end of period (in dollars)			$ 16,234		3,864	5,643	$ 16,234
Additional Disclosures
Total fair value of shares vested			$ 11,600		$ 2,000	$ 16,100
2016 Incentive Plan | Restricted Stock | Employee
Stock-based compensation
Percentage of awards other than options vesting on the annual anniversary date of the grant						33.33%
Vesting period						3 years
2016 Incentive Plan | Restricted Stock | Non-employee director
Stock-based compensation
Vesting period						6 months
2016 Incentive Plan | Predecessor | Restricted Stock
Additional Disclosures
Total fair value of shares vested				$ 900

STOCKHOLDERS' EQUITY - Exercisa

STOCKHOLDERS' EQUITY - Exercisable (Details)	12 Months Ended
	Dec. 31, 2018$ / sharesshares
$6.55 - $7.75
Share-based compensation
Range of grant prices per share, low end of the range (in dollars per share)	$ 5.65
Range of grant prices per share, high end of the range (in dollars per share)	$ 7.75
Outstanding
Number | shares	2,783,493
Weighted Average Exercise Price Per Share (in dollars per share)	$ 6.85
Weighted Average Remaining Contractual Life	8 years 8 months 12 days
$8.93 - $9.24
Share-based compensation
Range of grant prices per share, low end of the range (in dollars per share)	$ 8.93
Range of grant prices per share, high end of the range (in dollars per share)	$ 9.24
Outstanding
Number | shares	4,685,433
Weighted Average Exercise Price Per Share (in dollars per share)	$ 9.23
Weighted Average Remaining Contractual Life	7 years 8 months 12 days

STOCKHOLDERS' EQUITY - Assumpti

STOCKHOLDERS' EQUITY - Assumptions (Details) - Stock options - $ / shares	4 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Stock-based compensation
Weighted average grant date fair value of grants	$ 6.07	$ 2.92	$ 4.36
Assumptions:
Stock price volatility (as a percent)	56.29%	52.08%	60.18%
Expected term	5 years	6 years	6 years
Risk free rate of return (as a percent)	1.34%	2.63%	1.94%

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	Dec. 22, 2017	Dec. 31, 2018	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current:
Federal					$ (5,000)			$ 5,000
State					256
Total current income tax benefit (provision)					(4,744)			5,000
Deferred:
Federal					52,223		$ (95,791)
State					(52,223)
Total deferred income tax benefit (provision)							(95,791)
Total income tax benefit (provision)		$ (95,800)			(4,744)		$ (95,791)	$ 5,000	$ 0
Differences between the actual income tax benefit (provision) and the expected income tax benefit (provision)
Federal statutory rate (as a percent)			35.00%	35.00%			21.00%	35.00%
Expected tax benefit (provision)					166,057		$ (29,767)	$ (185,740)
State income tax expense, net of federal benefit					6,243			(2,587)
Stock-based compensation							(350)
Net operating loss limitation under IRC Section 382					(161,704)
TMS Divestiture					(157,767)
Change in state rate								(10,121)
Increase (reduction) in deferred tax asset							(201,903)	95,907
Change in valuation allowance and related items					202,592		136,432	392,846
IRC section 108 attribute reduction					(56,483)
Tax Cuts and Jobs Act of 2017								(280,874)
Permanent adjustments							(203)
Other					(3,682)			(4,431)
Total income tax benefit (provision)		(95,800)			$ (4,744)		(95,791)	5,000	$ 0
Deferred noncurrent income tax assets:
Net operating loss carry-forwards		204,751					204,751	205,570
Built in loss adjustment Section 382		88,835					88,835	90,897
Stock-based compensation expense		8,509					8,509	5,501
Asset retirement obligations		1,011					1,011	963
Book-tax differences in property basis								125,309
Unrealized hedging transactions								5,901
Disallowed interest Section 163(j)		3,370					3,370
Other		1,917					1,917
Gross deferred noncurrent income tax assets		308,393					308,393	434,141
Valuation allowance		(290,333)					(290,333)	(426,765)
Deferred noncurrent income tax assets		18,060					18,060	7,376
Deferred noncurrent income tax liabilities:
Basis difference in debt		(5,507)					(5,507)	(6,366)
Book-tax differences in property basis		(96,414)					(96,414)
Unrealized hedging transactions		(11,930)					(11,930)
Other								(1,010)
Deferred noncurrent income tax liabilities		(113,851)					(113,851)	$ (7,376)
Net current deferred income tax assets (liabilities)		$ (95,791)					$ (95,791)
Income tax provision	$ 280,900
Predecessor
Current:
Federal						$ 8,666
Total current income tax benefit (provision)						8,666
Deferred:
Federal						(22,491)
State						22,491
Total income tax benefit (provision)						$ 8,666
Differences between the actual income tax benefit (provision) and the expected income tax benefit (provision)
Federal statutory rate (as a percent)						35.00%
Expected tax benefit (provision)						$ (1,152)
State income tax expense, net of federal benefit						(43)
Stock-based compensation						(14,803)
Adjustments attributable to reorganization						275,460
Debt related costs						(4,089)
Cancellation of indebtedness income						103,268
Increase (reduction) in deferred tax asset						14,645
Change in valuation allowance and related items						(263,211)
IRC section 108 attribute reduction						(101,342)
Other						(67)
Total income tax benefit (provision)						$ 8,666

INCOME TAXES-Operating loss car

INCOME TAXES-Operating loss carryforward (Details) - USD ($) $ in Thousands	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2016	Jan. 31, 2016	Aug. 31, 2016	Mar. 31, 2016	Jun. 30, 2016	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income taxes
Amount of CODI			$ 844,700
Expiration of net operating losses		$ 891,500	750,000					$ 750,000		$ 891,500		$ 750,000
Deferred tax expense		95,800						4,744		95,791	$ (5,000)	0
Net operating loss carryforwards		975,000								975,000
Net operating loss carryforward subject expiration in 2037		$ 129,300								129,300
Carryforward period of NOLs that will expire in 2037		20 years
Net operating carryforward not subject to expiration		$ 845,700								845,700
Recognized tax benefit		81,600								81,600
Valuation allowance		290,300								290,300
Decrease in valuation allowance										136,400
Unrecognized tax benefits		$ 0	$ 0					0		0	$ 0	0
Open tax year (in years)											3 years
Interest and penalties								$ 0		$ 0	$ 0
Predecessor
Income taxes
Deferred tax expense									$ (8,666)
Unrecognized tax benefits	$ 0								$ 0
Interest and penalties	$ 0			$ 0	$ 0	$ 0	$ 0					$ 0

EARNINGS PER COMMON SHARE (Deta

EARNINGS PER COMMON SHARE (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 09, 2016	Dec. 31, 2018	Dec. 31, 2017
Basic:
Net income (loss) available to common stockholders	$ (479,984)		$ 45,959	$ 487,679
Weighted average basic number of common shares outstanding	91,228		157,011	132,763
Basic net income (loss) per share of common share (in dollars per share)	$ (5.26)		$ 0.29	$ 3.67
Diluted:
Net income (loss) available to common stockholders	$ (479,984)		$ 45,959	$ 487,679
Weighted average basic number of common shares outstanding	91,228		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	91,228		157,295	133,576
Diluted net income (loss) per share of common stock (in dollars per share)	$ (5.26)		$ 0.29	$ 3.65
Common stock equivalents excluded from computation of diluted earnings per share of common stock because of anti-dilutive effect	11,200		13,100	17,100
Predecessor
Basic:
Net income (loss) available to common stockholders		$ (32,794)
Weighted average basic number of common shares outstanding		120,513
Basic net income (loss) per share of common share (in dollars per share)		$ (0.27)
Diluted:
Net income (loss) available to common stockholders		$ (32,794)
Weighted average basic number of common shares outstanding		120,513
Weighted average diluted number of common shares outstanding		120,513
Diluted net income (loss) per share of common stock (in dollars per share)		$ (0.27)
Common stock equivalents excluded from computation of diluted earnings per share of common stock because of anti-dilutive effect		43,600

ADDITIONAL FINANCIAL STATEMEN_3

ADDITIONAL FINANCIAL STATEMENT INFORMATION (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Sep. 09, 2016
Accounts receivable:
Oil, natural gas and natural gas liquids revenues	$ 26,432	$ 24,110
Joint interest accounts	7,369	2,249
Other	1,917	10,057
Total	35,718	36,416	$ 116,859
Prepaids and other:
Prepaids	3,503	4,324
Income tax receivable	1,250	6,250
Other	35	54
Total	4,788	10,628	7,629
Funds in escrow and other:
Funds in escrow	570	563
Other	1,611	1,128
Total	2,181	1,691	1,637
Accounts payable and accrued liabilities:
Trade payables	68,959	35,688
Accrued oil and natural gas capital costs	41,461	50,743
Revenues and royalties payable	20,526	20,256
Accrued interest expense	16,971	10,985
Accrued employee compensation	3,421	9,805
Accrued lease operating expenses	6,292	2,024
Other	218	1,586
Total	$ 157,848	$ 131,087	173,688
Predecessor
Accounts receivable:
Total			116,859
Prepaids and other:
Total			8,961
Funds in escrow and other:
Total			1,610
Accounts payable and accrued liabilities:
Total			$ 160,000